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Power System Review

2012-13June 2014

38 Cavenagh Street DARWIN NT 0800

Postal Address GPO Box 915 DARWIN NT 0801

Email: [email protected]

Website: www.utilicom.nt.gov.au

Power System Review 2012-13

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ContentsGlossary 10

1. Executive Summary 13

1.1 Purpose of the Power System Review 131.2 Changes from the 2011-12 Review 141.3 Objective of the 2012-13 Review and report structure 151.4 Key Findings 161.5 Progress against recommendations from 2011-2012 Power System Review 221.6 Independent Investigation into the 12 March 2014 Darwin-Katherine System Black

Incident 251.7 Commission’s focus for the 2013-14 Review 26

2. Overview of the Northern Territory Power Systems 27

2.1 Legislative Framework 272.2 Overview of the transmission and distribution systems 282.3 Proposed Wholesale Electricity Generation Market 292.4 Structural Separation of PWC 302.5 Overview of generating plant 342.6 Industry participants 34

3. Power System Reliability 37

3.1 Introduction 373.2 Generation Reliability 373.3 Power System Security and Operation 383.4 Measures and Standards of Generating Reliability 393.5 Models used to Assess on Generating Reliability 413.6 Modelling Reliability in the Northern Territory Power Systems 423.7 The Economics of Generation Reliability 453.8 Reliability Review Conclusions 473.9 Progress against findings from 2011-12 Power System Review 483.10 System Reliability Key findings 48

4. Maximum Demand Outlook 51

4.1 Introduction 514.2 Definition 524.3 Historical MD Growth and Accuracy of the 2012-13 Forecast 544.4 Load Factor 574.5 PWC System and Network MD Forecasting Methodology 594.6 PV Projections 634.7 PWC Zone Substation Maximum Demand Forecasts 714.8 Load factor 744.9 Progress against findings from 2011-12 Power System Review 774.10 Maximum Demand key findings 77

5. Generation Performance 80

5.1 Introduction 805.2 Availability of existing generators 83

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5.3 New or proposed generators 865.4 Progress against key findings from the 2011-12 Power System Review 875.5 Key findings – generation operation and planning 87

6. Fuel Supply 89

6.1 Introduction 896.2 History of Northern Territory Gas Supply 896.3 Adequacy of Northern Territory Gas Supply 896.4 PWC Gas Supply 896.5 Progress against findings from the 2011-12 Power System review 916.6 Key Findings – Security of Fuel Supply 91

7. Generation Adequacy 93

7.1 Introduction 937.2 Generation adequacy assessment 947.3 Standards of service indicators 997.4 Contribution of PV 1007.5 Capacity and energy sufficiency 1017.6 Validity of use of Reserve margin as an indicator of future reliability performance 1027.7 Progress against findings from 2011-12 Power System Review 1027.8 Key findings – generation adequacy assessment 102

8. Electricity Networks Adequacy 105

8.1 Basis of network adequacy 1058.2 Network capacity and performance 1068.3 Incident report review 1108.4 Planned network enhancements 1128.5 Reliability 1148.6 Feeder performance 1198.7 Progress against findings from 2011-12 Power System Review 121

9. Customer Service Review 125

9.1 Structure of this year’s review 1259.2 PWC Network Services Performance 1269.3 PWC Retail Services Performance 1309.4 Customer hardship programs 1339.5 Progress against findings from the 2011-12 Review 1339.6 Key Findings 133

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Appendices

A Generating Units

A.1 Darwin-KatherineA.1.1 Channel IslandA.1.2 WeddellA.1.3 BerrimahA.1.4 Shoal Bay and Pine Creek PPAsA.1.5 Katherine

A.2 Tennant CreekA.3 Alice Springs

A.3.1 Ron GoodinA.3.2 Owen SpringsA.3.3 Brewer PPAA.3.4 Uterne PPA

B Generation Adequacy – Alice Springs and Tennant Creek

B.1 Alice SpringsB.2 Tennant Creek

C Tabular Demand Statistics and MD Forecasts

C.1 Darwin-Katherine SystemC.1.1 Comparison of Actuals and Forecast from Previous PSRC.1.2 Darwin-Katherine MD Forecasts

C.2 Alice SpringsC.2.1 Comparison of Actuals and Forecast from Previous PSRC.2.2 Alice Springs MD Forecasts

C.3 Tennant CreekC.3.1 Comparison of Actuals and Forecast from Previous PSRC.3.2 Tennant Creek MD Forecasts

D Details of PWC Network MD Forecasting Methodology

E Summary of Power and Water Corporation Technical Audit

F Alignment of Network Management Plan with Australian Electricity Industry Reporting

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List of Figures

Figure 2.1: Northern Territory energy supply infrastructure. 31

Figure 2.2: Darwin-Katherine Transmission Network (major components) 32

Figure 2.3: Alice Springs Transmission and Distribution Network 33

Figure 3.1: Electricity Supply Chain 38

Figure 3.2: Generation Reliability – Darwin Katherine System (USE per cent of energy) 43

Figure 3.3: Generation Reliability – Alice Springs System (USE per cent of energy) 43

Figure 3.4: Generation Reliability Low Scenario – Darwin Katherine System Reserve 44

Figure 3.5: Generation Reliability Low Scenario – Alice Springs System Reserve 44

Figure 3.6: Indicative Assessment - Optimal Level of Installed Generation 47

Figure 4.1: Demand as measured at different locations in a power system 52

Figure 4.2: System Historical Maximum Demand and 2012-13 Forecasts 55

Figure 4.3: Darwin- Katherine - Comparison of 2012-13 ZSS Actual (P50) and Forecast (P50) MDs 56

Figure 4.4: Load Factor Trends – Actual and 50 per cent POE Weather Conditions 58

Figure 4.5: Darwin-Katherine: Historical Non-coincident ZSS and Coincident ZSS MD Growth 59

Figure 4.6: Darwin Katherine: Daily MD versus Daily maximum Temperature 62

Figure 4.7: Desert Knowledge Alice Solar City (DKASC) average PV output time profile 67

Figure 4.8: Density functions of daily maximum demand for all regions 67

Figure 4.9: Density functions of daily maximum demand by region 68

Figure 4.10: Estimated uptake function 68

Figure 4.11: Darwin-Katherine System Maximum Demand Forecasts 71

Figure 4.12: Darwin-Katherine ZSS Maximum Demand Forecasts 72

Figure 4.13: Alice Springs System Maximum Demand Forecasts 73

Figure 4.14: Alice Springs ZSS Maximum Demand Forecasts 73

Figure 4.15: Tennant Creek System Maximum Demand Forecasts 74

Figure 4.16: Load Factor Trends – Actual and 50 per cent POE Weather Conditions 76

Figure 4.17: Darwin-Katherine: Historical Non-coincident ZSS and Coincident ZSS MD Growth 76

Figure 6.1: Gas Supply Locations 90

Figure 7.1: Darwin Katherine N – X assessment 95

Figure 7.2: Loss of load (LOLP) or Lack of Reserve (LOR) probability 96

Figure 7.3: Tennant Creek N–X assessment 97

Figure 7.4: Alice Springs N – X assessment 98

Figure 7.5: 3 Region SAIDI trends 99

Figure 7.6: 3 Region SAIFI trends 100

Figure 7.7: Uterne solar power station statistical variation 101

Figure 8.1: 11 kV PWC feeder utilisation 110

Figure 8.2: Adjusted SAIDI historical results comparison - Graph 118

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Figure 8.3: Adjusted SAIFI historical results comparison - Graph 119

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List of TablesTable 2.1: Power Networks’ Statistics (regulated network) 34

Table 2.2: Electricity licence holders at 30 June 2013 35

Table 3.1: LOLP and EUE Relationship 40

Table 3.2: Commonly used Probabilistic Reliability Indices 40

Table 3.3: Reliability Model Runs 42

Table 3.4: Assessment of VCR Undertaken in the NEM ($/MWh) 46

Table 3.5: Indicative Optimum Generation Level of Reliability 47

Table 4.1: Review of 2012-13 Actual and Forecast P50 Maximum Demands (MW) 54

Table 4.2: Temperature Correction Factors ** 61

Table 4.3: Sources used for estimated historical payback 65

Table 4.4: Sources used for projecting future uptake 66

Table 4.5: MD Offset Factors 69

Table 4.6: Projected cumulative uptake of PV by region (kW) 70

Table 4.7: Projected contribution of PV to offsetting MD by region (kW) 70

Table 5.1: Probability of Channel Island Machines Being Out of Service 84

Table 5.2: Channel Island Machines Actual vs. Predicted Availability 85

Table 7.1: Generation planning criteria 93

Table 7.2: N – X margins for 2012-13 94

Table 7.3: Availability by generating unit type: Darwin Katherine 96

Table 7.4: Percentage penetration of photovoltaic 100

Table 8.1: Summary of the transmission constraints (N-1 conditions) 107

Table 8.2: Summary of the substation constraints (N-1 conditions) 109

Table 8.3: Forecast capital expenditure ($ million, real $2013/14 with input cost escalation) 113

Table 8.4: Alice Springs transmission network performance 115

Table 8.5: Darwin-Katherine transmission network performance 115

Table 8.6: 2012-13 Distribution SAIDI results segmented by feeder category (adjusted) 116

Table 8.7: 2012-13 Distribution SAIFI results segmented by feeder category (adjusted) 116

Table 8.8: PWC and Ergon SAIDI and SAIFI comparison 117

Table 8.9: Adjusted SAIDI historical results comparison 118

Table 8.11: Adjusted SAIFI historical results comparison 118

Table 8.13: 2012-13 List of poorly performing feeders exceeding the SAIDI performance ratio 120

Table 8.14: 2012-13 Upgrade actions for poorly performing feeders 120

Table 8.15: 11 and 22 kV feeder utilisation 121

Table 8.16: 11 and 22 kV feeder utilisation long term trend 121

Table 8.17: 11 kV feeder utilisation above 80 per cent trend 121

Table 9.1: Connections and reconnections performance 126

Table 9.2: New Connections in urban areas to new subdivisions 127

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Table 9.3: Reconnections and new connections performance progress 127

Table 9.4: Quality of supply complaints 2012/13 128

Table 9.5: Quality of supply complaints trend 128

Table 9.6: Customer complaints due to network related activities 129

Table 9.7: Average time taken to respond to a customer’s written enquiry segmented into regions 130

Table 9.8: Telephone call answering reporting 131

Table 9.9: Progress on telephone call response 131

Table 9.10: Retail related complaints 132

Table 9.11: Progress on total complaint numbers 133

Table 9.12: Customer hardship summary 133

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Purpose of this Report

The Power System Review (Review) is prepared by the Utilities Commission in accordance with section 45 of the Electricity Reform Act.

Regular power system reporting aims to provide the routine release of comprehensive and authoritative data to industry participants, prospective participants, customers, regulators and policymakers, in order to:

- support planning and monitoring activities by providing data to assist identification of the optimal investment options, and to facilitate coordination of investment actions;

- advise on system performance against the price and service expectations; and - assist in holding electricity businesses accountable for reliability performance outcomes.

The Review provides information on the performance of the power system including:

- planning information, including demand forecasts, the adequacy of system capacity relative to forecast demand, and knowledge of planning and investment commitments;

- the performance and health of the system, which includes information on system performance trends, regulatory and technical compliance (including equipment capability relative to security standards) and the findings of investigations into power system incidents; and

- outcomes experienced by customers.

Disclaimer

The Review is prepared using information sourced from participants of the electricity supply industry, Northern Territory Government agencies, consultant reports, and publicly available information. The Commission understands this information to be current as at December 2013. Where there have been significant developments post December 2013, the Commission has noted these developments throughout the report.

The Review contains predictions, estimates and statements that are based on the Commission’s interpretation of data provided by electricity industry participants and assumptions about the power system, including load growth forecasts and the effect of potential major developments in particular power systems. The Commission considers that the Review is accurate within the normal tolerance of economic forecasts.

Any person using the information in the Review should independently verify the accuracy, completeness, reliability and suitability of the information and source data. The Commission accepts no liability (including liability to any person by reason of negligence) for any use of the information in this Review or for any loss, damage, cost or expense incurred or arising by reason of any error, negligent act, omission or misrepresentation in the information in this Review or otherwise.

Inquiries

Any questions regarding this report should be directed in the first instance to the Executive Officer, Utilities Commission at any of the following:

Utilities Commission GPO Box 915DARWIN NT 0801

Telephone: 08 8999 5480Fax: 08 8999 6262Email: [email protected]

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GlossaryTerm Definition

Act Electricity Reform Act

AEMO Australian Energy Market Operator

AER Australian Energy Regulator

CIPS Channel Island Power Station

DNSP Distribution Network Service Provider

ESOO Electricity Statement of Opportunities published by AEMO – provides technical and market data and information regarding investment opportunities in the NEM over the next ten years

EUE Expected Unserved Energy

Feeder Any of the medium-voltage lines used to distribute electric power from a substation to consumers or to smaller substations

GWh Gigawatt hour

IPP Independent Power Producer. Licensed IPPs are parties who do not wish to participate fully in the electricity supply market and generate electricity under contract for another generator.

kV Kilovolt

LOLP Loss of load probability – Probabilistic analysis of the adequacy of generation capacity

MD Maximum Demand

MW Megawatt

MVA Megavolt Ampere

N-X Planning criteria allowing for full supply to be maintained to an area supplied by N independent supply sources, with X number of those sources out of service

NEM National Electricity Market

NER National Electricity Rules

OSPS Owen Springs Power Station

Power system Refers to the Darwin-Katherine power system, Tennant Creek power system and/or the Alice Springs power system

Probabilistic analysis Analytical tool for determining the likely range of outcomes over a system as a whole arising from a series of individual events. For example, if each generating unit individually has a certain probability of being out of service at a particular time, probabilistic analysis calculates the probability of 1, 2, 3 or more units being out of service at the same time. This approach is also commonly called Monte Carlo analysis, and involves running many simulations of the system to determine the probability of certain outcomes occurring

PV Photovoltaic

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PWC Power and Water Corporation1

PWC Networks The networks business division of PWC

RGPS Ron Goodin Power Station

Region Refers to the Darwin Region, Katherine Region, Tennant Creek Region and/or the Alice Springs Region

Regulatory bargain Optimisation of the price, service levels and risk relationship between distribution businesses and customers embodied in a regulatory decision

Reserve plant margin

Total system capacity available less the actual maximum demand for electricity in a particular year, expressed as a percentage of maximum demand.

SAIDI System Average Interruption Duration Index – The average number of minutes that a customer is without supply in a given period

SAIFI System Average Interruption Frequency Index – The average number of times a customer’s supply is interrupted in a given period

Spinning reserves The ability to immediately and automatically increase generation or reduce demand in response to a fall in frequency

TNSP Transmission Network Service Provider

UFLS Under Frequency Load Shedding – Reducing or disconnecting load from the power system to restore frequency to the normal operating range

VCR Value of Customer Reliability

WA WEM Western Australian Wholesale Electricity Market

WPS Weddell Power Station

ZSS Zone Substation

1 From 1 July 2014, the generation and retail business units of Power and Water Corporation will be structurally separated into standalone Government Owned Corporations under the Government Owned Corporations Act. This 2012-13 Power System Review (and the 2013-14 Power System Review) relate to the period prior to structural separation of Power and Water Corporation.

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1. Executive Summary

1.1 Purpose of the Power System Review

On an annual basis, the Utilities Commission (the Commission) is required by the Electricity Reform Act (the Act) to prepare a Power System Review (the Review) that reports on power system performance and capacity in the Northern Territory.2

In addition to its statutory requirements, the Commission’s aim is for the Review to be used as a strategic planning tool to provide authoritative data to support the identification of the most economic options for augmentation and expansion of infrastructure to maintain security and reliability standards on a cost effective basis for the long term benefit of Territory customers.

Regular reporting of performance should also allow comparison of power system performance between jurisdictions, in particular systems with similar characteristics (such as geographical and environmental factors).

The Review relates to the Darwin-Katherine, Alice Springs and Tennant Creek power systems (referred to as the market systems) and is prepared with the assistance and advice of participants in the electricity supply industry, other electricity industry stakeholders and consultant reports.

In December 2012, the Commission released a new Electricity Standards of Service Code3 (ESS Code) which establishes standards of service and performance measures in the electricity supply industry. The ESS Code forms the basis for monitoring and enforcing compliance with and promotion of improved standards of services for this and future Reviews.

In July 2013, the Commission approved the distribution and transmission network performance target standards applicable to Power and Water Corporation’s (PWC) network business unit from 1 July 2014 to 30 June 2019. For the 2012-13 reporting period, PWC was requested to report, on a voluntary and best endeavours basis, as if the new Standards of Service Code, including targets set to apply from 1 July 2014, had been in effect from the full financial year.

For the 2012-13 Review, the Commission engaged Entura, engineering consultants with expertise in all aspects of the energy supply market to provide advice in regards to the generation, network, overall power system and customer service aspects of the review. Entura partnered with Marsden Jacob Associates to provide advice in relation to demand forecasting and overall power system reporting analysis. The Commission engaged MDQ Consulting, a consulting firm with expertise in gas markets and fuel supply issues to provide advice on the fuel supply component of the review.

The 2012-13 Review was delayed due to the investigation by the Commission of the System Black incident that occurred on 12 March 2014 in the Darwin-Katherine system and the finalization of the 2014 NPD. The findings and recommendations from the System Black investigation were provided to the Regulatory Minister on 2 April 2014 in accordance with a Terms of Reference from the Minister pursuant to section 6(1)(g) of the Utilities Commission Act. Although the System Black incident and the Commission’s investigation fall outside of the 2012-13 Review period, the Commission considers

2 Section 45, Electricity Reform Act.3 Available from the Commission’s website, www.utilicom.gov.au.

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the findings of the investigation to be of significant importance and have include a summary of its recommendations in section 1.6. The Commission considers that recommendations from the investigation should be pursued as a priority by PWC and they will be closely monitored by the Commission in future reviews.

On 24 April 2014, the Commission released its Final Determination in relation to the 2014 Network Price Determination (NPD), the culmination of an extensive two-year review process including a review of PWC Networks’ efficient costs (including proposed capital expenditure and proposed operating and maintenance expenditure) required to meet specified standards of service and increasing electricity demand for the five-year regulatory control period commencing 1 July 2014. The review included assessments by technical consultants and consultation with stakeholder groups. Where information was provided by PWC Networks’ as part of the 2014 NPD and relevant to the Power System Review, the Commission has considered this information.

1.2 Changes from the 2011-12 Review

Better Alignment with Industry Reporting

Regular and comprehensive reporting on power system, and distribution network performance and health is a feature of the electricity supply industry elsewhere in Australia. The Commission notes the increasing competitive interest in the provision of electricity at both the wholesale and retail level in the Territory. This drives the need for increased transparency in the provision of network and system control services.

In the National Electricity Market (NEM), the Australian Energy Regulator (AER) publishes an annual State of the Energy Market report to provide a high level overview of energy market activity in Australia, and supplement the AER’s extensive technical reporting on the energy sector. The Australian Energy Market Operator (AEMO) publishes detailed reports on system planning and the operation of energy markets, notably the National Transmission Network Development Plan, Electricity Statement of Opportunities report and Power System Adequacy report. At the distribution network level, network service providers are currently required under jurisdiction specific obligations to report on distribution planning and performance. This is progressively transitioning to become a requirement under the National Electricity Rules (NER).

These reporting arrangements have developed over the past decade or more, during which time industry participants have built their capacity to provide relevant information. While the Territory does not participate in the NEM, where applicable the Commission intends to continue to transition reporting requirements to be consistent with those of the NEM as they are considered to be good electricity industry practice and in the best long term interest of Territory consumers. This approach is consistent with the direction proposed by the Northern Territory Government as part of its regulatory reform of the electricity market.4

The Commission notes that the suite of strategic planning reports available in the NEM has been developed over time and any adoption of similar reporting formats by the Commission will need to be achieved in a staged approach to reflect this development process and the Commission's and Territory electricity entities capabilities and resource availability.

4 Department of Treasury and Finance, Northern Territory Electricity Market Reform, Information Paper, February 2014, http://www.treasury.nt.gov.au/PMS/Publications/Economics/Electricity%20Market%20Reform/I-EMR-2014.pdf

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http://www.treasury.nt.gov.au/PMS/Publications/Economics/Electricity%20Market%20Reform/I-EMR-2014.pdf


The 2012-13 Review further aligns with other power system reporting in the NEM. In particular, the Commission has placed considerable focus in the 2012-13 Review on actual system availability (generation and networks) to assess the security and reliability (dynamic performance) of the system, including voltage, forced outage rates and spinning reserve. For the 2012-13 Review, the Commission has also provided considerable emphasis on the objectives and methodology of the additional reporting and analysis.

While gaps still exist, the Commission acknowledges a continuing improvement in PWC’s ability to provide asset performance information and the level of analysis supporting that information, building on gains made during previous reviews. Appendix F provides a comparison between PWC Networks’ Network Management Plan and reporting required under the NER.

The Commission is aware of the significant work undertaken by the PWC Networks as part of the 2014 Network Price Determination process, particularly relating to the documentation, data provision and reporting at a level not provided by PWC Networks in the past. The Commission considers that the work undertaken is a considerable achievement for PWC Networks and at a time of significant competing priorities. The Commission acknowledges that PWC Networks may not have been able to address some issues raised in previous reviews, such as further alignment of the Network Management Plan with NEM planning reports, because of resources being directed towards the 2014 Network Price Determination.

1.3 Objective of the 2012-13 Review and report structure

The objective of the Review is to produce not just an obligatory reporting mechanism for regulated entities but also a strategic planning tool to provide authoritative data to support the identification of the most economic future options for augmentation and expansion of electricity infrastructure in the Territory to maintain security and reliability standards on a cost effective basis.

The Commission's overall objective is that the Review provides the following key information:

data to support the identification by market participants of the most economic future options for augmentation and expansion of infrastructure to maintain security and reliability standards;

credible and dependable medium and long term forecasts of future supply and demand conditions under various scenarios;

possible future generation, transmission and distribution capacity constraints (projected system adequacy for medium and long term), taking into account maintenance and outage plans;

integration with the planning and maintenance management of infrastructure assets;

analysis of generation, transmission and distribution performance data;

adequacy of sources of fuel for electricity generation for the medium and long term;

analysis of generation and networks reliability performance, and customer service performance information; and

analysis of power system incidents and identification of underlying systemic issues.

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2012-13 Report structure

The 2012-13 Review covers the following components:

power system reliability;

demand outlook;

generation outlook;

generation adequacy;

fuel supply;

network adequacy; and

customer service performance.

1.4 Key Findings

The Commission’s key findings for the 2012-13 Review are detailed below.

Power System Reliability

The 2012-13 Review is the first time overall power system reliability has been undertaken utilising techniques commonly used in the NEM and other power systems. Reliability of a power system is defined as its ability to perform its intended function of supplying customers over a defined period of time and under specified conditions (which include weather and number of plant items out of service). The 2012-13 Review provides an overview of the importance of generation reliability, composite reliability (transmission and generation reliability), customer supply reliability and power system security and operation.

The 2012-13 Review places particular emphasis of generation reliability including an assessment by Entura of the Expected Unserved Energy (EUE), the reliability index used in the NEM and the Western Australian Wholesale Electricity Market (WEM). The modelling undertaken by Entura assumed that the full technical capability of the generation system would be used to supply customers and avoid customer load shedding.

The results show that both the Darwin-Katherine and Alice Springs power systems have a high level of generation capacity over most of the 10 year forecast period (to 2022-23), however the results also illustrate the sensitivity of reliability to the assumed generator forced outage rates. This means the two power systems are likely to have the technical capacity to operate at a reliability level for the 10 year review period assuming a low 2 per cent forced outage rates for generators (92 per cent overall availability).

While this result in isolation is promising, the Commission is concerned with the actual availability of generation plant, particularly at Channel Island, noting that for 2012-13 five out of nine sets at Channel Island had less 92 per cent overall availability (although both commissioned generating sets at Weddell had approximately 97 per cent availability), with some considerably less. One of the Channel Island generating sets (Unit 2) had zero availability during 2012-13 due to life extension maintenance work and another four generating set (units 5, 7, 8 and 9) availability was less than 67 per cent due to cabling issues.

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The Commission recommends that further work be taken by PWC to incorporate reliability assessment and monitoring into PWC’s planning and reporting processes.

It is also noted that there is significant experience in the NEM in monitoring and modelling reliability that can assist in this development. Further that the different characteristics of individual Territory power systems that are important to the how each performs requires that system planning and operations staff have a major role in this development.

Demand Outlook

Demand forecasts are a critical input into the investment and operating decisions for a power system. System Maximum Demand (MD) is used for generator investment planning and as an input to annual operational decisions and Zone Substation (ZSS) and feeder MD are used by network providers for the network planning purposes to identify potential constraints on the network that may need network investment.

The 2011-12 Review published forecasts of system, ZSS and feeder MDs for the period 2012-13 to 2021-22 for the Darwin-Katherine, Alice Springs and Tennant Creek systems. These forecasts were developed on the basis of weather conditions that correspond to a 50 per cent and 10 per cent POE.

The expected growth in system MD was determined to be 2.7 per cent based on historical maximum demand (weather corrected) and zone substation growth.

A comparison of these forecasts to actuals was made for the 2012-13 year (same weather basis). For 2012-13, all the forecasts PWC Networks’ projected a higher MD than eventuated. While the actual size of the error was larger for the larger systems, the percentage error was smaller for the larger systems. This analysis suggests to the Commission that PWC’s forecasts err on the high side.

In terms of system historical actuals, weather corrected actuals (P50) and the 2012-13 forecast system MDs for the Darwin-Katherine, Alice Springs and Tennant Creek systems, observations from over the period 2007 to 2013 indicate:

only the Darwin-Katherine system showed increasing MDs; and

care is needed in interpreting MD growth rates as the non-coincident ZSS and system had different MD growth rates.

The Commission’s ZSS and system MD forecasts to 2022-23 is provided at Appendix C. Noting that PWC’s forecasts err on the high side, the Commissions identified the following issues and recommendations for improving the reliability of PWC Networks’ demand forecasts:

Lack of data on historical ZSS MDs and customer demographics at each ZSS limited the confidence that could be achieved in the ZSS MD forecasts. To address this it is recommended that investments be made to improve the data available including going back 15 years, breakup of customer types, rooftop PV and additional documentation of future spot loads at each ZSS.

The methodology used was limited but consistent with the data available and this had not changed since the last review. Accompanying additional data, it is recommended that the methodology be reviewed to incorporate explanatory variables such as population, rooftop PV and testing the assumption of linearity. In addition, the approach to weather correction had the risk of overestimating the impact of temperature in the temperature range associated with maximum demands, and the Commission recommends that this be reviewed.

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The review observed that the internal processes used by PWC should be improved to reduce the chance of error. This includes better documentation and labelling of numbers, and reducing the need for manual transcription of data between different spreadsheets.

Consistent with the 2011-12 Review, the Commission reviewed load factor for the Darwin-Katherine, Alice Springs and Tennant Creek system. The Darwin-Katherine system actual load factor of 61.7 per cent in 2012-13 was the highest in the review period and equal to that recorded in 2008-09. The weather corrected load factors were steady but below the load factors before and including 2009-10.

The Alice Springs and Tennant Creek systems had steadier load factors and showed no indication that this was decreasing.

Generation Outlook

The Commission notes that the generation planning criteria adopted by PWC for the Darwin-Katherine system is N-3 as a temporary measure to allow for life extension works at Channel Island Power Station.

There is adequate generation available at N-2 to 2022-23 but if using an N-3 standard as determined by PWC for Darwin-Katherine, and considering PWC demand forecasts and generation planned outages, the N-3 standard is not met in 2018-19 and 2019-20. This may not be an issue if PWC’s planning criteria for the Darwin-Katherine system returns to an N-2 criterion with the completion of life extension work at Channel Island Power Station.

The Commission notes that the forecast capacity for Alice-Springs is well in excess of the N-1 planning criteria for the period to 2022-23.

The Commission notes that there is not sufficient gas generating units in Tennant Creek to satisfy the N-1 planning criterion, without the reliance on diesel back-up at least until 2015-16 at which time new gas units will commence the replacement of retiring diesel units.

Energy growth forecast by PWC Generation applied to the Darwin-Katherine, Alice Springs and Tennant Creek were consistent with those used by PWC Networks’ in terms of maximum demand in the Darwin-Katherine system (2.7 per cent). Energy forecasts for Alice Springs and Tennant Creek showed virtually no growth.

Predominance of multiple contingency events

The Commission is concerned that approximately 50 per cent of the major system events examined by the Commission constitute double contingency events. Such a high level of double contingency events suggests that it is not appropriate for spinning reserve or system security decisions to be made using the common N-1 (N+1 machines in service) methodology. Furthermore triple or even higher order contingencies are conceivable.

As required by the System Control Technical Code, all multiple contingency events must be reported to the Commission as major events, irrespective of whether any load is curtailed. The Commission intends to closely monitor the reporting, analysis and PWC’s proposed corrective actions relating to multiple contingency event in future reviews.

Reliance on load shedding in lieu of spinning reserve

PWC’s practice of routinely shedding load for single contingency events would be unsatisfactory in most electricity networks. The Commission notes that the appropriate level of spinning reserve (and indirectly this load shedding practice) is currently being investigated by PWC. The Commission recommends that PWC consider the outcomes of its investigation including amending its spinning reserve practices if necessary.

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The Commission observes a mismatch between the historical values for Loss of load probability (LOLP) or N-X margin and the forecast. That is, the forecast performance is, in general, superior to past performance. While this is positive, it is difficult for the Commission to place considerable confidence on higher to unachieved levels of reliability as described by LOLP.

The Commission notes that PWC has not moved to a stochastic method for planning or assessing future generation adequacy and so has performed this analysis in this report. The results are encouraging but are heavily dependent on the availability forecast from PWC. The availability forecast is not detailed enough to provide a high degree of confidence. The Commission recommends PWC adopts this change to its planning methods and in so doing adjusts and refines the methods of forecasting generating unit availability.

As discussed earlier, the Commission observes that there is a disjoint between perceived generator reliability as exhibited by the actual system performance and that modelled in the Review. The Commission considers it appropriate that PWC provide greater transparency with respect to system incidents to allow the Commission to calibrate the accuracy of the planning tools in predicting future reliability margins.

Application of probabilistic analysis to generation reliability

The Commission used data provided by PWC to undertake probabilistic analysis as part of the 2012-13 Review. The Commission maintains that this practice should be adopted by PWC to ensure that optimal management of generating capacity occurs into the future.

Darwin–Katherine Projection

Generation adequacy appears to improve for the Darwin-Katherine region across the next 10 years based on PWC’s projected plant availability. However, as discussed above, the Commission is not confident that the projected plant availability is well enough understood to provide reliable projections.

Alice Springs Projection

The Commission notes that run hours on Owen Springs units 3 and 4 are significantly higher than those on units 1 and 2. The Commission remains concerned as to the serviceability of these units and will require further assurance of the ability of these units to contribute to reliable supply in Alice Springs.

Tennant Creek Projections

The Commission notes that the Ruston diesel units are due to be retired by 2017-18 and PWC propose three new 2MW gas sets. PWC propose smaller generating sets to operate as base load capacity, increasing the redundancy and reliability of the power station.

Generation performance trend

With respect to SAIFI and SAIDI indices the generating units have improved across the five year study window.

Fuel Supply Outlook

The Commission notes that PWC’s contingency fuel supply arrangements are significantly improved compared to the period pre-2009 when PWC was 100 per cent reliant on Amadeus basin gas. Since the commencement of Blacktip production there has been periods of planned and unplanned supply interruptions. PWC has successfully maintained gas supply to its power stations through the use of back-up supply from Darwin LNG and spare pipeline line pack. The addition of the Inpex LNG back-up arrangement from 2017 will materially improve security of gas supply to the Northern Territory.

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Darwin/LNG and Inpex LNG can supply the southern region but is subject to sufficient pressure being able to transport gas from Darwin to Alice Springs. Diesel, spare pipeline line pack or new gas from Amadeus would be the alternate if northern gas was unable to supply all of the southern gas demand.

In the event involving a major failure of Blacktip gas supply, existing contingency arrangements would exceed volume caps. Additional gas purchases from Darwin LNG, Inpex LNG and/or Amadeus would be required, subject to parties agreeing suitable commercial arrangements.

Networks Outlook

There is sufficient network capacity to meet future demand for the 10 year review period, subject to the following capacity concerns.

Capacity concerns

The Commission’s main capacity concern is the transmission line loop between Hudson Creek, Palmerston, McMinns, Weddell and Archer Substations. In the event of the loss of the Weddell-McMinns 66kV line or Hudson Creek-Palmerston 66 kV line, one line of the 66 kV loop will exceed its thermal limit by the year 2014. This scenario is forecast to worsen as the load increases in the near future, based on PWC demand forecasts, until a new line from Archer or Hudson Creek to Palmerston Substation is constructed. The Commission recommends that PWC consider the most appropriate timing for this project or further consider the option of bringing a 132kV supply into the Palmerston area to ensure security of supply.

Predominance of serious network faults

Genuine transformer faults are usually serious and could have catastrophic effect. Similarly, mal-operation of a transformer protection scheme could lead to a capacity shortfall with a risk of overloading the other transformer/s within the substation. The Commission is concerned with respect to the six transformer outages for the 2012-13 period. Similarly, the frequency of transmission line outages (89) within the Darwin-Katherine area is high and the Commission recommends this issue be addressed by PWC Networks.

Feeder loadings unit

In accordance with good electricity industry practice might suggest that the overall number of feeders with a utilisation above the 80 per cent target should be below 10 per cent. The number of 11 kV feeders exceeding the utilisation target is above 20 per cent and appears to worsen in the medium term assuming demand is consistent with PWC’s forecasts. This data would suggest that the overall planning of the 11 kV network and the capacity of the network to supply customers when feeders are out of service during contingency scenario, feeder or substation upgrade should be further assessed by PWC.

Electricity networks adequacy – transmission substations (Capacity constraints at N-1)

PWC has proposed some upgrade works to mitigate many of the potential overloads identified in the 2011-12 Review.

Feeder loading concerns

The Commission notes that again some feeders appear to be facing over-utilisation into the 2013-14 year. PWC advise that this is due to re-allocation of load not occurring in a timely manner. The Commission recommends PWC document plans to expedite load re-allocation to increase the time margin before a forecast over-utilisation.

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Alignment with NEM planning

Improvements in aligning the Network Management Plan with the requirements of the NER have been made in comparison with the 2011-12 report. The Commission is aware that PWC needs time to establish the systems and processes required to meet these reporting requirements, however there are still critical areas of reporting that need attention including:

o changes from the previous year’s reporting;

o options analysis to fully document the major strategies and plans in the yearly report;

o power factor at peak load;

o detail of the expected commissioning month of each specific major project; and

o fault level details at each substation.

Customer Service Performance

Supply reliability

The numbers of feeders with poor performance have decreased considerably which represents the overall work of PWC Networks in this area.

The Commission considers the planned upgrade actions for these feeders to be reasonable and in line with good electricity industry practice. However, it is recommended that PWC consider if additional engineering measures can be taken including additional remote control high voltage switches to improve the overall restoration time of the healthy sections of the feeder.

Two out of the four problematic feeders were also poor performers in the previous year. The Commission notes that feeder 22TC602 at Tennant Creek is performing significantly below standards. The Commission recommends PWC consider employing effective engineering solutions to improve the performance of 11PA17 Thorngate and 22TC602 Feeder 6. It is expected that the improvement on these two feeders will further improve the SAIDI and SAIFI for Rural feeders.

The Commission recommends PWC provide in future reviews, further details of the poor performing feeders including time to restore the feeder for each outage and specific details of the faulty equipment. This information will further support the Commission’s review of the network performance.

The Commission notes that PWC met its target standard (if it was applied to 2012-13) in three out of four feeder categories in relation to SAIDI and SAIFI performance. The only feeder type not complying with the target standard was Rural Short feeders. PWC advised that the main contributing factor to this poor performance was ‘Trees Blown into Mains’ and ‘Equipment - Failure or Defect’. PWC proposes to address these issues with further vegetation management activities and the feeder upgrade program. The Commission is satisfied with PWC’s response to addressing this issue but also suggest that analysis be undertaken on why SAIDI and SAIFI performance for the Urban feeder category was close to not meeting the target standard (if applied to 2012-13) and recommends that PWC review the reasons for this performance in the forthcoming year.

Customer service – Network

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The Commission notes that customer responsiveness and complaint information is not always categorised as Network or Retail related. While the Standards of Service Code allows for combined reporting, the Commission considers that this should only be a temporary solution until appropriate reporting mechanisms are initiated by PWC. The Commission recommends that PWC categorise complaints separately for Networks and Retail during 2014-15, for its own business purposes particularly given structural separation of PWC Retail will occur on 1 July 2014.

The total number of quality of supply complaints increased in each region, except Alice Springs.

Customer service – Network connections and re-connections

The percentage of on time customer reconnections significantly deteriorated in 2012-13 being below the average as well as the minimum of the last five years. However, on time new connections to urban areas where no extension or augmentation is required improved significantly to the highest level in the last five years.

Urban connections in new subdivisions improved from previous years.

Customer Service - Retail

The Commission noted a deteriorating responsiveness to telephone queries. During 2012-13, the percentage of calls not answered within 20 seconds of the caller asking to talk to a person increased to 60.8 per cent, up from 40 per cent the previous year. While the Commission notes that the volume of calls increased significant by over 20 per cent over the same period, the Commission considers it appropriate that PWC be able to proactively respond to an increase in telephone calls and put in place appropriate measures to address the issue.

1.5 Progress against recommendations from 2011-2012 Power System Review

The progress against recommendations identified in the previous review as the focus for the 2012-13 Review are described in the table below:

Issue Identified Progress

Reduction of the incidence of overloading of 11/22 kV

feeders.

The Commission notes that some feeders appear to be

facing over-utilisation into the 2013-14 year. PWC advise

that this is due to re-allocation of load not occurring in a

timely manner. The Commission requests PWC document

plans to expedite load re-allocation to increase the time

margin before a forecast over-utilisation.

Continued development of the 11/22 kV high voltage feeder

modelling and reporting to include identification of sections

of line that may be of lower rating than the trunk sections

and therefore be at risk of overloading even though the

trunk sections are adequate.

The Commission recommends that PWC perform voltage

level studies on the capacity of feeders to supply loads of

adjacent feeders during contingency scenarios and to

confirm that, in normal operation, the voltage drop at the

end of the feeder during maximum demand is within the

Networks Technical Code. For the 2013-14 Review, the

Commission will seek details of the voltage feeder

modelling including details of the diameter of each section

of the feeder for overloading consideration.

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Assessment of the state of loading of distribution

substations and low voltage distributors (lines or cables that

emanate from distribution substations) and in particular

large distribution substations supplying commercial and/or

industrial loads, and multiple residential loads.

The Commission notes PWC’s decision to begin an

experimental scheme on the use SmartGrids to monitor

distribution transformers. The Commission recommends

PWC provide details of the pilot scheme. It is assumed that

this project will lead to further steps in the implementation

of Smart Grid technology within the Territory. In regards to

low voltage distributors (lines and cables that emanate

from distribution substations) the Commission understands

that PWC and other utilities take action upon voltage

complaints due to high loads on the LV line. The

Commission recommends PWC implement remedial action

in these instances.

Timeliness of customer connections for properties in new

subdivisions and action taken by PWC to improve

performance.

During 2012-13, the average time for new connections to

new subdivisions was 14 weeks for 120 connections. In the

2011-12 Review it was noted that 27 per cent of such

connections were undertaken within 10 weeks and that this

was a cause for concern. The Commission notes that

without data on time taken for all 120 connections, it is

difficult to draw many conclusions. However it appears that

no significant improvement has been made in this area.

Plans to address poor reliability performance for Long Rural

feeder outages.

In the 2011-12 Review, the Commission requested

performance improvement on the two existing long rural

feeders within the Territory. The Mataranka feeder in the

Katherine region is now performing satisfactorily and it is

expected that further improvements will continue to be

made on the Tennant Creek feeder.

Continued development of electrical models, particularly in

the Darwin-Katherine and Alice Springs systems, to identify

both steady state and transient stability issues that must be

addressed in order to fully realise the reliability benefits

achievable from the significant investment in new

generation in the systems. This work should specifically

identify and document any deficiencies in current generator

technical standards or network configuration that may be

contributing to the transient stability issues in the systems,

and develop a plan to redress them.

Darwin-Katherine system: work has commenced on the

dynamic model, and the Darwin-Katherine steady state

model is complete.

Alice Springs system: System Control has both a dynamic

model and steady state model for Alice Springs.

The models will be reviewed by the Commission as part of

the 2013-14 Review.

Consistent with the above approach, finalise a

comprehensive, and consistent with industry practice,

policy on spinning reserves to be carried in each of the

systems, with the intent of increasing the resilience of the

systems to individual generator trips.

The Commission notes the review currently being

undertaken by PWC, with the assistance of SKM, and that

this review should be complete by mid-2014.

Improvement of generation reliability at a unit level to

reduce the number of Under Frequency Load Shedding

(UFLS) events that are occurring across all three systems.

The Commission observes that there is a disjoint between

perceived generator reliability as exhibited by the actual

system performance and that modelled in the review. The

Commission considers it appropriate that PWC provide

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greater transparency with respect to system incidents to

allow the calibration of the accuracy of the planning tools in

predicting future reliability margins.

Introduction of islanding schemes for generation to

minimise the duration of UFLS events.

The investigation into the System Black event of 30 January

2010 recommended that system islanding schemes be

implemented at strategic locations in the system. The

Commission’s investigation into the 12 March 2014

System Black incident identified that an islanding scheme

has not been implemented. The Commission recommends

that an islanding scheme be developed as a matter of

priority.

Use of probabilistic analysis as the primary tool for

assessing system adequacy and generation planning

purposes.

The Commission has used data provided by PWC to

undertake probabilistic analysis as part of the 2012-13

Review. The Commission maintains that this practice should

be adopted by PWC to ensure that optimal management of

generating capacity occurs into the future.

Further analysis of the reasons for the falling load factor in

the Darwin-Katherine and Alice Springs systems.

The 2012-13 Review has shown that on a system wide basis

there is no evidence to support any noticeable decrease in

load factors in either of the Darwin-Katherine, Alice Springs

and Tennant Creek systems. However, the lower load

factors in the Darwin-Katherine system over the past three

years may be an indication of higher MD growth compared

to energy. The review demonstrates that load factor can be

volatile as a single high demand day can significantly impact

its value.

The progress against additional recommendations from the previous review is described in the following sections.

Systems and processes required to meet reporting requirements

The Commission has observed significant progress through 2012-13 in this regard. The impetus provided by a number of information requests related to the 2014 Network Price Determination and separate operational investigations being undertaken by PWC through the financial year has led to a large volume of data being available to the Commission. The following items should be given further focus for the 2013-14 Review and beyond:

1) historical (actual) data should be presented in a consistent format to projections to provide transparent comparison of past trends and future forecasts;

2) further detail should be reported with respect to load forecasting inputs and the method used to predict generating unit availability. This will aid the Commission in validating the data presented; and

3) system event reporting should be further standardised such that the cause and impact of each system event that leads to loss of load can more easily categorised. This will provide the Commission with the ability to compare event severities across years in addition to the SAIFI and SAIDI measures that are used as present.

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The Commission acknowledges the considerable improvement in the standard of reporting of performance and planning for, in particular, the network assets of PWC.

Demand and energy forecasting

This is the subject of Chapter 5 of the 2012-13 Review.

Reliability and availability standards

This is the subject of Chapter 4 of the 2012-13 Review.

1.6 Independent Investigation into the 12 March 2014 Darwin-Katherine System Black Incident

The 12 March 2014 System Black incident affected some 65,000 customers in the Darwin and Katherine area. The Commission conducted an investigation into the incident at the request of the Regulatory Minister. The Commission’s recommendations are listed below:

The Commission recommends a detailed review of PWC’s switching processes and procedures including the development, implementation and authorisation of switching procedures. The Commission considers this a high priority.

A full condition assessment of the 132kV circuit breakers needs to be undertaken as a priority, including a risk assessment of the possibility of future failures of power system security. Depending on the outcome, an acceleration of critical maintenance may be required.

The Commission recommends that an islanding scheme be developed as a matter of priority. The investigation into the System Black event of 30 January 2010 recommended that system islanding schemes be implemented. This was also identified as focus for the 2012-13 Review in the 2011-12 Review.

The Commission recommends a review of PWC’s Black System Restart Procedure and incorporation of black-start procedures for CIPS and WPS to ensure compliance with the SCTC and good electricity industry practice.

The Commission recommends development of a documented and authoritative process for the reporting and implementation of recommendations from power system reports. The lack of progress in implementing an islanding scheme after the 2010 System Black incident confirms that a structured follow-up mechanism for monitoring actions against recommendations is warranted.

Although the investigation falls outside of the timeframe for the 2012-13 Review, the Commission will be monitoring PWC’s progress on rectifying the issues identified as part of the 2013-14 Review.

As detailed in the Commission’s investigation report into the 12 March 2014 System Black incident and, in accordance with clause 11.4 and 10.4 of PWC’s system control and generation licences respectively, the Commission will appoint an independent auditor to undertake a technical audit of PWC’s compliance with its licence obligations and its obligations to comply with relevant industry legislation, codes and rules. The audit will also include a review of PWC Network’s compliance obligations in accordance with clause 10.4 of its network licence. The Commission will include the findings of the technical audit and any PWC management response to required actions in the 2013-14 Review.

1.7 Commission’s focus for the 2013-14 Review

As part of the 2013-14 Review, the Commission will have particular focus on the following issues:

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incorporating reliability assessment and monitoring into PWC’s planning and reporting processes;

PWC’s review of spinning reserve requirements and any decisions to revise spinning reserve practices as a result (including assumptions of the study including the assumed value of customer reliability);

the recommended move to a stochastic method for planning or assessing future generation adequacy and in so PWC refining their methods of forecasting generating unit availability;

improved reporting of generator reliability and that exhibited by the actual system performance;

greater transparency with respect to system incidents to allow better calibration of the accuracy of the planning tools in predicting future reliability margins;

further monitoring of system incident reports and actions by PWC;

any forecasts and information that have changed significantly from previous forecasts and information provided in the preceding year’s report be explained in the Network Management Plan;

existing power factor at substation level;

expected commissioning month of projects in PWC’s 10 years Master Plan to monitor the progress and development of each specific project;

fault level details at each substation, single phase and three phase, for the present and long term forecast (5 years) for the 132, 66, 22 and 11 kV system (to better understand the correctness of the PWC system modelling);

poor performing feeders, including time to restore the feeder for each outage and specific details of the faulty equipment;

better categorisation of complaints for networks and retail during 2014-15;

improved customer reliability (SAIDI and SAIFI) across all feeder categories;

reduced quality supply complaints; and

improved responsiveness to customer telephone calls.

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2. Overview of the Northern Territory Power Systems

2.1 Legislative Framework

There are four main Acts that establish the legislative framework under which electricity supply operates in the Territory. These are:

Power and Water Corporation Act 2002;

Utilities Commission Act 2001;

Electricity Reform Act 2000; and

Electricity Networks (Third Party) Access Act 2002.

The Power and Water Corporation Act establishes PWC to generate, trade, distribute and supply electricity in the Territory. From 1 July 2014, the electricity retail and generation business units of PWC will be structurally separated into standalone Government Owned Corporations.

The Utilities Commission Act establishes the Commission as an independent statutory body with defined roles and functions for economic regulation in the electricity, water and sewerage industries in the Territory.

The Electricity Reform Act (the Act) provides the legislative framework for the operation of the electricity supply industry in the Territory. The Act describes, among other things, the key functions and responsibilities of the Commission, which include:

licensing of network operators;

setting network prices;

setting network access arrangements;

setting minimum service levels for network reliability and power quality; and

monitoring network capacity and performance.

The Electricity Networks (Third Party Access) Code (TPA Code)5 specifies the access regime for persons wishing to access PWC’s electricity network. By doing so, the TPA Code provides a framework for establishing competition in the generation and retail sectors. Key elements of the TPA Code include:

network access terms and conditions;

provision of information;

ring fencing of regulated businesses; and

network pricing.

Under the TPA Code, the Commission is responsible for determining the network conditions and charges, and monitoring and enforcing compliance with the determination. The arrangements for

5 The Territory’s regional and remote networks are not subject to the third party access framework and the Commission has no role in setting conditions of service and charges. These networks transport electricity to customers in the 72 communities and 82 outstations where essential services are provided through the Territory Government Indigenous Essential Services program; eight remote townships and three mining townships.

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the period 1 July 2009 to 30 June 2014 were determined in March 2009.6 The Commission’s final determination for the fourth regulatory control period (1 July 2014 to 30 June 2019) was released on 24 April 2014.

Section 45 of the Electricity Reform Act (the Act) requires the Commission to prepare an annual review on power system performance and capacity in the Territory.

The Act requires the Commission to:

report forecasts of electricity load and generating capacity;

report on the performance of the Territory’s power systems;

advise on matters relating to the future capacity and reliability of the Territory’s power systems relative to forecast load;

advise on other electricity supply industry and market policy matters; and

review the prospective trends in the capacity and reliability of the Territory’s power systems relative to projected load growth.

2.2 Overview of the transmission and distribution systems

The Northern Territory transmission and distribution systems are operated by PWC. The network comprises poles, wires, substations, transformers, switching, monitoring and signaling equipment involved in transporting electricity from the generator to the customers.

PWC is a Government Owned Corporation and is subject to oversight by a Shareholding Minister (the Treasurer) and Portfolio Minister (the Minister for Essential Services) under the Government Owned Corporations Act.

PWC is a vertically integrated electricity supplier which also provides water supply and sewerage services. The PWC Generation, Network and Retail units operate as separate businesses with internal transactions between units subject to oversight by the Commission. PWC is also responsible for providing System Control services. As of 1 July 2014, the Generation and Retail business units of PWC will be structurally separated from PWC and established as standalone Government Owned Corporations.

PWC’s electrical networks operate at transmission voltages of 132kV and 66kV and distribution reticulation at 22kV and 11kV.

This Review focuses on the following three larger electricity systems operated in the Territory:

Darwin-Katherine system – the largest system, that supplies Darwin city, suburbs and surrounding areas of Darwin, the township of Katherine and its surrounding rural areas. Power stations are located at Channel Island, Weddell, Pine Creek (privately owned) and Katherine.

Alice Springs system – that supplies its township and surrounding rural areas, from the Ron Goodin Power Station, Owen Springs Power Station, Brewer Power Station (IPP) and Uterne Solar Power Station (IPP).

Tennant Creek system – that supplies the township of Tennant Creek and surrounding rural areas from its centrally located power station.

6 Utilities Commission, March 2009, Final Determination Networks Pricing: 2009 Regulatory Reset.

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PWC also operates localised generation systems at Borroloola, Elliott, Daly Waters, Timber Creek, Ti Tree, Yulara and Kings Canyon. In addition, there is a large number of remote power systems spread across the Territory. Figure 2.1 provides an overview of the Territory’s energy supply infrastructure.

2.3 Proposed Wholesale Electricity Generation Market

On 23 September 2013, the Commission received notice from the Regulatory Minister under Part 7 of the Utilities Commission Act requesting that the Commission conduct a review into wholesale electricity market arrangements that are appropriate for the Territory, and to recommend preferred arrangements. The Terms of Reference were subsequently amended by the Minister on 8 November 2013 to provide for a reporting date of 28 February 2014.

The referral from the Minister identified that, in undertaking the review, the Commission should consider the following market objectives:

(a) to promote the economically efficient, safe and reliable production and supply of electricity and electricity related services of the Territory;

(b) to facilitate competition among generators and retailers in the Territory’s electricity system, including by enabling efficient entry of new competitors;

(c) to minimise the long-term cost of electricity supplied to customers from the Territory’s electricity system; and

(d) to encourage the use of measures that more efficiently manage the volume of electricity used including the variations between peak and average loads.

The referral from the Minister noted that the NEM is an established best practice regulatory framework that has been developed over a decade and provides a reference point for the Territory’s future regulatory framework.

The referral also noted that the Commission should have consideration for the Territory Government’s package of electricity supply industry reforms, including greater alignment of the Territory’s regulatory framework with the NEM, transfer of network regulation to the AER and adoption of the NER.

The Commission provided it Final Report to the Regulatory Minister on 28 February 2014, which recommended the adoption in the Territory (initially in the Darwin-Katherine system, with later application to Alice Springs and Tennant Creek), of a Northern Territory Electricity Market (NTEM).

The recommended NTEM would have the following key characteristics:

(a) separate reliability assurance and energy trading mechanisms; with

(b) the reliability assurance mechanism (RAM) to involve:

i. a central reliability assurance contracting body, setting minimum requirements for generating and controllable demand side investment to meet pre-determined reliability standards for the Territory;

ii. a regular tendering process for owners of generating and demand side capacity to submit offers to contract with the reliability body or submit notice that contracts have been entered into with customers for an equivalent amount of capacity;

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iii. term of contracts to reflect a balance between investment certainty and prevailing supply/demand balance; and

iv. reliability assurance contracts to be financial in nature and to impose a financial penalty on holders of a contract which does not have capacity available for operation when reserve is low.

(c) the energy trading mechanism to involve:

i. a security constrained gross dispatch pool, similar to the NEM;

ii. dispatch based on availability submissions from generators with prices initially required to be no more than demonstrable short run cost (with guidelines on how to assess costs);

iii. a marginal clearing price from real time operation; and

iv. settlement of the pool to allow for gross or net volumes at the discretion of market participants.

The Commission recommended that the NER form the basis for the establishment of formal rules and procedures for the NTEM. The Commission also noted that relatively simple amendments to existing Territory regulatory arrangements (System Control Technical Code, Network Technical Code, and Electricity Retail Supply Code) could enable interim establishment of energy trading arrangements and that have the basic features of the proposed NTEM energy trading procedures.

2.4 Structural Separation of PWC

The Commission notes that from 1 July 2014, the generation and retail business units of PWC will be structurally separated into standalone Government Owned Corporations (GOC). This 2012-13 Review relates to the period prior to structural separation of PWC.

The Commission will work with PWC and the new GOCs in 2014 to consider how information will be provided for future reviews.

The Standards of Service Code will continue to apply to the generation and retail businesses of the new entities and the networks division of PWC.

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Figure 2.1: Northern Territory energy supply infrastructure.

Source: Utilities Commission and Power and Water Corporation

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A schematic of the existing and future Darwin-Katherine transmission and distribution network is presented in Figure 2.2.

Figure 2.2: Darwin-Katherine Transmission Network (major components)

Source: Power and Water Corporation.7

7 Following commissioning of the Archer to Woolner 66kV line, the second connection to Hudson Creek will be removed.

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A schematic of the existing and future Alice Springs transmission and distribution network is presented in Figure 2.3.

Figure 2.3: Alice Springs Transmission and Distribution Network

Source: Power and Water Corporation.

The majority of the Territory, except for the Darwin and Alice Springs townships, has a very low customer density. The low load density and geographical spread of customers impact on network topography, with much of the transmission and distribution network being characterised by long radial lines.

A number of geographic and climatic aspects pose major challenges for the network, including regular cyclonic activity during the wet season, extreme lightning activity year-round, very high seasonal rainfall in the northern area, frequent flooding, high vegetation growth rates, hot conditions, extreme summer-winter and day-night temperature variations prevailing in inland areas, arid conditions and frequent dust storms in Central Australia and high termite activity. These geographic and environmental variations influence the design criteria for the transmission and distribution systems.

The three major PWC systems are not connected to the national grid and operate as separate stand-alone systems. Table 2.1 below contains descriptive statistics for the regulated electricity networks.

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Table 2.1: Power Networks’ Statistics (regulated network)

Power Network Statistic As at 30 June 2013

Regulated System D-K TC AS

Energy delivered (GWh) 1,455 26 219

Maximum demand (MW) 292.5 7.0 57.5

Number of employees 3308

Number of Transmission Terminal Stations

4

Number of Zone Substations 25

Number of Distribution Substations 4,374

Number of Major Power Transformers (22kV to 132kV)

57(excludes generator and spare

transformers)

Number of power poles 40 690

Transmission overhead (132kV and 66kV)

743 km

Transmission underground (66kV) 38 km

High Voltage overhead (22kV, 11kV and SWER)

3 195 km

High Voltage underground 728 km

Low Voltage overhead (includes service mains and streetlights)

1 781 km

Low Voltage underground (includes service mains and streetlights)

2 177 km

Source: Power and Water Corporation

2.5 Overview of generating plant

Appendix A identifies the power stations in the three networks, and the characteristics of the generating units that comprise them.

2.6 Industry participants

Electricity industry participants licensed to operate in the Darwin-Katherine, Alice Springs and Tennant Creek power systems at 30 June 2013 are listed in Table 2.2.

8 This employee figure is for both the regulated and unregulated network.

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Table 2.2: Electricity licence holders at 30 June 2013

Licensees Darwin-Katherine Alice Springs Tennant Creek

Generation PWC GenerationNGD (NT) P/LCosmo Power P/LLMS Generation P/L

PWC GenerationCentral Energy PowerUterne Power Plant Pty Ltd

PWC Generation

Network PWC Networks PWC Networks PWC Networks

Retail PWC RetailQEnergy LimitedERM Power Retail P/L

PWC RetailQEnergy LimitedERM Power Retail P/L

PWC RetailQEnergy LimitedERM Power Retail P/L

Source: Utilities Commission.

PWC generates most electricity for household and business use, operates the electricity transmission/distribution networks and provides retail services to its customers in the Darwin-Katherine, Alice Springs and Tennant Creek power systems.

PWC is responsible for providing System Control services although these are partly funded through a specific charge approved by the Commission and levied on retailers. As a market develops, it will become important to separate the System Control function from PWC and put in place fully independent funding. The adequacy of the level of funding is particularly relevant in light of the work load that System Control is facing in establishing a number of market related tasks such as economic dispatch arrangements, ancillary services framework, dynamic models for the systems, and testing plant to ensure compliance with the technical codes.9

There are five privately owned generation businesses. Three operate in the Darwin-Katherine system and two in the Alice Springs system, one of which (Uterne power plant) is a renewable energy (photovoltaic) facility. These five businesses generate electricity under power purchase agreements with PWC.

QEnergy and ERM Power Retail have been licensed by the Commission to operate as retailers in the Territory.

In May 2014, the Commission received an application from Rimfire Energy Pty Ltd for a licence to sell electricity and an application from Northern Power Opco Pty Ltd to for a licence to generate electricity. Both applications are currently being assessed by the Commission in accordance with the Electricity Reform Act. Both applications have been made available on the Commission’s website and comments sought from market participants and other stakeholders.

9 This view was also conveyed in the Commission’s Review of Electricity System Planning and Market Operation Roles and Structures – Final Report, December 2011, page 40.

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3. Power System Reliability

3.1 Introduction

In the 2011-12 Review, the Commission concluded that probabilistic analysis of the adequacy of generation capacity is necessary, particularly in the Darwin-Katherine and Alice Springs systems. The Commission’s view was that it was necessary to identify an optimum level of generation capacity for the Northern Territory’s power systems, and that this approach is used in Australia for identifying the potential for capacity constraints and is a more robust measure for generation planning purposes than the N-2 methodology10 currently used in the Territory.

This chapter introduces power system reliability concepts, the system reliability standard and assessment approach used in the NEM, and the application of these concepts and approach to the Darwin-Katherine and Alice Springs systems. The purpose of this was to address the following questions:

whether a reliability standard is appropriate for the Territory power systems, and if so what should this standard be?

how will the use of a reliability standard improve power system planning? and

how does reliability compare to that established in the NEM and the Western Australian Wholesale Electricity Market (WEM)?

3.2 Generation Reliability

Reliability of a power system is defined as its ability to perform its intended function of supplying customers over a defined period of time and under specified conditions (which include weather and number of plant items out of service).

Reliability is defined and reported through various indices and at various points within a power system’s supply chain. This is illustrated in Figure 3.1 below. Reliability standards provide for the adequacy of the power system to be understood from an economic basis and also for its standard to be compared to other power systems.

10 A system in the Northern territory is currently deemed to have adequate generation if there is sufficient capacity available to maintain supply despite the loss of the two largest units of generation plant, known as an N-2 event.

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Figure 3.4: Electricity Supply Chain

Source: Australian Energy Market Operator

Generation reliability relates to the ability of the generation system to meet customer load (as seen at the power stations) assuming the transmission system provides for all generation to be transported. This is also referred to as generation adequacy. This is what is reported in the NEM. Composite system reliability (also referred to as bulk supply reliability) is the reliability at major transmission supply points and includes both generation and transmission. Customer supply reliability relates to supply at various distribution points and includes generation, transmission and distribution.

From a system wide basis “generation reliability” is generally considered the most important and is the subject of this chapter. The importance of generation reliability relates to the potential for high economic loss associated with widespread and significant levels of customer load shedding that can occur as the result of generation shortages. For example, a generation shortfall of 20 MW would require about 6,000 homes to be cut off from supply.

The key factors that can lead to a generation system being “unreliable” are:

uncertain and high customer demands;

insufficient installed generating capacity;

poor generator availability & high risk operating practices; and

insufficient or unreliable fuel supplied to power stations.

3.3 Power System Security and Operation

A fundamental of power system operation (and design) is continuity of operation following a major disturbance such as the sudden failure of a generator unit or transmission line. This is referred to as power system security. Power system security can be maintained by having sufficient spinning generation capacity available to replace the failed generator unit or by shedding customer load. Most power systems are operated so that they can continue supplying all customers following the sudden loss of any one power system element.

In the Territory, the costs of starting and operating generators has resulted in operating regimes for the various power systems that does require sufficient “spinning” generation reserves to cover the loss of a large or largest generator unit. In the Darwin-Katherine power system the spinning reserve

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requirement is 25 MW which is less than the largest generator unit of 43 MW. Such an operating philosophy may result in customer load being shed on the sudden (contingent) loss of a large generating unit when there was spare generating capacity not being used. Such an operating regime maintains system security but reduces system reliability.

Reliability is considered to encompass adequacy and security.

Reliability is a measure of the ability of the power system to deliver electricity within accepted standards and in the amount desired, for the period of time intended, under the operating conditions intended.

Adequacy relates to the existence of sufficient facilities within the system to satisfy the consumer load demand at all times; taking into account scheduled/ unscheduled outages.

Security relates to the ability of the electric systems to respond to sudden disturbances arising within that system, such as electric short circuits.

3.4 Measures and Standards of Generating Reliability

Generation reliability is the result of a number of stochastic processes. Indices used to measure and report on generation reliability need to reflect the stochastic nature of the determining factors. In many cases indices used reflect the models used to determine (past or future) generation reliability.

3.4.1 Reliability in the 2011-12 Power System Review

The 2011-12 Review introduced Loss of Load Probability (LOLP) and indicated that:

“the Commission has assessed the LOLP, using an LOLP of a one day loss in ten years (or 0.027 per cent) as the benchmark of a reliable system. An LOLP greater than 0.027 per cent is indicative of an unreliable system “.

The 2011-12 Review showed indicative results from modelling that had LOLP at 0 day/year until 2017-18 and averaging about 0.013 per cent days/year after that. This gave an average LOLP over the review period of 0.008 per cent days per year.

LOLP refers to the number of days per year that would be expected to have load shedding. It says nothing about the amount of load that would be shed when this occurs. However an indicative relationship between LOLP and EUE can be surmised. A LOLP of 0.1 day/year translates to load being shed on average one day in every 10 years. If it is assumed that on that day 10 per cent of load is shed (corresponding to the largest generator breaking down when there is no reserve, plus additional load due to under frequency tripping) this would correspond to an EUE of 0.00274 per cent (of annual demand consumed). This is near the NEM and WEM reliability standard of 0.002 per cent. Table 3.1 presents LOLP, the level of shedding when this occurs, and the corresponding EUE.

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Table 3.3: LOLP and EUE Relationship

LOLP(days / decade)

LOLP(days / year)

LOLP( per cent days)

Energy shed on day shedding occurs

EUE

0.292 0.0292 0.0080% 7.5% 0.00060%

0.292 0.0292 0.0080% 25% 0.00200%

1 0.1 0.0274% 7.50% 0.00205%

1 0.1 0.0274% 25% 0.00685%

3.4.2 Review of Reliability indices and standards

LOLP is not used as a reliability index in the NEM or the WEM. A list of reliability indices including LOLP that are or have been used in the Australian States is presented in Table 3.2 below.

Table 3.4: Commonly used Probabilistic Reliability Indices

Index Description Use

Loss of Load Probability

The probability that generation will not meet all demand within a year.Usually expressed as days/year. This is the expected number of days per year that will have load shedding. It says nothing about the amount of shedding that is expected to occur.

Common in overseas electricity markets.Not used in the NEM or West Australia.

Expected Unserved Energy

This is the expected GWh that would not be met within a year.Expressed as a percentage of total system energy consumption per annum.

The reliability index used in the NEM and the Western Australian WEM.

Probability of Unserved Energy

The probability that generation will not meet all demand within a year.Expressed as a percentage.

Previously used in Victoria.Closely related to LOLP.

Loss of Load Frequency

This is the expected number of times the system has load shedding within a year.

Not widely used.This index would usually accompany another reliability index of the type above.

Prior to the formation of the NEM, individual States maintained and reported on generation reliability. In Victoria and a number of other states the reliability criteria was to have sufficient generation that shedding occurred no more than one year in every ten. This corresponded to a LOLP of 0.1 day/year and was consistent with international practice. This reliability standard carried over to the NEM.

The NEM has adopted the reliability index EUE and has a reliability criterion of having EUE less than 0.002 per cent of demand in any year. The Western Australian WEM also uses the reliability standard

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of no more than 0.002 per cent of energy unserved11. This corresponds very closely to having a probability of load shedding in any one year of less than 10 per cent.

The probabilistic nature of the reliability indices listed in Table 3.3 means that these can only be calculated through specific probabilistic approaches and models (which are briefly described below). Such indices cannot be derived from measureable factors of the power system such as installed generation capacity and maximum demand. However, criteria based on reserve margin (calculated as the difference between installed generation capacity and potential maximum demand) can be developed based on calibrations to probabilistic criteria.

Such calibrations are undertaken in the NEM where probabilistic modelling is done to determine the minimum reserve margin in each State that corresponds to the established standard of reliability. As the power system changes (due to issues such as demand growth, rooftop PV and wind generation development, and size and performance of generating units) the reserve level that has the power system operating at the reliability standard also changes. Because of this, AEMO recalculates the reserve margins in each State that corresponds to the reliability standard of USE in any year being less than 0.002 per cent (of annual system energy).

3.5 Models used to Assess on Generating Reliability

There is much literature on the quantitative approaches to the calculation of probabilistic reliability indices. Since the advent of powerful computers the approaches have been dominated by power system simulation models.

Models of this type simulate the operation of the power system in sequential time intervals over a specified study (modelling) period. Operation of the power system involves modelling the committing and dispatching generators based on a specified operating regime (such as spinning reserve criterion). The sequential intervals are typically 30 minute or 60 minute time periods. Importantly these models include the unforeseen and random breakdown of generator units based on probability distributions of breakdown and repair time and pseudo random numbers. Partial outages are also often included. Load variation is represented through the use of 30 minute (or 60 minute) demand files generated through separate models or through the use of historical system demands. As the breakdown of generator units is random, the model is run many hundreds of times and the results (i.e. statistics) collected from those model runs.

The key advantage of model simulations is that all the important factors mentioned above that influence generating reliability are explicitly represented, and can be modified as required. In addition, other factors that impact generation reliability can be included such as fuel supply issues and main constraints on transmission lines. For example, in the NEM water inflows to the main hydro power stations and the limits in the interconnecting transmission between the States are included in reliability modelling.

11 This is defined in Market Rules 4.5.9 (9b) and is the second criterion, the first being the level of reserve margin required.

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Interpretation of Modelling Results

Regardless of the model used, the operation of power systems such as in those in the Territory are vastly more complex than as incorporated in models. Different reliability models will output different reliability values of reliability indices (such as EUE). Because of this, utilities have calibrated their reliability models to the actual power system. This enables the value of reliability indices output from the model(s) being used to be properly interpreted in the context of the real power system. This has sometimes referred to as the “art of reliability modelling”.

3.6 Modelling Reliability in the Northern Territory Power Systems

The Darwin-Katherine and Alice Springs power systems have been modelled in the electricity simulation model PROPHET12. Power system data was entered to allow the model to be run over all years between 2013-14 and 2029-30. The data entered included all the power station generator units and their characteristics, historical demand patterns and forecast annual maximum demand and energy growth, and generator unit reliabilities taken from the generator asset review undertaken by Entura as part of the Review. Generator planned maintenance was included as described by PWC.

The model assumed that the full technical capability of the generation system would be used to supply customers and avoid customer load shedding.13 This is the approach used by AEMO in their evaluations of power system reliability.

The model was run over the study period for the Darwin-Katherine and Alice Springs power systems. Each system was modelled three times assuming different levels of generator forced outage rates. (Generator forced outage rates were the uncertain variable being considered.) The generator planned outage pattern was based on that used by PWC and was assumed to be the same in the three cases modelled. The percentage of time a generator us out of service for planned maintenance can also be expressed through a “planned outage rate”. This relationship for a generator - forced outage rate plus planned outage rate equals total unavailability.

A description of the model runs is shown in the table below.

Table 3.5: Reliability Model Runs

Scenario Generator Forced outage rates Overall Availability

Low 2% for all generators 92% for all generators

Medium 5% for all generators 89% for all generators

High 10% for all generators 84% for all generators

12 The PROPHET model provides for the physical power system to be modelled in detail using any specified time period. PROPHET is used by many participants in the NEM including AEMO.

13 It was not the intention of this study to review the value of different spinning reserve regimes.

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For each scenario the model simulated the study period 100 times14. The results from these simulations included for each 60 minute interval of the simulations:

the amount of load not supplied due to insufficient generation; and

the operating reserve margin.

The value of each of the reliability indices described above was calculated for each model run (from the amount of load not supplied). For example, the amount of annual unserved energy was collected for each year of the modelling runs and the average of the annual values calculated. From a reliability assessment perspective, these are the relevant results from the modelling. For each scenario modelled, the EUE for each year of the study period are shown in Figure 3.2 and 3.3 for the Darwin-Katherine and Alice Springs systems respectively (note that there are two points representing the last 10 years).

Figure 3.5: Generation Reliability – Darwin Katherine System (USE per cent of energy)

Figure 3.6: Generation Reliability – Alice Springs System (USE per cent of energy)

14 Experience in reliability modelling has shown that 100 simulations is sufficient for the reliability statistics obtained to have a high level of confidence. Each simulation involved each hour of the year being modelled.

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To monitor the performance of the generation system in reliably supplying power requires that not only periods of load shedding be monitored (which would occur about once every ten years if the power system is operating at a reliability level of 0.002 per cent EUE), but also “near misses”. To address this, monitoring generation reserves, and more particularly the times that load would have been shed had one generator unit failed and also had two generator units failed, is often used. This is termed N-1 and N-2 level of generator reserves.

Figure 3.4 and 3.5 below shows the amount of time the N-1 and N-2 generator reserves are unmet for the Darwin-Katherine and Alice Springs systems respectively for the Low Scenario (all generators have a 2 per cent forced outage rate).

Figure 3.7: Generation Reliability Low Scenario – Darwin Katherine System Reserve

Figure 3.8: Generation Reliability Low Scenario – Alice Springs System Reserve

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Given the high level of reserve margin that exists in these power systems and the operating regime assumed (all plant being made available), it is not surprising that the results show that both power systems have a high level of generation reliability over most of the study period. The results also illustrate the sensitivity of reliability to the assumed generator forced outage rates. The generator forced outage rates have been assessed to be between 2 per cent and 5 per cent.

The modelling indicates that the two power systems modelled are likely to have the technical capability to operate at a reliability level that does not exceed 0.002 per cent EUE.

3.7 The Economics of Generation Reliability

In general, modern power systems are developed and operated in a manner that matches the cost of providing generation to the value of supply reliability (the value customers place on reliability is termed the Value of Customer Reliability or VCR15). This is an objective of efficient electricity markets.

Optimal economic reliability is the basis of the established generation reliability standard in the NEM. To support this, studies are undertaken in the NEM to assess the VCR and the cost of generation supply.

Principle of Optimal Generation Reliability

The figure opposite illustrates the general principals of optimal generation reliability.

This shows an upward sloping supply curve for generation (implying increasing incremental cost of generation supply) and an increasing cost to customers for electricity supply curtailment. Also shown is the total economic cost which is the sum of these two components.

The lowest cost point on the total cost curve represents the optimal reliability level based on the supply and curtailment costs. This is the point where the incremental cost of reducing the expected level of load shedding by 1 MWh is equal to the cost to customers of this reduced level of load shedding.

15 VCR should not be confused with the Market Price Cap (MPC). VCR is often referred to by other terminologies including: Value of Lost Load “VoLL”,Value of System Security &Customer &Customer cost of service interruption.

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Studies of the value of VCR in the NEM have proven difficult. They are based on survey results from different classes of customers and different types of supply interruptions (such as time, frequency and duration). The results of a recent study undertaken on the value of VCR are presented in Table 3.5. This shows the results for each of the NEM participating States and five customer categories (the results are from the study dated March 2011 by Oakley Greenwood titled Valuing reliability in the National Electricity Market). This study indicates that the value of VCR to different customer varies, typically being about $17,000/MWh for residential customers and $33,000 for commercial customers. Agricultural customers have a very high value of VCR.

For the Territory the weighted average value of VCR for each of the power systems would be influenced by weather conditions and the composition of customer types. Based on a similar analysis as undertaken in the NEM, it has been assumed that the value of VCR in the Territory power systems would be $30,000/MWh.

PWC’s view is that VCR in the Territory would be less (between $15,000 - $20,000 /MWh) as the three regulated power systems have less industrial load.

Table 3.6: Assessment of VCR Undertaken in the NEM ($/MWh)16

Sector Victoria Queensland NSW South Australia

Tasmania

Residential 20,395 15,318 17,190 16,469 18,532

Agricultural 111,062 62,887 68,396 133,493 76,716

Commercial 90,763 18,649

Industrial 36,074 31,427 32,055 32,905 34157

State Wide 50,258 37,198 35,085 38,037 42,022

Reasonable estimates can usually be made regarding the costs of generation supply (that include capital, operating, and grid connection costs). Capital costs for peaking plant in the Territory have been assumed to be $1,300/kW. The reliability model established described above was run for the 2014 year progressively withdrawing generation capacity. The medium generator forced outage rates of 5 per cent were assumed. This provided for the relationship between the level of installed generation capacity and EUE for 2014 to be established . The results of this modelling for the Darwin-Katherine and Alice Springs systems are shown in Figure 3.6.

The economic balance is based on assumptions used for this study only and is intened to be indicative only.

The optimal level of reserve margin is a result of supply costs increasing on the margin and unserved energy costs decreasing on the margin. Additional generator capacity is needed as the reserve margin increases, while the amount of unserved energy decreaes in a asyntopic fashion as the reserve margin increases. The optimal level represents that point where the marginal cost of additional supply equals the marginal cost of unserved energy.

16 Source: Table 8, Valuing reliability in the National Electricity Market, Oakley, Greenwood, March 2011.

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The optimum reserve level and reliability level (expressed in terms of EUE and LOLP) for the system modelled as shown in Table 3.5 below.

Darwin-Katherine

On basis of the assumptions used the optimal level of installed plant in 2014 would result in reserve margin of 92 MW

Alice Springs

On the basis of the assumptions used the optimal level of installed plant in 2014 would result in reserve margin of 18 MW

Figure 3.9: Indicative Assessment - Optimal Level of Installed Generation

Table 3.7: Indicative Optimum Generation Level of Reliability

Optimum Reserve Level MW

EUE per cent of energy consumed

LOLPDays/year

LOLP per cent of Days/year

Darwin-Katherine 92 MW 0.007% 0.15 0.040%

Alice Springs 18 MW 0.005% 0.12 0.033%

3.8 Reliability Review Conclusions

Setting a reliability standard for a power system is not an easy task. In the NEM this evolved from the participating State reliability standards, existing models used to assess generator reliability, and assessment of the value customers place on reliability.

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Key criteria in the selection of a suitable reliability index are how it represents what customers value and the methods that are available for its calculation. Expected Unserved Energy (EUE) has been determined as the most suitable for use in the NEM and WA and it would be expected that this index would be a suitable measure in the Territory power systems. The reasons for this are that:

its meaning is clear;

it is amendable to valuation by customers;

there are tools available for its calculation; and

its consistency with the NEM and WEM provides for comparisons to be made.

The modelling presented in the chapter has demonstrated that a reliability index provides a basis for planning and assessing performance in power systems that are changing, as is the case in all the power systems in Australia.

The modelling also supported the indicative assessment of generation reliability undertaken in the 2011-12 Review and the benchmark reliability index that was presented in that review.

Each power system has different characteristics, and these can be important to how the power system performs and its reliability. The need to properly understand the relationship between the actual power system and quantitative methods / models to calculate reliability requires that system planning and operations have a major role in this development.

There is significant experience in the NEM and the WEM in monitoring and modelling reliability that can assist in this development.

Noting the above, the Commission considers that further work is need to incorporate reliability assessment and monitoring into the planning and reporting process used in the Territory.

3.9 Progress against findings from 2011-12 Power System Review

Reliability and availability standards

While not explicitly identified as focus for the 2012-13 Review, the Commission has been encouraging PWC to consider revised reliability standards for different points in the electricity industry supply chain. The Commission considers it appropriate that PWC note the findings of this chapter and consider how it can better incorporate reliability assessment and monitoring into its planning and reporting processes.

3.10 System Reliability Key findings

The economic basis and quantification of generation reliability were reviewed and these were seen as providing an improved basis of generation planning and assessing the economic performance of power systems that are changing, as is the case in Australia including the Territory power systems.

The reliability criteria Expected Unserved Energy (EUE) has been determined as the most suitable for use in the NEM and the Western Australian Wholesale Electricity Market and it would be expected that this index would be the most suitable measure in the Territory power systems.

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The Commission considers it appropriate that further work be undertaken by PWC to incorporate reliability assessment and monitoring into the planning and reporting processes used in the Territory. In doing so, it is noted that there is significant experience in the NEM in monitoring and modelling reliability that can assist in this development. Further, the different characteristics of the individual Territory power systems that are important to how each performs requires that system planning and operations staff have a major role in this development.

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4. Maximum Demand Outlook

4.1 Introduction

This chapter presents a review of PWC’s 2012-13 forecasts17 of annual maximum demand (MD) for the next ten years for the Darwin-Katherine, Alice Springs and Tennant Creek electricity systems (the three systems). These forecasts were developed by Power Networks (PWC Networks) for the system as a whole, transmission connection points, ZSS and feeders. Each MD forecast is expressed as the demand level that has a 50 per cent and 10 per cent probability of being exceeded, referred to as P50 and P10 respectively, representing the uncertainty of weather conditions each year.

This chapter reviews and presents the forecasts for the ZSSs and total system MD.

The forecasts form a critical input into the investment and operating decisions within PWC. In particular:

System MD forecasts are used by the System Controller for the purposes of generator investment planning and as an input to annual operational decisions;

The forecasts of ZSS and feeder MDs are used by PWC Networks for network planning purposes. The MDs identify potential constraints on the network that may need network investment; and

These forecasts are also required by PWC Generation, PWC Networks and PWC Retail, and other generators and retailers operating in the Territory for business planning purposes.

The high level of confidence required in the forecasts has resulted in the PWC Networks forecasts being reviewed by independent consultants, and a number of areas of improvement have been identified and implemented over the last two years. The 2012-13 forecasts were reviewed by Marsden Jacob Associates (Marsden Jacob) who reported their findings to the Commission.

The structure of this chapter reflects the importance of transparency in the forecasts. It is structured as follows:

a summary of the definitions and terms used;

the trends in system MD growth across the three systems, and any observed trends in demand load factor;

a comparison of the 2011-12 forecasts with actuals and reasons for differences;

the methodology used by PWC for the MD projections and any changes from the 2011-12 projections;

the outlook for rooftop PV development;

the forecasts on a system and ZSS basis; and

conclusions and recommendations.

17 Act [s45(1)(a)] requires the Commission to develop forecasts of overall electricity load and generating capacity in consultation with participants in the electricity supply industry.

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4.2 Definition

There are a number of terms used in this chapter that may need explanation. These terms are described below.

Demand Measured

Electricity demand is measured by meters located at different locations in the supply chain from generator terminals, sent out from power stations after subtracting parasitic (used in station) load, transmission connection points, zone substation supply, and used by customers. Generator and ZSS meters are illustrated in Figure 4.1. This shows the points of measurement and reporting of demand at different locations in the power system as required for this review.

Figure 4.10: Demand as measured at different locations in a power system

The locations used and reported on are different for system and ZSS demands:

System MD is measured and recorded at the generator terminals, referred to as “at gen”. The system MD projection is undertaken and reported on this basis.

The MD at each ZSS is that measured and recorded as that leaving the ZSS. The MD for each ZSS is developed on this basis. As ZSS MDs do not occur at the same time, the summation of ZSS MD is referred to as the non-coincident MD.

The difference between the sum of the ZSS MDs (that is, the non-coincident ZSS MD) and the system MD is that due to transmission losses between the ZSSs and generator terminals, the load used within the power stations, and the diversity of MDs between the ZSSs.

MVA and MW

Electricity flows on transmission lines are often measured and reported on a millions of volt amps (MVA) basis. The reason for this is that the ratings of network assets are defined in terms of MVA limits.

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Power flow is measured as megawatts (MW) or kilowatts (kW). MW are closely related to MVA, and PWC Networks assume the relationship of 1 MW = 0.96 MVA.

Weather Corrected MDs

Weather conditions, particularly temperature and the number of hot days that occur in a row, influence electricity demand. In any one day or any one month weather conditions can have a significant influence on the MD that occurs. Higher temperatures usually mean more cooling appliances are being used and electricity demand is higher. Energy used over a year is less sensitive as this is influenced by weather conditions over all days in the year. It is important to note that MD (a key planning factor) occurs on a single day which is different from the total demand, energy measured over all days of the year.

The relationship of temperature on the day of MD to actual experienced MD can be expressed by a constant that expresses the increase in MD (MW) for every 10C increase in maximum temperature above a defined reference temperature on that day.

Each MD forecast is expressed as the demand level that has a 10 per cent and 50 per cent probability of being exceeded (POE):

The P10 MD projection is that MD level expected to be exceeded one year in 10. This corresponds to a very hot day;

The P50 MD projection is that MD level expected to be exceeded one year in two. This corresponds to a hot day that could be expected on average.

Load Factor

Load factor is a measure of the MD compared to the energy consumed. Load factor over a given period is defined as the average demand during that period divided by the peak demand in that period and multiplied by 100 to give percent. Load factor over a year can be influenced by one very extreme demand day.

A decreasing trend in load factor is undesirable as more capacity in generation and transmission would be needed to supply the energy demanded than would otherwise be the case. This is one reason utilities monitor load factor.

Demand Diversity

The diversity of MD between ZSSs is defined as the sum of their individual MDs less the total system MD. The sum of the individual ZSS MD is referred to as the non-coincident MD. Diversity represents the degree to which the total MD is reduced through the ZSS MDs occurring at different times. Diversity can be expressed as a percent or total MW difference.

Diversity in MD is a desirable feature as it reduces the level of transmission and generation required.

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4.3 Historical MD Growth and Accuracy of the 2012-13 Forecast

The 2011-12 Review published forecasts of system, ZSS and feeder MDs for the period 2012-13 to 2021-22 for the Darwin-Katherine, Alice Springs and Tennant Creek systems. These forecasts were developed on the basis of weather conditions that correspond to a 50 per cent and 10 per cent POE.

A comparison of these forecasts to actuals was made for the 2012-13 year. To remove differences due to weather, comparisons were made on a “same weather basis”. This was done for the system MD and the individual ZSS MDs by weather correcting actual MDs to be on a P50 basis and comparing these to the respective P50 MD forecast.

4.3.1 System Maximum Demands

Table 4.1 below presents the comparison of system actual and system forecast MDs for the Darwin-Katherine, Alice Springs and Tennant Creek systems.

Table 4.8: Review of 2012-13 Actual and Forecast P50 Maximum Demands (MW)

Darwin-Katherine

Alice Springs Tennant Creek

Actual 292.5 52 7

Weather corrected (P50) actual 288.8 53 6.8

Forecast (P50) 303.3 57.7 7.8

Difference MW between forecast and P50 Actual

14.5 4.7 1.0

Difference as per cent of Actual MD 5.0% 9.0% 14.3%

As observed, all the forecasts projected a higher MD than eventuated. While the actual size of the error was larger for the larger systems, the percentage error was smaller for the larger systems. This analysis further suggests to the Commission that PWC’s forecasts err on the high side.

To consider this further, Figure 4.2 presents the system historical actuals, weather corrected actuals (P50) and the 2012-13 forecast system MDs for the Darwin-Katherine, Alice Springs and Tennant Creek systems. Observations from this analysis over the period 2007 to 2013 are as follows:

Only the Darwin-Katherine system showed increasing MDs. Care is needed in interpreting MD growth rates as the non-coincident ZSS and system had different MD growth rates. The system growth rate was also influenced by the low MD that occurred in 2007. These growth rates are shown below:

ZSS P50 (and corrected for transfers and spot loads) 3.08 per cent

System P50 (2007 - 2013) 2.06 per cent

System P50 (2008 - 2013) 0.98 per cent

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Darwin-Katherine

Over the period:

- MDs had a growth rate of 2.23 per cent p.a.

- temperatures have been below average

- demand sensitivity was estimated at 9 MW per oC.

The 2012-13 MD forecast was based on the general trend in growth continuing, and this did not occur. Demands over the past three years have had little growth.

Alice Springs

Over the period:

- MDs have decreased due to the Solar Cities program

- temperatures have been below average

- demand sensitivity was estimated at 2 MW per oC.

The forecasts did not recognise the decreasing demand trend since 2009-10. This indicates the need to explicitly consider rooftop PV.

Tennant Creek

Over the period:

- MDs have had little growth- temperatures have been below

average- demand sensitivity was estimated at

0.25 MW per oC.

Previous forecasts have consistently been high. The forecast error was based on assumed growth that did not occur.

Figure 4.11: System Historical Maximum Demand and 2012-13 Forecasts

Recorded temperatures were generally below the temperature that defines the P50 weather condition in all systems.

The decreasing MD in the Alice Springs system reflected the increasing contribution from solar (rooftop PV). This raises the question of the validity of using the same weather correction sensitivity to Alice Springs as is used in Tennant Creek (2.88 per cent).

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4.3.2 Zone Substation MDs: Darwin-Katherine

Figure 4.3 presents a comparison of the ZSS MD forecasts (on a P50 basis) and weather corrected (P50) actual ZSS MDs for the Darwin-Katherine system18. Woolner and Union Reef ZSSs did not have forecasts and are not included in the analysis. The corresponding tabular data is contained in Appendix D.

Figure 4.12: Darwin- Katherine - Comparison of 2012-13 ZSS Actual (P50) and Forecast (P50) MDs

Without going through a review of each substation, the following comments are made in relation to forecasts compared to the P50 actuals for the Darwin-Katherine ZSSs:

Forecasts were generally in excess of actual recorded and weather corrected P50 actuals, particularly for the large ZSS. Particular ZSS that had large forecast errors, and the error expressed as a percentage of the actual were:

o McMinns (63 per cent)

o Weddell (60 per cent)

o Archer (50 per cent)

o Centra Yard (26 per cent)

o Casuarina (20 per cent);

The summation of total ZSS forecast errors was significantly higher than the system error of 14.5MW:

o the summation of ZSS forecast errors that were above the P50 actuals was 61 MW; and

o the summation of forecast errors that were below the P50 actuals was 10.1 MW.

18 As Tennant Creek has only one substation this is covered in the system review. There was insufficient data for the Alice Springs system to be presented.

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4.4 Load Factor

The 2011-12 Review made the observation that the load factor in both the Darwin-Katherine and Alice Springs systems is trending down, whereas the trend had reversed in the Tennant Creek system. The reasons for a reducing load factor can be many, including one extreme demand day each year.

In the 2011-12, the Commission recommended that PWC provide analysis of the reasons, if any, for the falling load factor in the Darwin-Katherine and Alice Springs systems. The importance of load factor relates to the relationship between the causes of investment and the structure of tariffs designed to pay for investments. Network and generation investments are largely driven by increasing MD while tariffs are largely based on energy consumed.

The Commission distinguishes between system load factor and individual ZSS load factor. The relationship between ZSSs load factors (which can individually be different) and system load factor depends on the demand diversity between the ZSSs (discussed below). System load factor is relevant to transmission and generation investments, while individual ZSS load factors are relevant to distribution.

The trend of load factors for the Darwin-Katherine, Alice Springs and Tennant Creek systems is shown in Figure 5.4. This shows load factor calculated based on actual and weather corrected (P50) MDs.

The load factor for actual demand is higher in almost all years due to P50 MD being higher than actual due to below average temperatures. The Darwin-Katherine system actual load factor of 61.7 per cent in 2012-13 was the highest in the review period and equal to that recorded in 2008-09. The weather corrected load factors were steady but below the load factors before and including 2009-10. However the actual load factor in 2007-08 was the lowest shown.

The Alice Springs and Tennant Creek systems had steadier load factors and showed no indication that this was decreasing.

4.4.1 Diversification

As noted above, system load factor and ZSS load factors are related by the demand diversity between the ZSSs. This is the relationship between the non-coincident ZSS MD and coincident ZSS MD. This is mainly relevant to the Darwin-Katherine system.

The diversity19 between the Darwin-Katherine ZSS MDs was examined by comparing the growth in historical coincident and historical non-coincident ZSS P50 MDs. The growth in coincident ZSS P50 MD was taken to be the growth in system P50 MD (noting that any difference would only be due to changes in transmission losses). The graphs in Figure 4.5 show the historical coincident and historical non-coincident ZSS P50 MDs and the difference between these. To aid in visualisation the graphs have assumed no diversity in the year 2008 (where the actual level of diversity was 60 MW). The graphs show that the diversity between ZSS MD has been increasing.

19 The diversity is the difference between the summation of system P50 MDs and ZSS P50 MDs.

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55%

56%

57%

58%

59%

60%

61%

62%

63%

64%

2007/08 2008/09 2009/10 2010/11 2011/12 2012/13

Load Factor (50% POE) Load Factor (Actual MD)

Darwin-Katherine

The decreasing load factor (based on

actual MDs) trend was arrested in 2012-13

with the highest load factor of the review

period.

The weather corrected load factor has

settled at a lower level than previously.

.

Alice Springs

There is no evidence that load factor is

decreasing (on an actual or weather

corrected basis).

A trend analysis shows a slightly increasing

load factor. This is consistent with high PV

installations which act to reduce MD more

than energy consumption.

0%

10%

20%

30%

40%

50%

60%

70%

2007/08 2008/09 2009/10 2010/11 2011/12 2012/13

Load Factor (50% POE) Load Factor (Actual MD)

Tennant Creek

Load factor based on 50 per cent POE

demands indicates a stable load factor.

Actual load factor has been stable at about

50 per cent for the past 4 years.

Figure 4.13: Load Factor Trends – Actual and 50 per cent POE Weather Conditions

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Total ZSS Non-coincident and Coincident ZSS P50 Maximum Demands

Increase in diversity sine 2008 (between ZSS P50 Non-coincident and Coincident P50 MDs)

Figure 4.14: Darwin-Katherine: Historical Non-coincident ZSS and Coincident ZSS MD Growth

4.4.2 Load Factor Trends

The 2012-13 Review shows that on a system wide basis there is no evidence to support any noticeable decrease in load factors in either of the Darwin-Katherine, Alice Springs and Tennant Creek systems. However, the lower load factors in the Darwin-Katherine system over the past three years may be indicating higher MD growth compared to energy. The review demonstrates that load factor can be volatile as a single high demand day can significantly impact its value.

Increasing diversity between the MDs of the individual Darwin-Katherine ZSSs was observed from the historical analysis and this would assist in limiting an increase in Darwin-Katherine system load factor. However it would hide increasing load factors at the ZSS level which are relevant to the economics of distribution investment.

Consequently it is recommended that both system and ZSS load factors be monitored, and that any observed decrease in 2013-14 (should this occur) be investigated.

4.5 PWC System and Network MD Forecasting Methodology

This section describes the forecasting methodology developed and used by PWC for projecting future ZSS and system MDs. An appreciation of the methodology assists in the interpretation of projections and in an appreciation of the review comments. This is followed by commentary on the approach.

4.5.1 Description of Methodology

The approach used by PWC is based on developing trends of the weather corrected (P50) historical MD for the system and individual ZSSs. ZSSs also had corrections for transfers, large (spot) loads, and in cases of limited data assessed growth rates. From these trends ZSS MDs were developed. The

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system MD projection used a growth that accounted for bottom up growth (ZSS analysis) and system observations (top down).

ZSS MD projections were first undertaken, and the basis of the approach used by PWC is as follows:

forecasting approach is the same for all ZSS in all the three systems;

historical data is limited with about 65 per cent of ZSSs having six years of MD data;

no information on the demographic makeup of the individual ZSS20;

spot loads are removed to establish trends absent of these loads and all confirmed future spot loads were assumed to eventuate;

weather correction used a single “∆MD/∆temperature” factor on all ZSSs based on a linear regression of respective system MD versus temperature across the temp range 25oC to 35oC;

forecasting model assumed trends to be linear and determined through a least squares regression;

no explanatory variables were used in the forecasts; and

rooftop PV was not separately considered or forecast.

Following the ZSS MD forecasts, the key steps undertaken by PWC in developing the system MD forecasts were as follows:

a system MD projection was first done through a regression of weather corrected system MDs;

a second system MD projection was undertaken based on the growth in the non-coincident ZSS MDs, accounting for future large load blocks;

a comparison of the two system MD projections was undertaken – referred to as reconciliation. This provided a band of potential system MD growths;

from the above range of system MD growths, a subjective selection of a system MD growth rate for the Trend forecast was determined. Growth rates for the High Trend and Low Trend were subjectively determined through changes to the Trend growth rate; and

System MD forecasts for the three forecast scenarios (Trend, High and Low) were assumed to start from the weather corrected P50 2013 system MD. A least square linear regression was applied to linearise the three geometrical growth scenarios.

Appendix D presents additional detail on the approach used by PWC.

4.5.2 Commentary on Methodology

The previous section presented a description of the approach used by PWC in undertaking the system and ZSS MD forecasts. This section presents commentary on the approach used and improvements that could be made. This is presented under the heading:

Available Data and Pooling of Data;

Weather correction;

20 The time-series for each ZSS covers at most from 2007-08 to 2012-13 which limits the confidence in individual estimates for each ZSS.

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Treatment of spot loads;

Form of the regression model;

Inclusion of explanatory variables; and

Rooftop PV.

Available Data and Pooling of Data

The confidence in any statistical analysis relates directly to the available data. The small amount of data that was available for the forecasts is a significant issue in the forecasts. Here it is noted that:

The system had seven years of MD data. 65 per cent of ZSSs has six years of MD data and the others less. Some ZSSs had only one or two years of MD data.

There was no information of the customer types in each ZSS (such as industrial, commercial, mining and residential). This is a significant issue as each customer type is subject to different growth rates and different temperature sensitivities.

Grouping of ZSS based on the demographics (same type of customers and mix) provides for the data to be “pooled” in order that the level of confidence in the estimates developed is increased. This provides for a common relationship across the pooled data to be developed while still allowing each individual ZSS to have different intercepts (levels of demand).

Weather Correction

As the forecasting approach adopted by PWC was based on trends on the weather corrected (P50) MD data, the accuracy of the weather correction was a significant issue. The weather correction was undertaken by estimating a sensitivity factor that expresses the change in MD for a difference between the maximum temperature on the day and the maximum daily temperature that defines the P50 level (referred to as the Reference P50 Maximum Daily Temperature). These factors for each of the three systems are presented in the table below.

Table 4.9: Temperature Correction Factors **

Demand Sensitivity Factor Reference P50 Maximum Daily Temperature

Darwin-Katherine 3.2% 35.9oC

Alice Springs 2.88% 42.9oC

Tennant Creek 2.88% 42.3oC

** Correction in MD = Actual MD x Demand Sensitivity Factor x (Reference P50 Max Temp - Actual Max Temp)

Over estimating the impact of temperature in a year where the MD day occurred with a maximum temperature below the defined the P50 reference level would result in the P50 MD being too high, and vice versa when the temperature was above the defined P50 level.

A review of the process used to derive the Demand Sensitivity Factor (or slope) showed that this was defined as the slope of the linear trend of system MD versus maximum daily temperature on days where the temperature was above 25oC. However, weather correction is applied correcting MDs for

63


temperature differences in the range 32oC to 35oC, and for this temperature range the observed slope is less and more uncertain. The graphical display of daily MD versus daily maximum temperature for the Darwin-Katherine system is shown in the figure below.

Figure 4.15: Darwin Katherine: Daily MD versus Daily maximum Temperature21

Form of the Regression Model

PWC assumed the regression model form to be linear for all ZSSs and for the system. However, other model forms exist that may improve the regression and be more consistent with known developments in the market. Examples of other model forms are:

Linear-log: tests if explanatory variables have a diminishing effect on maximum demand over time;

Log-linear: tests if explanatory variables have an increasing effect on maximum demand over time; and

Double log: tests if there is a constant percentage effect of explanatory variables on maximum demand over time.

Treatment of Spot Loads

Spot loads are large demand increments that are not considered part of the normal demand growth. An example might be a very large industrial development. The treatment to exclude these from the regression model would increase the accuracy of the forecast. However, there is subjectivity required in relation to the probability of each individual spot load actually eventuating as programmed.

It is understood that the assumptions of the spot loads that were assumed to eventuate were different for the ZSS MD projections and the system MD projections. The forecasts for each ZSS assumed all spot loads for that ZSS would enter (or leave), while the system forecasts assumed only 50 per cent of the spot loads would enter. It is assumed that the logic for the system forecasts recognized the probability of not all spot loads eventuating.

21 Source: PWC report Network Demand Forecasting Procedure dated April 2013.

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The Commission considers it appropriate that this treatment be made consistent across the ZSS and system projections.

Inclusion of Explanatory Variables

Explanatory variables improve the accuracy of forecasts when a relationship exists and the explanatory variables introduced can be confidently forecast across the period of interest.

It was recognised that the limited number of observations across the ZSS limits the number of explanatory variables that can be tested together, and that PWC undertook a review of factors such as population and Gross State Product (common for all ZSSs).

While not used in the recent forecasts, the Commission considers it appropriate that consideration be given to including appropriate explanatory variables in PWC’s forecast model.

Rooftop PV

The increase in rooftop PV in many power systems has been one of the key factors that have resulted in reduced growth in demand supplied by the main grid. The Commission notes that this was one of the issues in the NEM that resulted in rooftop PV being explicitly forecast and explicitly represented in AEMO’s approach to demand projections. As previously noted, the Solar Cities program resulted in a large amount of rooftop PV being installed in Alice Springs. While there is less rooftop PV in the other systems, the potential exists for this to influence future MDs. Rooftop PV is discussed in the following section.

The Commission considers it appropriate that rooftop PV be explicitly forecast and explicitly represented in PWC’s MD forecasts for the three power systems.

4.6 PV Projections

4.6.1 Overview

The primary form of renewable energy likely to impact NT power systems is rooftop Solar Photovoltaic (PV) capacity. PV penetration is expected to continue to increase, particularly considering the fact that PWC still maintains a 1 for 1 gross feed in tariff22 (FiT), compared to most other jurisdictions which are rapidly scaling back the level of support for PV.

Increased penetration of PV will reduce the amount of output required from centralised generators, thereby reducing the Greenhouse Gas (GHG) emissions from the power system, as well as defer the amount of transmission and distribution network capacity investment to some extent, by lowering MD from what it otherwise would be.

Other renewable and non-renewable forms of distribution, as well as improvements in energy efficiency, will also have similar effects for the power system. However, PV is expected to be the most significant form of new distribution generation over the 10 year period to 2024. The impacts of

22 A 1:1 gross feed-in-tariff where the household with PV is paid a rate equal to their retail electricity rate for every kWh of generation (whether this generation offsets local demand or is exported to the grid).

65


energy efficiency will be implicitly included in demand forecasts. Therefore, only the effects of PV have been estimated through separate quantitative analysis.

This section focuses on the approach and results of this quantitative analysis. The main output of this analysis is the impact that the uptake of PV is likely to have on MD. It should also be noted that PV uptake may in some instances result in an additional cost to network services providers as well benefit (or deferred cost), particularly where increases in PV capacity result in bi-directional flows of power on existing network capacity that was not designed for such use. These broader implications are recognised but have not been analysed in this review.

4.6.2 Approach to estimating impact of PV on MD

The approach taken to estimating the impact of PV on MD is broadly aligned with that taken by AEMO for the National Energy Forecasting Report (NEFR) 2013. Marsden Jacobs reviewed this approach and found it to be robust and relatively straightforward. However, Marsden Jacobs recognised that there are both data limitations (of applying the method on either national data or just the NT) and margins of uncertainty. These qualifications accompany the results. There are two major steps required to estimate the impact of PV on MD. These are:

Project the amount of future PV capacity; and

Forecast the contribution this capacity makes to offsetting MD.

These are discussed in turn below.

4.6.3 Approach to projecting future uptake of PV

The uptake of PV is primarily driven by two factors. Firstly, as purchasing a rooftop PV system is a financial decision, households are motivated by the economics of that decision. This is both a rational expectation but is also evidenced by the fact that uptake has been strong in response to government incentives. Secondly, some demand is likely to be driven by environmental concerns. The AEMO NEFR methodology23 was in turn largely based on a study by consultants Intelligent Energy Systems (IES) for the Clean Energy Council24. IES estimated an uptake function that:

expressed uptake as a function of payback period;

was a piecemeal function comprised of two segments (one representing uptake motivated primarily by financial considerations and another by environmental); and

accounted for a ‘rush factor’ explaining higher than otherwise uptake at times just before government incentives were significantly reduced.

AEMO broadly adopted this approach but also explicitly applied an adjustment for saturation 25

effects which account for diminishing available rooftop space. The AEMO method appears to require such an adjustment as it relates uptake (measured in MW) to payback (years), whereas IES implicitly accounts for saturation effects as it expresses uptake as a percentage (per cent of available rooftop

23 ‘Forecasting Methodology Information Paper’, AEMO, 2013.24 ‘Analysis of Possible Modifications to the Queensland Solar Feed-in Tariff: Report for the Clean Energy Council’, IES,

22 June 2013.25 pp. 37-38, ‘Forecasting Methodology Information Paper’, AEMO, 2013.

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capacity). Therefore, if applying an IES approach for two separate years/regions both with the same payback period, the year/region where there is more eligible rooftop space (less saturated) will have greater uptake than the other (all else equal). The latter approach has been adopted.

Payback period is calculated as a discounted payback period. That is, it is the time taken for a household to recover their initial investment in PV, from savings on their electricity bill 26 and/or revenue from FiT, taking into account the interest rate of money used to fund that purchase (assumed to be diverted from mortgage payments).

For the purposes of estimating parameters of the payback function, estimates of historical payback were required. Table 4.3 below summarised the key assumptions used in this estimation:

Table 4.10: Sources used for estimated historical payback

Key assumption Source(s)

Historical 1:1 Gross FiT (equal to

retail variable tariffs)

Utilities Commission records

‘Solar Cities Data Analysis Report’, CSIRO, 10 July 2013

Historical PV installation cost ‘Forecasting Methodology Information Paper’, AEMO, 2013

‘Analysis of Possible Modifications to the Queensland Solar Feed-in Tariff:

Report for the Clean Energy Council’, IES, 22 June 2013

‘PV in Australia 2011’, Australian PV Association, May 2012

‘PV in Australia 2012’, Australian PV Association, May 2013

Historical Small-scale Renewable

Energy Scheme (SRES) subsidy

‘Modelling creation of Small-scale Technology Certificates’, ACIL

Tasmanian, December 2011

‘Small-scale technology certificates data modelling for 2013 to 2015’, Green

Energy Markets, February 2013

GEM website, http://greenmarkets.com.au/, last accessed 11/3/2014

CER website,

http://ret.cleanenergyregulator.gov.au/Latest-Updates/2012/December/of-1,

last accessed 12/3/2014

Long term average consumer

borrowing rate

‘Analysis of Possible Modifications to the Queensland Solar Feed-in Tariff:

Report for the Clean Energy Council’, IES, 22 June 2013

Where projecting future uptake required projection of factors affecting uptake in the future. Key assumptions of payback factors are provided in Table 4.4 below.

26 Most jurisdictions provide a net FiT for Solar PV whereas in NT, PWC provides a gross FiT. This means that households benefit from PV through revenue from the FiT but not from savings on their bill.

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Table 4.11: Sources used for projecting future uptake

Key assumption Source(s)

Projected PV system cost (assumed

to decline at 5 per cent per year in

real terms)

‘Forecasting Methodology Information Paper’, AEMO, 2013

Projected retail variable tariffs

assumed to increase 3.9 per cent per

year

Historical compound annual growth between 2006 and 2014, excluding

outlier increases

Feed-in Tariff (FiT) Gross FiT assumed to be maintained for financial years 2014/15 and

2015/16, thereafter reverting to a Net FiT of 8.41 c/kWh in 2016/17 and

increasing with CPI (to be consistent with FiT settings in most other

jurisdictions in Australia)

SRES long term price Set at current (2014) price of $39

Panel size Average panel size of PVs qualifying for SRES certificates by region (CER

database)

4.6.4 Approach to forecasting the contribution of PV to reducing MD

The reduction in annual maximum demand was calculated using the equation below (reduction in maximum demand from PV is estimated as the product of installed PV capacity and a factor that represents the percentage of that capacity expected to be generating at the time of maximum demand).

Equation: Reduction in Maximum Demand due to PV Installation

Reduction∈Demand (MW )Max Demand=Installed PV Capacity (MW )×PV Capacity Factor ( per cent)Max Demand

The PV capacity factor during the time of maximum demand (PV Capacity Factor (per cent)Max Demand in the above equation) was calculated using PV output time profile data provided by Desert Knowledge Australia (http://www.desertknowledge.com.au/Home) and analysis of regional maximum demand time profiles.

The assumed time profile of output from PV is shown in Figure 4.7 below.

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Figure 4.16: Desert Knowledge Alice Solar City (DKASC) average PV output time profile

Whereas, to determine the hour of the day at which maximum demand was most likely to occur density plots27 for the hour of MD for each of the top 30 demand days in each region was plotted.

Figure 4.17: Density functions of daily maximum demand for all regions

27 AS = Alice Springs, DK = Darwin & Katherine, TC = Tennant Creek in the density plot below.

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0.0%

0.2%

0.4%

0.6%

0.8%

1.0%

1.2%

1.4%

1.6%

1.8%

2.0%

0 2 4 6 8 10 12 14

Upta

ke (%

of e

ligib

le h

ousin

g st

ock)

Discounted payback (years)


Figure 4.18: Density functions of daily maximum demand by region

The PV capacity factor was derived by calculating the probability weighted average coincidence of PV output at times of maximum demand.

4.6.5 Modelling Results

Estimated uptake function

Estimates of historical payback (applying the approach described above) combined with historical uptake statistics (derived using a combination of Clean Energy Regulator (CER) and Australia Bureau of Statistics (ABS) data were used to estimate the coefficients of the uptake function using regression analysis. The estimated uptake function is presented below.

Figure 4.19: Estimated uptake function

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Projected uptake

Projections of future uptake (number of panels and total kW) were derived by applying the above uptake function to estimates of future payback. The results of this analysis are provided in Table 4.6 on the next page.

Notably PV uptake is expected to grow strongly reaching a cumulative 36 MW for the three regions by 2023-24 with the majority of this uptake (in both absolute and relative terms) occurring in Darwin. Although financial benefit through FiTs is projected to decline, this is more than offset by the combined effects of dwelling growth (approximately 1.8 per cent per annum compound annual growth in Darwin) and projected reductions in system cost.

Projected contribution to offsetting MD

The analysis of PV output and maximum demand data yielded the following factors (percentage of PV capacity expected to offset MD):

Table 4.12: MD Offset Factors

MD Offset Factor

Darwin & Katherine 61.10%

Tennant Creek 63.70%

Alice Springs 59.50%

Multiplying projected capacity with these offset factors provides the expected contribution of PV to offsetting MD. This is provided in Table 4.5.

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Table 4.13: Projected cumulative uptake of PV by region (kW)

Financial year

ending (kW) 2013/14 2014/15 2015/16 2016/17 2017/18 2018/19 2019/20 2020/21 2021/22 2022/23 2023/24

Darwin 6,601 7,664 10,056 12,705 13,234 14,413 16,117 18,240 20,695 23,414 26,337

Tennant Creek 298 341 438 544 565 611 677 758 851 954 1062

Alice Springs 3,849 4,056 4,596 5,140 5,364 5,679 6,065 6,623 7,207 7,805 8,409

Table 4.14: Projected contribution of PV to offsetting MD by region (kW)

Financial year

ending (kW) 2013/14 2014/15 2015/16 2016/17 2017/18 2018/19 2019/20 2020/21 2021/22 2022/23 2023/24

Darwin 4,033 4,683 6,144 7,763 8,086 8,807 9,848 11,144 12,645 14,306 16,092

Tennant Creek 190 217 279 346 360 389 431 483 542 607 677

Alice Springs 2,290 2,431 2,735 3,058 3,191 3,379 3,609 3,941 4,288 4,644 5,003

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4.6.6 Discussion

Historically, drivers for increasing uptake of renewable energy, non-renewable distributed energy and energy efficiency in the Territory have included both federal government initiatives (e.g. the Large Scale Renewable Energy Target (LRET), Small-scale Renewable Energy Scheme (SRES), appliance energy efficiency standards etc.) as well as some specific Territory initiatives (e.g. Alice Solar City (ASC) program and PWC Gross FiT etc.). These factors will continue to encourage the uptake of renewable energy, non-renewable distributed energy and energy efficiency in the Territory.

On the one hand, policy support may reduce over time. Notably the federal government has indicated a review of the LRET/SRES schemes and FiT levels have been reducing in most other Australian jurisdictions. On the other hand, the cost of emerging technologies continues to decline.

Marsden Jacobs explicitly modelled the contribution of rooftop PV to MD, whereas the impact of other technologies is implicitly accounted for in demand forecasts.

4.7 PWC Zone Substation Maximum Demand Forecasts

The results of the MD projections undertaken by PWC Networks for each of the three systems are presented in turn below.

4.7.1 Darwin-Katherine Maximum Demand Forecasts

The forecasts of system MD and ZSS MD on a P50 basis for the Darwin-Katherine system are shown in Figures 4.11 and 4.12 respectively. Corresponding tabular results are contained in Appendix D.

Figure 4.20: Darwin-Katherine System Maximum Demand Forecasts


0

10

20

30

40

50

60

70

80

MW

ArcherBatchelorBerrimahBrocks CreekCasuarinaCentre YardCityCosmo HowleyEast ArmFrancis BayHumpty DooKatherineLeanyerMantonMary RiverMcMinnsPalmerston

Figure 4.21: Darwin-Katherine ZSS Maximum Demand Forecasts

As described in the methodology review, the ZSS MD forecasts were done first. The ZSS MD forecasts reflect the growth trends and the assumptions of spot loads.

On a system wide bass, the Forecast Trend is higher than the historical trend. The Commission also note that excluding the 2007 year would have reduced the historical growth rate by about half. The higher Forecast Trend is considered due to the selection of a 2.7 per cent growth rate that is a combination of historical system MD growth and historical ZSS non-coincident MD growth. However the increasing diversity between the ZSS demands was not accounted for and is likely to be a factor in the overstatement of system MD demand growth. This growth rate is also assumed in some ZSS where there is limited data and this may also result in forecast error.

4.7.2 Alice Springs Maximum Demand Forecasts

The forecasts of system MD and the two ZSS MDs on a P50 basis for the Alice Springs system are shown in Figures 4.13 and 4.14 respectively. Corresponding tabular results are contained in Appendix D.

The PWC forecasts are consistent with the individual ZSS temperature corrected historical MD trends which has Ron Goodin significantly decreasing and Lovegrove increasing. However PWC did not provide any explanation as to why the growths of these two ZSS should be so different. The only comment made by PWC was that “a load of 4.36 MVA has been transferred from the Ron Goodin zone substation to the Lovegrove zone substation on a permanent basis in 2013-14”. Without any explanation to the contrary it would be expected that the two ZSSs would have similar growth outlooks, and this would be that each would have a growth outlook consistent with the system growth outlook.

The Commission also notes the trend that has been reported concerning a narrowing of winter and summer MDs in Alice Springs. While this has not yet occurred (the 2013 MD occurred on 24 January for Lovegrove and 24 January for Ron Goodin) a separate projection of winter MD should be undertaken (requiring historical winter MDs).

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Figure 4.22: Alice Springs System Maximum Demand Forecasts

Figure 4.23: Alice Springs ZSS Maximum Demand Forecasts

4.7.3 Tennant Creek Maximum Demand Forecasts

The forecast of system MW for Tennant Creek is shown in Figure 4.15 below. Corresponding tabular results are contained in Appendix D. This outlook is consistent with the historical trend which is a small growth moving forward.


Figure 4.24: Tennant Creek System Maximum Demand Forecasts

4.8 Load factor

The 2011-12 Review made the observation that the load factor in both the Darwin-Katherine and Alice Springs systems is trending down, whereas the trend had reversed in the Tennant Creek system. The reasons for a reducing load factor can be many, including one extreme demand day each year.

The Commission requested that the reasons, if any, for the falling load factor in the Darwin-Katherine and Alice Springs systems be better understood. The importance of load factor relates to the relationship between the causes of investment and the structure of tariffs designed to pay for investments. Network and generation investments are largely driven by increasing MD while tariffs are largely based on energy consumed.

The Commission distinguish between system load factor and individual ZSS load factor. The relationships between ZSS load factors (which can individually be different) and system load factor depends on the demand diversity between the ZSSs (discussed below). System load factor is relevant to transmission and generation investments, while individual ZSS load factors are relevant to distribution.

The trend of load factors for the Darwin-Katherine, Alice Springs and Tennant Creek systems is shown in Figure 4.16. This figure shows historical load factors (2007-08 to 2012-13) calculated based on actual and weather corrected (P50) MDs, and projected load factors (2013-14 to 2018-19) based on PWC Network system MD projections and PWC Generation system energy projections. The projected system energy growth for the Darwin-Katherine system has decreased significantly from the previous projections. The following observations are made:

The load factor of actual demands is higher in almost all years due to P50 MD being higher than actual due to below average temperatures. The Darwin-Katherine system weather corrected load factor of 61.7 per cent in 2012-13 was the highest in the review period and equal to that recorded in 2008-09. Actual load factors (calculated using actual MD and actual energy) have been steady over the past three years but were below the actual load factors before and including 2009-10.

The Alice Springs and Tennant Creek systems have had load factors that have decreased and then increased with no indication of any long term decline.

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Looking forward and based on PWC Generations’ energy forecasts, Alice Springs and Tennant Creek have projected load factors that will be either flat or slightly increasing. Darwin-Katherine is projected to have a decreasing load factor due to the low projected growth in energy. As noted, this was based on an energy forecast that was not reviewed.

4.8.1 Diversification

As noted above, system load factor and ZSS load factors are related by the demand diversity between the ZSSs. This is the relationship between the non-coincident ZSS MD and coincident ZSS MD. This is mainly relevant to the Darwin-Katherine system. Demand diversity between ZSSs is an issue that is recognised by PWC.

Darwin-Katherine

The decreasing trend in load factor (based on

P50 MDs) was reversed in 2012-13 when the

highest load factor (based on P50 MD) was

recorded. The load factor (based on actual

MDs) reflects the lower temperatures that had

occurred in the past.

A low energy forecast has load factor

decreasing in the future.

Alice Springs

There is no historical evidence that load factor

is decreasing (on an actual or weather

corrected basis). A trend analysis shows a

slightly increasing load factor. This is consistent

with high PV installations which act to reduce

MD more than energy consumption.


Tennant Creek

Historical load factor based on 50 per cent POE

demands indicates a stable load factor. Actual

load factor has been stable at about

50 per cent for the past 4 years.

PWC Generation has projected a low energy

growth rate consistent with the MD growth

rate.

Figure 4.25: Load Factor Trends – Actual and 50 per cent POE Weather Conditions

The diversity28 between the Darwin-Katherine ZSS MDs was examined by comparing the growth in historical coincident and historical non-coincident ZSS P50 MDs. The growth in coincident ZSS P50 MD was taken to be the growth in system P50 MD (noting that any difference would only be due to changes in transmission losses). The graphs contained in Figure 4.17 show the historical coincident and historical non-coincident ZSS P50 MDs and the difference between these. To aid in visualisation the graphs have assumed no diversity in the year 2008 (where the actual level of diversity was 60 MW). The graphs show that the diversity between ZSS MDs has been increasing.

Total ZSS Non-coincident and Coincident ZSS P50 Maximum Demands

Increase in diversity sine 2008 (between ZSS P50 Non-coincident and Coincident P50 MDs)

Figure 4.26: Darwin-Katherine: Historical Non-coincident ZSS and Coincident ZSS MD Growth

4.8.2 Load Factor Trends

The review has shown that on a system wide basis there is no evidence to support any noticeable decrease in load factors in either of the Darwin-Katherine, Alice Springs and Tennant Creek systems. However, the

28 The Diversity is the difference between the summation of system P50 MDs and ZSS P50 MDs.78


lower load factors in the Darwin-Katherine system over the past three years and the low projected growth in energy by PWC Generation compared to MD may be indicating higher MD growth compared to energy. The review did demonstrate that load factor can be volatile as a single high demand day can significantly impact its value.

Increasing diversity between the MDs of the individual Darwin-Katherine ZSSs was observed from the historical analysis and this would assist in limiting an increase in Darwin-Katherine system load factor. However it would hide increasing load factors at the ZSS level which are relevant to the economics of distribution investment.

Consequently it is recommended that both system and ZSS load factors be monitored, and that any observed decrease next year (should this occur) be investigated.


Further analysis of the reasons for falling load factor in the Darwin-Katherine and Alice Springs systems.

The Commission considered in the 2011-12 Review that PWC’s energy forecasts were too high, with energy growing faster than demand. For the 2012-13 Review, the Commission notes that PWC’s energy forecasts do not appear to reconcile with the system MD forecasts and historical trends in load factor. No further commentary is made as the forecasts were not provided with supporting documentation.

4.10 Maximum Demand key findings

After the review and analysis of the MD and energy forecasts provided by PWC the following observations, conclusions and recommendations are provided.

4.10.1 Zone Substation MD Forecasts

There is no statistical evidence based on the data provided to suggest that the ZSS MD forecasts would err on the high or low side.

However there were issues in the development of the forecasts which suggest a lower level of confidence in the ZSS MD forecasts than should be achievable, particularly for the Darwin-Katherine ZSSs. Three key issues are noted:

The lack of data available was a serious issue to the confidence of the MD forecasts. This lack of data included not only having ZSS MD data limited to the previous 6 years or less, but also not having available information on the split of customer types in each ZSS. Data going back more than six years must be available, and ZSS demographic information is available through billing data and other sources.

The approach to weather correction of the raw MD data introduced the risk of overcorrection, and the risk of significant error in the forecasts produced. The issues here included the temperature range over which the demand to temperature sensitivity was derived, and the use of a single sensitivity for all ZSS regardless of the customer mix.

The inclusion of spot loads without supporting evidence as to their likelihood. The assumption of 50 per cent of spot loads eventuating in the system MD forecasts indicates that there is uncertainty in these spot loads.


The ZSS MD forecasts for Alice Springs were not accompanied with information on the forecasts that had Ron Goodin substantially decreasing and Lovegrove increasing. While these trends were consistent with the historical data, prima facie there is significant uncertainty regarding these trends. Not specifically representing rooftop PV in the Alice Springs forecasts (given the level of rooftop PV installed) may be a significant issue to these forecasts.

The stability of the Tennant Creek MD was reflected in the forecasts.

4.10.2 System MD Forecasts

There were issues with the development of the Darwin-Katherine system MD forecast that would give reason to conclude that this forecast would err on the high side. The principle reason is the influence of the non-coincident ZSS MDs growth rate on the projected system growth that did not account for the observed increasing level of diversity between the ZSS MDs. Other reasons included the potential overcorrection of weather correction when temperatures had been at or below average for a number of years. This is supported by the historical system growth which is considerable lower than that projected.

The system MD growths for Alice Springs and Tennant Creek did not have the same issues as Darwin-Katherine given these systems have only three and one ZSS respectively.

4.10.3 System Energy Forecasts

The system energy forecasts produced by PWC Generation for the Darwin-Katherine system did not appear to reconcile with the system MD forecasts and historical trends in load factor. No further commentary is made as the forecasts were not provided with supporting documentation. The energy forecasts for Alice Springs and Tennant Creek showed virtually no growth and are in line with the MD forecasts.

4.10.4 Recommendations

Recommendations are made in relation to three areas, these being data, forecasting methodology, and processes. The respective recommendations in these areas are as follows.

Data

The Commission recommends that PWC consider:

establishing historical winter and summer MD demand going back at least 15 years;

developing data on the customer type mix in each ZSS and the trend in this mix;

obtaining evidence or not as to any trend in ZSS MD diversification;

obtaining historical rooftop PV installations by system (and if possible ZSS); and

fully documenting the details of the spot loads used in the forecasts and the basis for the probability of these loads eventuating in the outlook years.

Methodology

The Commission recommends that PWC review the approach used for the forecasting of ZSS and system MDs that gives consideration to the issues notes in this report, and in particular:

weather correction;

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use of explanatory variable;

rooftop PV; and

model form and assumption of linearity.

The Commission also considers it appropriate that PWC undertake a reconciliation of the system energy forecasts and MD forecasts.

Processes

The Commission recommends that PWC develop internal processes that streamlines data storage and flows, and limits error through issues such as minimising the number of spreadsheets used (manual transcription of data between different spreadsheets could be a source of error in determining forecasts) and this includes the proper labelling and identification of numbers.


5. Generation Performance

5.1 Introduction

5.1.1 Spinning reserve

PWC has engaged SKM to complete a review of their existing spinning reserve policies to assess whether a change is required. At the time of writing this report, SKM have completed the technical analysis for the existing spinning reserve and load shedding arrangements. To be completed included an economic dispatch analysis and new frequency response analysis with revised spinning reserve values.

The existing spinning reserve target for the Darwin-Katherine system is 25 MW and is significantly less than the size of the largest generator in the network. Consequently, tripping of a generator typically results in the need to shed some load. This approach is inconsistent with the operation of larger networks such as the Australian east coast network.

Providing additional spinning reserve would be costly and it may be appropriate to accept some load shedding in the event of a generator trip event. This can only be determined by the economic analysis that SKM are scheduled to complete in the coming weeks. However, a key input to this analysis which can strongly influence the outcome is the assumed value of customer reliability (VCR). The VCR used in the national electricity market varies from state to state and in every case exceeds $41,500 per MWh. The VCR can be provided for separate customer segments and for example exceeds $23,800 for residential customers in Victoria.

In the absence of any other changes, increasing the target spinning reserve can be expected to improve the reliability of electricity supply, while conversely reducing the amount of spinning reserve can be expected to reduce the reliability of electricity supply.

There is insufficient information available at the time of writing this report to assess the sufficiency of the spinning reserve targets used by PWC. It is recommended that PWC complete the review being conducted by SKM and ensure that the following information is available for next year’s Review:

value of customer reliability used in spinning reserve analysis and a robust analysis of how that value has been selected

new spinning reserve targets for each of the networks

extent to which the system can be expected to remain secure during multiple contingency events

analysis of the improvement/decrease of reliability expected due to any change of the spinning reserve targets

number of hours during the previous year during which the target spinning reserve margins were not achieved.

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Statistics provided by PWC show that for the Darwin-Katherine system their spinning reserve target was achieved 97.4 per cent of the time during the 2012-13 financial year. This might be considered unsatisfactory in the NEM but is good performance for a system of this size.

The document “Attachment D – Overview of half yearly reports January to June 2013” states for both the Alice Springs and the Tennant Creek systems that “Load shedding events generally result in a System Black”. Therefore, periods when there is inadequate spinning reserve are not reported. It is noted that the SKM spinning reserve study includes the Alice Springs network but not the Tennant Creek network, so as a result of this study the reliability of the Alice Springs network may be improved.

5.1.2 Incident report review

A small number of documents have been made available to the Commission, these include:

1. Attachment D – Overview of half yearly reports January to June 2013

2. Darwin – Katherine power system half yearly report January to June 2013

3. Tennant Creek power system half yearly report January to June 2013

4. Alice Springs power system half yearly report January to June 2013

5. Alice Springs power system – OSPS Unit #3 trip and UFLS Stage 1B 17 th November 2013 and 4th December 3013

6. Eight preliminary incident reports

Document One is a useful summary of a number of statistics for the three power systems. In particular it shows that for the six month period there were; eight load shedding events on the Darwin-Katherine system, six load shedding events on the Alice Springs system and one load shedding event on the Tennant Creek system.

Documents Two, Three and Four have identical introductory sections. One paragraph from these documents is repeated here:

“By implication, the definition of a Secure Operating State allows involuntary load shedding as a response to the Critical Credible Contingency Event, as long as the system returns to a Satisfactory operating state”.

The introduction also indicates that the power system is not in a Reliable Operating State unless: “… b) Involuntary load shedding will not occur if a credible contingency occurs…‘. The Commission takes this to mean that the three power systems rarely if ever operate in a “Reliable Operating State”. This situation would not be acceptable in other power systems including the Australian Eastern States.

Documents Two, Three and Four discuss some instances of network operation above the firm capacity. Only generator incidents are discussed further here.

Document Two includes a section that describes the eight involuntary load shedding events that occurred on the Darwin-Katherine System. The Commission makes a number of observations of each event:

7 January 2013 at 17:18. A line trip occurred for unforeseeable reasons and need not have resulted in any load shedding. However, two generators in the Katherine system tripped. One generator tripped due to an unstable governor and there is no evidence provided that the governor has been adjusted. The other generator tripped for reasons unknown. The document concludes; “Cause of the instability


and resultant generator trips at PC is unknown as a report has not been received from the Independent Power Producer”.

9 January 2013 at 12:54. Weddell Power Station Unit 2 tripped, with CIPS unit 8 tripping 25 seconds later. Tripping of the second (CIPS U8) machine is stated to be due to blocked diesel injectors that are also used for water injection. It is also stated that the injectors have been replaced and a cleaning program implemented.

13 January 2013 at 21:42. CIPS unit 8 tripped again due to blocked diesel injectors.

2 February 2013 at 10:50. Weddell Unit 1 tripped.

13 February 2013 at 11:02. CIPS unit 9 tripped.

27 February 2013 at 21:19. CIPS unit 8 tripped with CIPS unit 4 tripping 24 seconds later. Tripping of the second (CIPS U4) machine was due to a low gas pressure causing the machine to automatically switch over to diesel fuel, which at the time was not available. Diesel switch over has been disabled to prevent a reoccurrence.

10 March 2013 at 20:18. The Darwin and Katherine systems became separated due to a transmission system event. The Katherine Unit 4 failed to deliver its spinning reserve capacity due to its control system being in block control mode.

14 June 2013 at 10:56. CIPS unit 7 tripped.

Four of these eight load shedding events (events 1, 2, 6 and 7) would traditionally be described as double contingency events. Such a high level of double contingency events deserves very close attention. Given that double contingency events are so common on the Darwin-Katherine system it is reasonable to expect the occasional triple or higher order event to occur. Such events could reasonably be expected to result in a system black situation.

Document Three includes a section that describes the one involuntary load shedding event that occurred on the Tennant Creek System. For this recoverable event the load shedding scheme operated incorrectly, causing the system to go black. In the Commission’s opinion this was a double contingency event.

Document Four includes a section that describes the six involuntary load shedding events that occurred on the Alice Springs System. The Commission makes a number of observations of each event:

12 January 3012 at 19:10. OSPS Units 1 and 2 both tripped following a lightning strike. Protection setting changes have been made to reduce the probability of a reoccurrence of this event.

29 January 2013 at 14:18. OSPS Unit 1 tripped due to a mechanical failure.

22 February 2013 at 19:40. All OSPS units tripped due to activation of the power station gas detection system. Modifications are being made so that gas detection by one unit’s fire detection system will no longer trip all units.

12 March 2013 at 19:40. Ron Goodin Unit 9 tripped.

3 May 2013 at 11:19. A major network fault occurred and was slow to clear.

1 June 2013 at 10:12. Two generators tripped during testing of Unit 9 at Ron Goodin Power Station.

Three of these six load shedding events (events 1, 3 and 6) would traditionally be described as double contingency events. Such a high level of double contingency events deserves very close attention.

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All double contingency events should be defined as major events and be reported to the Commission as such. This should occur even if no load shedding occurs.

5.2 Availability of existing generators

5.2.1 Asset Management plan review

The Commission requested asset management plans from PWC for review. The following relevant documents were received and are discussed in the following paragraphs:

Generation – Asset Management Strategy – 6 June 2013 - Draft

Power and Water Corporation Generation North – Asset Management Plan High Voltage Generators – Draft

Life Extension Study, Phase III – A life extension scenario and associated costs – 6 July 2012 – KEMA.

The first document contains some background to the need for asset management and describes the content of a reasonable asset management plan. This document discusses, amongst other things, objectives of asset management, principles of asset management, and responsibilities of PWC staff and describes in some detail the required content of an asset management plan. The document also makes reference to a number of subordinate documents, for example:

“Asset Management Plans are to be summarised in the Plant Status Review Report”

“All Power Stations will have an operating and maintenance strategy that will sit as separate documents from the Asset Management Strategy”

The second document is an un-dated draft. The main body of the document comprises up to eight A4 pages of text and one single-sided A4 Appendix for each of the generator units covered. This document covers the nine Channel Island units, the three Weddell units and four Katherine Units. No corresponding document has been provided for the Alice Springs or Tennant Creek units.

The title of the second document, Power and Water Corporation Generation North – Asset Management Plan High Voltage Generators, suggests that it is the asset management plan(s) referred to in the first document. The Commission would have expected that each unit have its own asset management plan and that these plans would have content consistent with the requirements outlined in in the asset management strategy document. However, this document seems to be focused on strategy and, other than the single page appendices, contains no information specific to PWC machines.

The third document is a high quality, useful document prepared by KEMA to describe a “life extension scenario” for the Channel Island units excluding units eight and nine. Importantly, this document contains information about detailed inspections made to a number of the units and makes recommendations that in KEMA’s view would allow the Channel Island station to continue to operate until 2027. This document contains the type of information and level of detail that the Commission would expect to see in the “Plant Status Review Report” referred to in the asset management strategy.

Based on the Commission’s review of the three documents provided, a number of supplementary requests for information were provided to PWC including:

supply a copy of the latest “Plant Status Review Report”;

confirm that IBM Maximo was installed/implemented for asset management as indicated in the KEMA report;


confirm that all of the recommendations in the KEMA report were entered into the asset management tool (including the regular inspection items); and

supply Maximo reports of the regular scheduled maintenance items (due dates, historic completion dates etc) for each of the CIPS generators.

The Commission also notes that even if the life extension works at Channel Island are fully implemented, the station will come to the end of its refurbished life in 2027. Therefore, it will be necessary to begin serious planning for a replacement station by about 2017. This should be beginning to enter the current planning horizon.

5.2.2 Availability outlook

PWC operate the Darwin-Katherine network on what they call an N-3, capacity planning basis. PWC’s definition of N-3 is very different to the accepted meaning of N-3 used by other utilities. At the time of the site visit N-3 could have been loosely interpreted as:

N machines in service to service the load;

one machine in service to provide spinning reserve;

one machine out of service for routine maintenance; or

one machine unavailable for service (long term) due to major maintenance activity such as the Channel Island life extension project.

Based on this arrangement it is quite conceivable that a forced outage of one machine could lead to a scenario where it is not possible to provide any spinning reserve until the machine undergoing routine maintenance can be returned to service.

PWC has provided predictions of machine availability. At Channel Island they have predicted that each of the nine machines will be available 92 per cent of the time in each of the coming 10 years. The likelihood of a certain number of machines being available at any one time has been calculated from these values:

Table 5.15: Probability of Channel Island Machines Being Out of Service

Machines out of service Probability

0 47.2%

1 37.0%

2 12.9%

3 2.6%

>3 0.3 %

The future availability quoted by PWC does not seem to be based in any significant science. To demonstrate the high levels of variability actually experienced the actual 2012-13 availability for Channel Island is compared to the predicted 2013-14 availability in the following table:

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Table 5.16: Channel Island Machines Actual vs. Predicted Availability

Machine 2012-2013Actual Availability

2013-2014Predicted availability

Unit 1 GE Frame 6 Combustion Turbine (gas or diesel) 31.6 MW capacity

98.1% 92%


0.0% 92%


95.6% 92%


99.4% 92%


85.4% 92%

Unit 6 Mitsubishi Steam Turbine (waste heat) 32 MW capacity

98.8% 92%

Unit 7 GE LM6000 Combustion Turbine (gas or diesel) 36 MW capacity

85.1% 92%

Unit 8 Trent 60 Combustion Turbine (gas or diesel) 42 MW capacity

87.1% 92%

Unit 9 Trent 60 Combustion Turbine (gas or diesel) 42 MW capacity

66.5% 92%

The historic availability values for PWC machines are highly volatile, with no discernible pattern. Typically machine availability should follow one of three basic patterns:

1. increasing availability for relatively new plant;2. constant availability for mid-life plant; or 3. reducing availability for end of life plant.

One possible explanation for the PWC machines failing to follow one of these patterns is that the mean time between failures of their machines is following the expected pattern and that the mean time to repair is highly volatile due to some external influence. The mean time to repair could be influenced by many factors including; perceived urgency of repair, availability of the other machines, the season, network load, availability of repair staff, or available funding.

In the absence of any pattern to the machine availability it is not possible for the Commission to verify PWC’s assertion that each machine will have an availability of 92 per cent, but rather this seems highly unlikely or at least the variation around this number seems unpredictable. The Commission recommends the reliability of generating units be estimated based on planned maintenance activities on an annual basis in addition to an allowance for unplanned outages. This would give some validity to the year by year projections and aid in the assessment of adequacy.

Based on the figures presented above, generator availability (92 per cent) may not be optimal. Assuming a random distribution of generator outages, three or more machines could be expected to be unavailable for a service 2.9 per cent of the time. This analysis is overly simplistic and ignores the fact that peak demand


and minimum available generation may not coincide. Therefore, the reader is advised to refer to Chapter 8 which includes a more detailed assessment of generation adequacy across the three power systems.

The Commission recommends that PWC move to a probabilistic approach to determining the available capacity. The N-X approach is only applicable to systems where each individual component has very high availability (greater than 98-99 per cent) and this assumption is not applicable to the PWC machines.

5.3 New or proposed generators

The PWC document “Capacity Investment Planning Strategy” – Draft, approved 18NOV2013 provides some insight into the requirements for additional future capacity. The Commission makes the following observations from this report:

Darwin-Katherine Network

The report says: “Based on the current medium growth scenario, it is envisaged that the N-3 criterion will be exceeded in 2021; therefore further investment will be required to be completed by 2020”. The Commission questions the validity of the N-3 criterion beyond the completion of the Channel island life extension program and so does not agree with the conclusion that further investment is required due to the exceedance of this allowance.

The Commission observed that the Channel Island life extension project only extends the station life until approximately 2027. Presumably large scale additional investment will be required prior to 2027.

Alice Springs

The report says: “Alice Springs peak demand has not grown throughout the past three years”.

Planned retirement of existing machines will see the N-2 capacity requirement breached in 2017 or 2018. It is likely that additional capacity will be required at Owen Springs from then.

The Commission has received a licence variation application from Uterne Power Plant Pty Ltd (Uterne), a holder of an Independent Power Producer (Special Generation) licence. Uterne owns and operates a 1 MWp solar photovoltaic power plant located near Alice Springs. All output from Uterne is sold to PWC under a Power Purchase Agreement (PPA). Uterne requests a variation to its licence to allow for an increase in generating capacity to 4 MWp. The licence variation request is currently being considered by the Commission.

Tennant Creek

The report says: “Presently the N-1 criterion on gas is not fulfilled, which mandates investment. The five Ruston diesel engines are at the end of their technical life and becoming unreliable.”

The report says: “The investment need is for smaller generating sets to operate as base load capacity, increasing the redundancy and reliability of the power station. A business case has been approved by the Board to address this investment requirement. Three new 2 MW gas sets are planned to be installed in situ of current 1 MW sets at the end of their life. The Ruston diesel sets and associated infrastructure will then be retired.”

PWC appear to be planning adequately for future generation investment with the possible exception of the Channel Island station. Immediate investment does not seem to be required at Channel Island over and above the life extension works. However, when the station replacement does become necessary in 2027 this will be a major undertaking and some level of conceptual planning should begin to occur within the next three years.

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Any plan to replace the Channel Island station should consider opportunities to establish major generation at a new site and consequently provide geographic diversity of generation.


5.4 Progress against key findings from the 2011-12 Power System Review

Continued development of electrical models, particularly in the Darwin-Katherine and Alice Springs systems, to identify both steady and transient stability issues must be addressed in order to fully realise the reliability benefits achievable from the significant investment in new generation in the systems. This work should specifically identify and document any deficiencies in current generator technical standards or network configuration that may be contributing to the transient stability issues in the systems, and develop a plan to redress them.

The Commission notes that this has not been addressed for the 2012-13 Review. The Commission recommends this be addressed as part of the 2013-14 Review.

Consistent with the above approach, finalise a comprehensive, and consistent with industry practice, policy on spinning reserve to be carried in each of the systems, with the intent of increasing the resilience of the systems to individual generator trips.

The Commission requested in 2011-12 that PWC finalise a comprehensive, and consistent with industry practice, policy on spinning reserves to be carried in each of the systems, with the intent of increasing the resilience of the systems to individual generator trips. The Commission notes that this recommendation has not been completed, with the assistance of SKM, and that this review should be complete by mid-2014.

Improvement of generation reliability at a unit level to reduce the number of Under Frequency Load Shedding (UFLS) events that are occurring across all three systems.

The Commission has not seen any evidence to suggest that there has been a material improvement in this area for the 2012-13 Review.

5.5 Key findings – generation operation and planning

Predominance of multiple contingency events

Approximately 50 per cent of the major system events examined by the Commission constitute double contingency events. Such a high level of double contingency events suggests that it is not appropriate for spinning reserve or system security decisions to be made using the common N-1 (N+1 machines in service) methodology. Furthermore triple or even higher order contingencies are conceivable. All multiple contingency events should be reported to the Commission as major events, irrespective of whether any load is curtailed.

Reliance on load shedding in lieu of spinning reserve

The PWC practice of routinely shedding load for single contingency events would be unsatisfactory in most electricity networks. It is understood the appropriate level of spinning reserve (and indirectly this load shedding practice) is currently being investigated by PWC. The Commission is keen to be informed of the outcomes of that study and any decisions to revise spinning reserve practices as a result. The Commission will also look at the assumptions of that study including the assumed value of customer reliability.

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6. Fuel Supply

6.1 Introduction

98 percent of all electricity generation in the Northern Territory is based on gas-fired generation. PWC is currently responsible for the generation29, transmission and distribution of electricity in the Northern Territory. PWC’s three main electrical systems all of which use natural gas as a primary fuel source are: Darwin – Katherine system Tennant Creek system; and Alice Springs system

6.2 History of Northern Territory Gas Supply

From 1983, gas from Palm Valley was transported by a 150km pipeline as the main generation fuel for Alice Springs. In 1987 gas supply to Darwin commenced from Mereenie and Palm Valley after the construction of the Amadeus Gas Pipeline, which transported gas from central Australia to Darwin. Over this period PWC expanded electricity production and the Mereenie/Palm Valley gas producers extended gas contracts to supply the growing power demand in the Territory. In 2010, in the face of increased gas demand and due to rapidly declining gas production from the Amadeus Basin fields of Palm Valley and Mereeine, PWC commenced taking gas under a new long term gas contract with ENI Australia Limited (“ENI”) from ENI’s Blacktip gas field in the Bonaparte basin.

Currently, Mereenie and Palm Valley supply small quantities of gas to other customers in the Territory. Depending on relative gas pressures from Mereenie and Palm Valley, Blacktip gas also flows south to Tennant Creek or even further. PWC has also contracted to buy gas from the Dingo field to mix with Mereenie gas to make it more suitable for PWC’s generators in Alice Springs.

6.3 Adequacy of Northern Territory Gas Supply

PWC advised its gas usage for 2012-was approximately 21 PJ (annual daily average of 57.5 TJ/d).

PWC has forecast flat growth in gas demand from the three main electrical systems during the next five years, with increased efficiency from modern generation facilities (such as the new Owens Springs power station replacing the Ron Goodin station in Alice Springs) offsetting increases in power demand. Significant growth in demand for gas over the medium to long term is more likely from major new mining projects in the Territory or conversion of remote mining operations from diesel to gas, although commercialisation of these projects are naturally subject to ongoing investigations.

6.4 PWC Gas Supply

PWC has entered into a long term contract to purchase gas from ENI’s offshore Blacktip gas field in the Bonaparte Basin. Raw gas from Blacktip is processed into sales gas at ENI’s onshore processing plant at near Wadeye. Refer Figure 6.1 for location of ENI’s Blacktip field and the onshore processing plant. PWC and ENI have entered into a 25 year gas supply arrangement, commencing in 2010 for the supply of no less than

29 Either directly or through contracts with IPPs.


740 PJ of gas which based on current PWC forecasts is expected to meet electricity demand through to 2034.

PWC’s annual contract quantity for the 2012-13 period is in excess of its actual gas requirements. The annual contract quantities from Blacktip increase over time to allow for market growth in the Territory and are also considered to be in excess of PWC’s forecast demand over the medium to long term. While PWC’s annual quantities appear to be sufficient over the long term, additional peak daily capacity may be required in the medium term (estimated 2020-2025) due to peak demand growth in the Territory (extreme days of high humidity and temperature produces a few days of peak demand). The peak market tends to grow at faster rates than annual volumes. There are a number of potential fuel sources PWC could use to provide additional peak day capacity, including additional supply from Blacktip and Amadeus facilities as well as diesel peak shaving.

Figure 6.27: Gas Supply Locations

Source: APA website

6.5 Progress against findings from the 2011-12 Power System review

The Commission did not identify any matters in relation to fuel supply from the 2011-12 Review that should be a focus for the 2012-13 review.

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6.6 Key Findings – Security of Fuel Supply

The key conclusions regarding security of gas supply to the Northern Territory are:

PWC’s contingency supply arrangements are significantly improved compared to the period pre-2009 when PWC was 100 per cent reliant on the Amadeus basin gas fields which were in decline during the 1990s. There are a number of Territory gas supply options which can provide additional gas or back-up gas which were not available pre-2009. Since the commencement of Blacktip production there have been periods of planned and unplanned supply interruptions. PWC has successfully maintained gas supply to its power stations through the use of back-up supply from Darwin LNG and spare pipeline line pack. A shortfall in Blacktip production of less than 10 days would be considered to be a normal contingency event. If required, back-up supply from Darwin LNG is currently sufficient to cover all of PWC’s northern gas for up to five to six weeks (a longer period if not during peak demand).

The addition of the Inpex LNG back-up arrangement from 2017 will materially improve security of gas supply to the Territory, doubling the contingency supply period of up to 12 weeks and providing an additional source of back-up gas in the unlikely event of a simultaneous Blacktip and Darwin LNG supply failure. Emergency gas volumes available from Darwin LNG and Inpex LNG can supply power stations in the southern region however use of compression on the Amadeus Gas Pipeline would be required to transport gas from Darwin to Alice Springs. Diesel or new gas supply arrangements sourcing gas from the Amadeus Basin gas fields would be the alternate if northern gas was unable to supply all of the southern gas demand.

During an event involving a major failure of Blacktip gas supply (that is, greater than 5-6 weeks with Darwin LNG alone or more than 13 weeks with Darwin LNG and Inpex LNG), existing contingency arrangements would not satisfy the required gas demand. Additional gas purchases from Darwin LNG, Inpex LNG and/or Amadeus would be required, subject to parties agreeing suitable commercial arrangements. These purchases would likely be at a higher cost, however existing infrastructure can provide continuity of gas supply.

During the Commission’s investigation of the March 2014 System Black incident, the Commission noted that PWC had reported that generation sets 1 to 5 at Channel Island Power Station were no longer able to operate on diesel and were considered “gas only”. PWC later clarified that the sets could be retro-fitted to operate on diesel within 24 to 48 hours.

PWC's decision in the past few years to convert generation sets 1 to 5 to gas only and to purchase gas only sets at Weddell should result in cost savings, as the sets, when burning gas, are significantly more fuel efficient.

However, the Commission notes that in the event of failure of both Blacktip and Darwin LNG supply, PWC now has only 84MW (Channel Island generation sets 8 and 9) of installed dual fuel capacity in Darwin and 34MW in Katherine able to switch almost immediately to diesel fuel against a peak demand of 298MW (forecast maximum demand for 2013-14).

Given it would take up to two days before sets 1 to 5 can be retro-fitted to run on diesel, if there was a failure of both Blacktip and Darwin LNG supply, even when all sets capable of being used with diesel are available (Channel Island and Katherine) PWC would have insufficient generation capacity for reliable supply in the seasonal peak demand period, being usually November-December each year. This situation highlights the need for PWC to confirm alternative gas supply from Inpex LNG and/or Amadeus or at least consider whether instantaneous diesel needs to be maintained at Channel


Island to mitigate any risk of simultaneous failure of Blacktip and Darwin LNG gas before the Inpex plant and PWC additional back-up supply is in place.

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7. Generation Adequacy

7.1 Introduction

The Commission observes a mismatch between the historical values for Loss of load probability (LOLP) or N-X margin and the forecast. That is, the forecast performance is, in general, superior to past performance. While this is positive, it is difficult for the Commission to place considerable confidence on higher to unachieved levels of reliability as described by LOLP.

The Commission notes that PWC has not moved to a stochastic method for planning or assessing future generation adequacy and so has performed this analysis in this report. The results are encouraging but are heavily dependent on the availability forecast from PWC. The availability forecast is not detailed enough to provide a high degree of confidence. The Commission recommends PWC adopt this change to its planning methods and in so doing adjusts and refines the methods of forecasting generating unit availability.

As discussed earlier, the Commission observes that there is a disjoint between perceived generator reliability as exhibited by the actual system performance and that modelled in the Review. The Commission considers it appropriate that PWC provide greater transparency with respect to system incidents to allow the Commission to calibrate the accuracy of the planning tools in predicting future reliability margins.

Basis of adequacy assessment

The Commission has assessed generation adequacy in two ways in past reviews:

1. N-X criterion as used by PWC

2. A probabilistic approach to assess LOLP

This review continues this approach.

N-X criterion

PWC Capacity Investment Planning Strategy (Draft 30/11/2013) outlines the method by which an assessment of capacity adequacy should be made. The following criteria are applied by PWC in planning generation adequacy in each region:

Table 7.17: Generation planning criteria

System Standard

Darwin-Katherine N –330

Katherine N

Alice Springs N – 2

Tennant Creek N – 1 (gas)N (diesel)

It should be noted that this N-X criterion does not represent a real-time spinning reserve operation, merely an indication of a margin between installed capacity and the need for load shedding based on the largest X

30 This is a temporary measure to allow for CIPS 1- 6 life extension to occur without affecting adequacy. PWC do not indicate when this will be lifted and the N-2 criterion will be re-instated.


units being unavailable. The assessment is a simple calculation of maximum demand versus installed capacity less the X largest units.

In practice this allows one planned and one forced outage to occur in an N-2 system without the need for load-shedding.

Prolonging the N-3 criterion for Darwin-Katherine will lead to further investment in generating plant. PWC advises that the reinstatement of the N-2 planning criteria is planned for 2018-19 following completion of the life extension project. The transparency of major plant outage plans is, in general, not sufficient for the Commission to have confidence in the planning for reliability.

LOLP approach

The NEM applies a time based approach to the assessment of generation adequacy. Generators must provide AEMO with a projection of likely generation capacity for each day in a two year period. The aggregate of these capabilities is then compared with demand forecasts and a look ahead assessment of generation adequacy can then be made.

An adaptation of this approach can be made to better suit the Territory context. Without heavy inter-connection of power systems and multiple, competing power producers there is no need to use the de-centralised, profile overlay approach used in the NEM. A simple assessment of aggregate generation availability based on likely unit availability forecasts against a likely demand pattern forecast should be sufficient to assess the Loss of Load probability.

The Commission has extended the work done in the 2011-12 review to include a calculation of the probability of each of the Lack of Reserve (LOR) levels reported by AEMO as part of the NEM MTPASA process. This gives a richer assessment of the reserve margin.

7.2 Generation adequacy assessment

7.2.1 2012-13 performance

The Commission notes the following margins against the adequacy criteria employed by PWC for the 2012-13 year.

Table 7.18: N – X margins for 2012-13

Region Criterion Margin Marginas per cent of peak demand

Notes

Darwin-Katherine N-3 38 MW 9.7 %

N-2 83 MW 25.2 %

Alice Springs N-2 10.8 MW 20.3 %

Tennant Creek N-1 (gas) -2 MW -30 % Diesel generation required to meet system peak at N – 1

All regions except Tennant Creek maintain suitable margins against the relevant planning criterion for the region.96


7.2.2 Modelled results: Darwin-Katherine

N – X criterion

The following figure shows the Darwin-Katherine N-X assessment based on the PWC demand forecast and generation plans. Clearly the N-3 standard is not met from 2018-19 through 2019-20. It is not clear whether the CIPS 1-6 life extension works will be complete by that time to allow a reversion to the N-2 criterion.

Figure 7.28: Darwin Katherine N – X assessment

The Commission notes that the assessment is made on the 10 per cent POE maximum demand projection which provides some level of conservatism to the assessment and so further analysis, such as, probabilistic analysis should be employed to better understand the likelihood of the N-3 actually coinciding with sufficient demand to provide inadequate generation.

The Commission further notes that Weddell generating set 3 is not included in this analysis up until the end of 2013-14. PWC has advised that an air filter house fire caused an 18 month delay in commissioning of Weddell set 3.

LOLP approach

The following figure shows the Darwin-Katherine LOLP assessment based on the PWC demand forecast (50 POE), generation plans and the 2012-13 load pattern.


Figure 7.29: Loss of load (LOLP) or Lack of Reserve (LOR) probability31

This analysis is heavily dependent on the projected availability of generating units. The Commission notes the blanket application of 92 per cent projected availability for all generating units in the Darwin-Katherine region. This level of availability is above the national average of 87.9 per cent for 2011-12 and in excess of the 2012-13 availability figures for Channel Island and Katherine power stations (80.6 per cent and 73.28 per cent respectively). It is lower than the 2012-13 availability factor at Weddell (97.01 per cent). The Commission has calculated stats based on unit types in Darwin-Katherine as follows.

Table 3.7 shows that the optimal reserve margin would be 92 MW (LOLP of 0.04 per cent). All but 2015-16 and 2016-17 are above this level.

Table 7.19: Availability by generating unit type: Darwin Katherine

GE Frame 6 Mitsubishi Trent 60 GE LM6000 PD Solar Mars

Maximum 100.0% 98.8% 96.8% 99.1% 99.6%

Average 86.3% 78.8% 83.3% 90.4% 86.6%

Median 92.1% 78.9% 85.1% 92.0% 93.7%

minimum 0.0% 63.5% 66.5% 71.6% 7.9%

The table shows that (ignoring the Steam turbine at CIPS since it is dependent on the availability of its feeder GTs) only the Trent units have a median availability less than the projected 92 per cent. On this basis the Commission accepts that 92 per cent is an appropriate projection but future reviews must re-assess the appropriateness of this projection based on further historical data relating to the increased reliability of the Trent units and the refurbishment effect on CIPS 1-6.

31 Zero values are not plotted on the log scale. Zero values for probability of LOR3 from 2011-12 – 2014-15.98


A practice of estimating forced outage availability and then adjusting the overall availability based on a planned maintenance schedule for each generating unit across the forecast period may prove to be more reliable and informative.

7.2.3 Modelled results: Tennant Creek

The following figure shows the actual and forecast performance of the Tennant Creek generating units with respect to the PWC N-1 (gas only) planning criterion.

Figure 7.30: Tennant Creek N–X assessment

The reliance on diesel back-up at Tennant Creek under peak demand to meet the N-1 gas criterion until 2015-16 is of concern. For 2012-13 the PWC data suggests that demand would contravene the N-1 gas criterion around 17 per cent of the time. This high probability may be a contributing factor to the high SAIFI and SAIDI values in Tennant Creek for the 2012-13 period.

The LOLP analysis results for Tennant Creek are shown in Appendix B. The results show that even once there are sufficient gas units to meet the N-1 criterion the LOLP is over six times higher than that of the Darwin-Katherine region. The Commission suspects that this is linked to availability assumptions rather than reality. The Commission recommends that PWC re-assess the reliability of the generating units in the latter years of the forecast taking into account the substation refurbishment and attendant control gear upgrade.


7.2.4 Modelled results: Alice Springs

The following figure shows the actual and forecast performance of the Alice Springs generating units with respect to the PWC N-1 planning criterion.

Figure 7.31: Alice Springs N – X assessment

The forecast is well in excess of the planning level.

Table 3.7 shows that the optimal reserve margin would be 18 MW (LOLP of 0.033 per cent). This level of reliability is only achieved between 2016-17 and 2019-20.

The Commission observes that historic availability is evident in the Alice Springs and Tennant Creek systems and so 92 per cent availability appears to be conservative.

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7.3 Standards of service indicators

The analysis of LOLP is crude in that it identifies the probability of load exceeding available generation but does not provide any insight into the effect that this exceedance has on customers.

The following figure shows the SAIDI in each region for generation events compared to the agreed minimum standard (AMS).

Figure 7.32: 3 Region SAIDI trends

It can be seen that generation SAIDI is beginning to return to historical trend with the exception of Tennant Creek. The performance of the Alice Springs generating units is still above historical trend but below the AMS. The Katherine result for the past two financial years is sub-standard. PWC is in the midst of refurbishment of the switchboard but have also had ongoing performance problems with two of the generating units.

SAIFI results compared to the agreed minimum standard are shown in the following figure. The 2012-13 result is the best within five years (on aggregate).


Figure 7.33: 3 Region SAIFI trends

7.4 Contribution of PV

The Commission notes that steady uptake of embedded PV systems is occurring in the three power systems. This uptake is most notable in Alice Springs. Table 8.4 describes the uptake across the three power systems.

Table 7.20: Percentage penetration of photovoltaic

Location Connection type Number of PV systems

Number of connections

Percentage take up

Darwin Non residential 46 11493 0.40 %

Residential 1599 50745 3.15 %

Katherine Non residential 14 1275 1.10 %

Residential 56 4954 1.13 %

Tennant Creek Non residential 6 371 1.62 %

Residential 0 1353 0.00 %

Alice Springs Non residential 38 1965 1.93 %

Residential 529 10389 5.09 %

Totals Non residential 104 15104 0.69 %

Residential 2184 64441 3.39 %

The current PWC policy allows a maximum PV installation of 4.5kW per residential customer. The system size policy is in line with other Australian utilities’ practice.

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The rate of growth of solar PV is likely to erode reliability from the perspective of event recovery unless low voltage ride through and low frequency immunity is a feature of the PV inverters. The low spinning reserve regime maintained by PWC may be particularly sensitive to these characteristics unless some care is taken to ensure the robustness of these installations.

The Uterne solar power station can vary widely depending on weather conditions. The following figure shows this variation across the year and an example of the volatility within one day.

Figure 7.34: Uterne solar power station statistical variation

While the magnitude of variation is within the regulation capacity of the Ron Goodin and Owen Springs Power Station units the volatility can be managed. The Commission observes that further expansion of this plant will require consideration of regulation reserves. If similar volatility was displayed by domestic PV installations at any scale this may accelerate the rate at which it begins to impact on PWC operations and potentially network security or at least network frequency regulation.

The adequacy modeling presented in this chapter includes an allowance for the contribution of Uterne but discounts completely the contribution of domestic PV. While the size of the installation is small this remains suitably conservative. The effect on the calculation of adequacy (and actual adequacy) of increased levels of volatile generation must be considered in future reviews.

7.5 Capacity and energy sufficiency

The Commission has been advised by PWC that generating sets 1-5 at CIPS operate on gas and are no longer able to switch to diesel fuel. The switch can be made on three units within 24 hours in the case of an emergency. The remaining two sets can be converted within 48 hours of the emergency.


The analysis above shows that, given the quoted generating unit availability and limited changes to demand profiles, there is sufficient generation capacity with respect to the planning guidelines across the forecast period. This is of course dependent on fuel availability to support power and energy capacity.

7.6 Validity of use of Reserve margin as an indicator of future reliability performance

The Commission is aware that, in general, the three regions are not reliable. This report demonstrates, as have previous reviews, that PWC’s asset plans lead to satisfactory reliability (albeit suboptimal) for at least the Darwin-Katherine and Alice Springs regions. The reality is that major interruptions still occur on a regular basis due to the failure of generating plant. The analysis in this chapter indicates that these interruptions are not due to lack of capacity. Further, scrutiny of historical availability figures leads the Commission to conclude that the generating units are as reliable as PWC claim (if not more).

It is difficult for the Commission to determine the actual cause of the apparent lack of reliability while faced with an adequate design capability. The identifiable differences between the operation of the NT power systems and those elsewhere in Australia are the number of multiple contingency events and the spinning reserve arrangements.

It is not our intent to conflate these two concepts in a causal fashion. Rather it is the opinion of the Commission that the lower spinning reserve puts greater onus on other control systems (such as UFLS). These other systems have limited time in which to operate and often have no or limited practicable operating margin. In this way the Commission observes that it is possible to move from single to double contingency and therefore almost inevitable interruption because the robustness of the active control of generating units in the power system is hampered by their dependence on switching controllers and pre-programmed actions of other devices that may not be robust to the wide variety of system conditions that can result from mal-operation or failure of a single piece of network equipment.

The Commission is not convinced that PWC’s planning practices are valid within the operational framework of the networks. This suggests a capital investment program focussing on secondary systems and controls and serious consideration of increasing spinning reserve levels to increase robustness.


Use of probabilistic analysis as the primary tool for assessing system adequacy and generation planning purposes

The Commission has not seen any evidence to suggest that PWC has adopted probabilistic analysis as practice for its generation planning purposes.

7.8 Key findings – generation adequacy assessment

The Commission observes a mismatch between the historical values for LOLP or N-X margin and the forecast. That is, the forecast performance is, in general, superior to past performance. While this is positive, it is difficult for the Commission to place any weight on hitherto unachieved levels of reliability as described by LOLP.

The Commission notes that PWC has not moved to a stochastic method for planning or assessing future generation adequacy and so has performed this analysis in this report. The results are encouraging but are heavily dependent on the availability forecast from PWC. This availability forecast is not detailed enough to provide a high degree of confidence. The Commission requests PWC engage with this change to planning methods and in so doing adjusts and refines their methods of forecasting generating unit availability.

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The Commission observes that there is a disjoint between perceived generator reliability as exhibited by the actual system performance and that modelled in the review. The Commission considers it appropriate that PWC provide greater transparency with respect to system incidents to allow the Commission to calibrate the accuracy of the planning tools in predicting future reliability margins.


8. Electricity Networks Adequacy

8.1 Basis of network adequacy

In order to assess the transmission and distribution systems, the Commission has established the criteria which will be used to review the adequacy of the network to meet existing and future demand. These criteria will also help the Commission to review the processes and procedures established by PWC to manage the transmission and distribution network.

The Commission has used the following criteria for the 2012-13 Review:

Planning and monitoring. PWC’s capacity to actively plan the operation, maintenance and augmentation of the network is considered critical.

Existing and future system utilisation for the 2013-2024 period at the following system levels:

o Zone;

o Transmission line;

o Substation;

o Feeders;

o Distribution substation; and

o LV network

Transmission line utilisation from two perspectives:

o firstly, the utilisation is determined at time of peak loading with all lines in service – the so called “N” utilisation. This can be measured directly by comparing the peak load on a feeder with its rating; and

o secondly, the utilisation is modelled at time of peak loading to simulate the situation if another line is out of service (where multiple lines serve the same load) – “N-1” utilisation.

Substation utilisation. There are 30 actual and planned transmission/sub-transmission substations across the Darwin-Katherine, Alice Springs and Tennant Creek systems. An assessment of substation utilisation has been completed for these. Substation capacity and potential constraints have been measured by examining the substation utilisation with:

o all network elements (i.e. transformers) in service (an N rating); and

o one network element out of service (an N-1 rating).

Fault levels. Electrical equipment is designed to withstand current and associated short circuit forces in the event of a fault. It is crucial that the network and its equipment are capable to withstand a fault without experiencing damage or impact on the expected design life length.

Condition of the asset. PWC carries out routine maintenance and testing on major equipment to reduce the probability of plant failure. The routine maintenance is also supported by the review of transmission and distribution performance which uses several indicators and different upgrade actions. In addition, PWC is also executing major upgrades in the network to replace aging equipment to meet the Territory challenging atmospheric conditions.

Demand management. The Commission has reviewed the alternative strategies to meet the system demand which are commonly known as “Demand Management”. These activities are different from the typical upgrade of generation and network capacity to meet a higher system demand. At a high


level, PWC is considering new tariff structures, power factor correction, load shifting and embedded generation.

Security of the system. Adequacy of the PWC power system has been assessed by its whole capacity to operate under network contingency. Typically, there are some network configurations like radial transmission system, single bank transformer or single transformer zone substation that are more prone to be at risk of loss of supply under system contingencies. The Commission has reviewed the overall existing and future transmission network to determine if there are major capacity and adequacy shortfalls.

Reliability of supply. The Commission has reviewed the customer supply reliability data and provided commentary on trends relating to these measures.

8.2 Network capacity and performance

PWC has satisfactory processes in place to monitor the capacity and utilisation of the lines which are going to be overloaded in the present, near and long term future. The average and forecast transmission line utilisation across the network is within satisfactory limits. The average transmission line utilisation in 2013 is 28 per cent, increasing to 39 per cent in 2022.

However, the Commission would like to highlight that the average utilisation of the network, although providing a high level indication of the capacity of the network, does not capture specific network adequacy issues.

For the transmission network, the main capacity concern is related to the transmission line loop between Hudson Creek, Palmerston, McMinns, Weddell and Archer Substations. In the event of the loss of the Weddell-McMinns 66kV line or Hudson Creek-Palmerston 66 kV line, one line of the 66 kV loop will exceed its thermal limit by the year 2014. PWC forecasts that this scenario will worsen as the load increases in the near future until a new line from Archer or Hudson Creek to Palmerston Substation is constructed. The line overload is predicted to be up to 140 per cent based on requested load, however PWC has assumed that the estimated new load will only be 50 per cent of the requested load. The Commission encourages PWC to urgently further verify and confirm this assumption. The Commission recommends that PWC consider the most appropriate timing for this project or further consider the option of bringing a 132kV supply into the Palmerston area to ensure security of supply.

In addition, even after the commissioning of the new 66 kV transmission line, under the contingency scenario, this new line will reach 90 per cent of its capacity by 2020. As a result, the Commission encourages PWC to consider further planning studies to evaluate the adequacy of the transmission network and to provide further evidence in the 2013-14 Report of the long term adequacy of transmission line capacity in the Palmerston area.

Transmission lines that are close to the capacity limit need to be considered with consideration of their location within the network. This is particularly true in a small network such as the Darwin-Katherine area, where generation is located at one end of the region, at Channel Island, and the main load at the other end of the area, Darwin city. Considering these factors, the Commission welcomes the planning study for the new 132 kV corridor to improve the capacity from the generation area to the loading area.

For the Alice Springs system, the Commission is pleased with the rationale behind the options investigated to maintain the security standards, and encourages further collaboration between PWC Generation and Networks to finalise the most effective solutions to utilise the full capacity of the new Owen Springs Power Station.

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The summary of the transmission network constraints is presented in Table 8.1.

Table 8.21: Summary of the transmission constraints (N-1 conditions)

Line impacted Line outage 2013 impact 2018 impact

Hudson Creek to Berrimah 66 kV Line 1.


Exceeds normal rating but within emergency rating.

Exceeds normal rating but within emergency rating. In 2023 the line will reach 93 per cent of the emergency rating.





Hudson Creek to Palmerston 66 kV.

Weddell to McMinns 66 kV.

Exceeds both normal rating and emergency rating.

Within normal rating. Resolved through construction of Weddell-McMinns 66kV line or Hudson Creek-Palmerston 66 kV line.

Casuarina to Snell Street 66 kV.

Leanyer to Berrimah 66 kV.



Weddell to McMinns 66 kV.





New line Archer to Palmerston 66 kV.

N/A. Exceeds normal rating but within emergency rating.

Leanyer to Berrimah 66 kV.

Casuarina to Snell Street 66 kV.



Channel Island to Hudson Creek 132 KV.

The other Channel Island to Hudson Creek 132 KV line.

Within normal rating.

Exceeds normal rating and at 100 per cent emergency rating. Exceed emergency rating from 2019. Resolved if new 132 kV connection to Darwin city is established.

In the Territory, substation average utilisation is 34 per cent and is projected to increase to 48 per cent in 2017-18. The Commission is satisfied with PWC substation future demand projections and agrees with PWC’s view that a forecast load slightly in excess of the transformer rating is not necessarily an indication that an urgent action is required.


However, the Commission is concerned about the long term substation capacity of McMinns and Palmerston Substations which are well above 120 per cent under a contingency scenario. As a result, the Commission requires more details of the load transfer capacity and a risk analysis between McMinns and Palmerston Substations and question the capacity of the rebuilt McMinns Substation which appears will not be adequate from 2020. Hence, the Commission requires PWC to provide further details about the long term capacity of these two substations.

The Commission also invites PWC to provide more details of the supply of Darwin city under N-2 criterion. The Commission questions the plan that, under the failure of the second transformer at City Zone Substation, supply to the city can be only guaranteed by transferring load to the nearby Frances Bay Substation.

The Commission supports PWC in the initiative to complete an engineering investigation into the impact of cyclic loading factor to transformers, in excess of their nameplate rating for limited periods of time. Considering the Territory’s difficult climatic conditions, it would be prudent to confirm that cyclic loading factor can be implemented without affecting the transformer service age. It is worth remembering that faults within the transformer are often catastrophic and lead time to procure and install a new transformer, in the event of unrepairable damage, is usually between 6 to 12 months.

The summary of the substation network constraints is presented in Table 8.2.

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Table 8.22: Summary of the substation constraints (N-1 conditions)

Substation 2013 impact 2018 impact

Archer Contingency utilisation below 90 per cent

Contingency utilisation between 90 and 100 per cent

Berrimah Between 90 and 100 per cent of contingency utilisation.

Contingency utilisation below 90 per cent. Forecast based on completing Berrimah Substation rebuilt project

City Zone( N-2 category)

Contingency utilisation up to 135 per cent. It requires load transfer to adjacent substation

Contingency utilisation up to 115 per cent. It requires load transfer to adjacent substation. Forecast based on completing City Zone Substation rebuilt project

Hudson Creek 132/66 kV

Contingency utilisation below 90 per cent

Contingency utilisation between 90 and 100 per cent

Katherine Contingency utilisation up to 102 per cent. It requires local generation

Contingency utilisation up to 117 per cent. It requires local generation

McMinns Between 90 and 100 per cent of contingency utilisation.

Contingency utilisation up to 123 per cent. It requires load transfer to adjacent substation. Forecast based on completing McMinns Substation rebuilt project

Palmerston 66/11( N-2 category)



Palmerston 66/11( N-2 category)



Weddell Contingency utilisation up to 109 per cent. It requires load transfer to adjacent substation


Sadadeen Contingency utilisation up to 103 per cent. It requires load transfer to adjacent substation

Contingency utilisation below 90 per cent


In relation to feeder utilisation, the Commission acknowledges that the use of 55 per cent utilisation target for 11 and 22 kV feeders, as proposed by Ergon Energy, is acceptable. PWC has forecast that the average feeder utilisation will increase from 56 cent in 2013 to 59 cent in 2018.

As noted in the 2011-12 review, feeder utilisation should be limited to approximately 80 per cent so as to permit some transfer of load between feeders during emergencies. The Review has also pointed out that operating feeders in excess of 100 per cent of their capacity on a sustained basis, though such situations do arise across the industry, is not acceptable.

The summary of the feeder network constraints is presented in Figure 8.1.

Figure 8.35: 11 kV PWC feeder utilisation

0-10

%

10-2

0%

20-3

0%

30-4

0%

40-5

0%

50-6

0%

60-7

0%

70-8

0%

80-9

0%

90-1

00%

>100

%

0

5

10

15

20

25

2013 2018

Utilisation

Num

ber o

f Fee

ders


8.3 Incident report review

The Commission has analysed the major incidents of the reporting year, investigation conducted by PWC, results and recommendations. This analysis has been based on the following documents:

Half Yearly Report January-June 2013 ( for all the three PWC’s region);

System Control Incident Reporting correspondence from PWC to the Commission, 13 November 2013;

Overview of half yearly reports January to June 2013;

Major Incidents Reports for the events between 1 July 2012 and 31 December 2012; and

Any other information related to PWC major incidents contained in the overall package provided by PWC.

From the information available, it appears that in the 2012-13 reporting period there have been the following eight major incidents:

a) Darwin-Katherine system: City Zone Substation - Operation error – 12 August 2012;

b) Darwin-Katherine system: HV Operator Error (Lambrick Ave, Farrar) – 3 September 2012;

c) Darwin-Katherine system: Frances Bay Substation- Bus Protection Incident – 14 September 2012;

d) Darwin-Katherine system: Katherine black and load shedding – 4 October 2012;112


e) Darwin-Katherine system: Herbert Heading – Severe storm – 12 January 2013;

f) Darwin-Katherine system: Pine Creek and Manton area – Severe storm – 27 January 2013;

g) Tennant Creek system: Tennant Substation – Control system maloperation – 14 February 2013; and

h) Tennant Creek system: Tennant Substation – Alarm maloperation – 26 April 2013.

These key points are highlighted for PWC’s attention:

The main material available for this review is merely a summary of the incident report and, in general, does not provide adequate data for review. The Commission request PWC to complete and provide major incidents reports for any major events and provide the reports to the Commission in a timely manner;

The Commission is interested to review investigations conducted by PWC following major incidents. Post fault analysis and incident investigation is an effective method to enhance asset management and performance improvements by all utilities and it is expected that PWC improves in this engineering area;

The System Black at Katherine on 4 October 2012 represents a major concern as it highlights some critical issues, mainly within PWC Generation. In particular, the Commission highlights the repeated failure of the black start procedure, the poor communication between different business units and access of contractors to PWC’s substation secondary system with inadequate preparation. Considering the peculiarity of the Katherine power system which is fed radially from Darwin via one 132 KV line, it is likely that a similar black system scenario will happen again in the near future. The Commission recommends PWC address each remedial action identified in the Incident Report as a matter of priority and expects that evidence of actions completed or in progress be provided as part the 2013-14 Review. It is also recommended that the black start procedures are independently benchmarked with other Utilities and best industry practice and, as far as practicable, are tested and rehearsed on site;

As noted in the network performance analysis Section, the adjusted frequency of 66 kV circuit and transformer outages is beyond the acceptable level and needs urgent attention by PWC. It is suggested that a reasonable sample of main transformer or transmission line outages be treated by PWC as major incident and, hence, documented in a major incident report;

The Commission notes that only in the period January to June 2013 the following involuntary load shedding events were recorded:

o eight load shedding events in the Darwin-Katherine Power System (compared to six in the previous period);

o six load shedding events in the Alice Springs Power System (compared to four in the previous period); and

o one load shedding event in the Tennant Creek Power System (compared to 12 in the previous period).

Five out of these fifteen load shedding events were categorised by PWC System Control as major and affected thousands of customers. This data confirms that the power system as it stands, often is not capable to withstand the tripping of a generator without operating the under frequency load shedding (UFLS) scheme. It is understood that, in general, load shedding is the only method to recover the system within the Satisfactory Operating State as defined in the Network Connection Technical Code:

o Following a generator trip, there is a tendency of multiple events which denotes a low level of confidence on the overall security and reliability of the power system; and


o Where an HV Operator Error is the cause of the incident, recommendations and recommended time are usually acceptable and seem to be reasonable. It is expected that changes in procedures and proper training will generate a positive trend to performance results in the forthcoming years.

8.4 Planned network enhancements

PWC is completing or has planned large network projects that reflect the need to address capacity constraints to meet the Territory’s growth in demand, replace aging network system assets and improve network reliability and quality of supply.

Snell Street Substation replacement with the new Woolner Substation has been recently completed and City Zone Substation replacement is progressing satisfactorily. In summary, the major projects to be completed in the next five years are:

City Zone Substation replacement (construction underway);

Leanyer Zone Substation (construction commenced);

Berrimah Zone Substation replacement;

Frances Bay 2nd Transformer;

Replace McMinns Substation;

Replace Casuarina Zone Substation 66kV switchgear;

Wishart Substation;

Mitchell St Switching Station;

11 kV switchboard replacement at Sadadeen, Alice Springs;

22 kV switchboard replacement at Tennant Creek, Alice Springs; and

132/66 kV Terminal Station and Transmission Lines for City N-2 supply.

A summary of the major and minor capital projects as proposed by PWC is shown in Table 8.3:

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Table 8.23: Forecast capital expenditure ($ million, real $2013/14 with input cost escalation)

Project ($M) 2013/14 2014/15 2015/16 2016/17 2017/18

Total major projects 65.2 53.3 45.5 29.8 20.4

Capital Items and Essential spares

1.3 1.2 1.2 1.2 1.2

Asset Replacement and Upgrade Programs

3.3 8.2 6.7 3.4 2.1

HV Cable Replacement Program

2.0 1.6 1.5 1.5 1.6

ORMU Replacement Program

2.0 1.9 1.3 1.2 1.4

Feeder Upgrade Program

1.6 1.9 1.7 1.6 1.6

Customer Augmentation and Network Extension Program

8.9 7.8 7.7 8.1 8.4

SCADA and Communication Systems Replacement and Upgrade Program

2.2 1.7 1.7 1.7 1.7

Distribution Transformers and Switchgear Program

1.2 1.2 1.2 1.3 1.3

Protection Upgrade Program

0.9 1.0 1.1 0.9 0.5

Meters/Metering Program

0.7 1.3 1.9 3.1 3.5

Customer Connection Program

0.9 0.9 0.9 0.9 0.9

Underground Distribution Substation Replacement Program

0.3 1.2 0.9 1.4 2.4

Other minor works 1.5 1.4 1.4 1.3 1.4

Total Capital Expenditure

91.9 84.7 74.8 57.4 48.4


The Commission supports PWC’s large capital project program but would like to note the following:

The 2012-13 Report does not to provide adequate details of the different options considered during the planning phase of each project. Power system reporting should provide comprehensive and authoritative data to assist identification of investment options for the Commission to review. As noted in the 2011-12 Power System Review, the role of the Commission is also to evaluate how PWC is deploying the investment to address the emerging network constraints. The Commission


recommends PWC provide more exhaustive detail in regards to the options considered, including engineering review, financial and time considerations in the 2013-14 Report.

PWC’s planning report lacks details on how the major projects will improve the aging profile of each type of asset in the short and medium term. To review the effectiveness of the large capital projects plan, the Commission requests PWC provide a forecast of the aging profile of circuit breakers and instrument transformers in five and ten years’ time (2018 and 2023).

PWC has clearly identified that, as new load demand will increase, the existing 132 kV double transmission line back bone from Channel Island to Hudson Creek will reach its capacity in the N-1 condition in 2021. This corridor plays the key role to supply Darwin and the surrounding suburbs. The Commission supports the plan to implement a new double circuit 132 KV line to reach Darwin city. The Commission also understands that the existing 132 kV line is cyclone rated Category 3 and will be uprated to Category 4 only at the Elizabeth River Crossing in 2016-17. The Commission intends to monitor these two critical projects closely and requires further details in the next 2013-14 report.

Tennant Creek town and surrounding area is supplied by one substation which is equipped with an old and unreliable vacuum outdoor 22kV switchgear and busbar system. Considering the impact of a failure of the switchgear to the supply of Tennant Creek which typically requires several hours before supply is restored, the Commission recommends to urgently complete the planned replacement of the switchgear.

8.5 Reliability

Key indicators used to monitor the reliability performance of PWC’s network are divided into two categories:

transmission network performance; and

feeder network performance.

The 2011-12 Review noted that the increased expenditure in maintenance and capital projects, if appropriately targeted on those parts of the network significantly contributing to system reliability issues, should have a progressive improvement in the reliability of the PWC network.

In the 2013-14 Report the Commission would also be interested to monitor the following areas of PWC business activities:

Protection and control systems which are required to perform in a secure, reliable, fast and selective manner. Effective procedures, maintenance and modernisation of the equipment has an impact on correct and incorrect operation of protective devices and fault clearing time. The Commission would appreciate information in regards to the following:

o age of protection and control relays divided by protection scheme and/or voltage level;

o details of the routine maintenance and testing implemented; and

o any other data or indicator which PWC believes to be relevant.

Engineering resourcing also has an important impact on network performance. The Commission assumes that PWC has processes in place to retain and develop qualified resources in each business and geographic area, recruiting strategies and effective planning to manage the natural resource attrition. The Commission will seek to review details of these plans in future reviews.

8.5.1 Transmission network performance

To measure the reliability performance of the PWC transmission network, the key indicators are:

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system average circuit outage duration index (ACOD), which indicates the average duration of circuit outages experienced by the PWC transmission network

frequency of system outage index (FCO), which indicates the number of circuit outages experienced by PWC transmission network

system average transformer outage duration index (ATOD), which indicates the average duration of circuit outages experienced by the PWC transmission network

frequency of system outage index (FTO), which indicates the number of transformer outages experienced by PWC transmission network.

For the Alice Springs area all the indicators have been met successfully and the Commission is satisfied with PWC’s results.

Table 8.24: Alice Springs transmission network performance

Transmission performance indicators 2012/13 Target standard

2012/13 Alice Springs adjusted results

Target standard met?

Average Circuit Outage Duration (ACOD) (mins)

358.8 69 Yes

Frequency of Circuit Outage (FCO) 49.0 1 Yes

Average Transformer Outage Duration (ATOD) (mins)

123.3 0.0 Yes

Frequency of Transformer Outages (FTO) 0.8 0.0 Yes


For the Darwin area, the system outage for circuit and transformers is above the target allowable in the standards. Refer to Table 8.25 for details of the Darwin-Katherine area results.

Table 8.25: Darwin-Katherine transmission network performance

Transmission performance indicators 2012/13 Target standard

2012/13 Darwin-Katherine adjusted results


Average Circuit Outage Duration (ACOD) (mins)

358.8 227.2 Yes

Frequency of Circuit Outage (FCO) 49.0 89.0 No

Average Transformer Outage Duration (ATOD) (mins)

123.3 106.9 Yes

Frequency of Transformer Outages (FTO) 0.8 6.0 No


The Commission is generally satisfied with the investigation work completed by PWC to determine the causes of circuit outages and the 2014-15 program to test the earthing on transmission towers which should help to reduce circuit interruptions due to lightning. It is also noted that PWC did not record any Major Event Days which authorise the removal of the effect of severe outages to the key network reliability. However a frequency of circuit outage of 89 within the reporting year is not satisfactory and needs PWC’s attention.


Genuine transformer faults are usually serious and could have a catastrophic effect. Similarly, mal-operation of a transformer protection scheme could lead to a capacity shortfall with a risk of overloading the other transformers within the substation. In any case, transformer outages have an impact on the performance and adequacy of the network. The Commission considers that six transformer outages for the 2012-13 period is unsatisfactory and expects improvements in the next PWC Report.

In relation to the 2013-14 Power System Review and PWC’s Standards of Service Report, the Commission will seek that PWC provided the following:

details of each transformer outage be included in the report;

the cause of outages under the section “Other” category be allocated to the correct subgroup; and

post-fault analysis work be conducted in more depth in the next financial year.

8.5.2 Feeder network performance

To measure the reliability performance of PWC feeders, the key indicators are:

system average interruption duration index (SAIDI), which indicates the average duration of network and generation related outages experienced by a customer; and

system average interruption frequency index (SAIFI), which indicates the average number of network and generation related outages experienced by a customer.

PWC met the feeder network standards in three out of the four feeder categories. Refer to Table 8.6 and Table 8.7 for details.

Table 8.26: 2012-13 Distribution SAIDI results segmented by feeder category (adjusted)

Feeder categories Adjusted SAIDI target standard (minutes)

Adjusted SAIDI 2012-13 results (minutes)


CBD 18.8 1.1 Yes

Urban 136.0 111.0 Yes

Rural Short 496.3 536.9 No

Rural Long 2164.9 1108.7 Yes Source: Power and Water Corporation.

Table 8.27: 2012-13 Distribution SAIFI results segmented by feeder category (adjusted)

Feeder categories Adjusted SAIFI target standard(minutes)

Adjusted SAIFI 2012-13 results (minutes)


CBD 0.4 0.03 Yes

Urban 2.5 2.5 Yes

Rural Short 8.1 9.1 No

Rural Long 35.1 12.2 Yes


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PWC has advised that the main cause of SAIDI and SAIFI interruptions for the Rural Short feeder was ‘Trees Blown into Mains’ and that these interruptions occur in the Humpty Doo/Howard Springs rural area during adverse weather during the wet season. PWC further advised that vegetation management activities will be increased in the 2013-14 feeder upgrade program and changes made to the cutting profile targeting these problem areas.

PWC has advised that the second most significant cause of SAIDI and SAIFI interruptions was ‘Equipment - Failure or Defect’ and these interruptions occur in the Darwin rural area and in the Katherine region. PWC further advised that these issues are predominantly related to lightning damage on high voltage bridges and that thermo scanning and replacement of problem connections in these areas is included in the 2013-14 feeder upgrade program.

The analysis and remedial actions planned by PWC on Rural Short feeders and existing capital projects should improve the overall performance of this feeder group. The Commission also notes that SAIDI and SAIFI for the Urban feeder category are close to not meeting the target standard and expects that PWC will review the reasons for this performance in the forthcoming year.

To assess relative performance of PWC with regulatory expectations elsewhere in Australia, the Commission has compared PWC Networks’ 2011-12 performance with the minimum service standards applicable by Ergon. The analysis in Table 8.8 confirms that PWC Rural Short feeders require particular attention.

Table 8.28: PWC and Ergon SAIDI and SAIFI comparison

Key Indicator PWC Ergon Energy

SAIDI CBD 1.1 n/a

SAIDI Urban 111 135

SAIDI Short Rural 536 341

SAIDI Long Rural 1108 951

SAIFI CBD 0.03 n/a

SAIFI Urban 2.5 1.49

SAIFI Short Rural 9.1 2.97

SAIFI Long Rural 12.2 6.24


8.5.3 SAIDI and SAIFI historical comparison

To assess the feeder performance the Commission has also compared the latest adjusted SAIDI and SAIFI performance to the performance of the latest four year period.


Table 8.29: Adjusted SAIDI historical results comparison

Key Indicator 2009-2010 2010-2011 2011-2012 2012-2013

SAIDI CBD 19.4 166.6 10.4 1.1

SAIDI Urban 104 136 67 111

SAIDI Short Rural 237 586 256 536

SAIDI Long Rural 1145 1040 1998 1108


Figure 8.36: Adjusted SAIDI historical results comparison - Graph

SAIDI CBD SAIDI Urban SAIDI Short Rural SAIDI Long Rural0

500

1000

1500

2000

2500

2009/20102010/20112011/20122012/2013


Table 8.30: Adjusted SAIFI historical results comparison

Key Indicator 2009-2010 2010-2011 2011-2012 2012-2013

SAIFI CBD 0.6 1.0 0.4 0.03

SAIFI Urban 2.0 2.6 2.5 2.5

SAIFI Short Rural 6.0 9.3 10.4 9.1

SAIFI Long Rural 27.0 22.8 46.4 12.2


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Figure 8.37: Adjusted SAIFI historical results comparison - Graph

SAIFI CBD SAIFI Urban SAIFI Short Rural SAIFI Long Rural0

5

10

15

20

25

30

35

40

45

50

2009/20102010/20112011/20122012/2013

Source: The Commission.

The historical analysis confirms that the performance for the CBD feeders has definitely improved and that the performance of the Short Rural feeders needs specific attention by PWC. This is particularly true based on the favorable weather condition experienced during the 2012-13 season in the Territory characterised by higher maximum temperatures but fewer intense stormy periods.

8.6 Feeder performance

PWC and the Commission pay particular attention to the feeders categorised as “poorly performing feeders”. PWC Feeder Upgrade Program is an annual program that uses five calendar years of interruption data to analyse outage causes for poorly performing feeders and implement corrective action. The Commission supports this program and reviews SAIDI and SAIFI results annually to validate the effectiveness of PWC upgrade actions.

In the 2011-12 Report the poorly performing feeder category was defined by referring to the interruption frequency and duration thresholds by regions. The new Electricity Standards of Service Code has simplified the performance standards by implementing the SAIDI performance ratio benchmark.

In the 2011-12 Report there were eighteen feeders which performed as worst performing feeders. Nine of these feeders breached the threshold for two years consecutively and, as per the previous Service Code, were termed as “consecutively worst performing feeder”. In the 2012-13 Report four feeders have exceeded the new threshold limit as shown in Table 8.13 and Table 8.14.


Table 8.31: 2012-13 List of poorly performing feeders exceeding the SAIDI performance ratio

Feeder name Feeder category SAIDI threshold (mins)

SAIDI performance ratio

11PA17 Thorngate Urban 4.375 7.6

11BE01 Leanyer Urban 4.375 5.7

22TC302 Feeder 3 Urban 4.375 5.4

22TC602 Feeder 6 Rural Long 2.0 3.5


Table 8.32: 2012-13 Upgrade actions for poorly performing feeders

Feeder name 2012-13 Major interruption causes

2013-14 PN Feeder upgrade actions

11PA17 THORNGATE LightningEquipment failure or defect

This feeder was not identified as a poorly performing feeder in the 2013-14 feeder upgrades program. This feeder will be included in the next feeder upgrade program.

11BE01 LEANYER Equipment failure or defect

PWC propose as part of its substation replacement program.Yearly feeder inspections.

22TC302 FEEDER 3 Animals and birdsLightning

Install bat guards on approximately 120 poles.

22TC602 FEEDER 6 Damaged insulators Replaced damaged insulators.


The following observations are listed for PWC’s attention:

The numbers of feeders with poor performance have decreased considerably which denotes the overall effective work of PWC in this area.

The Commission considers the planned upgrade actions for these feeders satisfactory and in line with good industry practice. However, PWC is invited to consider if additional engineering measures can be taken including additional remote control high voltage switches to improve the overall restoration time of the healthy sections of the feeder. It is expected that the improvement on these two feeders will further improve the SAIDI and SAIFI for Rural feeders.

Two out of the four feeders of this group were still poor performers in the previous year. The Commission note that feeder 22TC602 at Tennant Creek is chronically performing below standards. It is understandable that some feeders are inherently prone to poor performance due to the type and length of the feeder, the surrounding vegetation, age of the asset and location. Despite the challenging conditions, it is expected that PWC employs effective engineering solutions to improve the performance of 11PA17 Thorngate and 22TC602 Feeder 6.

PWC is invited to provide further details of the poor performing feeders including time to restore the feeder for each outage and specific details of the faulty equipment. This information will further support the Commission’s review of the network performance.

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In the 2011-12 Power System Review, the Commission provided a list of recommendations for PWC to address. It is a firm intention of the Commission to monitor the progress of recommendations from all Reviews, to document and investigate the reason for any lack of progress or delays and provide a view as to whether these delays are justified. Progress against the 2011-12 Power System Review recommendations is detailed below:

Reduction of the incidence of overloading of 11/22 kV feeders

PWC has divided the feeder utilisation reporting between 11 and 22 kV. As expected, the 22 kV feeders due to their higher supply voltage have a lower utilisation and do not represent a concern. A feeder utilisation comparison between this and the previous Report is shown in Table 8.15.

Table 8.33: 11 and 22 kV feeder utilisation

Feeder Utilisation 80-90 90-100 Over 100 per cent

2011-2012 14 4 8

2012-2013 14 10 6

The Commission has also compared forecast feeder utilisation in the long term as shown in Table 8.16.

Table 8.34: 11 and 22 kV feeder utilisation long term trend

Feeder Utilisation 80-90 90-100 Over 100 per cent

2017 (from previous Report)

17 11 13

2018 (latest Report) 14 7 20

The Commission notes PWC’s statement that the high number of feeders in the over 100 per cent utilisation category appears higher than it should be due to load not yet being allocated to new feeders. However, as good industry practice, it is expected that the overall number of feeders with a utilisation above the 80 per cent target be below 10 per cent. In the PWC 11 and 22 kV distribution network, the number of feeders exceeding the target is close to 15 per cent. If the analysis is restricted to the 11 kV network, the number of feeders exceeding the utilisation target is above 20 per cent and appears to worsen in the medium term as shown in Table 8.35. In both cases, the utilisation of the 11 kV feeders is unsatisfactory and raises some concern about the overall planning of the 11 kV network and the capacity of the network to supply customers when feeders are out of service during contingency scenario, feeder or substation upgrade.

Table 8.35: 11 kV feeder utilisation above 80 per cent trend

Feeder Utilisation Total number of feeders

Feeder with utilisation above 80 per cent

Feeder with utilisation above 80 per cent

11 kV 2013 122 28 22.9 per cent

11 kV 2018 136 40 29 per cent


As a result, the Commission considers it appropriate that PWC consider:

allocating load to new feeders on a continuous basis for the reporting year and five year period;

reducing feeder loading below 100 per cent normal ratings as a matter of urgency; and

reducing the number of 11kV feeders with utilisation above the 80 per cent target in the short and medium term.

Long rural feeder utilisation

In the 2011-12 Review, the Commission requested performance improvement on the two existing long rural feeders within the Territory:

Mataranka (22KP07) in the Katherine region; and

Feeder 6 (22TC602) in the Tennant.

Mataranka feeder is now performing satisfactorily and it is expected that further improvements will continue to be made on the Tennant Creek feeder.

Continued development of the 11/22 kV voltage feeder modelling and reporting to include identification of sections of line that may be of lower rating than the trunk sections and therefore be at risk of overloading even though the trunk sections are adequate

The 2012-13 reporting from PWC still lacks on feeder modelling information. The Commission assumes that PWC perform voltage level studies on the capacity of feeders to supply loads of adjacent feeders during contingency scenarios and to confirm that, in normal operation, the voltage drop at the end of the feeder during maximum demand is within the Network Technical Code. The Commission will seek PWC to provide details of the voltage feeder modelling including details of the diameter of each section of the feeder for overloading consideration in future reviews.

Assessment of state of loading of distribution substations and low voltage distributors (lines and cables that emanate from distribution substations) and in particular large distribution substations supplying commercial and/or industrial loads, and multiple residential loads

In the past upgrading the rating of transformers was undertaken by utilities when obvious new and upgraded connections would exceed the rating of a transformer. Eventually when this preventative method was not successful, excessive voltage drop due to high load and fuse or protection operation would have warranted further investigation and highlighted a potential loading issue. Indeed, this method has been the typical engineering practice for decades. As noted by the Commission in the 2011-12 Review, advanced technology in control, metering and communication commonly known as Smart Grid is now making it possible to monitor and predict when a distribution transformer will be overloaded and trigger preventative upgrade of the transformer or trigger a different configuration of the network.

The Commission understands PWC’s concern on the capital cost of rolling out an extensive distribution transformer monitoring plan and welcomes PWC’s decision to begin an experimental scheme on this matter. This project will include different sources of input such as interval meter, customer demand and diversity factor. This method will be used as a screening test for further inspection and measurements on site to prevent future overloading. The Commission will seek that PWC provide details of the plan for the 2013-14 Review. It is expected that large distribution substations supplying residential, commercial and industrial loads are included in the pilot scheme. It is assumed that this project will lead to further steps in the implementation of Smart Grid technology within the Territory.

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In regards to low voltage distributors (lines and cables that emanate from distribution substations) the Commission understands that PWC and other utilities take action upon voltage complaints due to high loads on the LV line. However, the Commission assumes that PWC implements best design practice to prevent low voltage conditions taking place at the customer connection. Where voltage level complaints are raised by the customer, the Commission assumes PWC promptly implements remedial action including increasing LV conductor size, reducing length of LV circuits and implementing new distribution transformers.

The Commission is aware that PWC needs time to establish the systems and processes required to meet these reporting requirements, however there are still critical areas of reporting that need attention including:

Changes from the previous year’s reporting.

It is required that any forecasts and information that has changed significantly from previous forecasts and information provided in the preceding year’s report be highlighted and explained. It is expected that PWC allocate a specific subsection in the Network Management report to list all the relevant changes or confirm information from the previous years.

Option analysis.

The Commission request that PWC continue the improvement in documenting the major strategies and plans in the yearly report. For any system limitation highlighted in the report, discussion of the potential options that may address the system limitation in the forward planning period should be included. The discussion should contain technical key points, cost and timing of each investigated solution.

Power factor at peak load.

PWC’s Report does not provide any information about the existing power factor at substation level. Power factor of a load is one of the factors that affect the efficiency of power transmission. A low power factor requires PWC to generate, transmit and distribute more current to supply the real power demand. This increases generation and transmission costs as all components of the system such as generators, conductors, transformers, and switchgear need to be designed to carry the additional current.

Proposed commissioning time of major projects.

PWC’s 10 year Master Plan provides information only in regards to the financial year for each project. The Commission requires detail of the expected commissioning month to carefully monitor the progress and development of each specific project

Fault level details

Fault level details at each substation, single phase and three phase, for the present and long term forecast (five years) for the 132, 66, 22 and 11 kV system should be included in PWC’s report. This information is required to monitor the correctness of the PWC system modelling including information and methodology used for the study

Key Findings

The Commission recommends PWC address the following key findings in its 2013-14 reporting.

Capacity concerns

The main capacity concern is related to the transmission line loop between Hudson Creek, Palmerston, McMinns, Weddell and Archer Substations. In the event of the loss of the Weddell-McMinns 66kV line or Hudson Creek-Palmerston 66 kV line, one line of the 66 kV loop will exceed its thermal limit by the year 2014. This scenario will worsen as the load increases in the near future until


a new line from Archer or Hudson Creek to Palmerston Substation is constructed. The Commission recommends that PWC consider the most appropriate timing for this project or further consider the option of bringing a 132kV supply into the Palmerston area to ensure security of supply.

Predominance of serious network faults

Genuine transformer faults are usually serious and could have catastrophic effect. Similarly, mal-operation of a transformer protection scheme could lead to a capacity shortfall with a risk of overloading the other transformer/s within the substation. The Commission is concerned with respect to the six transformer outages for the 2012-13 period. Similarly, the frequency of transmission line outages (89) within the Darwin-Katherine area is not satisfactory.

Feeder loadings

As good electricity industry practice, it is expected that the overall number of feeders with a utilisation above the 80 per cent target be below 10 per cent. The number of 11 kV feeders exceeding the utilisation target is above 20 per cent and appears to worsen in the medium term. This data raises concern about the overall planning of the 11 kV network and the capacity of the network to supply customers when feeders are out of service during contingency scenario, feeder or substation upgrade.

Alignment with NEM planning

Improvements in aligning the Network Management Plan with the requirements of the NER have been made in comparison with the 2011-12 report. The Commission is aware that PWC needs time to establish the systems and processes required to meet these reporting requirements, however there are still critical areas of reporting that need attention including:

o changes from the previous year’s reporting;

o options analysis to fully document the major strategies and plans in the yearly report;

o power factor at peak load;

o detail of the expected commissioning month of each specific major project; and

o fault level details at each substation.

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9. Customer Service Review

9.1 Structure of this year’s review

The key measures and structure of this year’s review of customer service performance reflect the introduction Electricity Standards of Service (ESS) code released 1 December 2012. Specifically, reporting of customer service performance is slightly different to the 2011-12 Review to be more consistent with the ESS Code, where data was available. An attempt has been made to reconcile these key measures with the historical performance measurement to provide an indication of progress over time where this was possible and data was available.

The relevant schedules of the ESS Code relating to customer service performance are:

Schedule 2 – Network Services Performance Indicators; and

Schedule 3 – Retail Services Performance Indicators.

Data has been provided by PWC relating to customer service performance in these two areas. While this information is categorised broadly in line with the ESS Code, there are some minor inconsistencies (discussed in the individual sections below). However, the following should be taken into consideration when evaluating PWC’s consistency of reporting with the ESS Code:

1. Reporting against the ESS Code for 2012-13 was undertaken on a voluntary and best endeavours basis, acknowledging that the ESS Code will be applied retrospectively to report on nominated generation, network and retail performance measures for the six months prior to the ESS Code’s commencement32; and

2. The reporting of one of the indicators, Phone Answering, is combined for both network and retail and this is consistent the ESS Code as outlined in Schedule 2, 1.8.3 (b).

Specifically, the PWC data provides:

Network Indicators – which includes ‘Quality’ (in turn includes Quality of Supply and Complaints); and

Customer Service Indicators.

Some of the performance reporting is either not fully consistent with the ESS Code, or it is not clear whether the measures are constructed in a manner that is fully consistent with the ESS Code. In the latter case, the ambiguity in interpretation is noted and where it was deemed appropriate, assumptions have been made and noted.

32 p. 3, ‘2012-13 Standards of Service Report’, PWC, 2013.


9.2 PWC Network Services Performance

9.2.1 Reconnections and new connections

Performance of reconnections and new connections for 2012-13

The ESS Code outlines the following indicators for measuring of performance relating to connections and re-connections33:

The percentage and total number of re-connections not undertaken within 24 hours (this measure is reported by PWC in 2012-13 performance reporting and historical reporting);

The percentage and total number of new connections not undertaken in the CBD area or urban areas within 5 business days, excluding connections to new subdivisions where minor extensions or augmentation is required (appears to be the measure reported by PWC in 2012-13 performance reporting34 and historical reporting);

The percentage and total number of new connections in rural areas not undertaken within 10 business days excluding connections to new subdivisions where minor extensions or augmentation is required (appears to be the measure reported by PWC in 2012-13 performance reporting35 but not historical reporting); and

The number and average length of time taken to provide new connections in urban areas to new subdivisions where minor extensions or augmentation is required (appears to be the measure reported by PWC in 2012-13 performance reporting36, however, historically this was reported as the total number and percentage not completed with 10 weeks).

PWC’s performance relating to reconnections and new connections for 2012-13 is provided in the tables below.

Table 9.36: Connections and reconnections performance

Performance measure Total number Per cent of total not undertaken

within timeframe

Percentage and total number of re-connections not undertaken within 24 hours (excluding where minor extensions or augmentation is required)

11,060 1%

New connections not undertaken in the CBD/Urban areas within 5 days (excluding where minor extensions or augmentation is required)

518 5.2%

New connections not undertaken in the Rural areas within 10 days (excluding where minor extensions or augmentation is required)

255 1.7%

33 Schedule 2, 1.8.2 (a), ESS Code, Northern Territory of Australia, 2013.34 The PWC data provides the total and percentage of new connections not undertaken in the CBD/Urban areas within 5 days

but does not explicitly state this excludes connections where minor extension or augmentation is required (although this has been assumed).

35 As per the footnote above, although not explicitly stated, it is assumed that the figures provided by PWC exclude cases where minor extension or augmentation is required.

36 PWC data does not explicitly state that the figure provided is for cases where minor extension or augmentation is required, however, this is assumed.

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Table 9.37: New Connections in urban areas to new subdivisions

Total Avg. Time (weeks)

New Connections in urban areas to new subdivisions

120 14

Progress on performance of reconnections and new connections

As stated above, not all measures can be directly compared with historical performance. Historical performance for reconnections and new connections in urban areas where no extension or augmentation is required is provided below.

Table 9.38: Reconnections and new connections performance progress

2008-09 2009-10 2010-11 2011-12 2012-13 5 yr. avg.

Reconnections 0.8% 0.5% 0.3 % 0.1% 1.0% 0.5%

New connections (urban, no extension/augmentation required)

8.7% 7.9% 6.7% 12.% 5.2% 8.1%

The percentage of on time reconnections has significantly deteriorated in 2012-13 being below the average as well as the minimum of the last five years. However, on time new connections to urban areas where no extension or augmentation is required has improved significantly to the highest level in the last five years. This measure was noted as a performance issue in last year’s review.

Limited further trend comparisons can be made. The average time for new connections in urban areas to new subdivisions was 14 weeks. Whereas, in the 2011-12 it was noted that 27 per cent of such connections were undertaken within 10 weeks (the measured performance standard for 2011-12) and that this was a cause for concern. Without data on time taken for all 120 connections, it is difficult to draw many conclusions. However it appears that no significant improvement has been made in this area.

The 2011-12 Report does not provide any information in regards to time for reconnections where there is an existing supply. The Commission requests PWC provide this data for the 2013-14 Report, as required by the Electricity Standards of Service Code.

Urban connections in new subdivisions have improved from previous years. It is not possible to compare the Connections Rural or Connections Urban (extension needed) categories to the previous years as they are new performance indicators from the latest 2012 Service Code. However, based on the information provided for 2012-13, the Connection Rural results are considered satisfactory but the Connections Urban (extension needed) results require attention from PWC. It is expected that PWC be able to have new connections with extension needed below 10 weeks average length.


9.2.2 Quality of supply issues

Quality of supply performance for 2012-13

The reporting requirements for complaints relating to network quality of supply are outlined within Schedule 2, 1.8.4 (a) (ii) ‘the percentage and total number of complaints associated with the transmission network and distribution network quality of supply issues’.

The number and percentage of complaints relating to PWC’s quality of supply performance, by region, is summarised in the table below:

Table 9.39: Quality of supply complaints 2012/13

Fluctuating Low Power Part Power No Power

Total % Total % Total % Total %

Darwin 188 5% 78 2% 850 23% 2,632 70%

Katherine 14 2% 18 3% 211 34% 372 60%

Tennant Creek 10 8% 2 2% 22 17% 97 74%

Alice Springs 32 7% 13 3% 90 19% 339 72%

Progress on quality of supply performance

The categories provided by PWC are broader than the previous period and include ‘Low Power’ and ‘No Power’ events. These were not included in previous reporting. Therefore, the total of only those complaint categories included in previous years (these include ‘Fluctuating Power’ and ‘Part Power’) has been calculated and compared with historical performance. This is summarised in the table below:

Table 9.40: Quality of supply complaints trend

2008-09 2009-10 2010-11 2011-12 2012-13 5 yr avg.

Darwin 792 776 1,112 1,030 1,038 925

Katherine 109 317 149 197 225 199

Tennant Creek 21 77 19 23 32 33

Alice Springs 139 114 145 140 122 126

Total 1,061 1,284 1,425 1,390 1,417 1,282

The total number across regions, and totals for Darwin and Katherine, of comparable quality of supply complaints has deteriorated compared to last year and remains higher than the 5 year average.

The Commission considers Ergon Energy customer service performance to be a useful benchmark. Ergon Energy has a quality of supply rate of approximately 25 per 10,000 complaints per annum. Based on 80,000 customers, this would translate for PWC into 200-240 complaints per annum.

Voltage quality is critical for the operation of appliances, electronic devices and electric motors. Therefore, complaints in this area are carefully reviewed by the Commission.

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It is noted that in the period of 2012-13 the number of complaints has increased in comparison to the previous year and in relation to the Ergon benchmark. This performance needs attention from PWC.

9.2.3 Network Related Activities Complaints

Network related activities complaints performance for 2012-13

The reporting requirements for complaints relating to network related activities are outlined within Schedule 2, 1.8.4 (a) (i) ‘the percentage and total number of complaints associated with transmission network and distribution network related activities segmented into complaint categories’.

PWC provides the following data relating to network related activities complaints.

Table 9.41: Customer complaints due to network related activities

Network Related Activities Other

Access Issue Billing Issue Crew Issue

Total % Total % Total % Total %

Darwin 25 38% 9 14% 3 5% 29 44%

Katherine 2 50% 1 25% 0 0 1 25%

Tennant Creek

0 0 1 100 % 0 0 0 0

Alice Springs 1 20% 0 0 0 0 4 80 %

It has not been explicitly stated by PWC whether or not these complaints relate to network services (as distinguished from retail services), however it is assumed that this is the case. Furthermore, the ESS Code provides for two categories of complaints (quality of supply and network related activities). It is assumed that the other category is mutually exclusive to these two.

Performance relating to retail service complaints is discussed in section 9.3.

Progress on network related activities complaints

Compared to previous years, the data relating to complaints for 2012-13 has been separated into network and retail services complaints data (consistent with the ESS Code) and has been categorised (unlike prior years).

It is unclear whether the total of all complaints is directly comparable with prior years (presented as a total in prior years’ reporting). However, this comparison has been provided (refer to section 9.3).

9.2.4 Written enquiry response

As requested by the revised 2012 Electricity Standards of Service Code, PWC has reported the number of written enquiries and average response times. This is shown in Table 9.42.


Table 9.42: Average time taken to respond to a customer’s written enquiry segmented into regions

Region Average time taken to respond to a customer’s written enquiry (days)

Comments

Darwin 3.0 There were a total of 10 written enquiries received and reported back to customers in 2012-13.

Katherine n/a There were no written enquiries received for Katherine in 2012-13.

Tennant Creek n/a There were no written enquiries received for Tennant Creek in 2012-13.

Alice Springs 1.0 There was one written enquiries received for Alice Springs in 2012-13.


This performance indicator is new to the 2012 Service Code and, as a result, it is not possible for the Commission to compare the results to previous years. However, the number of written enquiries and the time taken to respond to the customer are considered acceptable.

9.2.5 Telephone call response

In Schedule 2, 1.8.3 (b) the ESS Code specifies that ‘Where relevant, and unless the Commission otherwise considers appropriate, the results [of telephone call response] will be a combined total for both PAWC Networks and PAWC Retail’.

While no telephone call response data has been included in reporting of network services performance, data has been provided in reporting of retail services performance. It is therefore assumed that the reporting of telephone call response relates to network and retail services combined. This is discussed in section 9.3. PWC will be required to provide these indicators as required by the ESS Code.

9.3 PWC Retail Services Performance

9.3.1 Telephone call response

Telephone call response performance for 2012-13

In Schedule 3, 1.1.5 (a) the ESS Code specifies that performance indicators for phone answering include:

Average time taken to answer the phone;

percentage and total number of calls not answered within 30 seconds; and

the percentage and total number of calls abandoned.

The reporting by PWC on this measure is broadly consistent with the ESS Code, with the exception that the percentage of calls not answered within 20 seconds has been provided rather than the percentage of calls not answered within 30 seconds.

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Table 9.43: Telephone call answering reporting

Average time taken to answer the phone. 180 seconds

Percentage and total number of calls not answered within 20 seconds of the caller asking to talk to a person.

124,052 60.8%

Percentage and total number of calls abandoned. 20,365 10%

In Schedule 3, 1.1.3 (a), the ESS Code also specifies that ‘for the purpose of calculating retail services performance indicators for Phone Answering, Complaints and Written Enquiries – only include those customers that are taking (or likely to take less than) 160 megawatt hours of electricity from the distribution network during the reporting period’. It is not explicitly stated, but assumed, that the PWC data only includes this subset of customers.

As with Schedule 3, the ESS Code specifies in Schedule 2, 1.1.5 (b) that ‘Where relevant, and unless the Commission otherwise considers appropriate, the results [of telephone call response] will be a combined total for both PAWC Networks and PAWC Retail’. It is assumed that the results have been combined for both networks and retail.

Progress on telephone call response performance

The reporting of calls not answered within 20 seconds has the benefit of allowing comparison with historical performance.

Table 9.44: Progress on telephone call response

2008-09 2009-10 2010-11 2011-12 2012-13

Percentages 62% 63% 62% 60% 39%

Numbers 87,013 91,614 88,888 101,306 124,052

This shows a significant deterioration on previous years’ performance, notwithstanding that the total number of calls increasing by 22 per cent. In the 2011-12 Review, it was noted that even 2011-12 performance was below the ‘minimum service standard of 63 percent’. No further discussion has been provided by PWC that explains factors behind this result or measures that have either been taken or proposed to address the issue.

While the Commission notes that the volume of calls increased in 2012-13, this should have been reasonably expected given billing issues associated with changes to regulated retail tariffs and action taken to address the increase in caller numbers. The Commission recommends that PWC consider what action should be required to improve this level of customer service.

9.3.2 Written Enquiries

Although required by the ESS Code under Schedule 3, 1.1.8 (a), PWC has not provided data for written enquiries relating to retail services.

However, data on written enquiries has been including the reporting of network services performance and relates to both network and retail services combined.


9.3.3 Retail Related Complaints

Number of customer complaints for 2012-13

Schedule 3, 1.1.6 specifies that the performance indicator for complaints ‘is the percentage and total number of complains associated with retail services segmented into complaint categories. The ESS Code further specifies in Schedule 3, 1.1.3 (a) that ‘for the purpose of calculating retail services performance indicators for Phone Answering, Complaints and Written Enquiries – only include those customers that are taking (or likely to take less than) 160 megawatt hours of electricity from the distribution network during the reporting period’.

Complaints data has been provided by PWC and is segmented into regions as required by code. However, the complaints are not segmented into categories other than specifying what proportion of the total complaints between 1 January 2013 and 30 June 2013 were ‘justified’37 complaints. Furthermore, it is not explicitly stated, but assumed, that this data (included in PWC’s reporting of retail services performance) relates to retail complaints (refer to network complaints in section 9.2.3) and for the required subset of customers (consuming less than 160 megawatt hours).

Table 9.45: Retail related complaints

1 July 2012 to 31 December 2012 Number of Complaints

Darwin 646

Katherine 34

Tennant Creek 26

Alice Springs 143

1 January 2013 to 30 June 2013 Number of Complaints Justified Complaints38

Darwin 937 20

Katherine 66 1

Tennant Creek 34 6

Alice Springs 174 2

Progress of number of customer complaints

Compared to prior years, the data relating to complaints for 2012-13 has been separated into network and retail services complaints data (consistent with the ESS Code) and has been categorised (unlike prior years).

It is unclear whether the total of all complaints is directly comparable with prior years (also presented as a total figure). However, this comparison has been provided.

37 No further detail about what was considered a justified complaint or otherwise has been given.38 PWC has its own criteria to determine whether or not a complaint is justified. The Commission has no comment on the

criteria used by PWC.134


Table 9.46: Progress on total complaint numbers

2008-09 2009-10 2010-11 2011-12 2012-1339

Darwin 1781 1830 1553 1516 1649

Katherine 160 160 146 147 104

Alice Springs 318 417 432 385 322

Tennant Creek 39 70 89 41 61

Total 2332 2235 2477 2220 2089

Assuming the total of 2012-13 complaints can be compared with prior years complaints, total complaints are at the lowest levels over the previous five years (except for a relatively small increase in Darwin and Tennant Creek).

9.4 Customer hardship programs

The requirements for reporting on customer hardship programs are provided in Schedule 3, 1.1.7 and not reproduced here. PWC indicates that extra resourcing is required to provide all the information required by the ESS Code. However, the following is provided:

Table 9.47: Customer hardship summary

Customers who participated in a customer hardship program during 2012-13.

281

Number of customers who accessed hardship vouchers from third parties, but paid for by Power and Water, during 2012-13.

887

This is the first year data on customer hardship has been reported and as such no comparison with prior years is available.

9.5 Progress against findings from the 2011-12 Review

Timeliness of customer connections for properties in new subdivisions and action taken by PWC to improve performance

The Commission acknowledges the changes to the reporting requirements under the new Standards of Service Code but notes that there is no evidence to suggest that there has been a material improvement in this area for the 2012-13 Review.

9.6 Key Findings

Customer service – Network

The Commission notes that customer responsiveness and complaint information is not always categorised as Network or retail related. The Commission considers it appropriate that PWC make efforts to categorise complaints on this basis. The following indices showed acceptable levels in 2012-13:

39 Includes all complaints (as opposed to ‘justified’ complaints) only.


On time new connections (no extension or augmentation)

Urban connections in new sub-divisions

Rural connections

The following indices showed unacceptable levels or deterioration in 2012-13:

On time reconnections

Urban connections (extensions needed)

Quality of supply

Number of complaints.

The following indices should be included in PWCs reporting:

Telephone call response

Customer Service - Retail

The following indices showed acceptable levels in 2012-13:

Number of complaints

The following indices showed unacceptable levels or deterioration in 2012-13:

Telephone call response

The following indices should be included in PWCs reporting:

Definition of justified complaints

136


A Generating Units

A.1 Darwin-Katherine

A.1.1 Channel Island

Unit GT 1* GT 2* GT 3* GT 4* GT 5* ST 6 GT 7 GT 8 GT 9 House Set 0.900 kW

Make / Model GE Frame 6 GE Frame 6 GE Frame 6 GE Frame 6 GE Frame 6 Mitsubishi GE LM6000 Trent 60 Trent 60 Kongsberg KG2

Engine Type Combustion Turbine

Combustion Turbine

Combustion Turbine

Combustion Turbine

Combustion Turbine

Steam Turbine

Combustion Turbine

Combustion Turbine

Combustion Turbine

Combustion Turbine

Fuel Type Gas or Diesel Gas or Diesel Gas or Diesel Gas or Diesel Gas or Diesel Waste Heat Gas Gas or Diesel Gas or Diesel Diesel

MW GMC RATING 31.6 31.6 31.6 31.6 31.6 32 36 42 42

N-1 FIRM GMC 31.6 31.6 31.6 31.6 0 16 36 42 42

N-2 FIRM GMC 31.6 31.6 31.6 0 0 0 36 42 42

Date Commissioned

1986 1986 1986 1986 1986 1987 2000 2011 2011 1986

* PWC has advised that generation sets 1 – 5 (GE Frame 6) have been converted to gas only but can be retro-fitted to use diesel within 24 to 48 hours.

A.1.2 Weddell

Unit Set 1 Set 2

Make / Model GE LM6000 PD GE LM6000 PD

Engine Type Combustion Turbine Combustion Turbine

Fuel Type Gas Gas

MW GMC RATING 43 43

N-1 FIRM GMC 0 43

N-2 FIRM GMC 0 0

Date Commissioned Feb-08 Nov-08

137


A.1.3 Berrimah

Unit GT 1 GT 2

Make / Model Stal Laval PP4 Stal Laval PP4

Engine Type Combustion Turbine Combustion Turbine

Fuel Type Kerosene Kerosene

MW GMC RATING 0 10

N-1 FIRM GMC 0 0

N-2 FIRM GMC 0 0

Date Commissioned 1978 1978

A.1.4 Shoal Bay and Pine Creek PPAs

Shoal Bay Pine Creek A Pine Creek B

Unit Set 1 GT 1 GT 2 ST 3 GT 1 GT 2 GT 3

Make / Model Caterpillar 3516G Solar Mars Solar Mars Peter Brotherhood Solar Centaur Solar Centaur Solar Centaur

Engine Type Reciprocating Spark Fired Combustion Turbine Combustion Turbine Steam Turbine Combustion Turbine

Combustion Turbine Combustion Turbine

Fuel Type Land Fill Gas Gas Gas Waste Heat Gas Gas Gas

MW GMC RATING 1.1 9.64 9.64 7.31 0 0 0

N-1 FIRM GMC 0 9.64 0 3.655 0 0 0

N-2 FIRM GMC 0 0 0 0 0 0 0

Date Commissioned Aug-05 Jun-96 Jun-96 Jun-96 1989 1989 1989

A.1.5 Katherine

Unit GT 1 GT 2 GT 3 GT4

138


Make / Model Solar Mars Solar Mars Solar Mars Solar Titan 130

Engine Type Combustion Turbine Combustion Turbine Combustion Turbine Combustion Turbine

Fuel Type Gas or Diesel Gas or Diesel Gas or Diesel Gas or Diesel

MW GMC RATING 7.4 7.4 7.4 12.5

N-1 FIRM GMC 7.4 7.4 7.4 0

N-2 FIRM GMC 7.4 7.4 0 0

Date Commissioned 1987 1987 1987 Jul-12

A.2 Tennant Creek

Unit Set 1 Set 2 Set 3 Set 4 Set 5

Make / Model Ruston 8ATC Ruston 8ATC Ruston 8ATC Ruston 8ATC Ruston 8ATC

Engine Type Reciprocating Diesel

Reciprocating Diesel




Fuel Type Diesel Diesel Diesel Diesel Diesel

MW GMC RATING 1.300 1.300 1.300 1.300 1.300

N-1 FIRM GMC 1.300 1.300 1.300 1.300 1.300

N-2 FIRM GMC 1.300 1.300 1.300 1.300 1.300

Date Commissioned

Unit Set 10 Set 11 Set 12 Set 13 Set 14 Set 15 Set 16 Set 17

Make / Model Caterpillar 3516G Caterpillar 3516G Caterpillar 3516G Caterpillar 3516G Caterpillar 3516G Solar Taurus Cummins QSK60 Cummins QSK60

Engine Type Reciprocating Spark Fired

Reciprocating Spark Fired




Combustion Turbine



Fuel Type Gas Gas Gas Gas Gas Gas or Diesel Diesel Diesel

139


MW GMC RATING 0.958 0.958 0.958 0.958 0.958 3.900 1.500 0.000

N-1 FIRM GMC 0.958 0.958 0.958 0.958 0.958 0.000 1.500 0.000

N-2 FIRM GMC 0.958 0.958 0.958 0.958 0.958 0.000 0.000 0.000

Date Commissioned

1999 1999 1999 1999 1999 2004 February 2008 December 2010

A.3 Alice Springs

A.3.1 Ron Goodin

Unit Set 1 Set 2 Set 3 Set 4 Set 5 Set 6 Set 7 Set 8 Set 9

Make / ModelMirrlees KVSS12 Mirrlees KVSS12

Mirrlees KV16P Major



Pielstick PC2-3 V16 DF

Pielstick PC2-3 V16 DF

Pielstick PC2-3 V16 DF ASEA GT35C

Engine Type Reciprocating Diesel


Reciprocating Dual Fuel






Combustion Turbine

Fuel Type Diesel Diesel Diesel and Gas Diesel and Gas Diesel and Gas Diesel and Gas Diesel and Gas Diesel and Gas Gas or Diesel

MW GMC RATING 1.900 1.900 4.200 4.200 4.200 5.500 5.500 5.500 11.700

N-1 FIRM GMC 1.900 1.900 4.200 4.200 4.200 5.500 5.500 5.500 0.000

N-2 FIRM GMC 1.900 1.900 4.200 4.200 4.200 5.500 5.500 0.000 0.000

Date Commissioned 1966 1967 1973 1973 1975 1978 1981 1984 November 1987

Unit F Set G Set J Set

Make / Model Kongsberg KG5 Kongsberg KG5 Mobile 3516 Cat

Engine Type Combustion Turbine Combustion Turbine Reciprocating Diesel

Fuel Type Gas or Diesel Gas or Diesel Diesel

MW GMC RATING 0.000 0.000 0.000

140


N-1 FIRM GMC 0.000 0.000 0.000

N-2 FIRM GMC 0.000 0.000 0.000

Date Commissioned 1992 1994

A.3.2 Owen Springs

Unit OSPS A (Ex RGPS H set) OSPS 1 OSPS 2 OSPS 3

Make / Model Solar Taurus 60 MAN 12V 51/60 DF MAN 12V 51/60 DF MAN 12V 51/60 DF

Engine Type Combustion Turbine Reciprocating Dual Fuel Reciprocating Dual Fuel Reciprocating Dual Fuel

Fuel Type Gas or Diesel Dual Fuel Dual Fuel Dual Fuel

MW GMC RATING 3.900 10.700 10.700 10.700

N-1 FIRM GMC 3.900 0.000 10.700 10.700

N-2 FIRM GMC 3.900 0.000 0.000 10.700

Date Commissioned 2004 October 2011 October 2011 November 2011

141


A.3.3 Brewer PPA

Unit G 1 G 2 G 3 G 4

Make / Model Waukesha Waukesha Waukesha Waukesha

Engine Type Reciprocating Spark Fired Reciprocating Spark Fired Reciprocating Spark Fired Reciprocating Spark Fired

Fuel Type Gas Gas Gas Gas

MW GMC RATING 2.128 2.128 2.128 2.128

N-1 FIRM GMC 2.128 2.128 2.128 0.000

N-2 FIRM GMC 2.128 2.128 0.000 0.000

Date Commissioned 23 December 1996 23 December 1996 23 December 1996 23 December 1996

A.3.4 Uterne PPA

Unit G 1

Make / Model SunPower T20 Tracker

Engine Type Photovoltaic

Fuel Type PV

MW GMC RATING 0.964

N-1 FIRM GMC 0.000

N-2 FIRM GMC 0.000

Date Commissioned 24 June 2011

142


B Generation Adequacy – Alice Springs and Tennant Creek

B.1 Alice Springs

Figure B.1: Loss of load (LOLP) or Lack of Reserve (LOR) probability – Alice Springs

143


B.2 Tennant Creek

Figure B.2: Loss of load (LOLP) or Lack of Reserve (LOR) probability – Tennant Creek

144


C Tabular Demand Statistics and MD Forecasts

C.1 Darwin-Katherine System

C.1.1 Comparison of Actuals and Forecast from Previous PSR

Table C.1: Darwin-Katherine SystemComparison of ZSS Actual and Forecast Maximum Demands (MVA)

Forecast Actual Actual 50 per cent POE

Difference

Archer 27.4 18.3 18.1 9.3

Batchelor 2.9 2.2 2.2 0.7

Berrimah 41.6 37.3 36.8 4.8

Brocks Creek 1.6 0.1 0.1 1.5

Casuarina 67.2 56.7 56.0 11.2

Centre Yard 0.5 0.4 0.4 0.1

City 56.4 54.1 53.4 3.0

Cosmo Howley 1.3 4.2 4.2 -2.9

East Arm 0.0 0.0 0.0 0.0

Francis Bay 6.1 11.6 11.4 -5.3

Humpty Doo 2.3 1.2 1.2 1.1

Katherine 29.9 29.2 28.8 1.1

Leanyer 0.0 0.0 0.0 0.0

Manton 4.0 4.1 4.0 -0.1

145


Mary River 1.4 2.4 2.3 -1.0

McMinns 34.3 21.1 20.8 13.5

Palmerston 35.4 36.0 35.5 -0.1

Pine Creek 12.9 0.0 0.0 12.9

Weddell 11.9 7.5 7.4 4.5

Woolner NA 36.1 35.7 -NA

146


C.1.2 Darwin-Katherine MD Forecasts

The ZSS and system MD forecasts for Darwin-Katherine are presented in the tables below.

Table C.2: Darwin-Katherine: Zone Substation Forecasts (MVA)

2012-13 ** 2013-14 2014-15 2015-16 2016-17 2917-18 2018-19 2019-20 2010-21 2021-22 2022-23 2013-24

Archer 18.32 22.62 24.05 25.47 26.90 28.33 29.75 31.18 32.60 34.03 35.45 36.88

Batchelor 2.24 1.99 1.74 1.49 1.24 1.00 1.00 1.00 1.00 1.00 1.00 1.00

Berrimah 37.31 36.51 30.37 36.09 36.10 36.11 37.28 37.30 37.31 37.32 37.33 37.35

Brocks Creek 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08

Casuarina 56.71 42.83 43.83 44.83 45.83 46.83 47.83 48.82 49.82 50.82 51.82 52.82

Centre Yard 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40

City 54.06 57.38 41.30 42.12 42.95 43.77 44.59 45.41 46.23 47.06 47.88 48.70

Cosmo Howley 4.21 4.90 4.90 4.90 4.90 4.90 4.90 4.90 4.90 4.90 4.90 4.90

East Arm 0.00 0.00 9.00 9.24 9.49 9.73 9.97 10.22 10.46 10.70 10.94 11.19

Francis Bay 11.58 12.13 29.57 30.12 30.67 31.22 31.77 32.31 32.86 33.41 33.96 34.51

Humpty Doo 1.23 1.23 1.23 1.23 1.23 1.23 1.23 1.23 1.23 1.23 1.23 1.23

Katherine 29.18 30.00 32.32 32.15 31.97 34.29 34.12 33.94 33.76 33.59 33.41 33.23

Leanyer 0.00 21.26 21.83 22.41 22.98 23.56 24.13 24.70 25.28 25.85 26.43 27.00

Manton 4.10 3.66 3.22 2.78 2.34 2.34 2.34 2.34 2.34 2.34 2.34 2.34

Mary River 2.36 3.42 3.48 8.28 8.34 8.40 8.47 8.53 8.60 8.66 8.72 8.79

McMinns 21.09 31.09 44.59 50.79 52.09 53.38 43.18 44.48 45.78 47.08 48.38 49.68

Palmerston 36.00 49.02 56.00 57.90 58.79 61.88 62.78 63.67 64.56 65.45 66.35 67.24

Pine Creek 0.00 1.70 1.70 1.70 1.70 1.70 1.70 1.70 1.70 1.70 1.70 1.70

Weddell 7.47 16.30 21.12 22.94 24.77 16.59 18.41 20.24 22.06 23.88 25.71 27.53

Woolner 36.12 37.80 40.48 42.06 42.24 42.43 42.61 42.79 42.97 43.16 43.34 43.52

Union Reef 10.38 10.48 10.57 10.66 10.75 10.85 10.94 11.03 11.12 11.21 11.31 11.40

147


** P50 Actual (corrected for transfers and spot loads)

148


Table C.3: Darwin-Katherine: System MD Forecasts (MW)

Forecast Trend High Trend Low Trend

2013/14 298 299 295

2014/15 306 310 301

2015/16 315 321 307

2016/17 324 331 313

2017/18 333 342 319

2018/19 342 353 326

2019/20 350 364 332

2020/21 359 374 338

2021/22 368 385 344

2022/23 377 396 350

2023/24 386 406 356


C.2 Alice Springs


C.2.2 Alice Springs MD Forecasts

The ZSS and system MD forecasts for Alice Springs are presented in the tables below.

Table C.4: Alice Springs: Zone Substation Forecasts (MVA)

2012-13

2013-14

2014-15

2015-16

2016-17

2917-18

2018-19

2019-20

2010-21

2021-22

2022-23

2013-24

Ron Goodin 32.35 26.37 24.75 23.12 21.50 19.88 18.26 16.63 15.01 13.39 11.76 10.14

Lovegrove 14.99 19.75 20.15 20.55 20.95 21.35 21.74 22.14 22.54 22.94 23.34 23.74

Sadadeen & Brewer Balance

6.06 6.06 6.06 6.06 6.06 6.06 6.06 6.06 6.06 6.06 6.06 6.06

ASP (FDRs) 53.65 53.53 53.40 53.28 53.16 53.04 52.91 52.79

(ASP ZSS) 53.40 52.18 50.95 49.73 48.51 47.28 46.06 44.84 43.61 42.39 41.17 39.94

Table C.5: Alice Springs: System MD Forecasts (MW)


2013/14 53 53 53

2014/15 53 54 52

2015/16 53 54 52

2016/17 53 54 51

2017/18 53 54 51

2018/19 53 54 50

2019/20 53 54 50

2020/21 53 55 49

2021/22 53 55 49

2022/23 53 55 48

2023/24 53 55 48

150


C.3 Tennant Creek


[Data cannot be located]

C.3.2 Tennant Creek MD Forecasts

The ZSS and system MD forecasts for Tennant Creeks are presented in the tables below.

Table C.6: Tennant Creek: System MD Forecasts (MW)


2013/14 6.75 6.86 6.66

2014/15 6.75 6.97 6.56

2015/16 6.75 7.08 6.47

2016/17 6.75 7.19 6.38

2017/18 6.75 7.30 6.28

2018/19 6.75 7.40 6.19

2019/20 6.75 7.51 6.09

2020/21 6.75 7.62 6.00

2021/22 6.75 7.73 5.90

2022/23 6.75 7.84 5.81

2023/24 6.75 7.95 5.71


D Details of PWC Network MD Forecasting Methodology

The steps undertaken by PWC in the development of the MD forecasts are presented below.

Zone Substation MDs

The methodology used for the development of each ZSS MD forecast was unchanged from that used in the 2012-13 forecasts. The process used is illustrated in the flow diagram below.

System Maximum Demand

There were three independent steps used in the System MD forecast as described below. The only relationship between the three steps was the weather corrected (50 per cent POE system MD) calculated in the first step, and a consideration of the system MD growth rate developed from system MD data.

Step 1: Review and weather correcting historical data

The steps undertaken are shown below together with the corresponding growth rates at each stage of the process. The final step provides the system 50 per cent POE MD historical trend. The process used is illustrated in the flow diagram below.

Step 2: Constructing System Demand Growth from non-coincident ZSS Maximum Demands

DataHistotical MD data collected.

Adjustments

Historical spot loads removed. There is limited data on historical spot loads.Known load transfers between ZSS included. Subjective judgement used.

Weather corretion

Ajusted data is weather corrected (P50).

Regression

Linear (least squares) regression undertaken. This represents the 50 per cent POE demand projection excluding future spot loads.

Future spot loads

Known future spot loads are added (or subtracted). The assumption is that the total planned spot load is added in.This represents the final "50 per cent POE ZSS Forecast.

Data

Historical "at gen" MD collected.Growth rate 2.23 per cent

Corrected Data weather corrected (50 per cent POE). Growth rate 2.06 per cent

Regression

Linear regression - 50 per cent POES MD historical trend.Growth rate 1.86 per cent


The steps undertaken to compare system growth developed from substation forecasts are shown below. The purpose of this was to reconcile the system growth rate developed in Step 1. The process used is illustrated in the flow diagram below.

Step 3: System Maximum Demand Forecasts – Trend, High and Low

The steps undertaken to develop the system MD growth forecasts are shown in the flow diagram below. The Forecast Trend is taken to be the expected or medium forecasts outlook.

The critical assumption used was selection of the 2.7 per cent annual MD growth from a consideration of the system growth based on historical system MD data and that determined based on ZSS growth.

154

ZSS data

Total summation of non-coincident ZSS MDs.Growth rate 4.00 per cent

AlignLinear regression and "offset" that aligns this with the 50 per cent POE demand in 2013. Growth rate 3.71 per cent

Spot loads

Known future spot loads removed and a linear regression undertaken.Offet determined that aligns this with the 50 per cent POE demand in 2013. Labeleld "Spatial Modified Spot Loads Trend".Growth rate 4.04 per cent

Regression

The above is scaled so that 2013 equals 50 per cent POE system demand.Linear regression and alignment with 2013 50 per cent POE system demand. Termed Spatial Adjusted Forecast Trend.Growth rate 3.58 per cent

Growth rate

Expected growth in system MD determined from Step 1 and 2 above. The average of the historical P50 system MD growth and Spatila Adjusted Forecast trend was 2.72 per cent.Growth rate of 2.7 per cent selected

linearise

MD projection developed by growth the 2013 50 per cent POE demand by 2.7 per cent.Projection linearised through linear (least squares) regression.Forecast Trend forecast

High and Low

High and low projection undertaken by applying the same process for growth rates of 3.2 per cent and 1.95 per cent respectively.High TrendLow Trend


E Summary of Power and Water Corporation Technical Audit

In December 2013, the Commission received a copy of an external technical undertaken on PWC’s compliance obligations related to its Tennant Creek and Alice Springs power systems. The technical audit covered three components:

a) Audit 22kV system protection settings to ensure clearance times comply with the Network Connection Technical Code (NCTC)

The Tennant Creek 22 kV clearance times were assessed. The fault clearance times comply with the Code (that is, are less than 500 ms) for all feeders except for the overcurrent protection of feeder 22TC602. The following recommendations were made as a result of the audit:

1. That a critical fault clearing time be determined for the Tennant Creek network. This critical clearing time then becomes a more onerous requirement than the 500 ms clearing time specified in the code.

2. Review the fault level for the Tennant Creek network. The audit recommends that minimum and maximum fault levels be calculated at the 22 kV substation, the remote end and 80 per cent of the length of the feeder.

b) Testing at Ron Goodin Power Station to investigate the power system oscillations observed in previous measurements

Oscillations had been observed during commissioning of Owen Springs Power Station (OSPS) and believed to emanate from Ron Goodin Power Station (RGPS). Recordings of generator outputs were obtained by PWC using their permanently installed Tesla recorders showing that the active power output of Sets 3 to 8 at RGPS were oscillating at approximately 4 Hz. Set 9 at RGPS and the OSPS generators were observed to oscillate at approximately 2 Hz. Site tests revealed that oscillations in the active power output of RGPS sets 4 to 8 could be clearly observed during testing. It was found that neither the AVRs nor the governors influenced the oscillations, ruling out problems with the generator control systems. It was also found that the fuel type did not influence them either. The frequency of the oscillations, which corresponds to half engine speed, leads to the conclusion that the oscillations emanate from the reciprocating engines themselves.The audit concludes that the major effect of the oscillations will be to cause greater wear on governor actuators in the Alice Springs network due to constantly working to counteract the oscillations in speed.

c) Audit of Brewer, Ron Goodin, Owen Springs and Pine Creek power stations for compliance to clause 6.4.3 of the System Control Technical Code (SCTC)

The audit investigated the qualifications of personnel at the power stations to operate HV equipment. From the evidence and observations of the auditor there appears to be general compliance with the SCTC clause 6.4.3. That is, register of people authorised to carry out electrical operation that interface with the HV network is maintained, and there are systems in place to ensure the HV electrical operations are performed only by Registered Operators. The audit noted considerable differences in the


records kept at the different stations of those operators who are qualified (registered) to carry out the HV interface operation and the evidence of compliance in terms of what forms/permits are required to be completed to ensure HV operations are carried out by ‘Registered’ operators.The audit made the following conclusions:

1. Station operators be issued with licences that identify that they have completed the necessary qualification and are registered to carry out HV electrical operations. The operators should be able to produce the license when asked for evidence of registration.

2. Procedures and the necessary forms to perform HV electrical operations should be consistent across all power stations operating on the NT PWC network. Efforts should be made by NT PWC to rationalise procedure/records for operation.

3. Clause 6.4.3 of the SCTC should be revised to make it clear as to the required evidence of compliance that HV electrical operations are performed only by Registered Operators.

4. Clause 6.4.3 (c) of the SCTC needs to be amended to reflect that the ‘Green Book’ for permit procedures is no longer in use.

156


F Alignment of Network Management Plan with Australian Electricity Industry Reporting

For the purposes of providing information to support this Review, PWC Networks provided a copy of its revised Network Management Plan.

Schedule 5.8 of the NER establishes the information that distribution network service providers will be required to include in their distribution annual planning reports in the future. The table below compares the overlap between those requirements, and the issues currently covered by PWC Networks in its Network Management Plan. The Commission recommends PWC further consider the character and content of the Network Management Plan to progress alignment with NEM practices.

Schedule 5.8 Requirement (Summarised) Coverage in PWC Draft Network Management Plan 2011-12

Coverage in PWC Draft Network Management Plan 2012-13

Information regarding the Service Provider and its network:

Description of network Operating Environment Number and Types of Assets Methodologies used in identifying limitations etc. Analysis and explanation of forecasts

Forecasts Description of methodology Load Forecasts

o Transmission/distribution connection points

o Sub-transmission lineso Zone substationso Forecasts for future connection points,

lines and zone substations Reliability forecasts A description of factors that may have a material

impact on networko Fault levelso Voltage Levelso Power system security requirementso Quality of Supplyo Aging and potentially unreliable assets


Information on system limitations Sub-transmission lines Zone substations High voltage feeders forecast to be overloaded

Planned investments under the regulatory investment test

A summary of planned investments of $2 million or more relating to:

o Refurbishment of replacemento Unforeseen network issues

N/A

N/A

Information on Joint Planning with other Transmission operators

Information on Joint Planning with other Distribution Operators

N/A40

N/A

N/A41

N/A

Information on the performance of the network Reliability measures and standards, performance

against them and proposed corrective action Quality of supply standards, performance against

them and proposed corrective action

Information on demand management activities

Information on investments in metering

A regional development plan consisting of maps showing: Transmission / distribution connection points,

sub-transmission lines and zone substations Emerging system limitations, including

overloaded distribution feeders

Addressed in detail Addressed at high level Not addressed

N/A Not applicable in the Territory’s context

Although only minor improvements have occurred in this regard through the 2012-13 year the Commission acknowledges that significant PWC Networks’ resources were directed to prepare and respond to the 2014 Network Price Determination. The Commission’s view is that in 2014-15, the Network Management Plan will be progressed further by PWC and PWC will give further consideration to making a version of the Network Management Plan publicly available.

Although further alignment with NEM practice is required, the Commission acknowledges the standard of this document has improved in contrast to past practice. Given the Network Management Plan is developing into a mature, quality document, the Commission considers there would be considerable benefit in PWC publishing a public version of the document.

40 It is assumed that PWC’s transmission assets will also be included the Annual Planning Report.41 It is assumed that PWC’s transmission assets will also be included the Annual Planning Report.

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