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Power System Review

2014-15

Charles Darwin Centre

19 The Mall DARWIN NT 0800

Postal Address GPO Box 915 DARWIN NT 0801

Email: [email protected]

Website: www.utilicom.nt.gov.au

Power System Review 2014-15

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Purpose of this Report

The Power System Review (Review) is prepared by the Utilities Commission (Commission) in accordance with section 45 of the Electricity Reform Act (ER 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 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, which include 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 Review is in respect of the financial year ending 30 June 2015, and information was received from industry participants during 2015-16 for the Commission to undertake the review. The Commission understands the information received to be current as at December 2015. Where there have been significant developments post December 2015, the Commission has noted these developments throughout the report.

The Review contains predictions, estimates and statements 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 an accurate report 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.

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Inquiries

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

Utilities Commission GPO Box 915DARWIN NT 0801

Telephone: 08 8999 5480

Email: [email protected]

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GlossaryTerm Definition

1P Reserves Proven reserves with a reasonable certainty of being recovered

2P Reserves Proven and probable reserves

ACQ Annual contract quantity (see also MDQ)

AEMO Australian Energy Market Operator

AER Australian Energy Regulator

AMS Agreed minimum standards

APA APA Group

CIPS Channel Island power station

EDL EDL NGD (NT) Pty Ltd

ENI ENI Australia Limited

ER Act Electricity Reform Act

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 10 years

ESS Code Electricity Standards of Service Code

EUE Expected unserved energy (see also USE)

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

FiT Feed-in-Tariffs

GMC Sustainable installed capacity

GWh Gigawatt hour

HV High Voltage

I-NTEM Interim Northern Territory Electricity Market

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

Jacana Energy Power Retail Corporation, a government owned corporation established in accordance with the Government Owned Corporations Act and trading as Jacana Energy

kV Kilovolt

LNG Liquefied natural gas

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

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LV Low Voltage

MD Maximum demand

MDQ Maximum daily quantity

MRL Minimum reserve level

MW Megawatt

MVA Megavolt ampere

N-X Planning criteria allowing for full supply to be maintained to an area supplied by the installed capacity of N independent supply sources, with X number of those sources out of service (with X usually being the units with the largest installed capacity)

NEGI North Eastern Gas Interconnector

NEM National Electricity Market

NER National Electricity Rules

NMP Network Management Plan (prepared by PWC)

P10 Maximum demand projection that is expected to be exceeded, on average, one year in 10 (a 10% probability)

P50 Maximum demand projection that is expected to be exceeded, on average, five years in 10 (a 50% probability)

p.a Per annum

PJ Petajoules (see also TJ)

PJ/d Petajoules per day

PJ/a Petajoules per annum

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.

PV Photovoltaic

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

Reserve plant margin Total system capacity available less the actual maximum demand (MD) for electricity in a particular year, expressed as a percentage of MD

1 From 1 July 2014, the generation and retail business units of PWC were structurally separated into standalone government owned corporations under the Government Owned Corporations Act.

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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

SRES Small-scale Renewable Energy Scheme

STC Small-scale technology certificates

SWER Single wire earth return

System Control Entity with a statutory role in monitoring and controlling the operation of the power systems in the Northern Territory and a business unit of PWC

Territory Generation Power Generation Corporation, a government owned corporation established in accordance with the Government Owned Corporations Act and trading as Territory Generation

TJ Terajoules (see also PJ)

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

USE Unserved energy (see also EUE)

VCR Value of customer reliability

WA WEM Western Australian Wholesale Electricity Market

WPS Weddell power station

ZSS Zone substation

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Contents

1. Executive Summary 2

1.1 Purpose of the Power System Review 21.2 Objective of the 2014-15 Review and Report Structure 21.3 Key Findings 41.4 Commission’s Focus for the 2015-16 Review 7

2. Overview of the Northern Territory Power Systems 9

2.1 Legislative Framework 92.2 Interim Wholesale Electricity Generation Market 102.3 Overview of the Transmission and Distribution Systems 112.4 Overview of Generating Plant 152.5 Industry Participants 16

3. Overall Power System Issues 19

3.1 Introduction 193.2 Supply Chain Robustness 193.3 Assessment of Response to Major System Incidents 193.4 System Operability and Standards of Service 203.5 System Planning 20

4. Maximum Demand and Energy Projections 21

4.1 Introduction 214.2 Projection Uncertainty 214.3 Review of 2014-15 Actual MDs and Projections 22

4.3.1 2014-15 ZSS Projections 224.3.2 2013-14 System Wide Projections 234.3.3 Alice Springs 23

4.4 Rooftop PV 244.5 System-Wide Projections 26

4.5.1 System-Wide MD Projections 264.5.2 System-Wide Energy Projections 27

4.6 Zone Substation MD Projections 284.6.1 Darwin-Katherine ZSS Projections 284.6.2 Alice Springs and Tennant Creek ZSS Projections 29

4.7 Load Factor Trend and Reconciliation of ZSS MD with System Wide MD Projections 30

5. Generation Reliability 32

5.1 Generator Reliability Standard 325.2 Review of 2014-15 Generating Reliability 33

5.2.1 Generation Response Reliability 335.2.2 Generation Capacity Reliability 345.2.3 Summary and Trend in Reliability Performance 35

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5.3 Generator Capacity Reliability – Minimum Reserve Margin 35

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6. Generation Adequacy and Reliability Outlook 37

6.1 Generator Adequacy N-X Outlook 376.2 Generation Reliability Outlook 39

6.2.1 Generator Capacity Reliability 396.2.2 Generator Response Reliability – Darwin-Katherine 41

7. Generation Performance 42

7.1 Spinning Reserve 427.1.1 Incident Report Review 44

7.2 Availability of Existing Generators 457.2.1 Asset Management Plan Review 457.2.2 Availability Outlook 46

7.3 Standards of Service Indicators 487.4 New or Proposed Generators 507.5 Progress against Key Findings from the 2013-14 Power System Review 507.6 Key Findings – Generation Operation and Planning 51

8. Fuel Supply 52

8.1 Introduction 528.2 Adequacy of Northern Territory Gas Supply 52

8.2.1 Territory Generation’s Gas Requirement 528.2.2 PWC Gas Supply 528.2.3 Gas Transportation Capacity 53

8.3 Security of Gas Supply 558.3.1 Introduction 558.3.2 Blacktip Gas Field 558.3.3 Amadeus Basin Gas 568.3.4 LNG Back-up Supply 578.3.5 Gas Transportation 588.3.6 Diesel Back-up 598.3.7 Contingency Analysis – Failure of Blacktip or Gas Transportation 60

8.4 Key Conclusions – Security of Gas Supply 618.4.1 11 September 2014 Supply Interruption 618.4.2 Analysis and Key Recommendations 628.4.3 Other Items Relevant to 11 September Event 62

9. Networks Adequacy and Reliability 64

9.1 Introduction 649.2 Planning and Monitoring 659.3 Transmission Line Utilisation 659.4 Terminal Station and ZSS Utilisation 679.5 Feeder Utilisation 689.6 Feeder Performance 699.7 Incident Report Review 709.8 Reliability 71

9.8.1 Transmission Network Performance 71

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9.8.2 Feeder Network Performance 729.8.3 SAIDI and SAIFI Historical Comparison 74

9.9 Planned and Recent Network Enhancements 759.10 Progress against Findings from 2013-14 Power System Review 77

10. Customer Service 81

10.1 Introduction 8110.2 PWC Network Services Performance 81

10.2.1 Reconnections and New Connections 8110.2.2 Quality of Supply Issues 8210.2.3 Network Related Activities Complaints 8410.2.4 Written Enquiry Response – Networks 8510.2.5 Telephone Call Response 85

10.3 Jacana Energy Retail Services Performance 8610.3.1 Telephone Call Response 8610.3.2 Retail-Related Complaints 8710.3.3 Customer Hardship Programs 88

10.4 PWC Retail Services Performance 8910.5 Progress against Findings from the 2013-14 Review 8910.6 Key Findings 89

Appendices

A Generating Units

A.1.1 Channel IslandA.1.2 WeddellA.1.3 Shoal Bay and Pine Creek PPAsA.1.4 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 Review of PWC Maximum Demand Projections

B.1 Previous Estimates – PSR14B.2 Approach and Reconciliation

C Demand Forecasting Methodologies

C.1 System-Wide Energy ProjectionsC.2 System-wide MD ProjectionsC.3 Zone Substation MD Projections

D Tabular Results

E Generator Related Load Shedding

F Not used

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G Progress against Recommendations from Previous Power System Reviews

List of Figures

Figure 2-1: Northern Territory energy supply infrastructure 12

Figure 2-2: Darwin-Katherine Transmission Network (major components) 13

Figure 2-3: Alice Springs Key Transmission and Distribution Network 14

Figure 4-1: Revision to 2013-14 Maximum Demand 23

Figure 4-2 Rooftop PV Costs (Installed) and Economic Payback Period 25

Figure 4-3 Projected Rooftop PV Installation 25

Figure 4-4 Reduction in Maximum Demand due to 1 MW of Rooftop PV 26

Figure 4-5: Alice Springs: Energy, Maximum Demand and Modelled Solar Panel 28

Figure 4-6 Darwin-Katherine Large ZSS - P50 MD Projections (MVA) 29

Figure 4-7 Darwin-Katherine Small ZSS - P50 MD Projections (MVA) 29

Figure 4-8 Alice Springs and Tennant Creek - ZSS P50 MD Projections (MVA) 30

Figure 4-9 Historical Load Factors – Actual MD 31

Figure 6-1: N-X Generation Reliability 38

Figure 6-2: Outlook for Generation Capacity Reliability 40

Figure 8-1 Northern Territory Gas Infrastructure 54

Figure 9-1: 22kV PWC feeder utilisation 69

Figure 10-1: Customer notifications relating to quality of supply and reliability 83

Figure 10-2: Customer notifications relating to quality of supply by region – PWC 83

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List of Tables

Table 1-1: System-Wide MD Annual Growth Projections (P50 Basis) 4

Table 1-2: Projected Households with Rooftop PV and Impact on System-Wide MD 5

Table 2-1: Power Networks’ Statistics (regulated network) 15

Table 2-2: Electricity Licence Holders at 30 June 2015 16

Table 4-1 Commission 2014-15 Projections – Comparison to Actuals MW 22

Table 4-2 2013-14 System-Wide Projections – Comparison to Actuals MW 23

Table 4-3 System-Wide Maximum Demand Projections MW 26

Table 4-4 System-Wide Energy Projections GWh 27

Table 5-1: UFLS Statistics Associated with Generation Response Reliability for 2014-15 33

Table 5-2: UFLS Statistics Associated with Generation Capacity Reliability for 2014-15 34

Table 5-3 Generator Reliability Outcomes for 2014-15 35

Table 5-4: Assessed Territory Power System MRLs 35

Table 6-1: Generation Planning Criteria 37

Table 6-2: N-X Margins for 2014-15 39

Table 7-1: Probability of CIPS and Weddell generation units being available for service 47

Table 7-2: CIPS generation units actual vs. predicted availability 47

Table 8-1 Gas Contingency Analysis 60

Table 9-1: Summary of the substation constraints (N-1 conditions) 68

Table 9-2: Darwin-Katherine transmission network performance 72

Table 9-3: 2014-15 Distribution SAIDI results segmented by feeder category 73

Table 9-4: 2013-14 Distribution SAIFI results segmented by feeder category 73

Table 9-5: PWC and Ergon SAIDI and SAIFI comparison 74

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Table 9-6: Adjusted (excluding major event days) SAIDI historical results comparison 74

Table 9-7: Adjusted (excluding major event days) SAIFI historical results comparison 75

Table 9-8: Forecast capital expenditure ($ million, real $2013-14 with input cost escalation) 76

Table 10-1 Connections and reconnections performance – PWC 82

Table 10-2 New Connections in urban areas to new subdivisions – PWC 82

Table 10-3 Customer Complaints due to Network-Related Activities – PWC 84

Table 10-4 PWC Average time taken to respond to a customer’s written enquiry segmented into regions 85

Table 10.5 Telephone Call Answering Reporting – Jacana Energy (2014-15) 86

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1. Executive Summary

1.1 Purpose of the Power System Review

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

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 of participants in the electricity supply industry, other electricity industry stakeholders and consultant reports. The Commission uses existing information from industry participants as a basis of the review, and timing of the Review is highly dependent on information being provided by industry participants in a timely manner.

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.

For the 2014-15 Review, the Commission engaged Entura, engineering consultants with expertise in the energy supply market, to provide advice on generation, network, overall power system and customer service aspects of the review. Entura partnered with Marsden Jacob Associates and MDQ Consulting to provide advice relating to demand forecasting, gas markets, fuel supply and overall power system analysis.

Consistent with the Northern Territory Government’s electricity reform program to align the electricity industry with national arrangements, the Australian Energy Market Operator (AEMO) provided high-level advice on the scope of the 2014-15 Review. The Commission aims to seek further AEMO involvement and input in future reviews.

1.2 Objective of the 2014-15 Review and Report Structure

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, for systems with similar characteristics (such as geographical and environmental factors).

Regular and comprehensive reporting on power systems, and distribution network performance and health is a feature of the electricity supply industry elsewhere in Australia. Consistent with good electricity industry practice and noting the Northern Territory Government’s regulatory reform agenda for the electricity market4, the Commission continues to transition reporting requirements in

2 Section 45, Electricity Reform Act.3 Available from the Commission’s website, www.utilicom.gov.au.4 Department of Treasury and Finance, Northern Territory Electricity Market Reform, Information Paper, February 2014,

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the Territory to be consistent with those of the National Electricity Market (NEM), with the involvement of AEMO in future reviews expected to assist the transition.

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

data to support the identification by current and potential 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 network reliability performance, and customer service performance information; and

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

For the 2014-15 Review, the Commission continues to place focus on power system incident reporting and planning, including the power system model and spinning reserve, generation availability and response, network planning and availability, generation and network reliability. The Commission has also considered the approach to power system planning in Alice Springs and Tennant Creek.

The 2014-15 Review is the first review after the structural separation of retail and generation business units from Power and Water Corporation (PWC). The Commission has therefore also considered the roles and responsibilities of the electricity market participants in managing the security and reliability of the system post-structural separation.

2014-15 Report Structure

The 2014-15 Review covers the following components:

overall power system issues;

maximum demand (MD) projections;

generator adequacy and reliability;

generation performance;

fuel supply;

network adequacy and reliability; and

customer service performance.

1.3 Key Findings

The Commission’s key findings for the 2014-15 Review are detailed below.

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


Overall Power System Issues (Chapter 3)

The Commission notes an overall improvement to performance in areas highlighted in previous reviews in fuel supply, generator plant reliability, network sensitivity to disturbances, reliability SAIDI and SAIFI index target standards being met in Darwin-Katherine and Alice Springs for generating plant, transmission network and distribution networks and customer service.

The Commission notes issues that have arisen through post-structural separation of PWC related to communication and administrative processes among the newly separated entities, particularly in outage planning and maintaining adequate redundancy in generation and or network resources. The Commission observed some progress post-2014-15 will continue to monitor developments in future reviews.

The Commission notes a gap post-structural separation in formal arrangements for independent planning for generation adequacy and that this is actively being considered by the Territory Government as part of its electricity reform program and the further development of wholesale market arrangements.

During 2014-15, the Commission noted a significant improvement in the power systems, particularly in the Darwin-Katherine power system, in terms of the number and severity of outages. The analysis and work undertaken by System Control and Territory Generation to investigate any incidents also improved significantly over this period.

The Commission commends the work undertaken by both System Control and Territory Generation, particularly in relation to voltage and frequency control issues and Under Frequency Load Shedding (UFLS) arrangements. The Commission recognises the significant work undertaken by both parties to address recommendations from various investigation reports, including the 12 March 2014 System Black investigation and the Commission’s technical audit in 2014, which appears to have contributed to improved power system reliability.

The Commission notes that while the level of investigation and reporting on major system incidents has improved significantly, timeliness and monitoring of actions from investigation reports could be improved.

Maximum Demand (MD) and Energy Projections (Chapter 4)

The Commission’s 10-year system-wide MD projections (based on a 50% probability of being exceeded and expected spot loads) are shown in the table below.

Table 1-1: System-Wide MD Annual Growth Projections (P50 Basis)Commission Projection

Darwin-Katherine 4.4 MW p.a (1.4% p.a)

Alice Springs 0.07 MW p.a (0.14% p.a)

Tennant Creek 0.2 MW p.a (2.8% p.a)

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The percentage of households with a rooftop photovoltaic (PV) installation is expected to increase uniformly over the next 10 years. The rate of uptake is projected to be slightly higher for Darwin-Katherine than was projected in the 2013-14 Review. Slight decreases in rate of uptake are expected in the Alice Springs and Tennant Creek power systems.

Table 1-2: Projected Households with Rooftop PV and Impact on System-Wide MDPercentage of households with rooftop PV (%) Reduction in System-Wide MD (%)

2015-16 2024-25 2015-16 2024-25

Darwin-Katherine 11% 29% 2.64% 4.67%

Alice Springs 22% 34% 5.69% 7.69%

Tennant Creek 18% 36% 4.81% 5.78%

Darwin-Katherine and Tennant Creek are projected to have small increases in energy demand (0.93% and 0.35% p.a respectively), while Alice Springs is expected to have energy demand decline slowly (-1.07% p.a) over the 10-year review period.

Generation Reliability and Performance (Chapters 5 and 7)

A review of load shedding events in 2014-15, found that all the Territory power systems satisfied a generation response reliability standard of 0.002% expected unserved energy (EUE) (being the standard used in the NEM and the WA WEM). The Darwin-Katherine system was at the standard and the other power systems performed better than the standard.

The Darwin-Katherine power system had two load shedding events in 2014-15 associated with generation capacity reliability. This is a significant improvement from the 11 events that were recorded in 2013-14. Alice Springs and Tennant Creek power systems did not record any such events in 2014-15, in comparison to three events in Alice Springs and one event in Tennant Creek during 2013-14.

The two Darwin-Katherine events were not related to generator breakdowns but nonetheless the severity of one of the events resulted in the percentage of unserved energy (USE) far exceeding the generation capacity standard of 0.002%. The Commission makes the observation that a limitation of the projections of reliability may not account for these types of events and that these issues will need to be considered in future development of a formal reliability standard.

All regions showed a slight increase in generation SAIFI with significantly low generation SAIDI. The SAIDI standards returned to trend in 2014-15 after the levels were significantly affected by a major system black incident in 2013-14. System incidents in 2014-15 represent a marked decrease in the frequency of multiple generator contingency events. This is pleasing and is reflected in the SAIDI and SAIFI indicators both being below 50% of the agreed performance standard for all regions.

Minimum Reserve Level (MRL) margins are unchanged from 2013-14. These indicators will need to be reviewed in the context of further development of the wholesale electricity market and possible adoption of a formal reliability standard.

There was an improvement in 2014-15 in actual real spinning reserve available due to improvements in performance of Channel Island power station (CIPS) generation units 8 and 9. The Commission considers there would be benefit in using value of lost load (VoLL) and value

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of customer reliability (VCR) for a more systematic methodology for determining spinning reserve levels.

While improvements in availability estimation methods by Territory Generation have led to greater projected availability, the Commission recommends that Territory Generation continue its progress in moving to a probabilistic approach to determining the available capacity at power station level.

The Commission notes improvements in governor response, however there remain considerable improvements needed in relation to excitation and governor modelling and the possible need for power system stabilisers for the three power systems.

Generation Adequacy and Reliability Outlook (Chapter 6)

The responsibility for planning for generation adequacy in the Darwin-Katherine power system is still in development post-structural separation of PWC and is an issue being considered as part of the Territory’s wholesale electricity market reforms.

The generation availability standard currently applied by Territory Generation for the Darwin-Katherine power system is N-3 to cater for the life extension works at CIPS, with the intention of reinstating the N-2 planning criteria in 2018-19 following completion of the project. The normal level of reliability, N-2, is achieved through to 2024-25.

Plans for augmenting Owen Springs and retiring Ron Goodin power stations in Alice Springs should maintain N-2 across the 10-year period to 2024-25. The plans for modernising the power station at Tennant Creek should maintain N-1 across the 10-year period to 2024-25.

Fuel Supply Outlook (Chapter 8)

The Territory’s gas system security is considered to be N-1 for a short to medium period of time, with an additional back-up arrangement from 2017 increasing gas system security to N-2 until 2022.

The Commission recommends that a review of PWC’s gas supply commitments to Eastern Australia via the North Eastern Gas Interconnector (NEGI) pipeline from 4th quarter 2018 be undertaken upon the commencement of the pipeline. The Commission notes that it will be in the interest of gas system security for Territory Generation to secure a long-term gas supply contract.

The Commission notes improved communication and emergency response processes put in place by major stakeholders including PWC, ENI, Territory Generation, APA Group and the Territory Government following the 11 September 2014 gas supply interruption that resulted in rotating outages across the Darwin-Katherine power system.

Networks Adequacy and Reliability (Chapter 9)

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

o Zone substation and feeder loading has stabilised earlier than was predicted. This is likely due to increased solar penetration and a reduction of demand.

o The investigation work completed by PWC Networks to determine the causes of circuit outages and the 2014-15 program to test the earthing on transmission towers is appropriate, which should help to reduce circuit interruptions due to lightning.

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o Significant work has occurred to address the poor performance of the 132kV Channel Island to Hudson Creek line and or its protection systems. Outstanding work includes upgrades to tower earth grids.

Significant progress seems to have been made on the work program to reduce the likelihood of an outage of the transmission lines between Hudson Creek, Palmerston, McMinns, Weddell and Archer substations.

The Standards of Service Report provided by PWC indicate that during 2014-15 there were no poorly performing feeders (this was also the case for 2013-14). The Commission notes that this represents a significant improvement in the performance of the worst feeders for at least four consecutive years and is a positive result.

Customer Service Performance (Chapter 10)

The 2014-15 financial year was the first year of reporting by PWC, Territory Generation and Jacana Energy post-structural separation. The Commission understands that PWC continued to provide some call centre services to Jacana Energy as a transitional arrangement during the review period.

The Commission had previously observed a steady increase in the number of customer complaints and deteriorating responsiveness with respect to answering the telephone calls. This appears to have greatly improved in 2014-15 through the efforts of Jacana Energy.

Timeframes for network re-connections and new connections improved in 2014-15.

The number of complaints relating to network quality of supply reduced in all regions other than Alice Springs where there was a small increase but the Commission considers the number of complaints remains high and further effort is required to break down the category of complaints recorded as ‘other’ to understand the spread of issues.

1.4 Commission’s Focus for the 2015-16 Review

Consistent with the Territory Government’s electricity reform program and aligning reporting requirements with national requirements and recognising AEMO has significant expertise in demand forecasting and generation adequacy at a system level, the Commission aims for greater involvement with AEMO for the 2015-16 Review.

The Commission notes that AEMO’s annual Electricity Statement of Opportunities (ESOO) publication, which uses current information provided by industry to report on the adequacy of existing and committed generation and transmission capacity in the NEM to meet MD and annual operational consumption forecasts over the next 10 years, will present an opportunity to incorporate national practices in the 2015-16 Review.

In the 2015-16 Review, the Commission will have particular focus on the following issues:

Overall Power System

Potential impacts on the power system as the full Northern Territory electricity market develops and further clarification around roles and responsibilities related to planning for generation adequacy.

Implications on the future development of a reliability standard, wholesale market and planning for generation adequacy and the roles of market participants.

The increasing independence of the System Control function and the future development and clarification of the role of Market Operator in the Territory post-structural separation of PWC.

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Actions taken by System Control to improve reliability in the Darwin-Katherine power system including improvements to the planning of actual availability and spinning reserve, the outcomes of a review and systematic determination of power system planning outcomes and levels of EUE which incorporate and are directly related to measures such as the accepted VCR.

Generation Reliability and Adequacy

A focus on developments in generator reliability and asset planning, particularly the development of asset management plans and strategies by Territory Generation.

Transitioning to reporting on generation reliability and adequacy in alignment with NEM and AEMO practices using indicators that accurately reflect the complexity of the system through probabilistic methods and incorporate greater understanding of how generation reliability at unit level flows on to generator reliability at system level.

Follow-up any recommendations following system incident investigations including the Alice Springs System Black incident that occurred on 30 January 2016 and any additional technical reviews or audits undertaken.

Fuel Supply

A continued focus on fuel supply security in the Territory and existing and future arrangements for procuring gas supply.

Broader consideration of other sources of supply available to the Territory and how these impact fuel supply security.

Network Adequacy and Reliability

PWC Networks efforts for improving the reliability, durability and segregation of the Channel-Island to Hudson Creek 132kV lines.

Planning for network adequacy and redundancy in the Alice Springs and Tennant Creek systems where significant generation capital investment is planned.

Customer Service

Improvements in customer service (retail) indicator reporting and compliance with the Electricity Standards of Service Code by retailers (for small customers connected to the regulated networks).

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2. Overview of the Northern Territory Power Systems

2.1 Legislative Framework

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

Power and Water Corporation Act 2002;

Power Generation Corporation Act 2014;

Power Retail Corporation Act 2014;

Utilities Commission Act 2000;

Electricity Reform Act 2000 (ER Act); and

Electricity Networks (Third Party) Access Act 2002.

The Power and Water Corporation Act 2014 establishes PWC to generate, trade, distribute and supply electricity in the Northern Territory (it also has functions in relation to water and sewerage services).

From 1 July 2014, the commercial electricity retail and generation business units of PWC were structurally separated into standalone government owned corporations, Power Generation Corporation (trading as Territory Generation) and Power Retail Corporation (trading as Jacana Energy). The monopoly parts of the business (networks and system control) and some residual retail and generation functions remain with PWC.

The Utilities Commission Act 2000 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 ER Act provides the legislative framework for the operation of the electricity supply industry in the Territory. The ER Act describes, among other things, the key functions and responsibilities of the Commission in the electricity industry, 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

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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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 was responsible for determining the network conditions and charges, and monitoring and enforcing compliance with a Network Price Determination (NPD). The Commission made its final NPD for the fourth regulatory control period (1 July 2014 to 30 June 2019).

From 1 July 2015, network access and price regulation transferred to the Australian Energy Regulator (AER). For the remainder of the fourth regulatory control period, the AER will administer the Commission’s 2014 final NPD. The Commission continues to maintain responsibility for network technical regulation (including standards of service reporting, and power system monitoring) and licensing.

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

The ER 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 Interim Wholesale Electricity Generation Market

On 28 February 2014, the Commission provided a report to the Minister pursuant to section 31 of the Utilities Commission Act regarding wholesale electricity market arrangements that are appropriate for the Northern Territory, including recommended preferred arrangements.

The Commission’s report proposed the establishment of a Northern Territory Electricity Market (NTEM) that comprises separate investment and energy trading mechanisms. The Commission recommended interim energy trading arrangements be established as a transition to a final wholesale electricity market. The Territory Government endorsed adoption of an interim wholesale electricity market in late 2014.

On 27 May 2015, the System Control Technical Code was amended to incorporate the role of System Control as the market operator of the Interim Northern Territory Electricity Market (I-NTEM). The I-NTEM calculates and publishes prices based on existing bilateral contracts between retailers and generators in a virtual settlement process.

The Commission understands that the Government is currently in the process of considering, in consultation with market participants, appropriate design elements and amendments required for the adoption of the full electricity market.

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2.3 Overview of the Transmission and Distribution Systems

The Territory’s transmission and distribution systems are operated by PWC Networks. 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’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, which supplies Darwin city, Palmerston, 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 – supplies its township and surrounding rural areas, from the Ron Goodin power station, Owen Springs power station and independent power producers (IPP) Brewer power station and Uterne Solar power station.

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

Territory Generation also operates localised generation systems at Yulara and Kings Canyon.

PWC operates localised generation systems at Borroloola, Elliott, Daly Waters, Timber Creek, Ti Tree and in Indigenous communities under the Indigenous Essential Services program.

Figure 2-1 provides an overview of the Territory’s energy supply infrastructure.

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Figure 2-1: Northern Territory energy supply infrastructure

Source: Utilities Commission and PWC

A schematic of the existing and future Darwin-Katherine transmission and distribution network is presented in Figure 2-2.

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Figure 2-2: Darwin-Katherine Transmission Network (major components)

Source: PWC.6

A schematic of the existing and future Alice Springs transmission and distribution network is presented in Figure 2-3.

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

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Figure 2-3: Alice Springs Key Transmission and Distribution Network

Source: PWC.

The majority of the Territory, except for Darwin and Alice Springs, 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 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 in the northern area;

extreme lightning activity year-round in the northern area;

very high seasonal rainfall in the northern area;

frequent flooding in the northern area;

high vegetation growth rates in the northern area;

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 in the northern area.

These geographic and environmental variations influence the design criteria for the transmission and distribution systems.

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The three major network systems are not connected to the national grid and operate as separate stand-alone systems. Table 2-3 below contains descriptive statistics for the regulated electricity networks.

Table 2-3: Power Networks’ Statistics (regulated network)

Power Network Statistic As at 30 June 2015

Regulated System D-K TC AS

Energy delivered (GWh) 1 623 29.2 221.2

Maximum demand (MW) 290.8 6.9 51.2

Number of transmission terminal stations 4

Number of ZSS 24

Number of distribution substations 4 535

Number of major power transformers (22kV to 132kV) 58(excludes generator and spare transformers)

Transmission overhead (132kV and 66kV) 702 km

Transmission underground (66kV) 41 km

High voltage overhead (22kV, 11kV and SWER) 3 224 km

High voltage underground 798 km

Low voltage overhead (includes service mains and streetlights)

1 810 km

Low voltage underground (includes service mains and streetlights)

2 235 km

Source: PWC May 2016

2.4 Overview of Generating Plant

The generation plants in the Darwin-Katherine power system are CIPS (310MW), WPS (129 MW), Katherine power station (34.7MW) Pine Creek power station (26.6MW) and Shoal Bay (1.1MW) with a total of 501.4MW GMC (Sustainable Installed Capacity). The fuel type of the generation units is made up of a mix of dual fuel (gas/diesel), gas only, steam and landfill gas.

The generation plants in the Alice Springs power system are Ron Goodin power station (44.6MW), Owen Springs power station (36MW), Brewer power station (8.5MW) and Uterne (4MW), with a total of 90MW GMC. The fuel type of the generation units is made up of a mix of dual fuel (gas/diesel), gas only, steam and photovoltaic.

There is 16.7MW GMC installed in the Tennant Creek power system with a fuel type of diesel and gas.

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

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2.5 Industry Participants

Electricity industry participants licensed to operate in the Darwin-Katherine, Alice Springs and Tennant Creek power systems at 30 June 2015 are listed in Table 2-4.

Table 2-4: Electricity Licence Holders at 30 June 2015

Licensees Darwin-Katherine Alice Springs Tennant Creek

Generation Territory Generation Territory Generation Territory Generation

Generation – Independent Power Producers (IPP)

NGD (NT) P/LCosmo Power P/LLMS Generation P/L

Central Energy PowerUterne Power Plant P/L

Network PWC PWC PWC

Retail PWC (to Jabiru)7

Jacana EnergyQEnergy LimitedERM Power Retail P/LRimfire Energy



System Control PWC

Source: Utilities Commission.

On 11 August 2014, the Commission issued a retail licence to Rimfire Energy Pty Ltd to sell electricity.

PWC holds a retail licence for the retail areas of Jabiru, Nhulunbuy, Alyangula, McArthur River Mine and Indigenous communities under the Indigenous Essential Services program.

On 26 November 2014, the Commission received applications from EDL NGD (NT) Pty Ltd for both retail and generation licences. Both applications were assessed by the Commission in accordance with section 16 (3) of the ER Act and approved subject to EDL obtaining a network access agreement with PWC.

The Commission received an application from Northern Power Opco Pty Ltd for a licence to generate electricity on 22 May 2014. As of 31 December 2015, consideration of this application was pending further information from the applicant.

PWC is responsible for providing System Control services and these are partly funded through a specific charge approved by the Commission and levied on retailers. As the market develops, it is becoming more important to separate the System Control function from PWC and put in place fully independent governance structures and 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.8

7 Jabiru, while part of the Darwin-Katherine regulated network for the administrative purposes of the Electricity Reform Act, is not physically connected to the Darwin-Katherine system.

8 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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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) is a renewable energy (photovoltaic) facility. These five businesses are known as Independent Power Producers and generate electricity under power purchase agreements with Territory Generation (PWC prior to structural separation).

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3. Overall Power System Issues

3.1 Introduction

This section builds on the analysis done in the following chapters of the Review and comments on broad issues arising, and the overall effectiveness of the three main Northern Territory power systems, identifying common issues and gaps in responsibility and or regulation that may threaten the ongoing robustness of power system management in the future.

3.2 Supply Chain Robustness

The Commission has, in previous Power System reviews, raised concerns over the performance of the elements of the Power System. Previous reviews have highlighted gas supply issues, generator plant and network equipment issues and sensitivity of the network to disturbances. The 2014-15 Review shows an improvement in these matters.

The reliability of the generating plant (Chapter 7), transmission network and distribution network (Chapter 9) in Darwin-Katherine and Alice Springs was within the target set for the SAIDI and SAIFI indices. In addition PWC are actively committing to addressing poor performing feeders and transmission elements where there is consistent poor performance.

An issue that has become apparent to the Commission is around outage planning and maintaining adequate redundancy in generation and network resources to guarantee continued supply. A series of Non-Reliable Operating State Notices across the three power systems suggest that there are administrative processes between System Control, Territory Generation and PWC Networks that may need attention to ensure the robustness of the power system is maintained.

The operating history of the three regions suggests the level of performance is not just defined by the apparent level and quality of the installed equipment but also the skill and diligence with which it is operated. The Commission accepts that communication may be less easily managed post-structural separation, but communication between the entities appears to be more effective through cleaner lines of communication, transparency and accountability of various roles and responsibilities.

3.3 Assessment of Response to Major System Incidents

The Commission notes work being undertaken by PWC System Control to investigate and report on major system incidents and is comfortable with the level of scrutiny and review undertaken as part of incident investigation.

The timeliness of reports remains an issue being addressed by PWC System Control but improved during 2014-15 and into 2015-16. The Commission’s aim is for findings and recommendations that arise from any investigation reports to deliver lasting performance improvements for the various power systems. The Commission also considers there would be benefit in greater transparency as to the actions arising from any investigation reports. The Commission notes the transparency and accountability that this approach produced following the 12 March 2014 Darwin-Katherine System Black investigation and encourages the consolidation of continuous improvement processes associated with incident reporting and responses.

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3.4 System Operability and Standards of Service

The 2014-15 Review shows a marked improvement in generation SAIDI and SAIFI and a comparable level of performance from the network assets from the previous year. The increased standards of service also appear to have led to fewer customer complaints by phone.

The Commission had previously observed a steady increase in the number of customer complaints and deteriorating responsiveness with respect to answering the telephone calls. This appears to have been greatly improved in 2014-15 through the efforts of Jacana Energy.

The Commission, while acknowledging the improved performance of the power systems in 2014-15, is also aware of system black events in Alice Springs in early 2016. This leads the Commission to conclude that the performance improvements are not yet consolidated and that further work is required to meet customer expectations, particularly in Alice Springs and Tennant Creek.

The Commission would like PWC to consider providing power quality monitoring data at key points in the network to better understand the power quality issues customers are experiencing. This will provide a point of reference for customer complaints and provide an understanding of any trends.

3.5 System Planning

Formal arrangements should be established for independent planning for generation adequacy to meet system peak demand. The Commission understands this is an issue being considered by the Territory Government as part of the move to the full NTEM and that in the short to medium term, such responsibility is likely to sit with the System Control/Market Operator function of PWC, with further work needed to determine a reliability standard in the Territory.

The Commission considers that in the current process of system planning, there is significant opportunity for improvement by consideration of the value of lost load, assumptions regarding asset reliability and applying an appropriate level of security for planned outages. The Commission’s view is that the assumed value of lost load or a VCR should be assessed as it is an important planning input and there remains some uncertainty around an appropriate value for the three power systems.

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4. Maximum Demand and Energy Projections

4.1 Introduction

The 2014-15 Review provides Zone Substation (ZSS) and system maximum demand (MD) projections for the period 2015-16 to 2024-25 for the Darwin-Katherine, Alice Springs and Tennant Creek power systems. The projections were prepared with the assistance of Marsden Jacob Associates (Marsden Jacob).

This chapter:

Compares the MD projections in 2015 for the 2013-14 Review to recorded actuals and presents reasons for differences.

Presents updated system-wide and ZSS MD projections and the reasons for any changes in the projections from those in the previous review.

Updates the finding on rooftop PV development expected in the three power systems and the associated impact this has to the respective system MD.

Further details of the issues identified, approaches used and results are contained in the described appendices.

4.2 Projection Uncertainty

There are many factors that can influence the MD recorded in a particular year. These include weather conditions on the day of MD and leading up to that day (for example, temperature, humidity, cloud, wind), day of the week, week of the year and statistical spread.

Different weather conditions from one year to the next can mean that there can be differences in the recorded MD all other things being equal. To normalise MD projections to that which would be those expected under ’average conditions‘, previous reviews have presented MDs in terms of temperature-corrected values. This was based on the premise that temperature is the main ‘statistical’ factor impacting the level of MD each year, and as such, projections needed to be compared to actuals on a temperature-corrected basis9.

Analysis by Marsden Jacob indicates that in all systems, temperature is not the only significant factor in the level of MD recorded each year, and there is a significant level of uncertainty due to other factors such as those mentioned above. For this reason in this Review, projected MDs are compared to recorded actuals (no temperature correction is undertaken) and the performance of the projections is based on whether these lie within a specified level of confidence associated with the projection.

The P50 and P10 MD projections (addressed later in this chapter) were developed based on the statistical uncertainty associated with each projection. This is similar to the approach adopted by AEMO. AEMO does not weather correct maximum demands, and its P50 and P10 projections are based on the total uncertainty associated with outturn maximum demands.

9 This issue has been discussed in previous review documents. Refer to Appendix C of this Review for demand forecasting methodology.

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4.3 Review of 2014-15 Actual MDs and Projections

The 2013-14 Review included ZSS MD projections based on a 50% Probability of Exceedance (P50) (signifying average weather conditions) and expected changes in ’spot‘ loads. The system-wide projections also included P10 MD projections based on extreme weather conditions. These projections are reviewed below.

The 2013-14 Review also presented ZSS and system-wide MD projections undertaken by PWC for the three power systems against actuals provided by PWC. A review of these projections and a comparison to the Commission’s projections is presented in Appendix B.

4.3.1 2014-15 ZSS Projections

A comparison of 2014-15 ZSS projections to actuals is shown in Table 4-5.

Modelling undertaken by Marsden Jacob shows that, generally, growth for energy use in Tennant Creek reflected broad population growth, suggesting the trend rate of growth slows over time. For Alice Springs the sole explanatory variable was trend, suggesting a constant rate of decline over time. Darwin-Katherine was best explained by a combination of economic activity and population. Marsden Jacob also found that temperature was not a significant explanatory variable in the regression across the three power systems.

Commentary is provided on reasons for differences.

Table 4-5 Commission 2014-15 Projections – Comparison to Actuals MW

ZSS Projection Actual Difference Comment

Darwin-Katherine

Archer 24.6 22.5 2.1 Expected load transfer shortfall of 3.1 MVA

Batchelor 2.2 2.1 0.1

Berrimah 29.7 34.0 -3.3 Expected 6.2 MVA out became 1.3MVA in

Brocks Creek 0.3 0.1 0.2

Casuarina 53.1 51.8 1.3 Expected 1.0 in did not occur

Centre Yard 0.4 0.4 – Note, demand is assumed

City 45.9 57.5 -11.6 Expected 10.1MVA out became 1.0MVA in

Cosmo Howley 5.2 4.4 0.8

Frances Bay 29.2 7.8 21.4 Expected 6.9 MVA in did not occur

Humpty Doo 2.5 1.7 0.8

Katherine 28.9 22.2 6.7 Significant overestimate

Leanyer

Manton 10.8 3.4 7.4 Expected 4.7 MVA in did not occur

Mary River 4.3 3.2 1.1

McMinns 26.7 28.5 -1.8 Expected 4.4 MVA in wa sonly 1.3 MVA

Palmerston 33.4 33.9 -0.5 Expected 4.4 MVA in was only 1.4 MVA in

Pine Creek 1.4 1.3 0.1

Weddell 9.6 8.6 1.0 Expected 3.0 MVA in was only 1.4 MVA in

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Woolner 34.0 41.7 -7.7 Underestimate

Union Reef 11.7 11.7 –

Alice Springs

Lovegrove 19.3 31.1 -11.8 Historical base significantly revised

Sadadeen 24.1 25.2 -1.1

Tennant Creek

Tennant Creek 7.2 6.7 0.5

4.3.2 2013-14 System Wide Projections

A comparison of system-wide MD projections to actuals is shown in Table 4-6.

Table 4-6 2013-14 System-Wide Projections – Comparison to Actuals MW

ZSS Projection Actual Difference Comment

Darwin-Katherine 293.13 290.82 2.31 Actual temp reduces projection by 1.3 MVA

Alice Springs 57.99 50.57 7.42 Overestimated MD

Tennant Creek 7.0 6.73 0.27

Source: PWC December 2015

As observed above, there were small difference between the projections and actuals for the Darwin-Katherine and Tennant Creek systems. The large difference for the Alice Springs system is discussed below.

4.3.3 Alice Springs

At the time of the 2013-14 Review, the Commission projected MD for the Alice Springs system in 2014-15 of 57.99 MVA. This compares with the actual recorded MD for that year of 50.6 MVA. This overestimation primarily reflects a significant revision in the reported MD for 2013-14.

At the time of the 2013-14 Review, MD for 2013-14 in the Alice Springs system was reported as 56 MVA. This was used in the modelling to project MD for each following year. For the current Review, the actual MD for 2013-14 was revised to 50.6 MVA, representing a significant revision (approximately 10% adjustment) as illustrated in Figure 4.1.

Figure 4-4: Revision to 2013-14 Maximum Demand

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While one year’s data typically does not affect analysis significantly, with so few observations it did increase the expected MD (it exacerbated PWC’s projection, which extrapolates from the most recent observation rather than the trend line).

4.4 Rooftop PV

The 2013-14 Review presented a projection of rooftop PV for the three power systems and provided analysis of the profiles of solar generation and the relationship of this to summer and winter maximum demands. These projections have been updated in the 2014-15 Review to account for:

updated PV costs (installed) that are lower than previously used;

combined PV and Li-Ion battery storage systems;

end of the Small-scale Renewable Energy Scheme (SRES) by the end of 2030 and associated small-scale technology certificate STC creation and or revenue; and

a declining contribution of rooftop PV to MD as the time of MD moves later into the evening.

The Commission notes that the current 1:1 Feed-in-Tariff (FiT)10 is not a result of a Government policy but rather a scheme implemented in 2001 by PWC to reflect the initiative for renewable technologies and was inherited by Jacana Energy post-structural separation of PWC. The value of the FiT is not mandated or regulated by Government or the Commission. The ongoing level of the FiT will be a matter for Jacana Energy to determine in consultation with its shareholding Minister.

From a customer perspective, the economics of installing rooftop PV is the same in all the three power systems.(Figure 4-2 below), which shows PV installation cost and the payback period for installations undertaken over the forecast period. Figure 4-5 shows declining rooftop PV installation costs, although net of STC subsidy, the system costs remain relatively constant and has a very slight increase.

The payback period shows a slight rise in in the first few years to 2019-20. The payback period from 2020-21 onwards declines due to two factors:

increasing energy tariff costs; and

combined PV Li-Ion battery systems become more main stream.

Battery storage is modelled as an additional cost above a standard PV system that allows more PV energy to be used directly by the customer than sold back to the grid. The savings from the batteries become greater in the later years as the technology matures and the additional capital costs reduce.

10 A 1:1 Feed-in-tariff refers to a policy where the customer is paid the retail tariff for each kWh of solar power exported to the grid.

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Figure 4-5 Rooftop PV Costs (Installed) and Economic Payback Period

The updated rooftop PV projections, together with the projections contained in the 2013-14 Review are shown in Figure 4-6 below. This shows rooftop PV installation rates are expected to remain roughly constant over the next 10 years. The percentage of dwellings with rooftop PV is projected to increase over the 2016 to 2024 period as follows:

Darwin-Katherine: 11% to 29%

Alice Springs: 22% to 34%

Tennant Creek: 18% to 36%.

The forecast PV outlook is incorporated in the regional MD projections presented in the following sections.

The corresponding ratio of reduction in summer MD (MW) associated with the capacity (MW) of rooftop PV installed is only slightly different in each of the power systems, being roughly about 0.6 in 2015 and decreasing to below 0.45 by 2021. The contribution of rooftop PV to summer MD is shown in Figure 4-7 below.

Figure 4-6 Projected Rooftop PV Installation

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Figure 4-7 Reduction in Maximum Demand due to 1 MW of Rooftop PV

4.5 System-Wide Projections

This section presents the system-wide MD and energy projections for the Darwin-Katherine, Alice Springs and Tennant Creek power systems.

4.5.1 System-Wide MD Projections

MD projections were developed based on expected spot loads (as assessed by PWC) and weather conditions that result in a MD that has a 50% probability of being exceeded over summer (P50 projection), and weather conditions that result in a MD that has a 10% probability of being exceeded over summer (P10 projection). The P50 and P10 projections are shown in the Table 4-7 below. The current analysis indicates significantly less effect from variations in maximum temperature. Actual 2014-15 results (as per Table 2-3) are included for comparison.

Table 4-7 System-Wide Maximum Demand Projections MW

Darwin-Katherine Alice Springs Tennant Creek

P50 P10 P50 P10 P50 P10

2014-15 290.8 (Actual) 51.2 (Actual) 6.9 (Actual)

2015-16 302.37 311.43 54.94 56.72 6.92 7.20

2016-17 306.21 315.27 54.98 56.75 7.08 7.35

2017-18 310.35 319.40 54.90 56.67 7.29 7.57

2018-19 314.06 323.12 54.79 56.56 7.49 7.76

2019-20 319.35 328.41 54.80 56.57 7.74 8.01

2020-21 323.46 332.52 55.06 56.83 7.95 8.23

2021-22 328.77 337.83 55.31 57.08 8.17 8.44

2022-23 333.27 342.32 55.41 57.19 8.40 8.68

2023-24 337.76 346.81 55.52 57.29 8.64 8.91

2024-25 342.24 351.30 55.62 57.40 8.87 9.15

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4.5.2 System-Wide Energy Projections

System-wide energy projections were developed over the outlook period. The key factor in energy supplied is underlying growth in electricity use. Maximum demand achieved on any one day has only a minor impact on total energy supplied over a year. Consequently the projections are not expressed in terms of P50 and P10, but usually in terms of low, medium and high growth outlooks. For this report a medium projection was undertaken and this is presented in Table 4-8 below. Similarly, Actual 2014-15 results (as per Table 2-3) are included for comparison.

Table 4-8 System-Wide Energy Projections GWh

Darwin-Katherine Alice Springs Tennant Creek

2014-15 1 623.00 (Actual) 221.20 (Actual) 29.20 (Actual)

2015-16 1572.48 214.98 30.88

2016-17 1584.67 212.66 31.00

2017-18 1601.77 210.37 31.11

2018-19 1618.34 208.11 31.22

2019-20 1634.47 205.88 31.33

2020-21 1650.06 203.66 31.43

2021-22 1665.33 201.48 31.54

2022-23 1680.21 199.31 31.65

2023-24 1694.69 197.18 31.75

2024-25 1708.76 195.06 31.86

The projected growth rates in energy for the three power systems are:

Darwin-Katherine: 0.93% p.a

Alice Springs: -1.07% p.a

Tennant Creek: 0.35%. p.a

Darwin-Katherine and Tennant Creek are projected to have small increases in energy demand, while Alice Springs is projected to have its energy demand decline slowly (1% per year). To better understand the reason for Alice Spring being different than the other power systems, the historical energy demands for Alice Springs are shown in Figure 4.5 below. A significant driver of this decline has been the uptake of solar panels. The Commission’s modelling examines the effect of solar panels on MD for both the summer and winter peaks.

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Figure 4-8: Alice Springs: Energy, Maximum Demand and Modelled Solar Panel

The figure shows that in Alice Springs, both MD and energy usage have broadly declined over the past five years. The inclusion of modelled PV demand suggests energy usage in Alice Springs may not be declining, just is being met through PV generation. As PV demand is modelled rather than observed, it is likely that some of the timing of uptake may be slightly out of step with actual usage. The slow increase in MD plus solar PV for Alice Springs is more in line with modelling and observations for other systems.

4.6 Zone Substation MD Projections

This section presents the ZSS MD projections for the three power systems. The projections were developed based on a 50% probability of being exceeded over summer and expected spot loads (as assessed by PWC). The projections are presented in the sub-sections that follow.

4.6.1 Darwin-Katherine ZSS Projections

The P50 ZSS projections11 for Darwin-Katherine are shown in Figure 4.6 and 4.7 below with the respective figures presenting large ZSS (greater than 20 MW) and small ZSS (less than 20 MW). P10 MD projections have a similar profile but are on average about 5% higher. These and the tabular values are presented in Appendix C.

The analysis suggests that individual day maximum temperatures are not significant predictors of variation in MD. The ‘best’ predictor is an average of the five days leading to the day of MD. With the exception of high growth mining and industrial areas, most ZSSs were projected to have limited growth over the projection period.

11 The projections are based on a linear log functional form with explicit modelling of the impact of temperature.

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Figure 4-9 Darwin-Katherine Large ZSS - P50 MD Projections (MVA)

Figure 4-10 Darwin-Katherine Small ZSS - P50 MD Projections (MVA)

4.6.2 Alice Springs and Tennant Creek ZSS Projections

The P50 ZSS projections for Alice Springs and Tennant Creek power systems are shown in Figure 4.8 below. The profile of the Alice Springs ZSSs is dominated by the decline in demand at Sadadeen. Both Lovegrove and Tennant Creek show little variation over time. For these systems, no combination of temperature inputs was a significant explanator of the observed variation.

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Figure 4-11 Alice Springs and Tennant Creek - ZSS P50 MD Projections (MVA)

4.7 Load Factor Trend and Reconciliation of ZSS MD with System Wide MD Projections

The relationship between energy expressed as average demand and MD is often presented as load factor, where load factor over a defined period is the ratio of average demand divided by MD. When this ratio is low it means that the power system is required to supply a high MD in comparison to the average demand. This is sometimes called a ‘poor’ load factor. When power systems have appliances such as air-conditioners increasingly installed that directly contribute to MD, but to a lesser extent average demand, load factor is observed to decrease.

The 2012-13 Review undertook a review of historical load factors for the three power systems with MD used on an actual recorded and weather-corrected basis12.

This section presents a review of load factor for the three power systems.

Figure 4.9 shows the historical load factors and projected load factors based on a P50 MD. As previously explained, historical outcomes are presented uncorrected as a significant element of the variation in demand is not related to temperature on the day.

12 Using the approach adopted by PWC. The intention was that by weather-correcting MD to what occurred in an average weather year, the underlying trend in any changes in load factor can be observed.

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Figure 4-12 Historical Load Factors – Actual MD

Darwin-Katherine

Load factor recovered following the sharp

decline in load factor in 2010-11, however a

further decline was reported in 2014-15.

Looking forward the load factor is expected to

continue to have a slow decline (the difference

in energy and MD growth rates are relatively

small).

Alice Springs

It is suspected that MD over the period 2011 to

2014 has been higher than would be expected

and that the projection is consistent with load

factors pre-2012.

The decline in load factor reflects the

increasing level of solar generation which is

having a decreasing impact on MD.

Tennant Creek

Actual load factor continues to be stable at

about 50% for the past six years.

Looking forward the load factor is expected to

decline as increasing solar is installed. This

system has the largest difference in energy and

MD growth rates with substantially higher

growth MD.

The historical analysis shows that load factor does appear to be lower than in the period 2007 to 2009 but has stabilised over the past five years with no indication of it declining.

Looking forward, reflecting the projections for MD and energy use, load factors for all systems are projected to decline over the next 10 years. The reason for this is increasing air-conditioning and increasing solar, which has a decreasing impact on MD.

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5. Generation Reliability

In recent years the annual Power System Review has presented and developed concepts of generation reliability that are both consistent with usage in the NEM and that are suitable to the Northern Territory power systems. In particular:

the 2012-13 Review introduced indices that express generating reliability, presented the standards of generating reliability used in the NEM, and indicated the economic optimum level of generation reliability for each of the Territory power systems;

the 2013-14 Review distinguished two types of generation reliability measures applicable to the Territory power systems:

o ‘generation capacity reliability’13 – representing the technical capability of the generation system to satisfy demand. Load shedding associated with generation capacity shortages can be lengthy and severe.

o ‘generation response reliability’ – being the level of generation reliability based on generator dynamic response and generator operating regime, in particular, spinning reserve regimes used in the Territory power systems (which for economic reasons is less the largest generator unit operating).

This chapter builds on the material presented in the 2012-13 and 2013-14 Reviews by:

reviewing the reliability standards for each of the Territory power systems;

reviewing the generating reliability performance over the 2014-15 year; and

reviewing the generation reserve margin standards and comparing to those reported in the 2013-14 Review.

5.1 Generator Reliability Standard

The previous reviews developed and presented the indices and standard of generation reliability for use in the Territory power systems. This is a loss of load probability (LOLP) of no more than one day in 10 years (or 0.027%)14 or an expected unserved energy (EUE) of 0.002% (being the standard used in the NEM and the WA WEM). Modelling showed that this reliability standard is consistent with the economic balance associated with the cost of generation capacity in the Territory power systems and a VCR of $30 000/MWh15. This was consequently the reliability standard for “generation capacity reliability”.

13 This is related to generation adequacy, which is usually associated with security.14 Historically, LOLP of 0.1 day/year was used as reliability criteria across Australia before formation of the

NEM based on reliability criteria of having sufficient generation that shedding occurred no more than one day in every ten years.

15 This is less than that used in the NEM of $41,000 per MWh in 2013. This is distinguished from the Market Price Cap in the NEM which is $13,800 for the year 2015-16.

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The 2013-14 Review introduced ‘generation response reliability’ but did not ascribe a standard to this. The 2013-14 Review indicated that the cost of reducing under frequency load shedding (UFLS) by increasing the level of spinning reserve (based on the understood cost of providing generation spinning reserve) was close to the VCR. This indicates that a suitable reliability standard for ‘generation response reliability’ is to have no more than 0.002% unserved energy (due to UFLS associated with generation response).

The Commission observed that this would not be expected to align with an LOLP of 0.1 day/per year due to the very short nature of the shedding events associated with generation response reliability. Consequently this review uses a standard of 0.002% unserved energy for generation response reliability (noting that future work will review this).

5.2 Review of 2014-15 Generating Reliability

This section reviews the reliability of generation supply, expressed as generation capacity reliability and generation response reliability over the 2014-15 year16. Power system incident reports identify the cause and date of events, generation and otherwise, that resulted in load shedding. As per the two generation reliability indices each reported a load shedding event that has been classified as associated with either:

generation response reliability - UFLS when there was sufficient generation available but not operating (load shedding events are typically less than 20 minutes duration); or

generation capacity reliability - UFLS that were severe and widespread when there was insufficient generation capacity to bring into service.

5.2.1 Generation Response Reliability

Table 5.1 presents for each of the three Territory power systems a summary of the UFLS corresponding to generation response reliability. The table shows the number of generator outage events that resulted in load shedding, the average amount of load shed, the average time to restore demand per incident, and from this, the total amount of load shedding that occurred reported as MWh and as a percentage of annual demand (providing EUE).

The table shows that the Darwin-Katherine system was at the reliability standard and the other power systems performed better than the standard. As observed the number of UFLS events was significantly higher than the LOLP standard of 0.1 day/year.

Table 5-9: UFLS Statistics Associated with Generation Response Reliability for 2014-15

Power System

Number of load

Shedding Event

Estimated Average Load

Shed per EventMW

Estimated Average Event

DurationMinutes

Estimated Load Shed

MWhEstimated %

EUE

Darwin-Katherine 6 9.01 15.7 29.2 0.002%

AliceSprings

4 7.63 13 6.72 0.0003%

Tennant Creek 3 .93 34 1.68 0.0008%

16 The 2013-14 Review discussed the reliability reporting undertaken by AEMO.

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5.2.2 Generation Capacity Reliability

The Darwin-Katherine power system had two UFLS events associated with generation capacity reliability. The other Territory power systems did not record any such events. The load shedding event on 3rd December 2014 was initiated by a transmission line trip that resulted in system separation and a significant level of generation loss. As shown, the severity of the event, which had load shedding at near the annual average load level for over 10 hours resulted in the % USE far exceeding the 0.002% standard. The nature of this event, which was transmission related, has been excluded this from generation reliability.

The load shedding event on 3 December 2014 was initiated by a transmission line trip that resulted insystem separation and a significant level of generation loss. As shown, the severity of the event, which had load shedding at near the annual average load level for over 10 hours resulted in the % USE far exceeding the 0.002% standard. The nature of this event, which was transmission related, has been excluded this from generation reliability. presents the details of these two events for the Darwin-Katherine power system. Shown are the date, details of the load shedding, the reasons for the event, and the % unserved energy for each event.

The load shedding event on 11 September 2014 was initiated by a gas shortage. Fuel supply is part of a generator’s technical profile and as such events are included in generation reliability reporting. As shown, this results in a level of load shedding at over four times the 0.002% standard.

The load shedding event on 3 December 2014 was initiated by a transmission line trip that resulted in system separation and a significant level of generation loss. As shown, the severity of the event, which had load shedding at near the annual average load level for over 10 hours resulted in the % USE far exceeding the 0.002% standard. The nature of this event, which was transmission related, has been excluded this from generation reliability.

Table 5-10: UFLS Statistics Associated with Generation Capacity Reliability for 2014-15

Date Estimated Load Shed

MWDurationMinutes

Load ShedMWh

Description % USE

11 Sep 2014 20 409 136.3 Gas shortage - Rotational Load Shedding; Insufficient Online Capacity - UFLS Backup Stage (2 Related Events)

0.009%

3 Dec 2014 130 644 1395.3 132kV Line Trip - Pine Creek/Katherine Separation (Pine Creek/Katherine Black) andChannel Island Power Station C2, C4, C7 Trip - Darwin UFLS Stage 3B (25 Min After Separation)

.090%

It was observed that the two events shown in Table 5-10 were not related to generator breakdowns as defined through generator forced outage rates, and on the basis of what constitutes sufficient generation capacity. This is similar to the type of events recorded in previous years. The observation is made that a limitation of the projections of reliability is that it may not account for these types of events and that these issues should be considered in future development of a formal reliability standard.

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5.2.3 Summary and Trend in Reliability Performance

A summary of the generation reliability outcomes for the 2014-15 year is shown in Table 5-11. Also shown is the reliability achieved in 2013-14 which is presented as generation response reliability17. The Commission observed that all the Territory power system show improved reliability performance. Generation capacity reliability is not presented for the 2013-14 year, noting that Darwin-Katherine and Tennant Creek each had a system black event18.

Table 5-11 Generator Reliability Outcomes for 2014-15

2014-15 2013-14

Power System Generator Response Reliability

Generator Capacity Reliability

Generator Response Reliability

Darwin-Katherine .002% .009% .004%

Alice Springs .0003% .000% .006%

Tennant Creek .0008% .000% .003%

5.3 Generator Capacity Reliability – Minimum Reserve Margin

Generator reserve margins are associated with having sufficient installed generator capacity to meet load peaks. The 2011-12 Review introduced this concept of MRL assessment and reporting in the Territory power systems, and the previous 2013-14 Review presented the assessed MRLs for each of the Territory power systems.

The MRLs reflect (for each the Territory power systems) the amount of installed generation capacity required to satisfy the reliability standard assuming all generation is made available for use. MRLs relate to generation capacity reliability.

Modelling indicated that the MRLs are unchanged from those presented in the 2013-14 Review, and these are shown in Table 5.4.

Table 5-12: Assessed Territory Power System MRLs

Power System MRL1

Darwin-Katherine 30 MW

Alice Springs 13 MW

Tennant Creek 2 MW

1 This is the level of installed generation capacity above the P10 MD level.

17 The 2013-14 Review presented reliability as a single index. However the UFLS events that comprised the reliability shown have been classified as generation response. There were two system black events in 2013-14 which are excluded.

18 The System Black events occurring in Darwin-Katherine and Tennant Creek in 2013-14 skew the generator capacity reliability results in 2013-14 substantially and would provide a less meaningful comparison.

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The Commission notes that after many years AEMO stopped determining and reporting the minimum reserve level (MRL) in July 2010 for generation reliability to be satisfied in each region19. This reflects the complex and dynamic nature of the regional NEM structure.

The Commission is of the view that in the interim, while a formal reliability standard is being developed, along with other developments in the Territory electricity market for wholesale energy, MRLs remain a useful metric on which to monitor future generation capacity reliability associated with having sufficient generator capacity to satisfy load peaks.

19 The MRL in the NEM was determined as the amount of installed capacity (needed in each NEM jurisdiction) relative to a one in 10 years’ MD level (P10) that would provide for the reliability standard of 0.002% unserved energy to be met.

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6. Generation Adequacy and Reliability Outlook

This chapter presents an assessment of generation adequacy for each of the Territory power systems over the next 10 years. This is undertaken using two approaches:

N-X - this has been the traditional approach in past power system reviews; and

meeting the reliability standard. This is presented in terms of modelling results and use of the developed MRLs.

The two approaches yield similar results.

6.1 Generator Adequacy N-X Outlook

PWC’s Capacity Investment Planning Strategy20 (Draft 30 November 2013) outlines the method PWC used to make an assessment of capacity adequacy. The following criteria were applied by PWC in planning generation adequacy in each region:

Table 6-13: Generation Planning Criteria

Power System N-X Standard

Darwin-Katherine N-321

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 units being unavailable. The assessment is a simple calculation of MD 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 long-term load shedding.

Prolonging the N-3 criterion for Darwin-Katherine will lead to further investment in generating plant. Territory Generation advises that the reinstatement of the N-2 planning criteria is planned for 2018-19 following completion of the Channel Island life extension project. The Commission recommends that making major plant outage plans transparent will significantly improve confidence in planning for reliability.

The Commission notes that structural separation highlights that it may not be appropriate for PWC or Territory Generation to undertake planning relative to generation adequacy and that a more structured, transparent and independent approach to generation adequacy and reliability assessment will be considered by the Territory Government in development of the NTEM through arrangements for the setting of a reliability standard.

20 PWC Capacity Investment Planning Strategy, Draft 30 November 201321 Territory Generation (and previously PWC) has advised that this is a temporary measure to allow for CIPS

generation sets 1 to 6 life extension to occur without affecting adequacy due to expire by 2018-19.

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Figure 6-13: N-X Generation Reliability

Source: The Commission

This analysis differs from past years for each of the power systems. It is understood, Territory Generation is not currently planning additional generation for the Darwin-Katherine power system and the Commission has removed previous PWC projections for extra units from the Darwin-Katherine analysis. Territory Generation has announced large scale upgrades for Alice Springs and Tennant Creek and these are represented for those regions.

N-3 is expected to be met until 2019-20, to coincide with the completion of the Channel Island life extension project.22 This assumes a continuation of 26MW capacity at Pine Creek either through a Power Purchase Agreement with Territory Generation or EDL operating with a stand-alone generation licence. The normal level of reliability, N-2, is still achieved through to beyond 2024-25.

The development of the second part of Owen Springs and the delayed retirement of Ron Goodin machines leads to a spike in capacity in Alice Springs in 2017-18. This is short-lived and the capacity carries on to meet the N-2 level through the 10-year Review period.

Tennant Creek remains compliant across the 10-year projection with the commissioning of two new 2MW generation sets and decommissioning of old Rustin sets by Territory Generation. It is understood that historically Territory Generation does not factor in the significantly aged diesel sets in generator response planning and considers them to be as a backup for when gas supply is not available. This is also due to the Tennant Creek diesel sets having only single fuel capability.

The Commission’s view is that the margin is adequate up to 2024-25. Alice Springs and Tennant Creek both show improved margins across the 10-year period.

22 Territory Generation expect N-3 to be met until 2019-20 but will move to N-2 after 2018-19.

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Going forward, the Commission is reconsidering use of the N-X standard to better align reporting requirements with the NEM and AEMO practices. A comparison of N-X margins is shown in Table 6.2.

Table 6-14: N-X Margins for 2014-15

Region Criterion Compliance with N-X until:

Margin 2014-15 Margin 2013-14 Margin 2012-13

MW as per cent of peak demand



Darwin-Katherine N-3 2019-20 52.48 18.0 78.7 28.0 38 9.7

N-2 > 2024-25 97.48 33.5 123.7 44.0 83 25.2

Alice Springs N-2 > 2024-25 15.3 30.3 7.7 13.8 10.8 20.3

Tennant Creek N-1 (gas) > 2024-25 1.1 15.8 -0.3 - 4.6 - 2 - 3023


6.2 Generation Reliability Outlook

This section presents for each of the Territory power systems, the outlooks for the two reliability indices, generator capacity reliability and generator response reliability.

6.2.1 Generator Capacity Reliability

Generator capacity reliability was assessed through modelling each of the Territory power systems with sufficient spinning reserves to cover the loss of any generator unit. This represents the technical capability of each power system. The results are shown in Figure 6.2 which presents for each of the power systems:

a comparison of installed generator capacity compared to the P10 MD plus the MRL (left side of the figure); and

the results of the modelling24 capacity reliability described above expressed as EUE per cent each year (right side of the figure).

The results show that:

all systems have more capacity than required by the MRL and that the projected level of EUE per cent is well below the target of 0.002%: (that corresponds to an LOLP of less than 0.1 day/per year);

all three power systems have virtually no load shedding due to generator breakdowns as defined through their respective forced outage rates:

o the results reflect the level of generation in each of the systems;

o the improvement in the Darwin-Katherine system is due to lower forced outage rates than projected in the previous review; and

o the results exclude load shedding events associated with fuel supply shortages and transmission trips/outages.

23 Diesel generation required to meet system peak at N-124 The modelling was undertaken on 5-minute time steps in order to capture load shedding due to ramping

constraints.

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Figure 6-14: Outlook for Generation Capacity Reliability

Installed Capacity, MD, MD + MRL Projected EUE%

Darwin-Katherine

Alice Springs

Tennant Creek


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6.2.2 Generator Response Reliability – Darwin-Katherine

The outlook of generator response reliability is restricted to the Darwin-Katherine system.

The assessment of generator response reliability is more complex than capacity reliability as assumptions are required in relation to how generators are operated and spinning reserve maintained, and the frequency response and level of load shedding that would occur on the loss of a generator unit.

As the reliability achieved is a principally determined by the level of spinning reserve maintained and the dynamics of operating generators, and not the amount of installed capacity, this is not presented on an annual basis over the next 10 years.

The modelling indicated that the level of generator response reliability for the Darwin-Katherine system is projected to be 0.0015%. This is under the 0.002% standard presented in Chapter 5. The results of the modelling reflect the following:

spinning reserve minimum of 25 MW for most of the time;

generator forced outage rates of about 2% per generator unit, corresponding to 7 days out of service due to breakdown per year. Based on an average breakdown time of 3.5 days this has units breaking down once every 6 months of operation; and

stage 1 load shedding occurring 65% of the time on the unexpected loss of the CIPS generation units 8 or 9 or one of the Weddell generator units.

It is noted that the modelling is considered approximate as generator unit response dynamics were not modelled.

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7. Generation Performance

7.1 Spinning Reserve

In previous reviews, the Commission commented on the level of spinning reserve provided for the Darwin-Katherine network and noted that PWC’s review of spinning reserve was yet to be completed. The Commission understands that the spinning reserve review has ended and a revised spinning reserve and load shedding policy is in place.

However, the original terms of reference of the spinning reserve review were not completed successfully as the value of lost load and the VCR were not determined and used as inputs to a systematic determination of the required spinning reserve levels.

In the 2012-13 and 2013-14 Reviews, the Commission made the following recommendation:

PWC complete the review conducted by SKM and ensure the following information is available for next year’s Review.

VCR 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 or 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.

The actual spinning reserve achieved during the 2013-14 year was 25 MW or more for 98.5% of the time (a 2.2% increase over the previous period). Like the previous year, this level of spinning reserve was highly reliant on the CIPS generation units 8 and 9, however the performance of these units has been significantly improved and therefore the improvement of real spinning reserve available is likely to be quite significant. The following charts show the proportion of time each level of spinning reserve was available, both with and without generation units 8 and 9, for the previous review period and the current review period.

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Figure 7.1: Cumulative Time Spinning Reserve Exceeded


The differences between the curves for the two review periods demonstrates increased reliance on Channel Island unit 9, which is likely due to increased confidence in its dynamic performance and unit 8 being out of service for four months in 2014-15. The recommendation made by the Commission last year that Territory Generation consider operating the CIPS generation units 8 and 9 at an output just below rating is no longer valid. However, it should be remembered that the Weddell units and Channel Island units 8 and 9 have low inertia so they should not completely displace the older heavier machines.

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This analysis demonstrates clearly that Territory Generation is consistently meeting System Control’s spinning reserve policy of maintaining 25 MW reserve. However, the scope of the analysis does not consider the appropriateness of the spinning reserve policy. The Commission notes that there are times when the maximum generation that would be lost for a single machine trip, exceeds 25 MW, and recommends inclusion of the determination of the value of lost load and the VCR for a systematic determination of the spinning reserve requirements. It is likely that these gaps will be addressed as part of the Territory Government’s development of the NTEM through arrangements for the setting of a reliability standard.

7.1.1 Incident Report Review

In 2012, the Commission approved amendments to the System Control Technical Code to include incident reporting provisions in the Code. The objectives of introducing incident reporting was to formalise investigation and reporting on major power system incidents, to inform the implementation of preventative measures and the response to adverse events.

Four major documents have been provided for this review covering six incidents on the Darwin-Katherine system, two events on the Alice Springs system and one event on the Tennant Creek system within the review period. The four documents are titled:

Reportable Generation Incidents – Darwin-Katherine 1 January 2014 – 31 August 2014

Darwin-Katherine Power System – UFLS Trip Events

Alice Springs Power System – UFLS Trip Events

Tennant Creek Power System – UFLS Trip Events

Three additional events documented in the report ‘Darwin-Katherine and Alice Springs – Network Events’ deserve analysis from a generator performance perspective. These events occurred on 20 November 2014, 30 November 2014 and 1 December 2014, respectively.

There are a number of outstanding final major incident reports due to be provided by PWC System Control to the Commission in accordance with the System Control Technical Code. For the 2014-15 Review period, major incident reports were required for 15 reportable generation incidents.

Of the 15 reportable incidents listed in Appendix E, Territory Generation engaged consultants to undertake an investigation and prepare the final report in relation to nine reportable incidents that involved load shedding as a result of a generation trip.

The detailed findings and recommendations of these reports are not duplicated in this Review. Instead a few important conclusions are included.

During the 2013-14 Review, the Commission become concerned at the large proportion of reportable events that could be characterised as double contingency events. By contrast there were no multiple contingency reportable events caused by generator failures during the 2014-15 year. The one multiple contingency event occurred on 11 September 2014 and involved rotational load shedding due to a gas shortage. This likely demonstrates very effective targeting of generator maintenance and improvement initiatives in the review period. It is noted that since July 2015 there have been two multiple contingency events on the Darwin-Katherine system (outside of the current review period) so while the result is very encouraging, focus needs to continue to remain on eliminating the potential for multiple contingency events.

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Examining the reportable events within the current review period and events back to January 2014, a number of observations can be made:

Channel Island units 8 and 9 have been adjusted during the period and now provide significantly more effective spinning reserve than during early 2014. The Commission understands that this is primarily due to adjustment of a ramp limiter within these units.

The Channel Island units 8 and 9 suffer a 2 second oscillation that can be excited by a power system event. Furthermore on one occasion this oscillation was excited by no apparent event, lasted more than two hours and resolved suddenly without explanation (4 March 2015). It was observed that CIPS unit 8 and 9 were constantly going into loop control modes 10 and 11, which are the MW rate of change limiters positive and negative.

This second observation suggests that the governor settings on units 8 and 9 may be fundamentally unstable. Widening these limiters (as has been done) could exacerbate such instability. The Commission recommends:

tuning of units 8 and 9 governors be checked; and

governor mode changes be monitored (if feasible) and added to the analysis of all future events to determine if switching between modes such as governing, maximum acceleration or deceleration control and exhaust temperature control may contribute adversely to the power system performance.

In the 2013-14 Review, the Commission noted a recurring theme in the report of generators in the Darwin-Katherine region not able to increase their output by an amount close to their assumed ‘reserve’ with sufficient speed to avoid load shedding. This meant (for example) if the system is carrying 25 MW of spinning reserve then tripping of a machine generating less than 25 MW could result in a need to shed load. This effect was particularly pronounced for the newer CIPS generation units 8 and 9, which did not provide as much output as expected either in the immediate (transient) period or the sustained period. In this review the Commission notes that the load uptake performance of the CIPS units 8 and 9 has been significantly improved.

Territory Generation has made significant progress against the recommendations that were made in this section of the 2013-14 Review. Further work is needed in the areas of:

correcting the performance of the power system models of the generators so that system performance can be predicted with confidence;

confirming the optimum tuning of the generator governors and voltage regulators. Determine if there is some benefit to be gained by implementing power system stabilisers on the newer generation units; and

finalising the spinning reserve review, documenting and implementing its findings.

7.2 Availability of Existing Generators

7.2.1 Asset Management Plan Review

The Commission reviewed the following relevant documents as part of the 2012-13 Review:

1. Generation – Asset Management Strategy – 6 June 2013 – Draft

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2. PWC Generation North – Asset Management Plan High Voltage Generators – Draft

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

The Commission has not received new copies of these or similar documents for the 2013-14 or the 2014-15 Review and understands that no significant further development of these documents has occurred. However, the Commission has been assured that Territory Generation has established its own standalone IT systems for asset management and revised documents will be available shortly. The Commission considers that this should be a priority for Territory Generation given that it has been two years since structural separation from PWC. The Commission also notes that the asset management strategy would be an input in the reliability of generator reliability projections. The Commission will seek evidence of demonstrable progress during the 2015-16 year.

The following sections refer to Territory Generation as the corporation is now responsible for generation in the relevant power systems.

7.2.2 Availability Outlook

Territory Generation operates the Darwin-Katherine network on an N-3 capacity-planning basis. rom the previous 2012-13 Review, the Commission understands N-3 is intended to represent the following scenario:

N generation units in service to service the load;

one machine in service to provide spinning reserve;

one machine out of service for routine maintenance; and

one machine unavailable for service (long term) due to major maintenance activity such as the CIPS 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.

Territory Generation has provided predictions of machine availability. Territory Generation has based its projections on known major machine works and past reliability observations. This is a significant methodology improvement over previous years. Territory Generation categorise their outages as planned, maintenance or forced outages. Maintenance outages are outages that can be deferred for 48 hours or more from the time of fault inception, but are too urgent to be delayed until the next planned outage.

From the data provided for 2016-17, on average 1.0525 machines will be out of service at Channel Island or Weddell power station for planned outages. Given that there is some ability to schedule maintenance outages it is reasonable to assume that only one machine will be out of service for a maintenance outage at any one time. On this basis, there will be a machine out of service at Channel Island or Weddell power stations for maintenance 36.3% of the time. For 2016-17, the data suggests one or more machines are likely to be on a forced outage 16.8% of the time.

25 Based on the availability data provided by Territory Generation there will likely be one machine out of service at all times. There may be short periods where two machines are out of service.

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Table 7-15: Probability of CIPS and Weddell generation units being available for service

Year

One machine out for planned

outage

One machine out for

maintenance outage

One or more machines out

for forced outage

One machine out for maintenance or one for forced

outage

One machine out for maintenance

and one for forced outage

2016-17

105%26 36.3% 16.8% 47.0% 6.1%

2017-18

51.8% 37.5% 17.3% 48.3% 6.5%

2018-19

41.2% 38.1% 17.5% 49.0% 6.7%

2019-20

35.7% 38.8% 17.8% 49.7% 6.9%

The last column of the table shows the probability of three machines being out of service at the same time.

The improved availability estimation method used by Territory Generation has resulted in much more credible (and much higher) availability estimates than for previous years.

Table 7-16: CIPS generation units actual vs. predicted availability

Machine

2012-13Actual

Availability

2013-14Actual

Availability

2014-15Actual

availability

2015-16Predicted

availability

Unit 1 GE Frame 6 combustion turbine (gas or diesel) 31.6 MW capacity

98.1% 97.3% 96.73% 95.12%


0.0% 67.4% 97.25% 85.15%


95.6% 100% 96.17% 95.14%


99.4% 77.3% 92.43% 89.89%


85.4% 59.7% 93.00% 73.42%

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

98.8% 72.5% 75.94% 73.08%

Unit 7 GE LM6000 combustion turbine (gas or diesel) 36 MW capacity

85.1% 95.2% 96.28% 87.38%

Unit 8 Rolls Royce Trent 60 combustion turbine (gas or diesel) 42 MW capacity

87.1% 95.5% 75.10% 83.73%

26 Based on the availability data provided by Territory Generation there will likely be one machine out of service at all times. There may be short periods where two machines are out of service.

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Unit 9 Rolls Royce Trent 60 combustion turbine (gas or diesel) 42 MW capacity

66.5% 92.5% 96.26% 89.69%

Source: Territory Generation

The historic availability values for Territory Generation’s generation units 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 Territory Generation’s generation units failing to follow one of these patterns is that the mean time between failures of the generation units is following the expected pattern and 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 generation units, the season, network load, availability of repair staff, or available funding.

The Commission recommends that Territory Generation 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%) and this assumption is not applicable to Territory Generation’s generation units.

7.3 Standards of Service Indicators

The following data is based on the Territory Generation’s Standards of Service Report 2014-15 and previous reports for historical context. The 2012 ESS Code does not set targets for generation SAIFI and SAIDI performance, and historical performance is used as a basis of comparison, with the historical agreed minimum standards (AMS) in the previous ESS Code used to provide context. Figures 7.2 and 7.3 show the SAIDI and SAIFI results for the past seven years compared to the AMS.

The Commission observed in the 2012-13 Review, that the SAIDI measure for each of the regions was returning to trend. This is again true with levels returning within the agreed standard for the 2014-15 year after the levels were distorted by the system blacks of 2013-14.

All regions show an increased SAIFI with significantly low SAIDI. It is the first time since these measures were first reported on in 2005-06 that the generation SAID and SAIFI measures have all been within the agreed service standard.

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Figure 7.2: 4 Region SAIDIs

Figure 7.3: 4 Region SAIFIs

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Figure 7.4: SAIFI vs SAIDI

Source: Territory Generation Standards of Service Report 2014-15

7.4 New or Proposed Generators

The PWC document, Capacity Investment Planning Strategy – Draft, approved 18 November 2013, was reviewed by the Commission as part of the 2012-13 Review. No additional written information was provided for the 2013-14 or 2014-15 Reviews.

In February 2016, the Northern Territory Government announced significant capital investment to the Alice Springs and Tennant Creek power systems to be commissioned in December 2017, with significant upgrades and new generation units in Owen Springs Power Station in Alice Springs to replace the Ron Goodin power station, and significant augmentation and enhancement to Tennant Creek power station. The capacity profiles shown in section 6.1 have been updated based on discussions with Territory Generation and include the revised asset plans for Alice Springs and Tennant Creek.

7.5 Progress against Key Findings from the 2013-14 Power System Review

The following findings come from the 2011-12 Review and still need to be addressed by PWC and Territory Generation.

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.

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At the time of the 2012-13 Review there had been little demonstrable progress on this item but progress was considered imminent as part of the spinning reserve review being completed by PWC. The expected generator modelling outcomes from the spinning reserve review have not yet eventuated.

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 change to the policy in Darwin-Katherine appears to lead to more consistent management of under-frequency events. The Commission requires further progress in the other power systems on this aspect of system management.

From the 2012-13 Review:

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 seen evidence to suggest that there has been a material improvement in this area. The reliability of the newer units has been improved and their response to frequency excursions has also been improved. The rate of double contingency events has fallen significantly in the 2014-15 period.

From the 2013-14 Review:

At the time of publishing the 2013-14 Review, a major investigation into the management of under-frequency events in Darwin-Katherine was underway and the Commission highlighted a number of expected outcomes from that investigation. The Commission is pleased to acknowledge significant progress on many of these including:

Addressing the governor performance of Channel Island units 8 and 9 with respect to the amount and consistency of governor response to under-frequency;

Progress on increasing governor responsiveness and removing unnecessary caps on governor performance;

The Commission observes that some items regarding excitation and governor modelling remain outstanding, in particular, confirmation of machine inertia and excitation system models. This data is critical when considering the need for power system stabilisers and the Commission considers that this should be an area of focus.

It remains the Commission’s view that considerable work is required by System Control to improve the timing of the reporting of major incidents. The Commission is aware that System Control is engaging additional resources to address this issue of compliance.

7.6 Key Findings – Generation Operation and Planning

While some progress has been made on the recommendations from previous reviews, the Commission remains concerned that there are significant issues left unaddressed or unresolved.

The Commission remains concerned that there are a large number of incident reports and other reports with important or significant recommendations that do not appear to be considered or acted on in a managed or deliberate way. The Commission further observes that if these recommendations are, in fact, being addressed, it is not clear how or in what timeframe in many instances.

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The 2014-15 set of system incidents represents a marked decrease in the frequency of multiple generator contingency events. This is a positive outcome and is reflected in the SAIDI and SAIFI indicators both being below 50% of the agreed performance standard for all regions.

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8. Fuel Supply

8.1 Introduction

The scope of this chapter is to:

review the adequacy of fuel resources and fuel transport for electricity generation for the medium and long term, including discussion of any significant risk to continuity of supply;

provide advice on the security of supply arrangements;

advise on the 11 September 2014 supply interruption; and

review potential developments in the area of fuel resources.

The methodology of the 2014-15 Review in this area is broadly consistent with the 2013-14 Review and where circumstances have not changed and details remain relevant, they have been re-stated in this report.

8.2 Adequacy of Northern Territory Gas Supply

8.2.1 Territory Generation’s Gas Requirement

PWC’s Gas Supply Unit continues to contract for long-term gas supply from ENI’s offshore Blacktip gas field in the Bonaparte Basin. Territory Generation purchases gas from PWC through commercially negotiated agreements27.

Territory Generation’s gas consumption for 2014-15 was 22.15 PJ. Approximately 85% of all gas consumed in the three main Territory power systems was in the Darwin-Katherine system. PWC’s gas sales to other parties and other generation requirements resulted in a total Northern Territory 2014-15 gas usage of 22.6 PJ (annual daily average of 61.9 TJ/d), representing an increase of 7.6% compared to 2013-14. PWC and Territory Generation have entered into a short-term two-year supply agreement post structural separation and are currently in negotiations to finalise a long-term gas supply agreement.

Territory Generation’s gas requirements are forecast to have flat to slightly negative growth in gas demand during the next five years, with increased efficiency from modern generation facilities and increased solar generation offsetting small increases in power demand. Increased competition from third-party generation may also reduce Territory Generation’s gas requirement over the medium to long term. The Commission considers that it is in the interest of power system security for Territory Generation to secure a long-term gas supply contract.

8.2.2 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. Refer to Figure 8-15 for the location of ENI’s Blacktip field and the Wadeye onshore processing plant. PWC and ENI have entered into a 25-year gas supply arrangement, which commenced in 2009 for the supply of up to 740 PJ of gas, with an initial annual quantity of 22.5 PJ/a

27 Hansard, Government Owned Corporations Scrutiny Committee Thursday 4 June 2015

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and increasing to 37 PJ/a in the last contract year28. The maximum gas processing capacity of the Wadeye plant is approximately 110 to 120 TJ/d29. PWC’s annual contract quantity from Blacktip for 2014-15 was substantially in excess of its actual gas requirements.

The annual contract quantities from Blacktip increase over time to allow for market growth in the Territory. These increases in annual quantities are considered in excess of PWC’s forecast growth gas demand in the Northern Territory market. The commencement of the Northern Gas Pipeline from late 2018 (referred to as the NEGI pipeline) will eliminate PWC’s current long supply position from Blacktip.

PWC’s maximum daily gas demand of approximately 78 TJ/d in 2014-15 is also substantially less than its contracted maximum daily supply capacity from Blacktip which is approximately 110 TJ/d. PWC did not utilise up to 40 per cent of its annual Blacktip supply entitlement in 2014-15, however on a peak day basis its spare capacity is estimated at only 25 per cent. PWC’s daily peak demand is expected to grow faster than its annual demand and should be monitored each year to ensure peak demand is adequately covered. Supply of additional gas to the eastern states via the NEGI Pipeline will also reduce PWC’s spare MDQ supply capability from Blacktip. However, the impact is expected to be softened by the commencement of supply from the Dingo gas field south of Alice Springs in April 2015.

A review of the impacts of PWC’s supply commitments to eastern Australia on security of the Territory’s gas supply (ACQ and MDQ basis), should be undertaken upon commencement of the NEGI pipeline in 4Q 2018.

8.2.3 Gas Transportation Capacity

The transportation capacity of the Bonaparte Pipeline and the Ban Ban Springs to Darwin section of the Amadeus pipeline is approximately 107 TJ/d30. Figure 8-15 is a map of the Northern Territory gas transportation pipeline infrastructure. PWC has entered into long-term transportation agreements with the owners of the Bonaparte and Amadeus gas pipelines sufficient to transport Blacktip gas to its various power station delivery points in the Territory.

28 Eni press release, ’Eni starts development of Blacktip gas field offshore Australia‘, 30 June 200629 Eni press release, ’Eni starts development of Blacktip gas field offshore Australia‘, 30 June 200630 PWC transportation assessment, Figure 1

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Figure 8-15 Northern Territory Gas Infrastructure

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8.3 Security of Gas Supply

8.3.1 Introduction

Gas supply to the Territory is assessed to have N+1 redundancy for a short to medium period of time. Both Blacktip and Darwin LNG can supply 100% of the Territory’s gas requirement, should either one of these sources of gas supply be interrupted. It is important to note that there are some limitations to the Darwin LNG back-up arrangement that affects its ability to cover 100% of the Territory’s gas demand (in the event of a complete Blacktip failure), namely:

supply is restricted to a maximum amount of 2.5 PJ/a in any calendar year; and

during periods of peak demand, Darwin LNG’s supply to the southern regions of Alice Springs may be restricted by insufficient Amadeus gas pipeline pressure. New supply from the Dingo gas field and potential additional supply from Mereenie/Palm Valley is likely to eliminate this risk.

As detailed in section 8.4.1, pipeline line pack, Amadeus Basin gas and diesel back-up generation provides additional energy support to the Territory. However, these measures are not capable of replacing 100% of Territory’s energy requirement in the event of a simultaneous Blacktip and Darwin LNG outage that extends over a small period, less than a day in the case of the 11 September 2014 incident.

The commencement of the INPEX back-up supply arrangement (in approximately 2017) will increase gas system security to N+2 until 2022. PWC’s Darwin LNG back-up arrangement expires in 2022 (unless a new extension agreement can be agreed by the parties). It is recommended that PWC seeks to extend its Darwin LNG back-up arrangement beyond 2022.

8.3.2 Blacktip Gas Field

8.3.2.1 Redundancy of Blacktip Infrastructure

The Blacktip gas field consists of two offshore wells with an unmanned and remotely operated well head platform. The onshore plant consists of three export compressors, simple separation and dehydration facilities and utilities such as power generation. This type of facility is similar to other upstream gas projects in eastern Australia like those in the Otway basin, which supplies gas to the Victorian domestic market.

Generally, unmanned offshore facilities will have a lower level of reliability than manned or onshore facilities. The additional time taken to fly out to an unmanned platform and assess the nature of any production issues will increase the time of a supply interruption.

The two development wells provide some level of field deliverability redundancy, given current sales to PWC are essentially from one well, although the productivity of the second well may not have the same capacity of the main producing well.

The onshore gas plant at Wadeye has three export compressors, which are required to be fully operational to produce gas at peak production rates. Where a gas plant has an extra unit on standby for each major processing element (that is compression, dehydration, liquids separation, utilities etc.), the gas plant is referred to as having full N+1 redundancy. At peak production rates (approx. 110 – 120 TJ/d), the Wadeye facility does not have full redundancy for periods of planned maintenance activity or a trip of major processing elements of the gas plant. Plant utilities such as steam and power are often a source of production issues for a plant like the Wadeye facility and an

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interruption to power was the cause of the 11 September 2014 interruption. Territory Generation’s peak day requirement for gas is approximately 78 TJ/d which is significantly below the peak capacity of the Blacktip gas plant.

At higher levels of daily gas demand, there is likely to be an increased reliance on back-up supply arrangements, as redundant plant capacity may not be available to cover minor (or major) trips to Blacktip gas production. Without full N+1 redundancy on all major elements of plant processing capacity, there is an increased risk of minor or major shortfalls during periods of plant failure coinciding with peak gas demand. Given PWC’s strong back-up arrangements, this is not an area of concern but should be noted and may involve a greater level of management of PWC’s daily gas supplies in the medium term.

8.3.2.2 Blacktip Planned and Unplanned Maintenance

Typically in gas sales agreements, there are limits on the duration of planned and unplanned maintenance interruptions of gas supply from Blacktip facilities in each contract year. Importantly, there are also restrictions on the number of days in a row for a single interruption. The duration and scale of any Blacktip supply shortfall will determine whether or not PWC is required to call upon its back-up gas arrangements. The permitted periods of planned and unplanned maintenance and maximum number of days of continuous interruption are well within PWC’s back-up capabilities from Darwin LNG.

8.3.2.3 Blacktip Reserves

Gas reserves and well deliverability are critical elements of gas supply security. Field performance should be regularly monitored over time. Blacktip’s current 1P31 reserves are sufficient to satisfy its long-term contractual obligations to PWC. Blacktip is at an early stage of its producing life, having produced for only seven years of a 25-year supply term to PWC. It is recommended that reserves, well deliverability and levels of reservoir water production be monitored at regular intervals over the life of the project.

While there are no current indications of Blacktip reserve or deliverability issues and ongoing risks are low, given 1P reserves are sufficient to satisfy ENI’s contractual obligations to PWC, a major failure of Blacktip reserves or deliverability would be classified as a catastrophic event and lead to a wide-scale gas shortage and or material cost implications for the Territory. It is recommended that PWC assess contingency plans in the event of a major failure of Blacktip reserves, especially since the large quantity of uncontracted reserves in the Amadeus Basin are likely to be supplied to customers in eastern Australia when the NEGI Pipeline is interconnected with the east Australian gas market.

8.3.3 Amadeus Basin Gas

8.3.3.1 Mereenie/Palm Valley

The development of the Blacktip field created gas-on-gas competition in the Territory for the first time. The large quantities of Blacktip gas supply and the unutilised productive capability of Amadeus Basin gas (albeit not as large as historical rates due to the partial depletion of its gas reserves) created a long supply market in the Territory. This supply length created a competitive gas market for customers and put downward price pressure for new gas supply contracts.

31 1P reserves denotes proved reserves under the Petroleum Resource Management System (PRMS), developed by the American society of petroleum engineers to classify oil and gas resources. 1P reserves have a 90% confidence level of being produced over the life of the asset.

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It is currently estimated there are over 100 PJ of conventional proven and probable tail gas reserves remaining in the Amadeus Basin, most of these in the Mereenie gas field.

The commencement of the NEGI pipeline from the 4th quarter of 2018 will open up new gas supply opportunities for Mereenie/Palm Valley gas in a scenario where the NEGI pipeline is used to supply large quantities of uncontracted Amadeus Basin gas reserves to eastern Australia and reduces the availability of additional supply and or back-up gas supply to PWC as a result.

8.3.3.2 Dingo

In September 2013, PWC entered into a new gas sales agreement to develop the Dingo gas field, located 60km south of Alice Springs. PWC’s initial supply tranche is 15.4 PJ over a ten year term from the Dingo gas field, with options to increase supply up to 31 PJ of gas over 20-year supply period if sufficient reserves are available32. Gas supply from the Dingo gas field to PWC commenced in April 2015. Dingo gas is connected into the pipeline transmission system at Brewer estate, 20km south of Alice Springs.

The development of Dingo provides an additional supply option for PWC and will also improve the efficiency of the new Owen Springs power station. Dingo gas is ’leaner‘(that is, it contains lower levels of LPGs) compared to “rich” sale gas from Mereenie. Modern gas engines run more efficiently utilising leaner sales gas compared to rich sales gas streams.

8.3.4 LNG Back-up Supply

8.3.4.1 Introduction

PWC’s back-up supply arrangements with Darwin LNG and INPEX are not considered traditional firm supply agreements as their respective LNG production would take precedence over supply to PWC. Given the scale of the LNG operations and the importance of power supply to the Territory, it is unlikely that Darwin or INPEX LNG would not supply gas to PWC when requested, unless the LNG facility is physically incapable of supplying gas such as during periods of planned or unplanned maintenance activities.

8.3.4.2 Darwin LNG

PWC has an existing back-up arrangement with Darwin LNG’s Wickham Point facility to supply up to 80 TJ/d, with a maximum annual purchase of 2.5 PJ. This arrangement will continue until 2022. Assuming a northern peak demand of 65 TJ/d (Darwin-Katherine region), the existing Darwin LNG back-up arrangement could supply the northern region for five to six weeks (or longer periods during low demand). PWC has previously utilised Darwin LNG back-up supply during periods of planned and unplanned interruption of Blacktip production, although actual rates of supply have been significantly lower than the 80 TJ/d maximum.

Other than the 11 September 2014 Darwin-Katherine system incident, PWC’s Darwin LNG back-up arrangement has been proven to be effective and is currently PWC’s main mechanism to manage supply shortfalls from Blacktip. At the time of the 11 September 2014 incident, Darwin LNG was undergoing planned maintenance and therefore not immediately available at the time when supply from Blacktip was interrupted.

The northern region of Darwin-Katherine (where the majority of generation is located) can be supplied using Darwin LNG back-up gas. Pipeline pressures in the Amadeus pipeline may not be 32 Magellan press release, 12 September 2013

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sufficient to transport Darwin LNG back-up gas south of Tennant Creek. Where there is a partial supply from Blacktip, Blacktip gas would continue to supply southern demand. Where there is a total loss of Blacktip gas, the southern region would be supplied through a combination of pipeline line pack, Darwin LNG (if pipeline pressure is suitable), Dingo gas, and diesel generation. In an extended outage, additional gas from the Amadeus Basin could be used to supply additional gas to the southern region.

8.3.4.3 INPEX LNG

PWC has executed an agreement for a second back-up supply with Inpex (developers of the second LNG plant in Darwin). This arrangement will commence upon operation of INPEX’s LNG plant in 2017 for a period of 15 years. PWC has a daily entitlement of 100 TJ/d, with a maximum quantity of 3 PJ per annum. This second PWC back-up arrangement will greatly improve security of gas supply to the Territory, not only in duration of northern back-up supply capability (by doubling the period of coverage to at least 13 weeks), but also by managing the circumstance of a simultaneous interruption of gas supply from Blacktip and Darwin LNG.

8.3.5 Gas Transportation

8.3.5.1 Pipeline Failure

Neither the Bonaparte pipeline nor the Amadeus pipeline have operating mid-line pipeline compressor stations. The Amadeus pipeline has a moth-balled compressor station at Tennant Creek. This compressor station is not required to operate to satisfy peak demand, based on the current direction of gas flow and sources of supply. The lack of an operating mid-line compressor station reduces the risk of a transmission interruption.

Pipeline rupture of the Bonaparte or Amadeus pipeline is likely to cause some level of gas interruption to electricity generation in the Territory. The location of the pipeline rupture would determine the extent of gas interruption, however this type of event is rare and even a major rupture is likely to be rectified within five to 10 weeks. Minor pipeline leaks are likely to be repaired within 24 hours. The gas transportation system does not have full redundancy in the event of a major rupture of the Amadeus gas pipeline and the location of the rupture would impact the ability of supply contingency solutions to cover a transmission failure.

8.3.5.2 Pipeline Line Pack

Spare gas stored in transmission pipelines is referred to as pipeline line pack. The amount of line pack that can be used to supplement gas demand during a shortfall of Blacktip production depends on:

the prevailing pipeline operating pressure. The quantity of spare pipeline line pack is increased at higher pipeline operating pressures; and

pipeline throughput and the amount of spare or unutilised firm transportation capacity. Gas transmission pipelines which are short, or transport gas close to their maximum design capacity have virtually no spare pipeline line pack. Gas pipelines that are long and have large quantities of unutilised capacity can have material quantities of spare line pack to supplement demand during periods of gas shortfall.

PWC provided high level estimates of available line pack that can be taken from the relevant pipelines before generation is restricted:

Bonaparte Gas pipeline – up to 35 TJ;

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Amadeus Gas Pipeline (Ban Ban Springs to Darwin section) – less than 5 TJ;

Amadeus Gas Pipeline (Ban Ban Springs to Alice Springs) – up to 115 TJ;

Wickham Point pipeline (Darwin LNG to Channel Island) – up to 1 TJ; and

Palm Valley to Alice Springs pipeline – less than 4 TJ.

It is important to note however, the above estimate of spare pipeline line pack will significantly change with commencement of NEGI pipeline.

The current quantity of spare pipeline line pack in the southern part of the Amadeus pipeline from Ban Ban Springs to Alice Springs is dependent on the direction of flow in the Amadeus gas pipeline. Currently, the Amadeus gas pipeline is flowing at small rates from Alice Springs to Ban Ban Springs (that is, a small northerly gas flow) which provides a material quantity of spare line pack that could be utilised in the southern regions. In the circumstance of a substantial increase in northern gas flow from the Amadeus Basin to Jemena’s northern gas pipeline the level of spare line pack in this section of the Amadeus pipeline will be reduced substantially.

The northern region has limited spare line pack especially in the section of the Amadeus pipeline from Ban Ban Springs to Darwin because of its short distance and high flow rates. The Bonaparte gas pipeline represents the largest source of spare line pack for the northern region, however at peak demand rates the northern region’s spare line pack would maintain Darwin-Katherine generation for less than one day if gas production ceased from Blacktip. The southern regions have access to a greater level of line pack (from the Ban Ban Springs to Alice Springs section of the Amadeus pipeline) and generation could be sustained for up to several days, depending on the prevailing flow of gas and pipeline pressure. Spare pipeline line pack is considered a small and short-term supplement to the main gas contingency strategy of using back-up supply from Darwin LNG or Inpex LNG.

8.3.6 Diesel Back-up

PWC has a number of facilities that are capable of using diesel as a last resort if no sources of back-up gas or spare line pack are available. Katherine, Tennant Creek, Ron Goodwin and Owen Springs power stations have duel fuel (that is, gas and diesel) generation capabilities. Channel Island has gas generators that can be converted to diesel in 24-48 hours, if required.

PWC has substantial diesel storage capacity at all its dual-fired facilities, although the new diesel tanks at Owen Springs power station have a smaller diesel storage capacity than the tanks at the old Ron Goodwin power station. Ron Goodwin power station is being phased out by the new Owen Springs power station.

The operational inventory of diesel storage varies, depending on the location and availability of back-up gas supply. Territory Generation has advised the operational target for diesel back-up at Channel Island power station is approximately seven hours of supply, although this is subject to adjustment at any time by Territory Generation. Tennant Creek and Alice Springs systems have higher levels of diesel inventory compared to the Darwin-Katherine system due to the easy availability of Darwin LNG back-up gas in the northern region.

8.3.7 Contingency Analysis – Failure of Blacktip or Gas Transportation

An analysis of the contingency arrangements for a major and minor failure of Blacktip supply and gas transportation capacity is detailed in Table 8-17.

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Table 8-17 Gas Contingency Analysis

Incident Event Contingency/Outcome

Partial loss of Blacktip supply, less than 10 days.

Minor plant failure or shutdown

northern supply from Darwin LNG and or INPEX LNG.southern supply from Blacktip.no impact, within normal contingency.

Partial loss of Blacktip supply for more than 5 weeks.

Major failure of plant/equipment requiring extended period of repair.

northern supply from Darwin LNG and or INPEX LNG, additional gas maybe required.southern supply from Blacktip.outside normal contingency and may require additional gas purchases from Amadeus/Darwin LNG/INPEX LNG.

Full loss of Blacktip supply for less than 10 days.

Significant failure of plant or extended maintenance.

northern supply from Darwin LNG and or INPEX LNGsouthern supply from pipeline Darwin LNG/INPEX LNG (subject to sufficient pipeline pressures), northern LNG back-up, Amadeus gas or diesel.no impact, within normal contingency, unless Amadeus gas required.

Full loss of Blacktip for more than 5 weeks.

Catastrophic failure of field or plant, reserve failure, fire/explosion.

northern supply from Darwin LNG or INPEX LNG, additional gas required.southern supply from additional Darwin LNG/INPEX LNG (subject to sufficient pipeline pressures), Amadeus Basin gas or diesel.outside normal contingency and requires additional gas purchases from Amadeus/Darwin LNG/INPEX LNG. Large additional costs, but gas should be available from Darwin LNG or INPEX to satisfy PWC’s full gas requirements, but this cannot be guaranteed.

Pipeline Rupture Minor Rupture – less than 24 hrs.

Blacktip, Darwin LNG or INPEX LNG back-up, pipeline line pack where rupture doesn’t prevent gas supply.Diesel where rupture prevents gas supply.No impact, within normal contingency.

Pipeline Rupture Major Rupture – more than 5 weeks

Blacktip, Darwin LNG or INPEX LNG back-up, pipeline line pack where rupture doesn’t prevent gas supply.Diesel where rupture prevents gas supply.possibly outside normal contingency and may require additional gas purchases from Amadeus/Darwin LNG/INPEX LNG.

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8.4 Key Conclusions – Security of Gas Supply

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

Northern Territory’s gas system security is considered to be N+1 for a short to medium period of time. One major source of gas can fail and be fully covered by supply from an alternate source. A compete Blacktip supply interruption can be fully covered by Darwin LNG (if available and subject to certain conditions).

ENI’s Blacktip field does not have full N+1 redundancy on all elements of field production and plant processing. This increases the Territory’s reliance on back-up gas arrangements and alternate sources of energy such as diesel generation.

Amadeus Basin gas and diesel back-up generation provides additional energy support to the Territory. However, these measures are not capable of replacing 100% of Territory’s energy requirement in the event of a sustained period of simultaneous Blacktip and Darwin LNG outage.

The commencement of NEGI pipeline from 4Q 2018 is likely to transform the Northern Territory gas market from one of excess conventional gas supply capability to limited quantities of uncontracted conventional gas reserves from Blacktip and the Amadeus Basin. While Darwin LNG and Inpex LNG will remain PWC’s main source of back-up gas, the likely reduction in Amadeus Basin’s uncontracted gas reserves from 4Q 2018 will reduce gas supply security in the Territory, as the availability of additional supply and or back-up gas from the Amadeus Basin is reduced;

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 twelve weeks and increasing gas system security to N+2 until 2022;

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

During an event involving a major failure of Blacktip gas supply (that is, greater than five to six weeks with Darwin LNG alone or more than 13 weeks with Darwin LNG and INPEX LNG supply), existing contingency arrangements would exceed their contractual volume caps. Additional gas purchases from Darwin LNG, INPEX LNG and or Amadeus would be required, subject to parties agreeing to suitable commercial arrangements. These purchases would likely be at a higher cost. However, existing infrastructure can provide continuity of gas supply and would be only subject to commercial agreement between the relevant parties.

Gas reserves and well deliverability are critical parts of gas supply security. It is recommended that reserves, well deliverability and levels of reservoir water production be monitored at regular intervals over the life of the Blacktip project.

8.4.1 11 September 2014 Supply Interruption

Blacktip (ENI) gas supply was interrupted due to an equipment failure offshore. System Control took measures to reduce load in an attempt to maximise the usage of the advised remaining gas, the measures taken included both voltage and frequency reduction, as well as reducing the minimum required spinning reserve. Territory Generation was also required to change over several generating units to operate on diesel (C9, C5, K1, K2).

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PWC System Control adopted a rotational load shedding scheme to further reduce load. The scheme involved eight blocks and each block was taken off supply for a duration of approximately one hour. Only seven blocks of the eight were used as ENI restarted production in the evening.

8.4.2 Analysis and Key Recommendations

The emergency event of 11 September 2014 highlighted a number of areas that required improvement to reduce the likelihood and mitigate the impacts of any future gas supply interruption. The following is a summary of the key recommended actions noted by PWC in its report to the Territory Government following the 11 September event:

review and improve ENI’s electrical utilities systems that supplies power to the Blacktip plant and unmanned wellhead platforms. A power interruption to the unmanned wellhead platform was the source of the gas supply interruption;

establish formal operational and communication protocols with all stakeholders involved in the gas supply chain to avoid situations where maintenance activities planned by stakeholders clash; and

improved internal PWC and government communications processes to more quickly inform senior management and government representatives of a potential gas supply problem.

Based on discussions with PWC on 17 February 2016, it is understood that PWC has implemented the following items as a consequence of the 11 September 2014 event:

an emergency response procedure that co-ordinates and manages any gas supply shortfall with major stakeholders, including ENI, Territory Generation and APA, to minimise electricity interruptions;

publication and co-ordination of planned maintenance activities between gas producers, Territory Generation and APA to minimise the risk of overlapping maintenance activities; and

improved internal communications within PWC and between PWC and the Northern Territory Government.

An emergency response exercise should be undertaken at regular intervals (at least every two years) to test and improve the existing response protocols and performance of key stakeholders. A line manager’s experience in managing an emergency response is critical to successfully managing a live emergency response and minimising any interruption in electricity supply.

8.4.3 Other Items Relevant to 11 September Event

A summary of other key items to the 11 September 2014 event:

if either Blacktip or Darwin LNG schedule planned maintenance activities, there should be heightened focus on gas security issues during these periods, since the gas supply system is operating without full back-up gas cover (that is, on a ‘N’ basis). Where the gas system is operating on ‘N’, it is recommended that preparations be made for the relevant period to reflect the higher level of supply risks, which should include:

o maximise pipeline line pack by ensuring there is no planned pipeline maintenance that reduces operating pressures along the pipeline and maximise gas flows into the pipeline a few days prior to the event;

o advise all relevant parties of the periods of ‘N’ gas system security to maximise readiness for other energy support, such as diesel generation back-up, pipeline line pack or alternate supply from the Amadeus Basin;

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o finalise in advance all technical and commercial issues with Santos and Central Petroleum to facilitate a quick ramp-up in production if required from the Amadeus Basin, including commercial arrangements for automatic spot gas sales if required; and

o review diesel inventories for all Territory power stations and prevailing capabilities to re-stock storage tanks at short notice.

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9. Networks Adequacy and Reliability

9.1 Introduction

The Commission has reviewed the method used by PWC to assess the transmission and distribution system network adequacy to meet existing and future demand. The method is primarily documented in the PWC Network Management Plan (NMP) 2013-14 to 2018-1933. Where possible the Commission has validated the results provided in the NMP against supporting data provided by PWC.

PWC did not issue a revised NMP in 2015. PWC advised this was due to preparations for the 2019 Network Price Determination by the AER. The Commission considers this not unreasonable given the 2014 NMP was only in the second year of its five-year outlook, however the Commission expects an updated version to be published in 2016. The Commission notes that PWC published an update to the NMP in January 2016, based on data and analysis available at the end of the 2014-15 financial year.34

The Commission has used the following criteria, which is similar to the PWC criteria as outlined in the NMP, for the 2014- 15 Review:

Planning and monitoring. PWC should have the capacity to measure, plan, operate, maintain and augment the network in order to maintain the adequacy of the system.

Existing and future system utilisation should be low enough to allow for load growth, peak loads and loadings during equipment outages. Conversely utilisation should be high enough to avoid unnecessary augmentation and unnecessary costs to customers. This assessment is made at the following system levels:

o zone;

o transmission line;

o substation;

o feeders;

o distribution substation; and

o low voltage (LV) network.

Poorly performing feeders. PWC should have plans to bring the reliability of any poorly performing feeders up to a satisfactory level.

Fault levels. Electrical equipment is designed to withstand current and associated short-circuit forces in the event of a fault. PWC should have documents that record what current system fault levels are and the design capacity of each installation. They should also have processes to ensure new and existing equipment capability is not exceeded by the system fault levels.

33 Power and Water Corporation Network Management Plan, 2013-14 to 2018-19 - https://www.powerwater.com.au/__data/assets/pdf_file/0020/64226/Network_Management_Plan_2013-14_to_2018-19.pdf

34 Power and Water Corporation Network Management Plan, 2013-14 to 2018-19, Update January 2016 http://www.powerwater.com.au/__data/assets/pdf_file/0016/121741/Network_Management_Plan_2013-14_to_2018-19_-_January_2016_Update.PDF

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http://www.powerwater.com.au/__data/assets/pdf_file/0016/121741/Network_Management_Plan_2013-14_to_2018-19_-_January_2016_Update.PDF


https://www.powerwater.com.au/__data/assets/pdf_file/0020/64226/Network_Management_Plan_2013-14_to_2018-19.pdf

https://www.powerwater.com.au/__data/assets/pdf_file/0020/64226/Network_Management_Plan_2013-14_to_2018-19.pdf


Condition of the asset. PWC should carry out preventative maintenance, planned corrective maintenance and asset replacements to reduce the probability of unexpected plant failure, at an acceptable cost.

Demand management. PWC should document the alternative strategies considered to meet the system demand. These activities can be different from the traditional methods, which were focused exclusively on upgrade of generation and network capacity to meet a higher system demand. The modern approach adopted by PWC includes considering new tariff structures, power factor correction, load shifting and embedded generation. Collectively these strategies are known as ‘non-network solutions’.

Security of the system. The PWC power system should continue to operate under reasonable network contingency conditions. There are some network configurations like radial transmission systems or single transformer ZSS where loss of supply is unavoidable. In these cases, there should be plans in place to restore supply to customers quickly.

Reliability of supply. PWC is required to publish reliability data in their annual ‘standards of service’ report in accordance with the Commission’s ESS Code. This data should show improving reliability over time.

9.2 Planning and Monitoring

PWC provided the Commission with an update of their NMP dated January 2015. The NMP is not explicitly required to meet PWC’s legislated obligations, however it does contain much of the information required by the Commission in an easily accessible form.

Section 1.3 of the latest NMP says:

The Plan’s key objectives are to:

provide stakeholders with greater transparency of the electricity network’s management and operation by documenting Power Networks’ mission, the major challenges and management strategies and plans;

satisfy much of the Commission’s reporting requirements for the regulated electricity network;

lay the foundation for subsequent regulatory price determinations;

provide a framework for continuously improving the network’s technical and economic performance; and

disseminate information on the proposed development of the network over the next five years and beyond, thereby facilitating the development of non-network alternatives to traditional network expansion.

The NMP demonstrates, at a high level, that PWC has suitable systems in place to monitor the performance of the network and plan work required to maintain the adequacy of the network.

9.3 Transmission Line Utilisation

Transmission assets are operated at 66kV or 132kV in the Darwin-Katherine region. The transmission voltages are lower than in other jurisdictions but the assets fulfil the same functional purpose.

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PWC has a program of monitoring the MD on each transmission circuit and predicting the growth of that over the coming 10 years. PWC also calculates what the demand would be in the event of a key circuit being unavailable for service and compares that ‘contingency loading’ with a higher ‘contingency rating’. In the 2012-13 Review, the Commission referred to that higher rating as the ‘emergency rating’.

Based on limiting the normal and contingency loadings to approximately 100%, PWC has devised a number of proposed network augmentations. These augmentations are shown on the ’10-year master plan’. The Commission considers that over the past few years, PWC has made significant improvements to its 10-year master plan.

The Darwin-Katherine system 10-year master plan shows the following key augmentations that address concerns raised in the 2012-13 Review. PWC has also reported good progress in implementing these plans:

establish the Wishart ZSS – Stage 1 complete;

establish a high capacity (120 MVA) 66kV Hudson Creek to Wishart circuit – after further analysis PWC determined that it is better to redirect a 66 kV line; and

establish a Palmerston to Archer 66kV circuit – commencing in the 2016-17 year.

The Commission considers that these changes add considerable flexibility into the operation of the 66kV network in the event that one key circuit is not available for service.

The NMP acknowledges that there is significant uncertainty about the quantity and timing of additional demand at the proposed development of East Arm industrial area in Darwin. However, PWC is engaging with the developers and current indications are that significant new load will not come on until 2019-20. PWC has plans in place for the possibility that this increased demand comes to fruition quicker than expected.

The Commission notes that section 4.1.1 of the NMP says:

“In addition, at the discretion of Power Networks, certain high impact but low risk failures such as the failure of a single zone substation High Voltage (HV) busbar, or the failure of both circuits of a double circuit line, shall be considered as second contingency events.”

It seems likely to the Commission that this is being applied to the two 132kV lines from Channel Island to Hudson Creek. An outage of these lines will certainly lead to a loss of supply to Darwin city and possibly a System Black of the Darwin-Katherine system.

Consistent with the Commission’s concerns expressed in the 2013-14 Review, PWC has completed extensive work to reduce the likelihood of an outage of this transmission line. Works completed include:

replacement of the six unreliable circuit breakers at the Hudson Creek end of the line;

the transmission line electrical protection project is 70% complete and scheduled for commissioning during the 2016 dry season;

circuit breaker fail and auto-reclose relays will be replaced as part of the transmission line protection replacement project due for completion during the 2016 dry season;

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new earth bonding has been installed between towers and overhead earth wires on both CIPS – HCTS 132kV transmission lines reducing the likelihood of a lightning strike on one circuit causing an outage of both circuits;

transmission tower earth grid testing has been completed and shortcomings identified. Improvements are yet to be identified and implemented; and

the Elizabeth River Crossing portion of the circuit is being upgraded to reduce the expected duration of a circuit outage that could result from a severe cyclone. The contract has been awarded and construction commenced May 2016 with completion scheduled for September 2016.

Once all of the remedial work on the 132kV line from Channel Island to Hudson Creek has been completed it may be reasonable to consider a double circuit failure as a second contingency event. In the NEM failure of a double circuit line similar to this one, it would likely be declared a credible event during lightning storms.

PWC has assessed the adequacy of its transmission circuits based on their thermal capability for a small number of contingency events. PWC acknowledge in the NMP that this assessment is indicative because other considerations such as voltage drop and transient stability can reduce the capability of transmission lines. The Commission’s view is that PWC should check these considerations, and report the results of those investigations in the next NMP. This would require an accurate power system model. The Commission made the same recommendation in the 2013-14 Review.

9.4 Terminal Station and ZSS Utilisation

In the Territory, substation average utilisation during 2013-14 was 38% and it was projected to stabilise at about 40% in 2018-19. Under first contingency operation the average utilisation was 57 per cent. Based on the values provided to the Commission for the current review the average utilisation has stabilised already. This may be due to factors including high solar penetration, lower than expected demand growth and the construction of several new or augmented zone substations.

There are a few stations where the first contingency loading exceeds 100%, but the overload is small and provided that PWC promptly executes contingency plans to return loading to an acceptable level then this can be tolerated.

There are many substations where adequate contingency supply can only be achieved by the transfer of load onto nearby substations. This method of achieving contingency supply is within industry best practice. However, this method is less transparent to industry observers and without detailed information on the actual transfers to be completed, it is not possible for the Commission to confirm the assertions in the NMP that adequate transfer capacity is available.

The Commission supports PWC in its initiative to complete an engineering investigation into the impact of cyclic loading factor on transformers, in excess of their nameplate rating for limited periods of time. PWC has not reported any progress against this initiative for the 2014-15 reporting period. Considering the Territory’s difficult climatic conditions, it would be prudent to confirm that a cyclic loading factor can be implemented without affecting the transformer service age. Table 9.1 provides the contingency utilisation for each substation, before any load is transferred.

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Table 9-18: Summary of the substation constraints (N-1 conditions)Substation 2013-14 2014-15 2018-19Archer 89% 74% 140%Batchelor No local backup No local backup No local backupBerrimah 86% 89% 61%Brocks Creek No local backup No local backup No local backupCasuarina 129% 64% 64%Centre Yard 80% 80% 80%City Zone 56% (N-1), 112% (N-2) 67% (N-1), 133%

(N-2)67% (N-1), 133% (N-2)

Cosmo Howley 69% (P10) 59% (P50) 69%Frances Bay 34% 18% 36%Hudson Creek 132/66kV 96% 78% 109%Humpty Doo No local backup 62% No local backupKatherine 93% 76% 82%Leanyer NA NA 84%Manton No local backup No local backup No local backupMary River No local backup No local backup No local backupMarrakai 20% NA 20%McMinns 85% 90% 94%Palmerston 89% 95% 143%Pine Creek Terminal No local backup No local backup No local backupPine Creek 66/11 ZS 86% 86%Pine Creek 11/22 ZS No local backup No local backup No local backupSnell Street Decommissioned Decommissioned DecommissionedTindal 55% 52% 51%Weddell 71% 55% 33%Wishart No local backup No local backup No local backupWoolner 81% 72% 98%Lovegrove 22/11 90% 80% 96%Lovegrove 66/22 69% 66% 71%Owen Springs 66% 58% 68%Sadadeen 137% 135% 102%Tennant Creek 92% No data 102%

Source: PWC

9.5 Feeder Utilisation

The Commission acknowledges that the use of 50 to 55% utilisation target for 11 and 22kV feeders, as utilised by Ergon Energy, is acceptable. PWC has forecast that the average 11kV feeder utilisation will increase from 47% in 2014 to 58% in 2019.

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The Commission has compiled the individual feeder utilisation data provided by PWC for 22 kV feeders along with 2014 data from the NMP into figure 9-1. There is a general trend that increasing numbers of feeders are becoming lightly loaded and a reducing number heavily loaded. This is consistent with the observation that new zone substations and new feeders have been constructed recently.

The Commission completed the same exercise with data provided for the 11 kV feeders. However, the results showed a dramatic increase of the number of feeders with loads in the range 30% to 80% which is not credible suggesting an error within the data. Therefore, the Commission has elected not to present this data at this time pending further review with PWC.

Figure 9-16: 22kV PWC feeder utilisation

Source: PWC

There are four 22kV feeders that exceed 100% utilisation during periods of MD. According to the NMP, work is underway to overcome these overloads. Of greater concern is that the NMP predicts the number of feeders loaded beyond 100% will rise to 19 and 4, at 11kV and 22 kV, respectively, by 2018. The Commission recommends plans be put in place to maintain the number of overloaded circuits at a low level.

9.6 Feeder Performance

PWC and the Commission pay particular attention to the feeders categorised as ‘poorly performing feeders’. PWC’s 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 Review, the poorly performing feeder category was defined by referring to the interruption frequency and duration thresholds by regions. The new ESS Code has simplified the performance standards by implementing the SAIDI performance ratio benchmark.

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The 2011-12 Review reported 18 feeders that 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’. The 2012-13 Review reported four feeders exceeded the new threshold limit.

The NMP reports that in the 2013-14 year there were no poorly performing feeders as no feeder had breached the threshold for two years consecutively. The 2014-15 standards of service report shows that again there were no poorly performing feeders in the 2014-15 period.

The Commission notes that this represents a significant improvement in the performance of the worst feeders for at least four consecutive years and is a very good result.

9.7 Incident Report Review

The System Control Technical Code requires PWC to notify the Commission and report to the Commission on certain power system events. The code requires PWC to provide a preliminary fault report for a ‘major event’ within 14 days and a final report as soon as reasonably practical.

The Commission received the ‘Darwin-Katherine and Alice Springs – Network Events – Reportable Major Incidents: 04 July – 30 Jan 2015’ report which contains reports for nine major incidents. The Commission received one further report and did not receive reports for the two incidents that occurred on 13 June 2015 and 28 April 2015. The incidents reviewed include:

11 February 2015: 132kV Channel Island – Manton Line Trip. Protection Issues at Manton. Darwin-Katherine power system split into two islanded power system. Temporary supply shutdown to Manton and Batchelor Zone Substation during restoration;

30 January 2015: 66kV Micro Sub/Marrakia - Forced Outage 66MM202 (MM-HD-MR) - Operating Issues, Load diverted to PA-HD-MM (Bypass);

01 December 2014: Pine Creek Units P1 & P2 Trip on OPS Feeder Fault–Katherine UFLS Stage 1;

30 November 2014: CB 132PK01 Trip–Katherine UFLS Stage 2 Operation;

28 November 2014: Casuarina ZSS 66/11kV TF3 Trip;

20 November 2014: CB 66PK01 Trip–Pine Creek Island Black;

16 November 2014: Braitling Feeder 11LG16 Manual Trip;

21 September 2014: Humpty Doo ZSS CB 66HD203 Trip;

11 July 2014: Pine Creek ZSS CB 132PK03 Trip; and

04 July 2014: Archer ZSS 11kV Bus 2 Trip.

The reports not received include:

03 December 2014: 132kV Line Trip - Pine Creek/Katherine Separation (Pine Creek/Katherine Black);

13 June 2015: 132kV Line Trip - Pine Creek/ Katherine Separation (Pine Creek/Katherine Black); and

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28 April 2015: Manton Transformer Trip. (Coomalie 22MT04, Lake Bennet 22MT06 and Acacia 22MT07 feeders affected).

The Commission made the following observations during the review of 10 network incidents:

Katherine and Pine Creek are over represented in the total number of major events. This is largely due to the radial nature of the Darwin-Katherine connection. However, it also suggests that the line maintenance, tower earthing and protection systems should be maintained to the highest standard in an attempt to reduce the number of incidents.

Many of the major events were resolved very quickly (i.e. less than 30 minutes) and the events of longer duration were resolved very quickly given the complexities that those incidents posed.

System Control investigation reports make recommendations for each of the incidents to reduce the likelihood of similar incidents in the future. PWC should implement all of those recommendations. Furthermore, PWC should read the recommendations in the widest possible context to determine if they can be applied to other sites.

Over frequency tripping occurred at Pine Creek and Katherine for several events. System Control should coordinate the over frequency trip settings of generators so that frequency rise can be arrested before the trip decision is made on too many machines.

9.8 Reliability

Reliability performance of PWC’s network is analysed in two categories:

transmission network performance; and

feeder network performance.

PWC has increased expenditure on maintenance and capital projects in recent years. If this expenditure is appropriately targeted on those parts of the network, significantly contributing to system reliability issues, this should result in a progressive improvement in the reliability of the network. Moreover, improvement is evident in the poorly performing feeder category.

Under the ESS Code, licensed utility entities (primarily PWC) are required to report performance against specific indicators and targets for network distribution and transmission. PWC Standards of Service Report for 2014-15 was provided to the Commission in December 2015.

9.8.1 Transmission Network Performance

To measure the reliability performance of the PWC transmission network, the key indicators are:

system average circuit outage duration index (ACOD), which indicates the average duration of circuit outages experienced by the PWC transmission network;

frequency of circuit 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; and

frequency of transformer outage index (FTO), which indicates the number of transformer outages experienced by PWC transmission network.

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No transmission system exists in the Alice Springs and Tennant Creek power systems and therefore the performance indicators and targets do not apply.

For the Darwin- Katherine power system, the Commission approved targets to apply for the network regulatory period of 1 July 2014 to 30 June 2019.

All performance targets were met. The Commission notes improvements year-on-year since 2012-13 for all four performance indicators. Refer to Table 9-19 for details of the Darwin-Katherine area results.

Table 9-19: Darwin-Katherine transmission network performance

Transmission performance indicators

2014-15 Target

standard

2012-13 Darwin-

Katherine adjusted results

2013-14 Darwin-


2014-15 Darwin-


Target standard

met

Average Circuit Outage Duration (ACOD) (mins)

358.8 227.2 132.1 114.7 Yes

Frequency of Circuit Outage (FCO)

49.0 89.0 60.0 40 Yes

Average Transformer Outage Duration (ATOD) (mins)

123.3 106.9 55 0.0 Yes

Frequency of Transformer Outages (FTO)

0.8 6.0 1 0.0 Yes

Source: PWC Standards of Service Reports 2013-14 and 2014-15.

The Commission is generally satisfied with the investigation work completed by PWC to determine the causes of circuit outages.

9.8.2 Feeder Network Performance

To measure the reliability performance of PWC feeders, the key indicators are:

SAIDI, which indicates the average duration of network and generation-related outages experienced by a customer; and

SAIFI, which indicates the average number of network and generation-related outages experienced by a customer.

PWC met the feeder network SAIDI standard in all four feeder categories. However, there has been some deterioration in the performance of long rural feeders and a deterioration in all categories when the system black event of 12 March 2014 is excluded.

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Table 9-20: 2014-15 Distribution SAIDI results segmented by feeder category

Feeder categories

SAIDI target standard (minutes)

SAIDI 2012-13 results

(minutes)


(minutes)


(minutes) excl. 12 March


(minutes)

Target standard

met (2014-15)

CBD 18.8 1.1 292.1 0.1 0.7 Yes

Urban 136.0 111.0 288.1 52 127.6 Yes

Rural Short 496.3 536.9 525.3 229 372.9 Yes

Rural Long 2164.9 1108.7 206.4 156 755.9 Yes


PWC met the feeder SAIFI standards in all four feeder categories though there has been some deterioration in the long rural feeder category.

Table 9-21: 2013-14 Distribution SAIFI results segmented by feeder category

Feeder categories

SAIFI target standard(minutes)

SAIFI 2012-13 results

(minutes)


(minutes)


(minutes)Excl. 12 March


(minutes)

Target standard

met (2014-15)

CBD 0.4 0.03 0.6 0.01 0.1 Yes

Urban 2.5 2.5 1.6 0.9 1.6 Yes

Rural Short 8.1 9.1 4.1 3.3 4.8 Yes

Rural Long 35.1 12.2 3.4 2.5 7.2 Yes


PWC advised that the following activities will be undertaken during 2014-15 to improve the SAIDI and SAIFI performance of the networks. Underground cable monitoring and replacement has been added to this list since the previous report:

replacement of dated air break switches with remotely controllable gas break switches;

hardware upgrades such as replacing pin insulators with post insulators and installing fiberglass crossarms;

installation of animal guards;

underground cable monitoring and replacement

installation of fault indicators to aid rapid fault location; and

trials of new technologies such as fuse savers.

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To assess relative performance of PWC with regulatory expectations elsewhere in Australia, the Commission has compared PWC Networks’ 2014-15 performance with the minimum service standards applicable to Ergon. The analysis in Table 9-22 shows PWC feeder performance is improving.

The Commission does note that the Territory’s classification of feeders and methodology for exclusions differ from that applied by Ergon.

Table 9-22: PWC and Ergon SAIDI and SAIFI comparison

Key Indicator PWC 2012-13 PWC 2013-14 PWC 2014-15Ergon Energy

Target

SAIDI

SAIDI CBD 1.1 0.1 0.7 n/a

SAIDI Urban 111 52 127.6 146

SAIDI Short Rural 536 229 372.9 406

SAIDI Long Rural 1 108 156 755.9 916

SAIFI

SAIFI CBD 0.03 0.6 0.1 n/a

SAIFI Urban 2.5 1.6 1.6 1.9

SAIFI Short Rural 9.1 4.1 4.8 3.8

SAIFI Long Rural 12.2 3.4 7.2 7.1

Source: PWC Standards of Service Reports 2013-14, 2014-15 and Ergon Minimum Service Standard35.

9.8.3 SAIDI and SAIFI Historical Comparison

To assess feeder performance, the Commission has compared the 2014-15 adjusted SAIDI and SAIFI performance to the performance of the latest five-year period.

Table 9-23: Adjusted (excluding major event days) SAIDI historical results comparison

Key Indicator 2010-11 2011-12 2012-13

2013-14Incl. System

Black

2013-14Excl. System

Black 2014-15

SAIDI CBD 166.6 10.4 1.1 292 0.1 0.7

SAIDI Urban 136 67 111 288 52 127.6

SAIDI Short Rural

586 256 536 525 229 372.9


35 Queensland Department of Energy and Water Resources. Report of Performance against Minimum Service Standards by Energex and Ergon Energy for 2013-14.

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Table 9-24: Adjusted (excluding major event days) SAIFI historical results comparison

Key Indicator 2010-11 2011-12 2012-13

2013-14Incl. System

Black36 2014-15SAIFI CBD 1.0 0.4 0.03 0.6 0.1SAIFI Urban 2.6 2.5 2.5 1.6 1.6SAIFI Short Rural

9.3 10.4 9.1 4.1 4.8

SAIFI Long Rural

22.8 46.4 12.2 3.4 7.2

Source: PWC Standards of Service Reports 2013-14 and 2014-15

9.9 Planned and Recent 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 ageing network system assets and improve network reliability and quality of supply. Significant projects recently completed or underway include:

Darwin city ZSS replacement (complete);

Leanyer ZSS (complete);

Wishart modular substation (complete);

Frances Bay second transformer (complete);

Strangways ZSS to replace McMinns (pre-commissioning and testing underway);

22kV switchboard replacement at Tennant Creek (construction under way);

Mitchell St switching station (complete);

improve cyclone performance of Elizabeth River 132kV crossings to category 4 (in construction for commissioning pre 2016-17 wet season);

Palmerston to Archer transmission line (concept design and budgeting phase – 2017-18)

22kV switchboard replacement at Sadadeen, Alice Springs (deferred);

new 11kV switchboard at Sadadeen, Alice Springs (planning phase);

Berrimah ZSS replacement (in review);

replace Casuarina ZSS 66kV switchgear (under construction); and

132/66kV terminal station and transmission lines Weddell-Woolner (long-term planning).

A summary of the major and minor capital project expenditures as proposed by PWC is shown in Table 9.8.

36 For the purpose of this report the Commission has chosen to remove the 2013-14 System Black incident from the SAIDI data but not from the SAIFI data. This is justified on the basis that the cause of the System Black was within PWC Networks control but the duration was exacerbated by generation-related issues.

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Table 9-25: Forecast capital expenditure ($ million, real $2013-14 with input cost escalation) Project ($M) 2015-16 2016-17 2017-18 2018-19

Total major projects 46.4 25.6 14.0 24.2

Capital items and Essential spares

0.7 0.7 0.7 0.7

Asset Replacement and Upgrade Programs

7.2 6.0 5.9 3.3

HV Cable Replacement Program

1.3 1.5 1.5 1.5

ORMU Replacement Program 2.5 1.3 1.2 1.3

Feeder Upgrade Program 2.4 1.7 1.6 1.5

Customer Augmentation and Network Extension Program

6.5 6.7 6.5 6.5

SCADA and Communication Systems Replacement and Upgrade Program

1.6 1.6 1.6 1.6

Protection Upgrade Program 1.0 1.1 0.9 0.5

Meters/Metering Program 1.1 1.7 2.8 3.1

Customer Connection Program

0.8 0.8 0.8 0.8

Underground Distribution Substation Replacement Program

1.5 0.9 1.4 2.4

Other minor works 1.1 1.1 1.1 1.1

Total Capital Expenditure(Last year’s report)

75.4

(84.7)

51.8

(74.8)

41.0

(57.4)

49.0

(48.4)

Source: PWC Network Management Plan

The last row of the table above (in brackets) shows the total capital expenditure predicted by PWC in the previous version of the NMP as predicted expenditure has been reduced for 2015-16 and 2016-17 and remains consistent for 2017-18.

The Commission supports PWC’s large capital project program but notes the following:

The 2013-14 NMP does not provide adequate details of the different options considered during the planning phase of each project. Future NMPs should provide appropriate detail for the Commission to confirm that PWC has reviewed its investment options.

Power system reporting should provide comprehensive and authoritative data to assist identification of investment options for the Commission to review. As noted in earlier reviews, the role of the Commission is also to evaluate how PWC is deploying investments to address emerging network constraints.

The Commission recommends PWC provide more exhaustive detail regarding the options considered, including engineering review, financial and time considerations.

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PWC has identified that the rate of demand increase is expected to slow and consequently the existing 132kV double transmission line back bone from Channel Island to Hudson Creek may not reach its capacity in the N-1 condition by 2021.

PWC has a preliminary plan that when the line reaches capacity the system may be augmented by a 132kV double circuit line from Weddell power station to Woolner. This would significantly improve the capacity and fault resilience of the entire network. The Commission also understands that the existing 132kV line is cyclone rated category 3 and will be uprated to category 4 only at the Elizabeth River Crossing in 2016-17.

9.10 Progress against Findings from 2013-14 Power System Review

In the 2013-14 Review, the Commission provided a list of recommendations for PWC to address. It is the 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 2013-14 Review recommendations is detailed below:

The main reliability concern was related to the transmission lines from Channel Island to Hudson Creek. Significant work has been completed to address this concern including; circuit breaker replacements, protection replacements (under way), lightning protection modifications and earth grid testing. Recommended improvements to tower footing earthing are yet to be addressed.

PWC did not provide a new 2015-16 NMP. An update to the 2014-15 NMP was published in January 2016 to reflect actual power system performance and provided a number of additional data sets based on stakeholder feedback and continuous development opportunities.37 No additional commentary on the updated information was provided. The Commission expects that PWC will update the full NMP in 2016.

Improvements in aligning the NMP with the requirements of the NER have been made in comparison in the 2013-14 report. However, the Commission recommended that the following critical areas of reporting need attention. Given that the NMP has not been updated, no progress appears to have been made on these items, including:

changes from the previous year’s reporting;

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

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

fault level details at each substation (this was included in the January 2016 Update and will be reviewed in the 2015-16 Review).

Review of PWC Compliance Framework

In the 2013-14 Review the Commission noted comments from PWC that its lack of appropriate compliance process and procedures for its regulatory obligations was a low risk. The Commission disagreed with this conclusion.

In May 2015, the Commission conducted an audit of PWC’s licence obligations to maintain an adequate compliance framework by reviewing PWC’s compliance process and compliance reporting against specific ‘establishment’ principles of the Australian Standard 3806-200638. The audit focused on the areas of establishing a framework, specifically compliance principles 1 to 5 (commitment), 37 Power and Water Corporation Network Management Plan, 2013-14 to 2018-19, Update January 2016


38 Superseded by Australian Standard 19600:2015 Compliance management systems - Guidelines

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principle 6 (implementation) and principle 12 (continual improvement) as it was considered that PWC would not have had sufficient opportunity to implement a compliance process sufficiently mature to conform to the remaining principles of the Australian Standard 3806-2006.

The Commission found that, in relation to licence obligations to have a compliance process and compliance reporting, PWC complied in all material respects relating to the requirements of Australian Standard 3806-2006, ‘Commitment’ Principles 1-5, ‘Implementation’ Principle 6 (clauses 4.1.1 to 4.1.3), and the establishment elements of ‘Continual Improvement’ Principle 12, except for the following:

i. Principle 1: 3.1(j) Regular review of the compliance program is required – A review of the continued suitability, adequacy and effectiveness of the compliance program/framework as a whole has not occurred since 2010.

ii. Principle 2: 3.2.3 Development – In developing the policy, consideration should be given to … (d) severity of risk of non-compliance – Appropriate consideration was not given to the severity of the risk of non-compliance as there is the possibility of medium to low risk obligations not being audited, or insufficiently monitored and non-compliances occurring and going undetected.

iii. Principle 4: 3.4.1 Objectives – Clear targets should be established to achieve compliance objectives and should be measurable, time-related and indicate the level of performance required – Measurable targets have been set for high risk obligations relating to safety and environment but have not been set for regulatory obligations to achieve the success criteria defined in PWC’s Compliance Management Strategy.

iv. Principle 4: 3.4.1 Objectives – These targets should form part of the performance management agreements of the individuals concerned and should be linked to remuneration – Targets do not form part of performance management agreements of responsible individuals.

v. Principle 4: 3.4.2(g) Strategy – The strategy should include … (g) how the organisation will monitor and measure its delivery on its strategy – The strategy does not articulate how it will monitor and measure its delivery on success criteria.

vi. Principle 5: 3.5.3 Prioritisation – Prior to the implementation of its compliance program an organisation should identify its compliance risks and rank the likelihood and consequences of potential compliance failures and allocate resources for their treatment accordingly – The prioritisation methodology employed by PWC may result in some compliance obligations not being adequately controlled and monitored.

vii. Principle 6: 4.1.2(a) Top management responsibility – Top management should (a) Ensure that the commitment to compliance is upheld at all times and that failures and conduct that are prejudicial to compliance culture are dealt with appropriately – Under the current monitoring and reporting regime it appears that some obligations categorised as moderate and low risk may not be audited or effectively monitored. This gap in monitoring and reporting could lead to compliance failures not detected or dealt with appropriately.

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viii. Principle 6: 4.1.2(c) Top management responsibility – Top management should … (c) Ensure that effective and timely systems of reporting are in place – As per 4.1.2(a).

ix. Principle 6: 4.1.2(f) Top management responsibility – Top management should … (f) Be measured against compliance key performance indicators – It was evident that key performance indicators have not been established for the success criteria for compliance management of regulatory obligations, and top management are therefore not measured against these.

x. Principle 12: 6.1.1 Compliance program review - The top management should ensure that the organisation’s compliance program is reviewed on a regular basis to ensure its continued suitability, adequacy and effectiveness – A review of the continued suitability, effectiveness and adequacy of the compliance framework/program as a whole has not been performed since 2010.

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10. Customer Service

10.1 Introduction

This is the second financial year for which the ESS Code has operated for the full period. For the 2014-15 year, PWC and Jacana Energy provided Standards of Service reports relating to their relevant areas in network services and retail services performance respectively. However, it is understood that they are still undergoing a transitional arrangement of customer service resources while full structural separation of Jacana Energy from PWC is being undertaken.

The key measures and structure of this year’s review of customer service performance reflect the ESS Code released 1 December 2012.

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.

Specifically, the PWC data provides:

network indicators – which includes ‘quality’ (in turn includes quality of supply and complaints); and

customer service indicators.

10.2 PWC Network Services Performance

10.2.1 Reconnections and New Connections

Performance of reconnections and new connections for 2014-15

The ESS Code outlines the following indicators for measuring of performance relating to connections and reconnections39:

the percentage and total number of re-connections not undertaken within 24 hours of receipt by the network provider of a valid request for re-connection from the customer;

the percentage and total number of new connections, in the CBD area or urban areas, not undertaken within five business days, excluding connections to new subdivisions where minor extensions or augmentation is required (this measure included in the PWC Standards of Service Report 2014-15);

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 (this measure included in the PWC Standards of Service Report2014-15); 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 (this measure included in the PWC Standards of Service Report 2014-15).

PWC’s performance relating to reconnections and new connections for 2014-15 is provided in the tables 10.1 and 10.2.

39 Schedule 2, 1.8.2 (a), ESS Code, Northern Territory of Australia, 2013.81


Table 10-26 Connections and reconnections performance – PWC

Performance Measure Total numberPercentage of total not

undertaken within timeframe

2013-14 2014-15 2013-14 2014-15

Re-connections not undertaken within 24 hours40 14 790 15 418 0.07% 0.032%

New connections not undertaken in the CBD/urban areas within five days (excluding where minor extensions or augmentation is required)

51 36 3.85% 2.07%

New connections not undertaken in the rural areas within 10 days (excluding where minor extensions or augmentation is required)

15 0 3.84% NA

Table 10-27 New Connections in urban areas to new subdivisions – PWC

Performance Measure

Total Avg. Time (weeks)

2013-14 2014-15 2013-14 2014-15

New Connections in urban areas to new subdivisions

109 104 12.5 11.1

Source: PWC Standards of Service Report 2014-15

10.2.2 Quality of Supply Issues

Quality of supply performance for 2014-15

The reporting requirements for complaints relating to network quality of supply are outlined within schedule 2, 1.8.4 (a) (ii) of the ESS Code as ‘the percentage and total number of complaints associated with the transmission network and distribution network quality of supply issues’.

The number of complaints reduced in all regions other than Alice Springs where there was a small increase. The predominant issue remains ‘no power’.

The percentage of complaints relating to PWC’s quality of supply performance, by region, is summarised in the Figure 10.1 and Figure 10-18.

Figure 10-17: Customer notifications relating to quality of supply and reliability

40 This measure was not reported in PWC’s 2014-15 Standards of Service report but reported separately to the Commission in May 2016.

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Figure 10-18: Customer notifications relating to quality of supply by region – PWC

Source: PWC Standards of Service report 2014-15.

The Commission remains concerned that the information reported does not provide enough insight into the nature or cause of the complaints for the Commission to form a view as to whether the response, from a planning or operational sense, is adequate. Taken on face value the decrease in overall complaints would appear to be a positive outcome (although there is no improvement in

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Alice Springs). This may or may not indicate an increase or (decrease) in the quality of supply but could also be attributable to customer fatigue due to continued poor performance.

The Commission recommends the measurement and routine analysis of power quality data through the network as a method of determining the actual network performance. This data can then be used to understand the customer notification data in context.

10.2.3 Network Related Activities Complaints

The reporting requirements for complaints regarding network-related activities are outlined within schedule 2, 1.8.4 (a) (i) of the ESS Code as ‘the percentage and total number of complaints associated with transmission network and distribution network-related activities segmented into complaint categories’.

PWC provided the following data relating to network-related activities complaints. The category breakdown has changed each year and the Commission recommends that PWC settle on a standardised format so that meaningful year on year comparisons can be made.

Table 10-28 Customer Complaints due to Network-Related Activities – PWC

Network Related Activities

Metering Connection / Disconnectio

n

Reliability Planned Outages

Street Lights

Other

Darwin 19 (15) 7 22 (41) 15 4 42 (54)

Katherine 3 (0) 0 0 (1) 1 1 3 (1)

Tennant Creek 0 (1) 0 0 (2) 0 0 0 (4)

Alice Springs 2 1 5 1 1 3 (1)

Total

2014-15 2013-14 2012-13

Darwin 109 123 66

Katherine 8 2 4

Tennant Creek 0 7 5

Alice Springs 15 2 1

Total 132 134 76

Source: PWC Standards of Service Report 2014-15. Bracketed entries relate to 2013-14.

The number of complaints remains high for 2014-15. The Commission notes some effort in breaking down the ‘Other’ category to provide a better indication of the spread of issues. This category remains the highest of the categories however.

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10.2.4 Written Enquiry Response – Networks

PWC reported the number of written enquiries and average response times. This is shown in

. PWC’s Standards of Service Report 2014-15 reports the average time taken to resolve a customer’s complaint, which results in a higher average. For this measure the Commission has reported in Table 10-4 the time taken to acknowledge a complaint, consistent with the ESS Code.

Table 10-29 PWC 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)

No. of written enquiries receiving a response

2014-15 2013-14 2012-13 2014-15 2013-14 2012-13

Darwin 5 1 3 78 129 10

Katherine 6 1 NA 6 2 0

Tennant Creek

NA 1 1 0 3 1

Alice Springs 5 1 NA 12 7 0

Total 6 1 3 97 141 11

Source: PWC Standards of Service Report 2014-15

The volume of written complaints has decreased somewhat but the time taken to respond to those complaints has increased.

10.2.5 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 . PWC is required to provide these indicators by the ESS Code.

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10.3 Jacana Energy Retail Services Performance

10.3.1 Telephone Call Response

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 Jacana Energy for 2014-15 on this measure is consistent with the ESS Code. It is noted that the percentage of calls not answered within 20 seconds has been changed to the percentage of calls not answered within 30 seconds, which is consistent with ESS Code and industry practice.

Table 10.30 Telephone Call Answering Reporting – Jacana Energy (2014-15)

2014-15 2013-1441 2012-1342

Average time taken to answer the phone

45 seconds 371 seconds 180 seconds

Number of calls 122 555 245 132 204 033

Total % Total % Total %

Calls not answered within 30 seconds of the caller asking to talk to a person

35 541 29 182 868 74.6

Calls not answered within 20 seconds of the caller asking to talk to a person43

124 052 60.8

Calls abandoned 3309 2.7 46 575 19 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 Jacana Energy 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’.

41 Telephone call answering reporting measures were reported by PWC prior to structural separation on 1 July 2014.

42 Ibid.43 20 seconds was used as a reference point for 2012-13 data.

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Progress on telephone call response performance

The Commission notes the marked improvement in this area in 2014-15 and acknowledge Jacana Energy’s additional staffing of the call centre. Jacana Energy expects additional improvements once transfer of the call centre operations is complete and the new retail operating system is implemented.

10.3.2 Retail-Related Complaints

Number of customer complaints for 2014-15

Schedule 3, 1.1.6 of the ESS Code specifies that the performance indicator for complaints as ‘is the percentage and total number of complaints 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’.

Jacana Energy was not able provide segmented customer complaint information or responsiveness to written enquiries for 2014-15, but noted that such data would be available for the 2015-16 Review and more reliable data will be available from January 2017 when the new call centre and systems are in place.

Complaints data provided from 2014-15 is specific to electricity whereas in the past this data has related to electricity, water and network issues combined.

The Commission is unable to form a judgement as to the trend of electricity-related complaints but looks forward to a more consistent data presentation in the future that will allow such judgement. In general the Commission is pleased that progress has been made in responding to customers through improved phone answering performance.

Table 10.6 Total complaint numbers

2010-11 2011-12 2012-13 2013-14 2014-1544

Darwin 1 553 1 516 1 649 1 301

Katherine 146 147 104 53

Alice Springs 432 385 322 160

Tennant Creek

89 41 61 17

Total 2 477 2 220 2 089 1 531 171

44 2014-15 is the first year where electricity only complaints are recorded here.

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10.3.3 Customer Hardship Programs

The requirements for reporting on customer hardship programs are provided in schedule 3, 1.1.7 of the ESS Code. The level of hardship program penetration can be summarised as shown in Table 10.8.

Jacana Energy reported that the number of customers on hardship programs is 0.78 per 100 customers. This measure is used by the AER. Jacana Energy advises that this is ‘broadly consistent’ with retailers in other jurisdictions. Jacana Energy advise that the customer hardship program is under review.

Table 10.8 Customer hardship program summary

Service measures associated with a customer hardship program

Alice Springs Darwin Katherine Tennant

Creek1) Number of customers on a customer

hardship program at the end of the reporting period, with an average electricity bill:

l. between $0 and $500 24 58 1 1ll over $500 but less than $1 ,500 63 215 14 0lll. $'1,500 but less than $2,500 11 74 2 1IV. $2,500 or more 7 58 5 0

2) Number of customers that completed a customer hardship program. A customer has completed a customer hardship program if the customer no longer meets the eligibility criteria (as defined in the relevant customer hardship program) due to the customer's participation in that customer hardship program

18 74 4 1

3) Number of customers that exited a customer hardship program. A customer has exited the relevant customer hardship program if the customer has come to an agreement with the relevant electricity entity to exit that customer hardship program.

4 13 1 0

4) Number of customers that were removed from a customer hardship program. A customer has been removed from the relevant customer hardship program if (in the relevant electricity entity's reasonable opinion) the customer has not complied with its obligations under that customer hardship program.

58 188 11 2

5) Number of customers on a customer hardship program that received hardship vouchers or equivalent under (and as

2 3 1 0

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defined in) the relevant customer hardship program

6) Number of customers on a customer hardship program that ceased to be a customer under a contract for supply with a relevant electricity entity

23 97 1 1

7) Number of customers that applied for a customer hardship program and had their application refused by a relevant electricity entity. An application is refused when a customer does not (in the electricity entity's reasonable opinion) meet the eligibility criteria in the relevant customer hardship program

0 1 0 0

8) Average electricity bill of all customers who were on the customer hardship program, as identified in 1) above

$1,130.73 $1,423.24 $1,482.64 $1,092.76

9) Number of customers who have been checked for compliance 481 1912 102 18

10) Number of customers that received e-vouchers and not on hardship program between reporting period

21 41 1 0

11) Number of hardship agency contacts 333 832 18 412) Number of customers that transferred

program from one property to another 5 11 0 0

Source: Jacana Energy

10.4 PWC Retail Services Performance

PWC’s 2014-15 Standards of Service Report did not include performance indicators in relation to Retail Services. The Commission will monitor PWC’s compliance with the retail services indicators in the ESS Code for 2015-16.

10.5 Progress against Findings from the 2013-14 Review

The key points of progress are the marked improvement in telephone call response and improved assessment of network-related complaints.

10.6 Key Findings

The Commission reiterates the importance of breaking down complaint data across the various entities within the electricity supply industry as this gives the best chance to determine customer satisfaction with the overall quality of electricity supply. Structural separation is beginning to provide additional transparency in this regard.

The Commission is pleased with the continuing improvement or maintenance of standards in most areas reported. In particular, the telephone call loading has improved significantly in response to improvements made by Jacana Energy in this area.

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The Commission further asserts that customer complaints should only be one source of data on the effectiveness of managing the electricity supply. This is particularly the case for power quality issues. The Commission is interested in understanding the true technical performance of the networks with respect to power quality to get a more objective measure of power quality.

The Commission will continue to monitor compliance with the ESS Code in 2016.

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Appendices

91


A Generating Units

92


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

1.65MVA

Make / Model GE Frame 6 GE Frame 6 GE Frame 6 GE Frame 6 GE Frame 6 Mitsubishi GE LM6000 Trent 60 Trent 60 Cummin

C1675 D5

Engine Type Combustion

Turbine

Combustion

Turbine

Combustion

Turbine

Combustion

Turbine

Combustion

Turbine

Steam

Turbine

Combustion

Turbine

Combustion

Turbine

Combustion

Turbine

Reciprocating

Diesel

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 2014

* PWC has advised that generation units 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 Set 3 House Set 0.9MVA

Make / Model GE LM6000 PD GE LM6000 PD GE LM6000 PD Caterpillar 3412

Engine Type Combustion Turbine Combustion Turbine Combustion Turbine

Fuel Type Gas Gas Gas

93


MW GMC RATING 43 43 43

N-1 FIRM GMC 0 43 43

N-2 FIRM GMC 0 0 43

Date Commissioned Feb-08 Nov-08 Mar-14 2008

A.1.3 Shoal Bay and Pine Creek

Shoal Bay Pine Creek A

Unit Set 1 GT 1 GT 2 ST 3

Make / Model Caterpillar 3516G Solar Mars Solar Mars Peter Brotherhood

Engine Type Reciprocating Spark

Fired Combustion Turbine Combustion Turbine Steam Turbine

Fuel Type Land Fill Gas Gas Gas Waste Heat

MW GMC RATING 1.1 9.64 9.64 7.31

N-1 FIRM GMC 0 9.64 0 3.655

N-2 FIRM GMC 0 0 0 0

Date Commissioned Aug-05 Jun-96 Jun-96 Jun-96

94


A.1.4 Katherine

Unit GT 1 GT 2 GT 3 GT4

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

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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 Reciprocating Diesel 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

Reciprocating Diesel


Fuel Type Gas Gas Gas Gas Gas Gas or Diesel

Diesel Diesel

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

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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 / Model

Mirrlees KVSS12 Mirrlees KVSS12 Mirrlees KV16P Major Mirrlees KV16P Major Mirrlees KV16P Major

Pielstick PC2-3 V16 DF



ASEA GT35C

Engine Type Reciprocating Diesel


Reciprocating Dual Fuel






Combustion Turbine

Fuel TypeDiesel 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

Note: Units F, G, J at Ron Goodin power station were de-commissioned in 2011.

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

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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 G 2

Make / Model SunPower T20 Tracker

Engine Type Photovoltaic Photovoltaic

Fuel Type PV PV

MW GMC RATING 0.964 3.1

N-1 FIRM GMC 0.000 0.000

N-2 FIRM GMC 0.000 0.000

Date Commissioned 24 June 2011 August 2015

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B Review of PWC Maximum Demand Projections

As part of the 2013-14 Review, the Commission (with the assistance of Marsden Jacob) and PWC developed projections for maximum demand (MD) across the three networks: Darwin-Katherine, Alice Springs and Tennant Creek. The projections looked at both regional MD and MD on a zone substation (ZSS) basis. The appendix presents a review and comparison of those projections.

B.1 Previous Estimates – PSR14

Both PWC and the Commission provided 10 year projections for annual regional and ZSS MD. In both cases, a projection was made on ‘underlying’ MD. These are the projected MDs reflecting ongoing trend growth, ‘average’ or P50 maximum temperature and incorporating expected changes in loads, either between ZSSs or as a result of expected major shift in demand. These last mentioned changes primarily reflect major infrastructure demands, such as new hospitals being established or mines closing.

PWC and the Commission undertook different approaches to projecting MD across ZSSs.

PWC’s approach involved adjusting MD for shifts in loads and for variation in temperature (that is, temperature correction). The temperature correction involved estimating a linear MD versus temperature relationship/slope which was used all each ZSS. This slope was then applied to the most recent observed MD to obtain its projections for that ZSS.

the Commission’s approach involved pooling all data in the system to derive generic growth rates for typical, industrial, commercial, mining and abandoned regions serviced by the ZSS. The projections also included effects for temperature. The Commission then projected future MD by extrapolating the regressed average line.

Table B 1 shows the projected MD in 2014-15 for each ZSS estimated by both PWC and the Commission. Also shown are the load changes expected during the year and the resulting trend demand projected by both PWC and the Commission.

Table B 1 ZSS MD and load transfer projections for 2014-15 – PSR 2013-14

ZSS PWC projection Commission projection

Expected load adjustment

MVA

Darwin-Katherine

Archer 26.9 24.6 5.5

Batchelor 1.9 2.2

Berrimah 32.7 29.7 -6.2

Brocks Creek 0.1 0.3

Casuarina 52.3 53.1 1.0

Centre Yard 0.4

City 47.9 45.9 -10.1

Cosmo Howley 5.1 5.2


ZSS PWC projection Commission projection

Expected load adjustment

MVA

Frances Bay 28.5 29.2 16.9

Humpty Doo 1.5 2.5

Katherine 27.3 28.9

Leanyer 21.3

Manton 8.2 10.8 4.7

Mary River 3.27 4.3

McMinns 26.9 26.7 4.4

Palmerston 34.0 33.4 0.1

Pine Creek 1.4 1.4

Weddell 11 9.6 3.0

Woolner 46.7 34

Union Reef 10.8 11.7

Wishart Modular 9 9

Alice Springs

Lovegrove 20.0 19.3

Sadadeen 28.4 24.1

Tennant Creek

Tennant Creek 7.2 7.2

B.2 Approach and Reconciliation

Table B 2 overleaf presents a comparison of actuals and projected ZSS MD undertaken by PWC and the Commission. The projections reflect what loads were expected to be transferred in 2014-15 and the P50 temperature. The actual MD will vary from the projection due to three sources:

the expected load transfer did not occur;

the maximum temperature for the day of MD may have differed from P50 assumption; and

other factors not modelled or expected and forecasting error.

The reconciliation below places the two projections on the same basis (with adjustments for the first two factors above).

Table B 2 2014-15 projections – Generation of Comparable Projections

Actual PWC projections (before transfers) Commission projections (before transfers)

ZSS Demand TransfersActual

temperature

Demand excluding transfers

P50 excluding expected load

transfersAdjustment for

temperatureAdjusted

projection



temperatureAdjusted

projection

DARWIN-KATHERINE

Archer 22.5 2.4 33.6 20.1 21.4 -1.5744 19.8 18.7 0.081 18.749

Batchelor 2.1 33.8 2.1 1.9 -0.1307 1.8 1.5 0.119 1.619

Berrimah 34.0 1.3 33.8 32.7 38.9 -2.6144 36.3 35.6 0.119 35.709

Brocks Creek 0.1 33.8 0.1 0.1 -0.0036 0.0 0.0 0.119 0.110

Casuarina 51.8 33.3 51.8 51.3 -4.2703 47.1 50.6 0.024 50.629

Centre Yard 0.4 32.7 0.4 0.4 -0.0410 0.4 0.4 -0.093 0.307

City 57.5 1.0 32.7 56.5 58.0 -5.9375 52.0 55.6 -0.093 55.483

Cosmo Howley 4.4 34.4 4.4 5.1 -0.2441 4.8 4.2 0.232 4.445

Frances Bay 7.8 34 7.8 11.6 -0.7069 10.9 11.6 0.157 11.757

Humpty Doo 1.7 34.4 1.7 1.5 -0.0719 1.4 1.3 0.232 1.523

Katherine 22.2 40.4 22.2 27.3 3.9363 31.3 28.6 1.264 29.894

Leanyer 33.8

Manton 3.4 33.8 3.4 3.5 -0.2363 3.3 5.7 0.119 5.830

Marrakai 33.8

Mary River 3.2 33 3.2 3.3 -0.3033 3.0 3.1 -0.034 3.081

McMinns 28.5 1.3 35.4 27.2 22.5 -0.3605 22.2 22.3 0.416 22.670

Palmerston 33.9 1.4 33.5 32.5 33.9 -2.6030 31.3 33.2 0.062 33.250

Pine Creek 1.3 36 1.3 1.4 0.0045 1.4 0.0 0.524 0.524


Actual PWC projections (before transfers) Commission projections (before transfers)

ZSS Demand TransfersActual

temperature

Demand excluding transfers



temperatureAdjusted

projection



temperatureAdjusted

projection

Weddell 8.6 1.4 33.5 7.2 8.0 -0.6117 7.4 6.0 0.062 6.065

Woolner 41.7 0.2 34.3 41.5 46.7 -2.3896 44.3 34.1 0.214 34.303

Union Reef 11.7 28 11.7 10.8 -2.7271 8.1 11.6 -1.089 10.475

ALICE SPRINGS

Lovegrove 14.7 4.7 39.4 10.0 20.0 –1.0 19.0 19.3 –0.1 19.2

Sadaddeen 25.2 –6.8 40.0 32.0 28.4 –2.7 25.7 24.1 –0.1 24.0

TENNANT CREEK

Tennant Creek 6.7 37.7 6.7 7.2 –0.9 6.3 7.2 –0.2 7.0


As would be expected with one year projections, both PWC and the Commission were reasonably close to that expected (after adjusting for actual transfers and temperature effects).

However in some cases there were major variations. The major variations were for Brocks Creek and Union Reef (PWC) and Manton and Pine Creek (the Commission):

In the case of Brocks Creek, PWC assumed no growth as the mine had closed. Its projection was for 0.05 MVA. Rounding issues may be the reason for the current PWC projection of 0.1.

In the case of Union Creek, the adjusted projection was particularly affected by the PWC temperature correction (Union Creek’s maximum temperature coincided with a temperature of 28°C, well below its P50 base of 35.9°).

In the case of Manton, the Commission classified the ZSS as a residential substation. However, contrary to other residential zones, Manton has been declining. The region may be better defined as equivalent to an abandoned mine with the reduced reliance on Manton Dam.

In the case of Pine Creek, PWC and the Commission had similar projections (1.4 vs 1.5 MVA). However the adjustment for temperature (36° for MD) in the Commission model resulted in a large adjusted value.

In all of these cases, the small demands associated with each locality magnified the impact of small differences.


C Demand Forecasting Methodologies

This appendix outlines the approaches used by the Commission in undertaking the MD and energy projections.

C.1 System-Wide Energy Projections

The approach to modelling system energy demand was equivalent to that used for system MD. Energy demand was modelled on the major potential drivers of usage:

population growth;

economic activity; and

trend growth.

With limited data it was difficult to include many more factors. In each system, energy use reflected slightly different drivers. In all three systems, the underlying important measure was the level of energy use which reflects both that met by the system and that by PV.

C.2 System-wide MD Projections

The approach by the Commission had similarities to that used by PWC with rooftop PV and spot load being considered separately (that is, removed from the regression model) and the same data range (starting in 2006-07).

The Commission examined the drivers of overall regional MD for the three power systems. Econometric analysis was again undertaken examining a number of functional forms and the appropriate explanatory variables.

There was no preferred model as all four functional forms considered (linear, log linear, linear log and double log) provided reasonable explanations of changes in maximum demand. The most appropriate model form was determined to be double-log for Darwin-Katherine and Alice Springs, and a linear-log for Tennant Creek.

The best estimate of overall change varied across the systems. Growth for energy use in Tennant Creek reflected broad population growth. This suggests that trend rate of growth slows over time. For Alice Springs the sole explanatory variable was trend. This suggests a constant rate of decline over time. Finally, Darwin-Katherine was best explained by a combination of economic activity and population. The coefficients suggest that growth is fairly constant but that the impact of economic surges can be perverse.

Temperature was not a significant explanator in the regression. The P10 MD was developed from the regression estimate using the regression error (1.4 standard deviations).


C.3 Zone Substation MD Projections

The approach used by the Commission (for the Darwin-Katherine and Alice Springs systems) was based on the following:

Model

Removing spot loads in order that significant ‘load lumps’ were removed from the statistical model;

Developing a least squares linear regression model of ‘corrected’ MDs that examined the explanatory variables Gross State Product (GSP), population and trend;

Developing demographic profiles of the individual ZSS through mapping the physical ZSS locations to Australian Bureau of Statistics data on customer type locations;

‘Like’ ZSS data was ‘pooled’ in the statistical trend analysis in order to increase the level of confidence in the estimates developed. This provided for a common relationship across the pooled data while allowing individual intercepts for each ZSS;

The 2008 MD figures are used in the regression, generated MD data are not;

Using actual MDs rather than temperature corrected MDs and including temperature explanatory variables in the model. The temperature explanatory variables trialled were the maximum temperature two days before, maximum temperature the day before, and the maximum temperature on the day of MD. This approach reflected a lack of confidence in the high ∆MD/∆ temperature sensitivity that had been used (3.2%);

Projections

Based on an outlook of GSP, population and P50 maximum temperatures (based on a 50% probability of being exceeded) and using the developed regression model, project future P50 MDs. Then add back in spot load changes to obtain the MD outlook;

The MD outlook based on a 10% probability of being exceeded (P10) was developed from the temperature MD sensitivity established;

The projection is taken to commence from the 2015 P50 estimated MD with the slope defined by the least squares.


D Tabular Results

This chapter provides the graphical quantities shown in Tabular format. This is done in the order the graphs appear in the report. No explanation is provided on the numbers as this is contained in the main body of the report and associated appendices.


Table E 1 Darwin-Katherine ZSS projections: P50Adjusted projections 2015-16 2016-17 2017-18 2018-19 2019-20 2020-21 2021-22 2022-23 2023-24 2024-25Archer 25.6 33.9 39.1 44.3 48.1 49.0 49.5 49.7 49.9 50.0Batchelor 2.4 2.1 1.8 1.5 1.1 0.8 0.5 0.2 -0.1 -0.4Berrimah 34.0 31.3 31.5 32.8 33.0 33.2 33.4 33.5 33.7 36.6Casuarina 32.2 32.4 32.5 32.7 32.9 33.1 33.2 33.4 33.6 33.8City 46.6 46.6 46.6 46.6 46.7 46.7 46.7 46.7 46.7 46.8Cosmo_Howley 5.0 5.3 5.7 6.1 6.4 6.8 7.2 7.5 7.9 8.2Frances_Bay 22.9 22.9 22.9 23.0 23.0 23.0 23.0 23.0 23.0 23.1Humpty_Doo 3.0 3.1 3.3 3.5 3.7 3.8 4.0 4.2 4.4 4.5Katherine 30.6 26.5 26.7 26.8 27.0 27.2 27.4 27.5 27.7 27.9Manton 8.5 8.2 7.9 7.6 7.3 6.9 6.6 6.3 6.0 5.7Mary_River 4.7 5.1 5.5 5.8 6.2 6.5 6.9 7.3 7.6 8.0McMinns 29.6 32.6 35.6 24.2 24.4 24.6 24.8 24.9 25.1 25.3Palmerston 42.3 51.2 52.8 54.3 55.9 57.5 59.0 60.6 62.2 63.7Pine_Creek 2.5 2.7 2.8 3.0 3.2 3.4 3.5 3.7 3.9 4.1Weddell 12.8 17.1 7.2 7.4 7.6 7.8 7.9 8.1 8.3 8.5Woolner 36.9 33.7 33.9 34.1 34.3 34.4 34.6 34.8 35.0 35.1Union_Reef 12.2 12.5 12.9 13.3 13.6 14.0 14.3 14.7 15.1 15.4Tindall 7.6 3.4 3.6 3.8 4.0 4.1 4.3 4.5 4.7 4.8

Table E 2 Alice Springs / Tennant Creek ZSS projections: P502015-16 2016-17 2017-18 2018-19 2019-20 2020-21 2021-22 2022-23 2023-24 2024-25

Lovegrove 19.86 24.96 24.96 24.96 24.96 24.96 24.96 24.96 24.96 24.96

Sadadeen 24.13 18.82 17.87 16.92 15.98 15.03 14.08 13.13 12.19 11.24

Tennant Creek 6.63 6.63 6.63 6.63 6.63 6.63 6.63 6.63 6.63 6.63


Table E 3 Darwin-Katherine ZSS projections: P102015-16 2016-17 2017-18 2018-19 2019-20 2020-21 2021-22 2022-23 2023-24 2024-25

Archer 25.9 34.1 39.4 44.6 48.4 49.3 49.8 49.9 50.1 50.3Batchelor 2.7 2.4 2.0 1.7 1.4 1.1 0.8 0.5 0.1 -0.2Berrimah 34.3 31.6 31.8 33.1 33.3 33.5 33.6 33.8 34.0 36.9Casuarina 32.5 32.6 32.8 33.0 33.2 33.3 33.5 33.7 33.9 34.0City 46.9 46.9 46.9 46.9 46.9 46.9 47.0 47.0 47.0 47.0Cosmo_Howley 5.2 5.6 6.0 6.3 6.7 7.1 7.4 7.8 8.1 8.5Frances_Bay 23.2 23.2 23.2 23.2 23.2 23.3 23.3 23.3 23.3 23.3Humpty_Doo 3.2 3.4 3.6 3.8 3.9 4.1 4.3 4.5 4.6 4.8Katherine 30.9 26.8 26.9 27.1 27.3 27.5 27.6 27.8 28.0 28.2Manton 8.8 8.5 8.2 7.8 7.5 7.2 6.9 6.6 6.3 5.9Mary_River 5.0 5.4 5.7 6.1 6.5 6.8 7.2 7.5 7.9 8.3McMinns 29.9 32.9 35.8 24.5 24.7 24.9 25.0 25.2 25.4 25.5Palmerston 42.6 51.5 53.0 54.6 56.2 57.7 59.3 60.9 62.4 64.0Pine_Creek 2.8 2.9 3.1 3.3 3.5 3.6 3.8 4.0 4.2 4.3Weddell 13.0 17.3 7.5 7.7 7.8 8.0 8.2 8.4 8.5 8.7Woolner 37.1 34.0 34.2 34.3 34.5 34.7 34.9 35.0 35.2 35.4Union_Reef 12.4 12.8 13.2 13.5 13.9 14.3 14.6 15.0 15.3 15.7Tindall 7.8 3.7 3.9 4.0 4.2 4.4 4.6 4.7 4.9 5.1

Table E 4 Alice Springs / Tennant Creek ZSS projections: P102015-16 2016-17 2017-18 2018-19 2019-20 2020-21 2021-22 2022-23 2023-24 2024-25

Lovegrove 20.97 26.07 26.07 26.07 26.07 26.07 26.07 26.07 26.07 26.07

Sadadeen 25.24 19.93 18.98 18.03 17.08 16.13 15.19 14.24 13.29 12.35

Tennant Creek 7.74 7.74 7.74 7.74 7.74 7.74 7.74 7.74 7.74 7.74


E Generator Related Load Shedding

Table E.1: Darwin-Katherine: Generator Outage Events that resulted in load shedding in 2014-15

Date Description Report Received for PSR

27/07/2014 Loss of generator 3 at Weddell – Lube oil card fault X

01/08/2014 Loss of generator 3 at Weddell X

12/08/2014 CIPS generator unit 9 Emergency shutdown X

11/09/2014Gas shortage - Rotational Load Shedding; Insufficient Online Capacity - UFLS Backup Stage (2 Related Events)

05/11/2014 Loss of generator 6 at Channel Island X

25/11/2014 Loss of generator 2 at Weddell X

29/11/2014 CIPS generator unit 9 tripped X

03/12/2014132kV Line Trip - Pine Creek/Katherine Separation (Pine Creek/Katherine Black) and Channel Island power station C2, C4, C7 Trip - Darwin UFLS Stage 3B (25 Min After Separation)

Table E.2: Alice Springs: Generator Outage Events that resulted in load shedding in 2014-15


03/10/2014 RGPS Unit R9 Tripped & Operated UFLS Stage 2B X

25/01/2015 RGPS Unit R5 Tripped & Operated 22RC8979 X

27/04/2015 RGPS Unit 5 Tripped – UFLS Stage 1A and 1B

05/06/2015 Owen Springs Unit 1 Trip - UFLS Stage 1A and 1B


Table E.3: Tennant Creek: Generator Outage Events that resulted in load shedding in 2014-15


13/02/2015

TCPS Unit 15 tripped – UFLS Stage 3

26/04/2015

TCPS Unit 14 tripped – UFLS Stage 1

26/102014 Restoration of TCPS Feeder 3 Operated UFLS X


F Not used


G Progress against Recommendations from Previous Power System Reviews

The progress against recommendations identified in previous reviews is detailed in the table below:

Table G.1: Progress recommendations from previous reviews

2013-14 Review Recommendation Progress

Generator reliability declined markedly from 2012-13 to 2013-14

There has been improvement in the 2014-15 review period.

Alice Springs and Tennant Creek generator reliability standards need to be developed taking into account the nature of those power systems.

Formal performance standards have not been provided.

Poor performance of the 132kV Channel Island to Hudson Creek line to be investigated and rectified

Replacement completed of the six unreliable circuit breakers at the Hudson Creek end of the line.The transmission line electrical protection project is 70% complete and scheduled for commissioning during the 2016 dry season.Circuit breaker fail and auto-reclose relays will be replaced as part of the transmission line protection replacement project due for completion during this dry season.New earth bonding has been installed between towers and overhead earth wires on both CIPS – HCTS 132kV transmission lines reducing the likelihood of a lightning strike on one circuit causing an outage of both circuits.Transmission tower earth grid testing has been completed and short comings identified. Improvements are yet to be identified and implemented.The Elizabeth River Crossing portion of the circuit is being upgraded to reduce the expected duration of a circuit outage that could result from a severe cyclone. The contract has been awarded and construction is to commence May 2016 with completion September 2016.


The ‘normal’ and ‘contingency’ ratings that PWC Networks applied in evaluating adequacy of transmission circuits to be reviewed

No comment or revised data provided.

Structural separation of PWC and the establishment of Jacana Energy should place greater focus on customer service performance.

Structural separation appears to have improved complaints management significantly.

The Commission recommends PWC System Control, review its resources and processes for the reporting of major incidents with the aim of improving the timing of major incident reports.

A much higher proportion of major events have been correctly reported on this year. However, there is no formal procedure of tracking that the report recommendations are being implemented.

Progress towards finalisation of the remaining 12 recommendations from the System Black Recommendation reports

These will be subject to a technical audit to be conducted in 2016.

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: VCR 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. ‘

Significant progress has been made as evidenced by a reduction in the number of double contingency generation events and the number of load shedding events.

However, the Commission still requires that the VCR and the value of lost load be defined.


The Commission recommends that Territory Generation consider operating the CIPS generation units 8 and 9 at an output just below rating.

This recommendation is superseded by improvements in the performance of Channel Island power station units 8 and 9.

The Commission recommends that Territory Generation move to a probabilistic approach to determining the available capacity.

No progress appears to have been made on this item. The Commission reiterates that N-X analysis is not the best method when the reliability of individual items of equipment is below 95%.

The Commission recommends PWC consider the need to have contingencies in place for the eventuality that load grows rapidly at East Arm.

Discussions with PWC suggest that suitable contingencies are in place and that load growth is slower than expected.

The Commission recommends that PWC reviews its resources and processes for investigating and reporting major incidents and aims to improve the timing of provision of reports to the Commission.

System Control appears to have outsourced this function and is now providing suitable reports. However, the reports are being prepared in groups, perhaps bi-annually. This may place excessive reliance on the memory of field staff.

The Commission recommends PWC provide more exhaustive detail regarding the options considered, including engineering review, financial and time considerations.

This item will be reviewed as part of the 2015-16 Review.


Further work be undertaken by PWC to incorporate reliability assessment and monitoring into PWC’s planning and reporting processes.

No direct evidence of progress has been provided to the Commission.

PWC’s approach to weather correction for ZSS and system MD forecasts be reviewed.

This was discussed with PWC in the context of the two projection methodologies that were used in the 2013-14 Review. It is understood that this will be included in a review by PWC of MD forecasting approaches that will follow this Review.

PWC consider the outcomes of its investigation on the appropriate level of spinning reserve (and indirectly this load shedding practice) including amending its spinning reserve practices if necessary.

This work is ongoing and a significant reduction in both the number of load shedding events suggests that this work has improved system reliability.


PWC adopt a stochastic method for planning and assessing future generation adequacy and in so doing adjust and refine the methods of forecasting generating unit availability.

This recommendation is superseded by the recommendation that consideration be given to power system planning post-structural separation of PWC.

PWC document plans to expedite feeder load re-allocation to increase the time margin before a forecast over-utilisation.

There is no evidence that PWC has formal plans in place, however the NMP clearly show that the time margin before a forecast over utilisation is increasing.

PWC perform voltage level studies to confirm the capacity of feeders to supply loads of adjacent feeders during contingency scenarios.

Contingency analysis performed by PWC appears to consider the thermal capability of feeders only and ignores the fact that capacity can be limited by voltage drop. The analysis is too simplistic and remains a concern to the Commission.

PWC provide details of SmartGrids pilot scheme. This project should lead to further steps in the implementation of Smart Grid technology within the Territory.

Generic information on smart grids is provided in section 4.2.5.2 of the network management plan. PWC plans to roll out 1000 interval meters to a selection of customers.If additional ‘smart grid’ work is being completed to the network then this has not been communicated to the Commission.

The reliability of generating units be estimated based on planned maintenance activities on an annual basis in addition to an allowance for unplanned outages.

There has been significant improvement in 2014-15. Territory Generation has provided predictions of machine availability and has based its projections on known major machine works and past reliability observations. This is a significant methodology improvement over previous years.

PWC provide more exhaustive detail in regards to the options considered, including engineering review, financial and time considerations in relation to its proposed network projects.

These details have not been provided to the Commission. The Commission recognises that this detailed information may not belong in the network management plan. This information should reside in separate reports and be referenced in the NMP.

PWC consider what action is required to address the increase in number of customer calls and improve the associated level of customer service.

Significant progress has been made on this issue by Jacana Energy following structural separation.

PWC further consider the character and content of the Network Management Plan to progress alignment with NEM practices.

No significant progress has been made



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.

This work is ongoing and needs to be accelerated.

Improvement of generation reliability at a unit level to reduce the number of UFLS events that are occurring across all three systems.

Significant progress has been made on this issue, as evidenced by the low level of generator double contingency events during the 2014-15 period.

12 March 2014 System Black (further recommendations were made in the 2012-13 PSR45)

Progress

A full condition assessment of the 132kV circuit breakers be undertaken as a priority, including a risk assessment of the possibility of future failures of power system security.

PWC undertook replacement of all Hudson Creek 132 kV circuit breakers.

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

Completed June 2014. System Control has implemented a program of annual review of black start procedures.

45 Further recommendations were made in the Commission’s Investigation Report to the Treasurer on the 12 March 2014 System Black Incident that occurred in the Darwin-Katherine Power System.


Development of a documented and authoritative process for the reporting and implementation of recommendations from power system reports.

PWC has not provided details of its processes for reporting (including to the Board) and implementation of recommendations from power system reports, including system incident reports and the PSR.The Commission has the impression that PWC, Territory Generation and System Control receive many technical reports containing valuable recommendations. However, there do not seem to be formal systems in place to track, accept or reject those recommendations or to prioritise implementation.

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