Evoenergy Non- Network Options Report for Molonglo Rit-D Project

EVOENERGY NON- NETWORK OPTIONS REPORT FOR MOLONGLO RIT-D PROJECT

Non-network options report for RIT-D project subject to the regulatory investment test for distribution in accordance with National Electricity Rules clause 5.17.3.

1 CONTENTS

DEFINITIONS AND ABBREVIATIONS 5 Definitions 5 Abbreviations 6 EXECUTIVE SUMMARY 7 Background 7 Identified Network Need 7 Potential Credible Options 7 Deferral value 8 1. INTRODUCTION 10 1.1 Scope and Purpose 10 1.2 Obligations 10 1.3 Structure of Report 11 2. BACKGROUND 12 2.1 Existing Supply System 12 2.2 Relevant Statutory and Regulatory Obligations 12 2.2.1 National Electricity Rules 12 3. DESCRIPTION OF IDENTIFIED NEED 14 4. ASSESSMENT METHODOLOGY AND ASSUMPTIONS 16 4.1 Methodology 16 4.2 Economic Assessment Timeframe 16 4.3 Electrical Demand 16 4.3.1 Scenarios 17 4.3.2 Maximum Demand 18 4.3.3 Load profile 19 4.4 Load Transfer Capability and Supply Restoration 22 4.5 Network Asset Failure Rate and Outage Duration 22 4.6 Discount Rate 22 4.7 Value of customer reliability 22 4.8 Approach to estimating project costs 23 5. POTENTIAL CREDIBLE NETWORK OPTIONS 23 5.1 Base case (Preferred Network Option) 23 5.1.1 Technical definition and characteristics 24 5.1.2 Costs 24 5.2 Credible network options 25 5.2.1 Alternative Network Option 1: Extend Hilder feeder and operate Streeton, Black Mountain and Hilder feeders to thermal limits 25 5.2.2 Alternative Network Option 2: Install new 11 kV feeders from existing zone substations 25

2 5.2.3 Alternative Network Option 3: Construct Molonglo zone substation in two stages 26 6. POTENTIAL CREDIBLE NON-NETWORK OPTIONS 27 6.1 Non-Network Option 1 – Batteries located within Molonglo load centre 27 6.2 Non-Network Option 2 – Battery located at future Molonglo zone substation site 28 7. TECHNICAL INFORMATION FOR NON-NETWORK OPTIONS 28 7.1 Target Area 28 7.1.1 Specific target area 29 7.2 Contributions to power system security, reliability and/or fault level 32 7.3 Investment timing requirements 32 7.4 Technology Specific Requirements 32 7.4.1 Battery 32 7.4.2 Demand Management 35 7.4.3 Embedded generator 36 7.5 Available funds for deferral 37 8. SUBMISSIONS 38 8.1 Invitation for submissions 38 8.2 Information from non-network providers 39 8.3 Next steps 40 8.3.1 Timeline 40 8.3.2 Documents 41 VERSION CONTROL 42 DOCUMENT CONTROL 42

3 Disclaimer Whilst this document contains material relevant to the electricity industry legislation, codes of practice and standards, it is not intended to provide legal advice on how electrical contractors can meet their own statutory obligations or comply with legislation, codes of practice or industry. Whilst care has been taken in the preparation of this document, Evoenergy does not guarantee that the information contained in this document is accurate, complete or up to date at time of publication. To the extent permitted by the relevant legislation Evoenergy will not be responsible for any loss, damage, cost or expense incurred as a result of any error, omission or misrepresentation in relation to the information contained in this document. Note Printed versions of this document are “uncontrolled copies” - the latest version is available on the Evoenergy website.

DEFINITIONS AND ABBREVIATIONS

Definitions TABLE 1. DEFINITIONS ACT Government – The ACT Government Electrical Inspectorate is the inspecting authority in the ACT Electrical and is responsible for inspecting and approving the consumer’s electrical installation Inspectorate

Demand response A change from normal mode of load operation induced by a signal triggered by a network constraint or other constraint, to reduce demand for energy or market ancillary services within a region Embedded A system comprising of multiple embedded generating units (e.g. solar PV system with generating system a battery storage system)

Embedded A generating unit connected within a distribution network and not having direct access generating unit to the transmission network

Evoenergy Evoenergy is the ACT’s principal Distribution Network Service Provider (DNSP) and is responsible for the distribution of electricity to all customers within the ACT. Firm delivery Maximum allowable output or load of a network or facility under single contingency capacity conditions, including any short term overload capacity having regard to external factors that may affect the capacity of the network or facility1 Frequency control Services used by the energy market operator to maintain the frequency of the system ancillary services within the normal operating band, which functions to provide a fast injection or reduction of energy to manage supply and demand, respectively High voltage (HV) Any voltage greater than 1 kV AC Load centre Regions on the electricity distribution network close to load/centres of demand Low Voltage (LV) The mains voltages as most commonly used in any given network by domestic and light industrial and commercial consumers (typically 230 V)

Network Evoenergy’s distribution network

Non-network A person who provides non-network options; proposing to become a generator (the provider relevant owner, operator or controller of the generating unit (or their agent)) RIT-D proponent The Network Service Provider applying the regulatory investment test for distribution to a RIT-D project to address an identified need2 Thermal constraint A thermal limitation on the capability of a network, load or generating unit such that it is unacceptable to either transfer, consume or generate the level of electrical power that would occur if the limitation was removed Utilities Technical The ACT Government team responsible for the technical administration of utility Regulation Team requirements and administration of the Utilities (Technical Regulation) Act 2014 Value of Unserved A quantified measure of the resource availability to continuously serve all loads at all Energy delivery points while satisfying all planning criteria, results involve analysing all hours of a particular year and calculations are presented as units of energy or currency Weighted average Relevant weighted average cost of capital for a network service provider for a regulatory cost of capital control period, being the return on capital for that network service provider for that regulatory control period calculated in accordance with National Electricity Rules

1 As per definition from National Electricity Rules for firm delivery capacity 2 As per definition from National Electricity Rules for RIT-D proponent

Abbreviations

TABLE 2. ABBREVIATIONS AC Alternating Current ACT Australian Capital Territory AEMC Australian Energy Market Commission AEMO Australian Energy Market Operator AER Australian Energy Regulator AS Australian Standard AS/NZS A jointly developed Australian and New Zealand Standard CBD Central Business District CEC Clean Energy Council CPI Consumer Price Index DER Distributed Energy Resource DNSP Distribution Network Service Provider DSE-RIP Demand Side Engagement Register of Interested Parties FCAS Frequency Control Ancillary Services FAQ Frequently Asked Question FY Financial Year HV High Voltage LV Low Voltage MW Megawatt NEM National Electricity Market NER National Electricity Rules NNOR Non-network options report POE Probability of Exceedance PV Photovoltaics RIT-D Regulatory Investment Test for Distribution STPIS Service Target Performance Incentive Scheme UTR Utilities Technical Regulator V Volt VA Volt-Ampere VAr Volt-ampere-reactive VCR Value of Customer Reliability W Watt WACC Weighted Average Cost of Capital ZS Zone Substation

EXECUTIVE SUMMARY

Background This Non-Network Options Report (NNOR) has been prepared to inform non-network providers that may be able to provide services to defer or avoid a network augmentation project. The National Electricity Rules (NER) require a Regulatory Investment Test – Distribution (RIT-D) be completed for augmentation capex projects with a value greater than $6m. The RIT-D requires a NNOR where an initial assessment has identified potentially credible non-network options that may defer or avoid the augmentation project being considered by the RIT-D.

The Molonglo Valley District is a greenfield development area situated in Canberra’s west, approximately 10 km from the Canberra central business district (CBD). Over the next 30 years, the area, as one of the major urban growth corridors in Canberra, will be developed into the new suburbs of North Weston, Coombs, Wright, Denman Prospect, Whitlam and Molonglo3.

Land releases and development have already commenced in parts of the Molonglo Valley, with several new suburbs established. These suburbs will continue to grow over the next decade alongside new suburbs that will begin construction in the next few years. Land releases between 2020 and 2024 will support an estimated 4,357 residential dwellings in addition to a shopping centre, schools, commercial areas and community facilities.

To supply the increased demand for electricity in Molonglo Valley District, Evoenergy has identified a need to establish a new zone substation.

Identified Network Need In the short term there is a rapidly approaching constraint in the 11kV distribution network. Peak demand is forecast to exceed the combined thermal capacity of the existing 11kV feeders supplying the area by summer 2021/2022. Over the longer term, the load in the Molonglo Valley load will be sufficiently large to fully utilise a large zone substation with multiple transformers. The identified need addressed by this NNOR is for the 11kV feeders. However, Evoenergy’s assessment of permanent options (as opposed to temporary or deferral options) covers both the feeder constraint and constraints on the zone substations that either currently or potentially in the future may supply the Molonglo Valley.

The tables below present forecast maximum demand for the central forecast scenario. Red values indicate demand is greater than the winter (23.4MVA) or summer (20.9MVA) thermal capacities of the existing 11kV feeders.

TABLE 1: MAXIMUM DEMAND FORECAST - WINTER Scenario POE 2020 2021 2022 2023 2024 2025 Base 50 18.0 20.0 25.3 28.9 31.0 32.5

TABLE 2: MAXIMUM DEMAND FORECAST - SUMMER Scenario POE 2019/20 2020/21 2021/22 2022/23 2023/24 2024/25 Base 50 14.8 16.7 21.6 24.8 26.7 28.0

Potential Credible Options Evoenergy’s initial assessment of non-network solutions for the Molonglo Valley area has found two credible non-network options. These are both based on the use of batteries to temporarily defer investment in a network augmentation. Option 1 involves two or more batteries located within the Molonglo Valley District near the load centre. This could include residential batteries aggregated by a Virtual Power Plant (VPP) scheme and controllable loads or larger more centralised batteries. Option 2 involves a single large battery located at or near the future Molonglo zone substation site. Option 2 requires Evoenergy to complete initial civil works at

3 Coombs, Wright, Denman Prospect and North Weston are partially constructed. Construction is either in the early stages or not commenced at the other suburbs listed.

the future zone substation site and a feeder extension to connect the site, so the deferral value of this option is lower than for Option 1.

The potential credible options assume that a battery or batteries will be installed with a primary purpose that is not to support Evoenergy’s network. That is, the value available to defer the network option, is unlikely to be sufficient to entirely fund the required battery and additional investment drivers are likely to be required. Examples of additional investment drivers include as part of a larger energy investment project, due to a government program obligation, for wholesale electricity price arbitrage, participation in the frequency control ancillary services (FCAS) market or as part of a back-up system for an electricity user. The majority of the battery’s value will likely come from these additional purposes, with network support payments from Evoenergy providing an additional revenue stream.

Evoenergy has undertaken a preliminary evaluation of a wide range of non-network options for Molonglo such as demand management and embedded generation. These services were assessed as less likely to deliver a credible non-network solution for the Molonglo constraint. Notwithstanding, Evoenergy is technology/solution agnostic and seeks submissions on all feasible solutions to defer investment at this site. This may include partial solutions including demand response, embedded generation and smaller batteries for Evoenergy to evaluate whether it can combine solutions to address the identified need.

Evoenergy’s initial assessment of the constraint indicates that the most viable solution is a small number of batteries located on 1-2 feeders in the Molonglo Valley close to loads with a combined battery capacity of 4MW/8MWh and installed at a site/s to be agreed with Evoenergy before November 2021.

Deferral value The available funds for deferral are determined by the financial benefits to Evoenergy of deferring capital expenditure. For the identified need in the Molonglo Valley, the deferral benefit is made up of two components, avoided financing costs and avoided depreciation of capital assets.

The maximum payment to a non-network service provider will depend on the expected unserved energy the service will result in. As Evoenergy uses probabilistic planning and does not have deterministic planning compliance obligations, there is no requirement for a service provider, or Evoenergy, to reduce expected unserved energy to zero. The base case network option will result in zero unserved energy over the deferral period.

TABLE 3: DEFERRAL VALUE (FY19/20 PAYMENT) Location Defer to FY21/22 Defer to FY22/23 Defer to FY23/24 Molonglo ZS Site $260,000 - $340,000 $530,000 - $690,000 $790,000 - $1,030,000 Load Centre $460,000 - $570,000 $910,000 - $1,140,000 $1,370,000 - $1,710,000

If there are no additional costs to Evoenergy (including unserved energy costs and risk margins) a non- network solution provider can receive total payments, in present value terms, up to the amounts presented in the table. This could be as a once off payment, but is more likely to be structured as an availability payment plus a variable component linked to the actual usage of the non-network solution by Evoenergy. Evoenergy will consider and negotiate pricing structures included in a submission.

Next Steps Evoenergy is seeking proposals from any non-network provider that is able to provide services which meet or partially meet the identified network need. Submissions will be required to provide detail about the type, scale and cost of non-network solutions offered by providers.

Submissions can be lodged via email to: [email protected]

Submissions must be received by 23 June 2020 at 5pm. In addition, non-network providers must submit a Special Connection Request form via Evoenergy’s website, and attach, where prompted, the relevant documentation.

Evoenergy will review each non-network option proposal and may seek further information from the non- network provider to better understand the design of the proposed solution and its impacts on the network and other network users.

An overview of the timeline, from the publication of this NNOR to when the preferred option is required to be operational, is provided in Table 17 below.

TABLE 4: TIMELINE ACTIVITIES DATES Publish NNOR and request for submissions4 27 March 2020 27 March 2020 - 25 Consultation period5 for non-network providers to provide submissions June 2020 Public briefing session during consultation period – Details to be confirmed April 2020 Evoenergy review of submissions received (non-network proposals) June 2020 – July 2020 Draft project assessment report6 is released August 2020 August 2020 – Consultation period for preferred option and request for submissions7 September 2020 September 2020 – Evoenergy review of submissions received October 2020 Publish final project assessment report8 November 2020 Prepare draft contract(s) with preferred non-network provider(s) (where a non- November 2020 – network option or options are preferred) December 2020 Preferred option operational November 2021

4 Evoenergy will notify registered parties on Demand Side Engagement Register of Interested Parties (DSE-RIP) form As per NER clause 5.17.4(g), available from https://www.evoenergy.com.au/emerging-technology/demand-management 5 Not less than 3 months in duration from notifying registered parties on DSE-RIP as per NER clause 5.17.4(h) 6 Within 12 months of end of consultation period on NNOR as per NER clause 5.17.4(i) 7 Not less than 6 weeks in duration from publication of the draft assessment report as per NER clause 5.17.4(m) 8 As soon as practicable after the end of the consultation period on draft project assessment report as per NER clause 5.17.4(o), unless NER clause 5.17.4(p) applies

1. INTRODUCTION

Over the next 30 years substantial greenfield development is expected to occur in the Molonglo Valley District, which is situated in Canberra’s west, approximately 10 km from the Canberra CBD. When complete, the newly developed suburbs of North Weston, Coombs, Wright, Denman Prospect and Whitlam in this region are expected to support an estimated 21,000 dwellings plus shopping centres, schools and community facilities.

To supply the increased demand for electricity in Molonglo Valley District, Evoenergy has identified a need to establish a new zone substation. The capital expenditure expected for such works is valued at greater than $6m and therefore Evoenergy is required under the NER to undertake a RIT-D. NER Chapter 5 sets out the processes and public consultation obligations of DNSPs when applying the RIT-D.

As Evoenergy’s initial assessment has identified potentially credible non-network options that may defer or avoid the augmentation project, the RIT-D requires a NNOR. This NNOR has been prepared to inform non- network providers, and encourage them to make credible non-network option submissions on the provision of services to address the identified need, and defer or avoid a network augmentation project.

1.1 Scope and Purpose

Under the RIT-D process, Evoenergy is required to consider all credible network and non-network options to meet future electricity demand. The RIT-D process9 10 involves the following key stages:

 Stage 1: Screening for non-network options and publishing a NNOR,  Stage 2: Undertaking consultation on non-network options,  Stage 3: Assessment of credible options,  Stage 4: Publishing a draft project assessment report and undertaking consultation on the preferred option, and  Stage 5: Publishing a final project assessment report.

As a part of Stage 1, Evoenergy has developed this NNOR in accordance with the requirements of Chapter 5 clause 5.17.4 of the NER. This report outlines the need for the proposed investment, and the range of feasible network and non-network options available to resolve the identified need. The information contained within this report should enable third-parties to provide informed submissions to supply non-network solutions to Evoenergy to defer and/or avoid the requirement for a significant network augmentation.

Details regarding the process for non-network providers to make submissions for non-network solutions are provided in Section 8.

1.2 Obligations Evoenergy has obligations relating to this NNOR, including:

9 NER version 134 clause 5.17.4, available from https://www.aemc.gov.au/sites/default/files/2020- 03/NER%20v134%20full.pdf 10 AER, Regulatory investment test for distribution application guidelines, December 2018, available from https://www.aer.gov.au/system/files/AER%20-%20Final%20RIT-D%20application%20guidelines%20- %2014%20December%202018_0.pdf

 To ensure that the NNOR is published in a timely manner having regard to the ability of parties to identify the scope for, and develop, alternative potential credible options or variants to the potential credible options.11  To notify persons registered on its demand side engagement register of the report's publication.12  To provide Registered Participants, Australian Energy Market Operator (AEMO), interested parties, non-network providers and (if relevant) persons registered on Evoenergy’s demand side engagement register with not less than three months in which to make submissions on the NNOR from the date that this report is published.13  To pay particular attention when considering the risk, value of optionality and expenditure timing of non-network options. In particular, modelling, forecasts and assumptions should be consistent, open and transparent to help effectively explore non-network options.14  To satisfy capital expenditure objectives, and identify capital expenditure and operating expenditure trade-offs.15 1.3 Structure of Report This document is structured as follows:

 Section 2 provides background information on the network location and the associated infrastructure.  Section 3 describes the identified need that is to be addressed.  Section 4 reviews the planning methodology and assumptions used in the assessment of the credible options.  Section 5 details the credible network options, provides an indicative assessment of their respective augmentation costs and the estimated commissioning dates.  Section 6 details the credible non-network options.  Section 7 presents the technical characteristics of the identified need, intended to guide non- network providers in developing credible non-network options.  Section 8 provides guidance on the assessment process to third parties interested in submitting a response and the next steps.

11 As per NER clause 5.17.4 (f) 12 As per NER clause 5.17.4 (g) 13 As per NER clause 5.17.4 (h) 14 AER Regulatory investment test for distribution application guidelines Section 4.2, December 2018, available from https://www.aer.gov.au/system/files/AER%20-%20Final%20RIT-D%20application%20guidelines%20- %2014%20December%202018_0.pdf 15 NER clause 6.5.7 (a)

2. BACKGROUND

2.1 Existing Supply System The Molonglo Valley load centre is approximately 7 km from Evoenergy’s nearest existing zone substations, Woden and Civic. Both of these zone substations have three 132/11 kV transformers and would require major extensions to alleviate space constraints and accommodate additional transformers. Civic zone substation has a firm delivery capacity of 110 MVA and Woden has a firm delivery capacity of 100 MVA.

The figure bellow shows the Molonglo Valley District and immediate surrounds.

FIGURE 1 MOLONGLO VALLEY REGION

Supply is being provided to the existing stage of the suburbs of Wright and Denman Prospect in the Molonglo Valley District from the Streeton feeder from Woden zone substation and the Black Mountain feeder from Civic zone substation. Initial supply will be provided to Whitlam through a connection to the Black Mountain feeder. Supply is being provided to the suburbs of Coombs and Weston through the Hilder feeder from Woden zone substation.

The attributes of the existing feeders in the Molonglo Valley are shown in the table below.

TABLE 5: MOLONGLO VALLEY 11KV FEEDER ATTRIBUTES Maximum Winter Firm Winter Thermal Feeder Demand FY19 Peak Season Rating (MVA) Rating (MVA) (MVA) Black Mountain 5.5 7.3 2.8 Summer Streeton 6.2 8.2 5.8 Winter Hilder 5.9 7.8 7.4 Winter Total 17.6 23.4 14.0* Winter Note: Values may not add due to rounding *Total of maximum demand is lower than the sum of individual feeder maximum demand due to diversity of peak demand timing 2.2 Relevant Statutory and Regulatory Obligations

2.2.1 National Electricity Rules The RIT-D process assess the economic efficiency of the proposed credible option investments. The process is defined by clauses 5.17.1 - 5.17.4 of the NER and the Australian Energy Regulator’s (AER) RIT-D guideline16.

16 AER Application Guidelines RIT-D, December 2018, available from https://www.aer.gov.au/system/files/AER%20- %20Final%20RIT-D%20application%20guidelines%20-%2014%20December%202018_0.pdf

The RIT-D proponent, Evoenergy, is required to apply the RIT-D for all projects where the estimated capital cost of the most expensive potential credible option to address the identified need is greater than $6 million.

All projects meeting the RIT-D threshold must be screened for potential credible non-network options that address the identified need. Where a non-network option is a potential credible option, or that forms a significant part of a potential credible option, Evoenergy must, as per NER clause 5.17.4, prepare and publish a NNOR.

The NNOR is intended to inform non-network providers of non-network solutions on the costs and market benefits associated with potential credible options, and provide an opportunity for them to consider how they could address the identified need.

Clause 5.17.4(e) of the NER requires the NNOR include: (1) A description of the identified need. (2) The assumptions used in identifying the identified need (including, in the case of proposed reliability corrective action, why the RIT-D proponent considers reliability corrective action is necessary). (3) If available, the relevant annual deferred augmentation charge associated with the identified need. (4) The technical characteristics of the identified need that a non-network option would be required to deliver, such as: (i) The size of load reduction or additional supply, (ii) Location, (iii) Contribution to power system security or reliability, (iv) Contribution to power system fault levels as determined under clause 4.6.1, and (v) The operating profile. (5) A summary of potential credible options to address the identified need, as identified by the RIT- D proponent, including network options and non-network options. (6) For each potential credible option, the RIT-D proponent must provide information, to the extent practicable, on: (i) A technical definition or characteristics of the option, (ii) The estimated construction timetable and commissioning date (where relevant), and (iii) The total indicative cost (including capital and operating costs). (7) Information to assist non-network providers wishing to present alternative potential credible options including details of how to submit a non-network proposal for consideration by the RIT- D proponent.

Evoenergy must provide Registered Participants, AEMO, interested parties, non-network providers and persons registered on the demand side engagement register not less than three months in which to make submissions on the NNOR from the date that the NNOR is published.

3. DESCRIPTION OF IDENTIFIED NEED

The need for the Molonglo zone substation was identified in Evoenergy’s revised regulatory proposal for the 2019-24 period17.

The Molonglo Valley is one of the major urban growth corridors in Canberra and is expected to experience sustained development over a number of decades. This development will drive a permanent increase in peak demand for electricity.

The timing of demand increases is driven by the ACT Land Release Program18 19, which provides a forecast of all land release for greenfield and infill development in the ACT, and the Molonglo Development Forecast, which outlines developer intentions in the Molonglo Valley.

Land releases and development has commenced in parts of the Molonglo Valley, with several new suburbs already established. These suburbs will continue to grow over the next decade alongside new suburbs that will begin construction in the next few years. Land releases between 2020 and 2024 will support an estimated 4,357 residential dwellings in addition to a shopping centre, schools, commercial areas and community facilities.

TABLE 6: MOLONGLO VALLEY LAND RELEASE FORECAST20 2020 2021 2022 2023 2024 TOTAL Residential (Lots) 481 965 949 1,062 900 4,357 Commercial/Other (m2) 12,261 35,183 15,000 60,000 - 122,444

Development across the suburbs in the Molonglo Valley region is proceeding rapidly:  Coombs and Wright are the most developed and are filling at a steady rate.  Denman Prospect is being developed over a five-stage approach and includes dwellings, a commercial centre, schools and community facilities.  Planned development for the suburb of Whitlam is being undertaken in a four-stage approach involving construction of dwellings followed by a school and local centre in 2023.

In the short term, there is a rapidly approaching constraint in the 11kV distribution network comprised of the Black Mountain, Streeton and Hilder feeders. Peak demand in the 11kV distribution network will exceed the combined thermal capacity by summer 2021/2022. Over the longer term, the load in the Molonglo Valley will be sufficiently large to fully utilise a new zone substation with multiple transformers.

The identified need addressed by this NNOR is for the constraint on the 11kV feeders.

The map below shows the long-term development plan with zoning types and densities for the currently undeveloped area north of the Molonglo River. The yellow square at the top of the map is the proposed site of the future Molonglo Zone Substation.

17 Evoenergy Revised regulatory proposal, November 2018, available from https://www.aer.gov.au/system/files/Evoenergy%20-%20Revised%20Regulatory%20Proposal%20- %20Main%20Document%20-%20November%202018.pdf 18 ACT Government Budget 2019-20 Indicative Land Release Program, available from https://apps.treasury.act.gov.au/__data/assets/pdf_file/0004/1369795/2019-Indicative-Land-Release-Program.pdf 19 Indicative Land Release Program Maps 2019-20 to 2022-23 https://www.planning.act.gov.au/__data/assets/pdf_file/0008/1370537/2019-20-to-2022-23-Indicative-Land-Release- Program-Land-Release-Maps.pdf 20 Evoenergy, Ibid, footnote 19

FIGURE 2: MAP OF MOLONGLO VALLEY WITH LAND RELEASE

Based on Evoenergy’s conversion of the development forecast to electricity demand (see section 4.3.2), where there is no investment to increase the 11kV feeder capacity in the Molonglo Valley there will be cumulative expected unserved energy valued at $59m by FY23/24. The table below shows the expected unserved energy by year.

TABLE 7: EXPECTED VALUE OF UNSERVED ENERGY (NO CAPACITY INCREASE) FY19/20 FY20/21 FY21/22 FY22/23 FY23/24 Value of Unserved Energy - - $1,195,445 $17,482,605 $40,070,390

4. ASSESSMENT METHODOLOGY AND ASSUMPTIONS

This section outlines the methodology and assumptions that will be used by Evoenergy to assess all credible network and non-network options that address the identified need. This assessment will take place at the conclusion of the NNOR consultation period and the outcomes will be published in the draft project assessment report as per the requirements of the RIT-D. 4.1 Methodology Evoenergy applies a probabilistic planning methodology where the costs and benefits for each credible option are measured against a ’no investment’ base case.

Evoenergy has shown21 that an investment to augment the network in the Molonglo Valley area has a higher NPV than a ‘no investment’ option. Updated assumptions with respect to the demand forecast since that analysis was completed have not significantly changed the results. The ‘do nothing’ option results in thermal limits of existing network assets being breached and large amounts of involuntary load-shedding, which drives large unserved energy costs that will be borne by customers (and Evoenergy through the Service Target Performance Incentive Scheme (STPIS) mechanism22).

For the purpose of this NNOR, non-network options submitted to Evoenergy will be assessed against the proposed network option.

Submissions received for non-network solutions to defer the network option will be assessed probabilistically against the nine scenarios detailed in this report. The costs and risks (predominantly the risk of unserved energy) for each solution will be calculated for each scenario and weighted by the probability assigned to the scenario.

There are no deterministic obligations that Evoenergy must meet related to the forecast network constraint being addressed by the network investment.

4.2 Economic Assessment Timeframe Evoenergy’s initial analysis of the identified need used a 20-year period that covered multiple future stages of investment. The long-term forecast for growth in the Molonglo Valley that is driving the need for investment has not changed since the initial analysis was undertaken so a 20-year period will continue to be used, covering the period 2021-2041.

Evoenergy’s analysis indicates that credible non-network options result in deferral of the network option for 1 to 3 years. Non-network solutions may be reusable to defer future stages of investment but there is a high degree of uncertainty and Evoenergy cannot commit to incurring upfront costs for future deferral benefits that may not eventuate. Evoenergy’s preferred assessment timeframe for deferral options is the period of the initial deferral (1-3 years). After the deferral period the expenditure profile of the network option is expected to be the same as an equivalent option that does not include deferral (i.e. timing of all future stages is unchanged). Therefore, the assessment of options in the NNOR is limited to a three year period.

4.3 Electrical Demand The sections below cover the forecasts used by Evoenergy to assess options that may meet the identified need.

21 Evoenergy’s revised regulatory proposal for 2019-24, Appendix 4.3: Molonglo Zone Substation PJR, November 2018 available from https://www.aer.gov.au/system/files/Evoenergy%20-%20Revised%20Proposal%20- %20Appendix%204.3%20-%20Molonglo%20ZS%20PJR%20-%20November%202018.pdf 22 AER Service Target Performance Incentive Scheme, November 2018, available from https://www.aer.gov.au/networks- pipelines/guidelines-schemes-models-reviews/service-target-performance-incentive-scheme-2018-amendment

The following items have been excluded from the forecasting scope:

Government incentives – The Suburban Land Agency have implemented significant incentives for houses in the new suburb of Whitlam to have no connection to the gas network along with other electricity based requirement, including having all electric appliances, install solar PV systems, EV chargers and home energy monitoring. The impact of this incentive is unknown, so no changes have been made to ADMD based on this information

The COVID-19 crisis – At the time of publication, Australia and the world are in the midst of the COVID-19 pandemic. The effects of this on the housing market in Canberra is yet to be seen.

4.3.1 Scenarios Evoenergy has considered three load growth scenarios, high, base and low. These scenarios are determined by the probability of proposed developments going ahead:

 The high growth scenario assumes the ACT government land release program continues as planned and all land released in the Molonglo Valley is developed immediately.  The base scenario assumes that 75% of developments not yet committed proceed.  The low growth scenario assumes that only 50% of developments proceed.

Evoenergy expects the base scenario to be more likely than the high and low scenarios. This is based on previous outcomes of developer applications from Evoenergy experience. Due to this, a 50% weighting is applied to the base scenario and a 25% weighting to each of the high and low growth scenarios.

Evoenergy has also modelled three load Probability of Exceedance (POE) forecasts for each of the load growth scenarios for a total of nine scenarios to reflect the uncertainty in actual peak demand in any given year. These are the 90%, 50% and 10% levels, where the percentage refers to the likelihood that actual peak demand exceeds the forecast in any given year. This variability is usually attributed to weather, where cold winters and hot summers result in higher than forecast peak demand (POE10) and mild winters and summers result in lower than forecast demand (POE90).

Evoenergy does not ordinarily calculate POE10 or POE90 forecasts for distribution feeders. POE10 forecasts are produced for Zone Substations and POE10 and POE90 forecasts are produced for Bulk Supply Points. These forecasts are contained in Evoenergy’s 2019 Annual Planning Report23. The actual demand during FY19, which is the basis for the forecast, is assumed to be close to a POE50 forecast given the conditions present during that year in the target area.

The probabilities applied to the POE scenarios are derived from the likelihood of demand being more extreme than the scenario. A 10% probability is attached to the POE90 and POE10 scenarios and the remaining 80% to the central POE50 scenario

The resultant probabilities for each of the nine scenarios are presented in the table below.

TABLE 8: SCENARIO PROBABILITIES POE Total 90 50 10 Low 3% 20% 3% 25% Scenario Base 5% 40% 5% 50% High 3% 20% 3% 25% Total 10% 80% 10% 100%

23 Evoenergy Annual planning report 2019, available from https://www.evoenergy.com.au/-/media/evoenergy/about- us/annual-planning-report-2019-final.pdf?la=en&hash=5AB807B56CA18F99596EC38DAEAD1657E68F1526

4.3.2 Maximum Demand Maximum demand forecasts are driven by the expected new load attributable to new developments each year. Evoenergy has based the maximum demand forecast for the Molonglo Valley of the latest ACT Land Release data, which provides the number of residential lots and square meters of commercial space released each year. Evoenergy has also considered developer applications in forming the number of new premises connected in the Molonglo Valley area.

Evoenergy has applied a one year lag between land release and connection of a lot to the electricity network. Each residential lot is assumed to add 2.2kVA to coincident maximum demand in a POE50 scenario and each square meter of commercial/other space is assumed to add 0.1kVA. The residential lot estimate is an average of single dwellings and multi-unit blocks. The forecast uses very conservative estimates of coincident maximum demand and assumes very high energy efficiency of the homes and commercial spaces that will be built in the Molonglo Valley. The Whitlam development has requirements and incentives for developers to include EV charging points in homes, which may contribute to higher demand growth than forecast by Evoenergy.

Additional diversity factors have been applied on a case-by-case basis for some large loads with special characteristics. These values are based on Evoenergy’s historic experience with new developments, expectations for energy efficiency of the new premises and expectation for rooftop solar PV to reduce grid electricity consumption, especially in summer months.

The maximum demand forecast increase each year is used to create a forecast annual load profile. Each 15-minute interval increased proportionally based on maximum demand growth.

The POE50 forecasts are developed first and the POE90 and POE10 forecasts calculated using the approach outlined in section 4.3.1 above.

The forecast aggregate coincident maximum demand across the Streeton, Black Mountain and Hilder feeders during Summer and Winter is shown in the tables below. These forecasts also include existing and expected new block loads that are outside the Molonglo Valley that will use these three feeders. Red values indicate the maximum demand is above the combined thermal capacity of the existing 11kV feeders.

For financial modelling purposes, the alignment of financial years to seasonal peaks is: FY20/21 = 2021 winter and 2020/21 summer.

TABLE 9: MAXIMUM DEMAND FORECAST - WINTER Scenario POE 2020 2021 2022 2023 2024 2025 90 14.0 17.6 19.0 22.5 24.9 26.2 Low 50 17.6 19.0 22.5 24.9 26.3 27.3 10 18.5 20.0 23.4 25.8 27.3 28.3 90 17.3 19.2 24.3 27.8 29.7 31.2 Base 50 18.0 20.0 25.3 28.9 31.0 32.5 10 18.9 21.0 26.3 30.0 32.2 33.7 90 18.0 20.3 26.3 30.9 33.5 35.4 High 50 18.7 21.1 27.4 32.1 34.9 36.9 10 19.7 22.2 28.4 33.3 36.2 38.3

TABLE 10: MAXIMUM DEMAND FORECAST - SUMMER Scenario POE 2019/20 2020/21 2021/22 2022/23 2023/24 2024/25 90 10.9 13.9 15.8 18.5 19.5 20.7 Low 50 14.4 15.8 19.0 21.1 22.4 23.3 10 15.7 17.1 20.6 22.9 22.4 23.3 90 13.1 14.7 18.9 21.8 23.3 24.9 Base 50 14.8 16.7 21.6 24.8 26.7 28.0 10 16.1 18.2 23.4 26.9 26.7 28.0 90 13.6 15.6 20.6 24.4 26.4 28.4 High 50 15.4 17.7 23.5 27.8 30.2 32.0 10 16.8 19.3 25.5 30.1 33.2 32.0

4.3.3 Load profile

When assessing the financial costs and unserved energy implications of non-network submissions, Evoenergy will use the actual load profiles of the Black Mountain, Streeton and Hilder feeders during a 12 month period covering the 2018/19 summer and 2019 winter. This load profile approximately aligns with FY19 and will be treated as a financial year for the assessment of options.

The use of this load profile is reasonable for forecasting because it represents actual customer electricity usage characteristics in the area, the makeup of the new developments is expected to largely reflect the existing load uses in the area and because FY19 was a typical year with no unusual or major demand events during the year.

The assessment is to be undertaken at an area level, using the sum of forecast load on all three feeders. If a non-network submission is determined to be credible Evoenergy will work with the respondent to determine the impact of the solution on low level constraints such as on individual feeders and branches depending on the type and preferred location of the solution.

Seasonal Demand The current annual load shape and average daily load shape for the existing feeders serving the Molonglo Valley area is shown in the figures below.

FIGURE 3: NORMALISED ANNUAL LOAD PROFILE peak 1.0

0.8

0.6

0.4

0.2 Demand (Normalised)

0.0

Jul Jul Jul Jul Jul

Jan Jan Jan Jan

Jun Jun Jun Jun

Oct Oct Oct Oct Oct

Apr Apr Apr Apr Apr

Feb Feb Feb Feb Sep Sep Sep Sep Sep

Dec Dec Dec Dec Dec

Aug Aug Aug Aug

Nov Nov Nov Nov

Mar Mar Mar Mar

May May May May Demand peaks annually during the winter months with a lower peak during summer and clear shoulder seasons in between. Summer peaks can reach similar levels as typical winter daily peaks, but annual peaks are much more likely to occur during winter.

The profile used by Evoenergy for assessing network capacity has a clear annual peak event approximately 10% higher than typical daily peaks.

Average Day The average daily load profile shows an evening peak after solar PV generating hours. There is no significant commercial or industrial loads during the day, which would be visible as a midday or early afternoon peak. These characteristics are expected to continue during the forecast period. There may be a decrease in demand during the middle of the day due to increased penetration of rooftop solar in the new housing developments. However, this does not directly impact the network constraint, which is driven by evening peak demand during winter months so adjustments for changes in solar PV generation have not been factored into the load forecast used for assessment purposes.24

FIGURE 4: NORMALISED AVERAGE DAY LOAD PROFILE 1.0

0.8

0.6

0.4

0.2 Demand (Normalised)

0.0

15:00 00:45 01:30 02:15 03:00 03:45 04:30 05:15 06:00 06:45 07:30 08:15 09:00 09:45 10:30 11:15 12:00 12:45 13:30 14:15 15:45 16:30 17:15 18:00 18:45 19:30 20:15 21:00 21:45 22:30 23:15 00:00

Extended Periods of High Demand The chart below shows the load profile during the week of the year with the most intervals above the thermal capacity of the existing network. For most non-network options, periods of persistently high demand that must be reduced or supplied through alternative means determines the cost and appropriateness of the solution.

FIGURE 5: WEEK OF PERSISTENT PEAK DEMAND (BASE CASE | POE50)

35 30 25 20 15 10 Demand (MW) 5 0 08-07 23:15 08-08 23:00 08-09 22:45 08-10 22:30 08-11 22:15 08-12 22:00 08-13 21:45 08-14 21:30

FY18/19 FY19/20 FY20/21 FY21/22 FY22/23 FY23/24 FY24/25 Capacity

The chart below shows the load profile during the week containing the annual maximum demand event. The days either side of the annual maximum demand event are mostly lower than the daily peaks in the week of persistent peak demand.

24 If a credible non-network submission is received that is partly dependent on midday rooftop solar PV generation Evoenergy may alter its assessment to include additional solar PV penetration in the load forecast.

FIGURE 6: WEEK OF ANNUAL MAXIMUM DEMAND EVENT (BASE CASE | POE50) 35 30 25 20 15 10 Demand (MW) 5 0 07-11 06:15 07-12 06:00 07-13 05:45 07-14 05:30 07-15 05:15 07-16 05:00 07-17 04:45 07-18 04:30

FY18/19 FY19/20 FY20/21 FY21/22 FY22/23 FY23/24 FY24/25 Capacity

Duration Curves The chart below shows the spare capacity on the existing feeders for each interval of the year for the Base Case POE50 scenario. Negative values (left hand side) indicate demand is greater than the thermal capacity of the feeders. There are a small number of intervals where demand is forecast to exceed capacity during 2022.

FIGURE 7: AVAILABLE CAPACITY DURATION CURVE (BASE CASE | POE50) 25

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Available Available Capacity(MW) -5

-10

-15

FY18/19 FY19/20 FY20/21 FY21/22 FY22/23 FY23/24 FY24/25

Distributed Energy Resources All detached dwellings in Stage 1A of Denman Prospect are required by the developer to install 3kW rooftop PV systems. Of all dwellings in this suburb, 30% are detached, making this the maximum likely penetration rate. There are no similar mandates for multi-unit or commercial buildings. Energy storage systems are voluntary to adopt.

Evoenergy is not aware of any developers who are planning on mandating or providing significant incentives for household battery installation.

4.4 Load Transfer Capability and Supply Restoration The forecasts for maximum demand across the Molonglo Valley area include all feasible load transfers to defer the reaching of thermal limits. No additional load transfers are possible.

The initial assessment assumes that there is sufficient capacity to transfer loads between the three feeders in the Molonglo Valley and the location of a non-network solution. However, non-network solutions are preferred to be located on the Black Mountain and Streeton feeders as these are most affected by load growth and because there are more opportunities to transfer load from Hilder to Streeton than in the other direction (Black Mountain and Hilder are not tied so can only transfer via Streeton). Where submissions are received for non- network solutions, Evoenergy will undertake a detailed review of the availability of load transfers to the proposed location of the solution and work with the non-network provider to confirm the expected performance of the solution to address network constraints.

4.5 Network Asset Failure Rate and Outage Duration The primary driver of the network augmentation is to manage thermal constraints on the network. Provision of redundancy after a network asset failure is not a significant value driver for this project.

The failure of a single 11kV feeder is the most likely asset failure that would impact supply in the Molonglo Valley. A failure of a zone substation transformer may result in temporary outages but there is currently sufficient capacity at the relevant zone substations that switching should be sufficient to restore load.

Where a non-network solution can provide redundancy, the value of that redundancy to Evoenergy will be quantified using the asset failure and outage restoration assumptions in the table below.

TABLE 11: NETWORK ASSET FAILURE RATE AND OUTAGE DURATION Assumption Value Probability of feeder failure 3%25 (per annum) Expected outage duration 8 hours26 (firm capacity exceeded) Expected outage duration 1 hour27 (load below firm capacity)

4.6 Discount Rate A discount rate of 2.78% has been applied in the initial assessment of options considered in this report. This corresponds to the average rate in Evoenergy’s 2019-24 final regulatory determination post-tax revenue model. This rate is a real vanilla WACC28 and all values discounted using this rate should be in real FY19/20 dollar terms. 4.7 Value of customer reliability Evoenergy will use a Value of Customer Reliability (VCR) of $34.11/kWh (real $2019) of unserved energy. This value was derived from the AER 2019 final report on VCR values29 using the ACT residential value of $21.38/kWh and commercial value of $44.52/kWh. A weighting of 45% residential and 55% commercial is used, which is the volume mix of forecast new loads in the Molonglo Valley area.

25 Evoenergy estimate used during initial assessment of options and in the Molonglo ZS PJR. 26 Evoenergy estimate used during initial assessment of options and in the Molonglo ZS PJR. 27 Evoenergy average 28 A 'real vanilla WACC’ is a financial term for the weighted average cost of capital (the return required by investors to provide equity and debt funding to a business) excluding tax effects (‘vanilla’) and inflation (‘real’). 29 https://www.aer.gov.au/system/files/AER%20-%20Values%20of%20Customer%20Reliability%20Review%20- %20Final%20Report%20-%20December%202019.pdf

The AER proposes annual escalation of VCR values using the CPI-X approach, where X is an adjustment for changes in customer preferences. Evoenergy has assumed that there will be no changes in customer preferences and VCR values will increase by CPI. Evoenergy’s assessment is in real terms so there will be no change in VCR values over the assessment period. 4.8 Approach to estimating project costs Evoenergy has conducted a preliminary bottom-up assessment of the capital costs of all network options. The cost of network options will be updated during the assessment phase of the RIT-D process.

Operating costs for new assets, such as zone substations, are estimated as a percentage of capital expenditure. The standard value used by Evoenergy is 1% of capital costs. This amount is typically used for comparison of long-lived capital asset options and is an average rate over the life of the asset. Evoenergy expects a similar amount of dollar operating costs (excluding payments to the non-network solution provider) for the management of non-network solutions and can therefore exclude these operating costs from the assessment of alternative options. An assessment of operating costs will be undertaken where there is an expectation of a significant difference in cost to Evoenergy between the two options being considered and the non-network solution provider can provide an accurate estimate of the operating costs that would be incurred by Evoenergy for their proposed solution.

5. POTENTIAL CREDIBLE NETWORK OPTIONS

5.1 Base case (Preferred Network Option) The base case is the investment included in the AER determination for Evoenergy’s 2019-24 regulatory control period.

The base case will establish a new zone substation in Molonglo in three stages. The first stage is to relocate Evoenergy’s mobile substation (referred to as a MOSS), which is a skid mounted 132/11 kV setup with 15 MVA transformer capacity and install two new feeders from the MOSS to the Molonglo Valley load centre. The first stage also includes civil works to establish the zone substation site, including space for the future permanent transformers and switchgear that will be installed in stages 2 and 3. Stage 1 is proposed to be completed by June 2021.

To enable the delivery of electricity from the substation to loads in the Molonglo Valley, Evoenergy will install new underground 11kV cable feeders (including the undergrounding and reconfiguration of a section of the Black Mountain feeder) from the Molonglo zone substation during 2021-24.

Stages 2 and 3 are expected to occur after 2025 and are FIGURE 8: EVOENERGY'S 132KV TRANSMISSION LINES AND to address long-term zone substation transformer PROPOSED MONLONGLO ZONE SUBSTATION SITE constraints in the Molonglo Valley. Additional feeders will be installed during stage 2 as this stage will add additional 11kV switches to enable more feeders to be connected to the zone substation. The need for stages 2 and 3 will be reassessed as demand approaches the capacity of the stage 1 zone substation.

5.1.1 Technical definition and characteristics

Substation The Molonglo zone substation site will be located on the northern side of William Hovell Drive to the east of Coulter Drive. Development works for the establishment of the MOSS at the Molonglo zone substation will include all earthworks, fencing, earthgrid, communications, drainage, roading, 132kV busbar and breakers. The MOSS will be relocated from its current location at Angle Crossing to Molonglo.

The 132 kV connection for the MOSS and future permanent zone substation will be via a loop-in-loop-out connection to the Stockdill-Woden 132 kV transmission line30. This includes the 132kV structure and busbar to enable the MOSS to be operational until the permanent zone substation infrastructure is constructed and commissioned during stages 2 and 3.

The completion of all three stages of the 132/11 kV 15 MVA Molonglo zone substation construction will accommodate the expected demand of the new suburbs in the Molonglo Valley, providing 55 MVA of additional firm delivery capacity. The new zone substation will also supply some loads outside the Molonglo Valley currently connected to the Civic and Woden zone substations. This will ensure that Civic and Woden zone substations reserve capacity that may be needed for new developments in their surrounding areas and may enable Evoenergy to defer future upgrades of those substations that would be required if the Molonglo zone substation was either not constructed or built with a lower final capacity.

Feeders During the establishment of the MOSS, any new loads in the Molonglo Valley will be connected to the Streeton and Black Mountain feeders. The Black Mountain feeder runs past the proposed Molonglo zone substation site and will be used to supply early loads connected to the MOSS.

All new feeders and feeder segments installed will be underground using 11 kV 3c/400mm2 AL XLPE cable.

The exact location of new feeders will be determined as the new suburbs are developed and will adjust for changes in patterns of development and load growth in the Molonglo Valley. Evoenergy plans to install two new feeders during the establishment of the stage 1 zone substation. The MOSS has limited 11kV switching so if more than two new feeders are installed during stage 1 the MOSS may not be able to utilise all of the feeders.

Evoenergy will install additional feeders during stage 2 to supplement the 11kV feeder capacity installed to the Molonglo Zone Substation during stage 1. These additional feeders will be enabled by the additional 11kV switches that will be installed during stage 2.

Construction timeframes The timing of the substation and feeder works is intended to precede thermal constraints on the existing 11kV feeders.

The establishment of the MOSS at Molonglo zone substation is expected to be completed by June 2021, while construction of feeders will respond to demand growth and is expected to continue until 2024.

The timing of future stages 2 and 3 will depend on the rate of load growth in the Molonglo Valley area.

5.1.2 Costs The preliminary cost estimate of this option is $29,201,553 comprising $22,887,445 for all three stages of the Molonglo zone substation and $6,314,108 for 11 kV feeders. These amounts are exclusive of contingency and GST.

The preliminary cost of this option and timing of expenditures is outlined in the table below.

30 ACT Second Electricity Supply Project, Evoenergy’s 132kV transmission line provided in Figure 2, available from https://www.evoenergy.com.au/-/media/evoenergy/about-us/act-second-electrical-supply-project- flyer.pdf?la=en&hash=BEF44DF61059BCEF46DB5621BA5AC374B4152AA4

TABLE 12: TOTAL COST BY YEAR (BASE CASE) FY24/25- FY28/29- FY19/20 FY20/21 FY21/22 FY22/23 FY23/24 TOTAL 28/29 33/34 Substation 9,733,908 8,418,947 4,734,590 22,887,445 Feeders 1,982,589 4,331,519 6,314,108 Total 0 11,716,497 0 0 0 12,750,466 4,734,590 29,201,553

5.2 Credible network options Evoenergy has considered three alternative network options. These were reviewed in detail in the Molonglo zone substation project justification report (PJR)31 submitted as part of Evoenergy 2019-24 regulatory proposal and were assessed to be more expensive than the base case option. For additional information and economic assessment of these options refer to the Molonglo zone substation PJR.

5.2.1 Alternative Network Option 1: Extend Hilder feeder and operate Streeton, Black Mountain and Hilder feeders to thermal limits Alternative Network Option 1 considers extending the 11 kV Hilder feeder to the Molonglo Valley load centre, and operating all three feeders up to their thermal limits. Currently, the Hilder feeder supplies parts of Coombs and Weston and is tied to the Streeton feeder at multiple points.

This option requires:  Bringing forward the planned undergrounding of the Black Mountain feeder  Directional drilling beneath the Molonglo River to extend the Hilder feeder

This option does not add any new capacity to the Molonglo Valley and only enables greater transfers between the existing feeders, allowing a tie between the Hilder and Black Mountain feeders and improved load restoration following a fault.

Alternative Network Option 1 is not selected as it is not a prudent or acceptable solution and would not defer construction of Molonglo zone substation and associated 11 kV feeders. The extended Hilder feeder will not provide long term benefits as the additional feeders installed alongside the new zone substation will provide sufficient capacity.

5.2.2 Alternative Network Option 2: Install new 11 kV feeders from existing zone substations

Alternative Network Option 2 considers installing new underground 11 kV feeders from existing zone substations to Molonglo Valley in two stages.

Typically, Evoenergy’s zone substations supply a radius of 5km. Only Civic and Woden are within this distance of the Molonglo Valley. Alternative options within 10km are the Latham and Belconnen zone substations.

 Woden zone substation has no spare 11kV circuit breakers and would require significant works to install additional feeders.  Civic zone substation has six spare 11kV circuit breakers but five are already allocated to new projects within the vicinity of the substation.  Latham zone substation has three spare 11kV circuit breakers  Belconnen zone substation has insufficient transformer capacity to take new loads without significant augmentation.

31 Molonglo zone substation PJR, November 2018, available from https://www.aer.gov.au/system/files/Evoenergy%20- %20Revised%20Proposal%20-%20Appendix%204.3%20-%20Molonglo%20ZS%20PJR%20- %20November%202018.pdf

Under this option Evoenergy will install 10 new feeders, five each from the Latham and Civic zone substations. Due to a lack of 11kV circuit breakers some feeders will be double banked to reduce cost. However, this will affect the reliability of supply for customers on these feeders.

The project would be implemented in the following stages:

Stage 1 (2021) – all civil works (trenching and directional drilling and installation of conduits) for the Latham–Molonglo feeders and installation of two feeder cables Latham–Molonglo. Stage 2 (2023) – installation of third feeder cable Latham–Molonglo. Stage 3 (2025) – installation of fourth feeder cable Latham–Molonglo. Stage 4 (2027) – installation of fifth feeder cable Latham–Molonglo. Stage 5 (2029) – all civil works (trenching and directional drilling and installation of conduits) for the Civic–Molonglo feeders and installation of two feeder cables Civic–Molonglo. Stage 6 (2031) – installation of third feeder cable Civic–Molonglo. Stage 7 (2033) – installation of fourth feeder cable Civic–Molonglo. Stage 8 (2035) – installation of fifth feeder cable Civic–Molonglo.

Alternative Network Option 2 is not selected due to; its higher net present cost, constructability issues, long feeder lengths causing derating, voltage drop, network losses and a need for additional investment in voltage regulating devices, future reliability concerns due to feeder lengths with multiple joints in close proximity to each other and space constraints limiting the required extension of switchboards at the Latham and Civic switch rooms.

5.2.3 Alternative Network Option 3: Construct Molonglo zone substation in two stages

Alternative Network Option 3 involves establishing a new 132/11 kV Molonglo zone substation in two stages. Stage 1 will install an initial 55 MVA transformer by June 2021. Stage 2 will add a second 55 MVA transformer.

This option has the same end result as the base case option, a permanent dual 55 MVA transformer zone substation at Molonglo. However, under this option the MOSS is not used, which increases the upfront capital cost. This option reduces risks associated with reusing the MOSS, which may require significant maintenance after being moved.

The scope of works involved in establishing the Molonglo zone substation includes:

 Installation of a new Molonglo zone substation equipped with one 132/11 kV 30/55 MVA transformer and one 11 kV switchboard by June 2021.  Installation of a second 132/11 kV 30/55 MVA transformer and second 11 kV switchboard by 2030 (exact timing dependent on rate of load growth and value of energy at risk).  Installation of 11 kV feeders from Molonglo zone substation to the load centre.

Leading up to June 2021, new loads in the Molonglo Valley will be connected to the Streeton (supplied from Woden zone substation) and Black Mountain (supplied from Civic zone substation) feeders. These feeders will be operated up to their thermal limits until the Molonglo zone substation and new feeders are available.

Alternative Network Option 3 was not selected due to its higher net present cost. However, it is the primary fallback option if the relocation of the MOSS fails as a large amount of the early design (132kV system, site plan, etc.) and civil works will be mostly identical for both this option and the base case.

6. POTENTIAL CREDIBLE NON-NETWORK OPTIONS

Evoenergy’s initial assessment of non-network solutions for the Molonglo Valley area has found two credible non-network options. These are both based on the use of batteries to temporarily defer investment in a network augmentation.

The initial analysis for the Molonglo Valley32 determined that the use of a network owned battery to defer the zone substation investment was not a credible option. A third-party owned battery was at the time of that analysis was also not a credible option. However, ACT government policies, such as the inclusion of ACT located batteries in the ACT Renewables Reverse Auction program, trials of batteries by energy companies and declining prices may change the business case for a third party owned battery to provide network support services.

The potential credible options assume that a battery will be installed with a primary purpose that is not to support Evoenergy’s network with a commercial arrangement to support Evoenergy’s network during times of peak demand. That is, the value available to defer the network option, is unlikely to be sufficient to entirely fund the required battery and additional investment drivers are likely to be required. Examples include as part of a larger energy investment project, due to a government program obligation, for wholesale electricity price arbitrage, participation in the FCAS market or as part of a back-up system for an electricity user. The majority of the battery’s value will come from the primary purpose, with grid support payments providing an additional revenue stream.

Evoenergy has undertaken a preliminary evaluation of a wide range of non-network options for Molonglo such as demand management and embedded generation. While these services were assessed to be less likely to deliver a credible non-network solution for the Molonglo constraint, Evoenergy is technology/solution agnostic and seeks submissions on all solutions to defer investment at this site. This includes receiving partial solutions for Evoenergy to evaluate whether it can combine solutions to address the identified need.

6.1 Non-Network Option 1 – Batteries located within Molonglo load centre Technical definition and characteristics Non-Network Option 1 involves two or more batteries located within the Molonglo Valley District near existing loads or within new developments. Two batteries would be most optimally located where each is connected to the Black Mountain and Streeton feeders at 11kV. Where there are three or more batteries, they may also connect to the Hilder feeder. Approximately equal sized batteries are expected to most efficiently meet the identified need, but this is not a requirement and some locations may be better suited to smaller or larger batteries. These factors will be considered in more detail during the consultation phase as multiple battery providers may be included in a credible non-network option.

A larger number of residential or commercial ‘behind-the-meter’ batteries connected to the low voltage network and aggregated via a Virtual Power Plant (VPP) scheme may also meet Evoenergy’s requirements, either as a standalone solution or paired with a larger 11kV connected battery. Such an arrangement may spread the batteries across a larger geographic area and prevent local constraints from limiting the effectiveness of the batteries to discharge during network peak events.

Evoenergy will consider submissions for small-medium sized batteries and VPPs from multiple independent respondents if the solution from each respondent individually does not address the network constraint but together can. Evoenergy will coordinate between the multiple respondents to develop a complete solution. Each respondent will remain responsible for the identification of a suitable site, land acquisition and the connection process to install batteries to the network.

32 Molonglo zone substation PJR, November 2018, available from https://www.aer.gov.au/system/files/Evoenergy%20- %20Revised%20Proposal%20-%20Appendix%204.3%20-%20Molonglo%20ZS%20PJR%20- %20November%202018.pdf

To reduce unserved energy in the Molonglo Valley to defer the zone substation construction by one year, the combined battery size must be approximately 4MW/8MWh or higher. Smaller batteries may be sufficient to avoid most but not all of the expected unserved energy, but the funds available for deferral will be significantly reduced due to the higher unserved energy costs.

Batteries located at the load centre may be able to provide network support services in the future to defer the installation or extension of additional 11kV feeders to the local area if required by demand growth. However, there is a high degree of uncertainty about future feeder investments. Evoenergy cannot commit additional funds for potential future benefits at the time of the batteries being installed. This may form a future revenue stream for a battery but is highly uncertain.

This option has been identified as a credible non-network option by Evoenergy. It minimises the immediate investment at the future Molonglo zone substation site and the batteries have the potential to provide future services to support Evoenergy’s network. Evoenergy seeks market feedback regarding the effectiveness of this option and other options as market participants may have alternative solutions that are more viable or special insights into the effectiveness of solutions that Evoenergy is not aware of.

Estimated construction timetable and commissioning date Batteries must be installed by the end of FY20/21 or at the latest November 2021 to be operational for the summer 2021/22 peak. Batteries may also be installed earlier than these dates. Submissions should detail the proposed timeline, inclusive of the network connection process.

6.2 Non-Network Option 2 – Battery located at future Molonglo zone substation site Technical definition and characteristics Non-Network Option 2 involves a single large battery located at or near the future Molonglo zone substation site. Evoenergy will complete initial site works and new feeders from the future zone substation site connecting to the load centre. The feeder investment is identical to the feeder component of stage 1 of the preferred network option. The battery will be able to use the new feeders to charge and discharge until the new substation is built. The Black Mountain feeder, which runs past the site, may also be available to the battery.

This option enables a single, larger battery to be installed. This may suit some non-network providers that are intending to install a battery for a purpose that requires larger sizes than are appropriate for locations not near a zone substation. After the zone substation is installed, and more so after stage 2 is completed, the battery will be located with a low likelihood of constraints on the Evoenergy network, which will reduce the risk of network constraints limiting the operation of the battery. The battery owner may be required to pay rent to Evoenergy for the duration of the battery’s life if the battery is located on Evoenergy owned land and will be responsible for disposal/removal.

As the battery will be located away from the load centre, there will be limited opportunities for the battery to provide network support services after the zone substation is built. The available funds for deferral are also lower due to Evoenergy needing to invest in the site and feeders to enable the deferral.

Estimated construction timetable and commissioning date Batteries must be installed by the end of FY20/21 to be operational for the summer 2021/22 peak. Submissions should detail the proposed timeline, inclusive of the network connection process. 7. TECHNICAL INFORMATION FOR NON-NETWORK OPTIONS

7.1 Target Area Non-network solutions must be located such that they are able to support the capacity of the existing 11kV feeders in the Molonglo Valley. In practice, this requires the non-network solution to be located along the trunk of each feeder.

Evoenergy, subject to the constraints imposed by the NER, will support non-network service providers on land options for their solutions. This may include making available Evoenergy owned sites and negotiating with ACT government departments and developers.

Distributed non-network solutions, such as demand management, should be spread throughout the Molonglo Valley District to be able to support all three existing feeders (Evoenergy’s forecasts indicate all three feeders will exceed their thermal capacity by 2022). Distributed solutions that are contained to a small portion of the area (such as a few large loads in a commercial area) may not be able to manage constraints on some feeders so are unlikely to be appropriate as a standalone solution.

Centralised or partially centralised non-network solutions, such as large batteries or embedded generators, should be located close to the load centre and near the feeder ties to be most effective. A solution with multiple batteries/embedded generators spread over the load area is likely to be more effective than a single system.

Evoenergy will also consider non-network solutions located at or near the future Molonglo Zone Substation site. This will require Evoenergy to complete site establishment works and installation of new feeders from the zone substation site to the load centre to enable the non-network solution to support the capacity of the existing feeders. As the capital investment that can be deferred by Evoenergy will be lower, the maximum fund available to pay for deferral will also be lower. There are also uncertainties regarding the exact location of the future zone substation and land purchase timing that must be resolved before Evoenergy can commit to an option located at the future zone substation site.

The general area is shown on the map below.

FIGURE 9: MOLONGLO VALLEY TARGET AREA

7.1.1 Specific target area The below maps show the preferred locations for the location of:

1. Two batteries at the load centre, one in the new suburb of Whitlam on the Black Mountain feeder and a second in Denman Prospect on the Streeton feeder 2. A single battery at the future Molonglo zone substation site with new feeders to be installed to ensure the battery can be charged and discharged before the new zone substation is established.

FIGURE 10: TARGET AREA FOR BATTERIES AT THE LOAD CENTRE

Note: BESS 2 is pointing towards the next stage of Denman Prospect located to the north of the existing developed area. The initial assessment of locations indicate the battery can be located within either the existing or under development stages of Denman Prospect.

FIGURE 11: TARGET AREA FOR BATTERY AT THE FUTURE MOLONGLO ZONE SUBSTATION SITE

7.2 Contributions to power system security, reliability and/or fault level The non-network solution is not required to contribute to power system security and/or fault level.

Evoenergy uses a probabilistic planning approach that values reliability in terms of unserved energy. There are no regulatory obligations to maintain redundancy in the ACT.

Power system security and fault level is not applicable as the project focus is in the distribution network. Any benefits that a non-network option provider may provide for power system security is likely to be small and the benefits would not flow to Evoenergy or its customers.

The non-network solution must meet all Evoenergy criteria, including the connection policy where required.

7.3 Investment timing requirements Evoenergy’s forecast for the Molonglo Valley indicates that under the base case the thermal constraints of the 11kV feeders will be reached by summer 2021/22. The identified network option will result in a new substation and additional feeders being completed by the end of FY20/21.

A non-network solution to defer the zone substation will need to be commissioned and ready to operate by the end of FY20/21 or at the latest by the start of summer 2021/22 (before November 2021). The non-network solution must enable Evoenergy to defer the zone substation construction by at least one year to end of FY21/22. This requires the non-network solution to meet the 2022 winter peak while the zone substation will be operational for the 2022/23 summer peak.

Where the non-network solution involves batteries or embedded generators, submissions should account for the connection approval process timelines as per the National Electricity Rules. Evoenergy will follow its standard processes for approving connections and is not able to offer expedited approval timelines for submissions responding to this report.

Where a submission is to locate a battery at the future zone substation site, Evoenergy will have the site prepared and new feeders installed by the end of FY20/21. Site preparation works will begin early-mid FY20/21. A non-network solution using this option must defer the completion of the zone substation and 132kV lines to the site being until the end of FY21/22. 7.4 Technology Specific Requirements

7.4.1 Battery Evoenergy’s analysis indicates that it may be feasible for a battery to defer the network investment by one year. There is a low likelihood of deferral for two years. The size of battery required for a three year deferral is prohibitively large to fit within the target area and is approaching sizes that are unlikely to be connectable to an 11kV network.

Size and capacity Evoenergy has used a probabilistic model to test a range of battery sizes and calculated the expected unserved energy. This modelling assumes the battery is fully dedicated to network constraint management. Additional unserved energy may result from other battery control types.

Both the MW discharge rate and MWh capacity of the battery are necessary to evaluate the effectiveness of a battery solution to meet the network constraint.

The table below shows the calculated expected unserved energy (the probability weighted average across all scenarios) forecasts for five battery sizes.

TABLE 13: EXPECTED UNSERVED ENERGY FORECAST ESTIMATES BY BATTERY SIZE Battery Size FY19/20 FY20/21 FY21/22 FY22/23 FY23/24 FY24/25 2 MW / 4 MWh - - 251,294 9,763,960 27,365,707 46,909,070 4 MW / 8 MWh - - 29,880 5,517,152 18,524,513 34,941,471 8 MW / 16 MWh - - 328 1,640,825 8,670,235 19,099,677 16 MW / 32 MWh - - - 127,561 1,761,763 5,848,192 16 MW / 64 MWh - - - - 284,730 1,534,238 Table Notes: Unserved energy values only includes unserved energy due to reaching thermal limits of existing feeders and does not include possible additional losses under n-1 asset failure scenarios.

The results presented in the table show that an 8MW/16MWh battery can reduce expected unserved energy to $328 in FY21/22. This shows that a battery of this size is a good option for deferral. A 4MW/8MWh battery will result in $29,880 of unserved energy during FY21/22. This may be an acceptable option as the available funds for deferral (see section 7.5), which must cover both unserved energy costs and payments to non- network providers, are much higher than this amount. A 2MW/4MWh battery would result in a much higher expected unserved energy cost that may be larger than the available funds for deferral. Only a 16MW/32MWh or larger battery would result in an expected unserved energy cost less than the available funds for deferral in FY22/23.

The charts below shows duration curve of energy reduction required to ensure there is no unserved energy under the base case and the high case. Due to load growth the quantity of energy that must be discharged from a battery (or dispatched by an embedded generator or withdrawn through demand management) increases rapidly over time. The number of days requiring some form of intervention also increases rapidly over time.

FIGURE 12: DAILY ENERGY REDUCTION REQUIRED (BASE CASE | POE50)

Required (MWh/day) DailyEnergy Reduction

1 6

56 66 11 16 21 26 31 36 41 46 51 61 71 76 81 86 91 96

101 106 111 116 121 126 131 136 141 146

FY21/22 FY22/23 FY23/24 FY24/25

In the highest scenario (High Case | POE10), the energy required during the highest demand days is significantly higher (49.0MWh in 2023) than in the base scenario (Base Case | POE50) (18.7MWh in 2023). However, the probability of the highest scenario is relatively small.

FIGURE 13: DAILY ENERGY REDUCTION REQUIRED (HIGH CASE | POE10)

120 100 80 60 40

Required (MWh/day) DailyEnergy Reduction

1 6

11 26 16 21 31 36 41 46 51 56 61 66 71 76 81 86 91 96

101 106 111 116 121 126 131 136 141 146

FY21/22 FY22/23 FY23/24 FY24/25

Control/direction capabilities The effectiveness of a battery to manage network capacity constraints depends on how the battery is managed. There are a range of options that a battery operator may propose. Several options are presented below.

TABLE 14: SELECTION OF BATTERY OPERATION TYPES Battery Suitability Expected Battery Correlation to Evoenergy Network Operation for Operation Constraints Type Evoenergy Wholesale prices are generally higher in the evening when demand generally also peaks Discharge during high in the Molonglo Valley but local network Wholesale price events, generally constraints are more likely to be driven by Not suitable electricity caused by generator local weather and there is a reasonable in isolation arbitrage availability in NSW and likelihood that a local network peak event weather events in NSW could occur at a time of low wholesale prices in NSW. Discharge mostly linked to contingency Charge/discharge under events such as a generator failure and short direction of AEMO to term balancing of the market. Unlikely to Not suitable FCAS maintain system coincide with local network constraints and in isolation frequency may worsen constraints by charging at these times If Evoenergy can accurately forecast network Battery operates under Day-ahead constraints at least a day in advance one of the above types quarantine of unserved energy can be avoided. This type is except when Evoenergy required most appropriate where only a few days a forecasts a constraint, at battery year are expected to require the battery. Medium which time the battery capacity for Battery provider may lose revenue on these switches to supporting network days and may require additional payments the network only on the support after a contracted number of days of network day of the constraint. support are reached. Battery is always in a Full time fully charged state and The battery will always be ready to support network discharges when the network but will have reduced revenue High support network constraints from other sources. occur.

The chart below shows a simplified battery dispatch profile during the peak week during 2023 in the Base Case | POE50 scenario. In this case the battery is fully dedicated to managing network capacity so immediately charges after demand drops below network capacity to ensure it is ready for the next demand event. This method of operation prevents the battery being used for electricity price arbitrage or participation in the FCAS markets so is unlikely to represent the actual operation of a battery. Depending on the size of the battery, some capacity may continue to be used for other revenue generating activities during this time.

FIGURE 14: INDICATIVE BATTERY PROFILE, WEEK OF PERSISTENT PEAK DEMAND (2023, BASE CASE | POE50) 30 25 20

15 MW 10 5 0 07/08 08/08 08/08 09/08 09/08 10/08 10/08 11/08 11/08 12/08 12/08 13/08 13/08 14/08 23:15 11:15 23:15 11:15 23:15 11:15 23:15 11:15 23:15 11:15 23:15 11:15 23:15 11:15

Demand Charge Discharge Capacity

Use of system charges for charging of stand-alone battery storage systems

Evoenergy’s current suite of electricity network tariffs are highly cost reflective for market customers. However, Evoenergy recognises that they were not specifically designed to apply to stand-alone battery storage systems and therefore will not apply to any stand-alone battery storage system. We intend to consider more fit for purpose tariffs in our next pricing review which would then be in place from July 2024.

In light of this, Evoenergy is willing to consider waiving both distribution use of service charges and transmission use of service charges for standalone batteries responding to this RiT-D until June 2024.

7.4.2 Demand Management Evoenergy’s preliminary analysis33 indicated that demand management is unlikely to be available in sufficient quantities in the required locations to provide the required deferral capabilities.

Should a submission include demand management as a component of a non-network solution, the technical characteristics in the sub-sections below will be incorporated into the submission.

Customer demand characteristics To be effective, the customers that will provide a demand reduction must ordinarily demand energy during network peak times. It must also be demonstrated that the customers have the sufficient demand flexibility to reduce demand during these times when requested.

The submission must detail the certainty that demand will be reduced and the maximum demand reduction that can be accessed over different time periods, for example if there is a limit on how much demand can be reduced over a single hour, day or week.

Required characteristics The submission must outline how demand reduction requests will be managed and the required notice period before each demand management event.

33 Molonglo zone substation PJR, November 2018, available from https://www.aer.gov.au/system/files/Evoenergy%20- %20Revised%20Proposal%20-%20Appendix%204.3%20-%20Molonglo%20ZS%20PJR%20- %20November%202018.pdf

Temporary demand management vs permanent demand management The objective of this NNOR is to find options to defer a large network investment over the short term. Temporary demand management is expected to be more appropriate for this.

Due to the significant demand growth expected in the Molonglo Valley district over the next 30 years, permanent demand reduction may have benefits for deferring later stages of the Molonglo zone substation project. These benefits may be considered by Evoenergy when reviewing submissions but only where the solution meets the minimum requirement of deferring the zone substation construction by at least one year.

7.4.3 Embedded generator To meet the network constraint in the Molonglo area (non-dispatchable) renewable embedded generators are not suitable as the primary component as the must be paired with a large battery or non-renewable generator. Therefore, if renewable embedded generators are included in a non-network proposal it is expected to be as a sub-component of a primarily battery or diesel/gas based system.

Diesel or gas powered generators may be a feasible option and could also be paired with a battery and/or renewable embedded generators. The fuel costs for a generator in FY21/22 and FY22/23 may be small relative to the funds available for deferral, but the fixed costs of establishing the generator connection and purchase/rental of the generating unit may be large.

A likely scenario is where a generator planned to be used as an emergency backup for a major electricity user is made available for 1-2 years to provide network support. Alternatively, a generator may be temporarily connected to provide network support and then removed to be used elsewhere by the owner.

A non-network service provider including diesel or gas powered generators in a proposal will need to show that they can obtain the required approvals from the territory government and other regulators to install and operate the generators.

Due to the ACT Government Zero Emissions Policy34 the installation of a diesel or gas powered generator may be opposed by government parties. It is not known to Evoenergy if generators that may be installed for emergency back-up purposes (the most likely situation that Evoenergy expects government approval may be granted) are restricted from providing grid support services.

The table below shows the expected generation required from an embedded generator, the maximum output in any 15 minute period in the highest demand forecast scenario and the expected value of unserved energy for a dispatchable generator of selected sizes. A generator sized larger than the expected capacity shortfall in the High Case | POE10 scenario will have zero expected unserved energy.

TABLE 15: EMBEDDED GENERATOR DEFERRAL STATISTICS FY19/20 FY20/21 FY21/22 FY22/23 FY23/24 FY24/25 Expected Generation - - 35 513 1,175 1,848 (MWh) Max Output (MW) 5.0 10.0 12.8 14.9 (High Case | POE10) USE - - $85,184 $5,812,748 $17,777,922 $32,087,629 (2 MW generator) USE - - $2,203 $1,507,063 $7,063,819 $15,100,762 (4 MW generator) USE - - - $10,249 $500,136 $2,044,100 (8 MW generator) Table Notes: Unserved energy values only includes unserved energy due to reaching thermal limits of existing feeders and does not include possible additional losses under n-1 asset failure scenarios.

34 https://www.environment.act.gov.au/cc/zero-emissions-government/zero-emissions-government-framework

The table above shows that a 5MW generator is necessary to have zero unserved energy during FY21/22. A 4MW generator will result in an expected unserved energy of $2,203, which is much smaller than the available funds for deferral and therefore a suitable option. A 2MW generator results in more unserved energy but this amount is also less than the available funds for deferral and may be a reasonable option. A generator is expected to produce 35MWh of output during FY21/22, which will determine the fuel costs that will need to be considered by a non-network provider. The deferral payments are expected to cover the operating expenses of a generator. However, the deferral payments are small compared to capex costs for connecting and having a generator. Evoenergy’s assessment is that the only viable embedded generator solution is where a large business is already installing a generator as emergency back-up and has already committed to covering the capital costs of installation and connection. Viability depends on if any businesses have plans to install emergency backup in the network constraint area (and due to locational constraints would probably require at least 2 generators geographically separated). Viability also depends on the limitations included in the government approval for the generator, which may prevent the generator being used for services (such as network support) that are not a strict definition of emergency backup. 7.5 Available funds for deferral The available funds for deferral are determined by the financial benefits to Evoenergy of deferring capital expenditure. For the identified need in the Molonglo Valley, the deferral benefit is made up of two components, avoided financing costs and avoided depreciation of capital assets.

Deferral benefits are calculated annually. The proposed option must defer at least part of the network option build from FY20/21 to FY21/22, FY22/23 or beyond (beyond FY22/23 is considered extremely unlikely).

Deferral of components of the construction of the proposed Molonglo Zone Substation and associated 11kV feeders will avoid financing costs incurred by Evoenergy during the period of deferral. Evoenergy has calculated these deferral benefits using the WACC approved by the AER in the 2019-24 regulatory determination.

Deferral will also reduce depreciation of capital assets during the deferral period. Evoenergy uses a 40 year depreciation lifetime for substation assets and a 50 year lifetime for distribution lines. The deferral benefit for an investment deferred by one year is calculated as: value * WACC + value / lifetime

For simplicity, opex costs incurred by Evoenergy to manage the non-network option are assumed to be equal to incremental opex costs that the network investment would have required. Network assets generally do not require opex when they are new so the value of opex for the network option would be low during the deferral period.

The available funds for deferral is required to cover both payments to the non-network service provider, unserved energy costs and any risk margin required by Evoenergy.

A risk margin may be required by Evoenergy where there is uncertainty whether the deferral will be successful. An example is where a significant new development occurs in the target area, requiring the zone substation to be constructed as per the base case timeline and resulting in a loss of value to Evoenergy of any payments already made to a non-network service provider.

TABLE 16: DEFERRAL VALUE (FY19/20 PAYMENT) Location Defer to FY21/22 Defer to FY22/23 Defer to FY23/24 Molonglo ZS Site $260,000 - $340,000 $530,000 - $690,000 $790,000 - $1,030,000 Load Centre $460,000 - $570,000 $910,000 - $1,140,000 $1,370,000 - $1,710,000

The table above shows the range of maximum value of deferral to Evoenergy in FY19/20 present value terms. The range covers the uncertainty in the preliminary cost estimates for the base case network option and does not incorporate uncertainty in other variables such as demand growth and uncertainty in the effectiveness of the non-network solution.

The deferral value calculation only considers costs that are avoidable by Evoenergy during the deferral period and not the total cost of the preferred network option.

If there are no additional costs to Evoenergy (including unserved energy costs, administration costs and risk margins) a non-network solution provider can receive total payments, in present value terms, up to the amounts presented in the table. This could be as a once off payment, but is more likely to be structured as an availability payment plus a variable component linked to the actual usage of the non-network solution by Evoenergy. Evoenergy will consider and negotiate pricing structures included in a submission.

8. SUBMISSIONS

This section provides non-network providers with an invitation for submissions, guidance on how to make submissions, and supporting information. Submissions are intended to provide non-network providers and interested parties with an opportunity to propose how they could address the identified need through alternative potential credible options. 8.1 Invitation for submissions Evoenergy is seeking submission from interested providers of credible non-network options that either partially or completely address the identified need outlined within this NNOR.

All submissions should completely and comprehensively address the required information listed in Section 8.2 and include information listed within Evoenergy’s Demand Side Engagement Strategy35.

Where additional information is required by a non-network provider in addition to that provided in this report, it is recommended that non-network providers contact Evoenergy as early as possible to allow adequate time for response.

Requests for additional information will be anonymised and published with Evoenergy’s response on the Evoenergy website. Initial responses will be provided within 10 days. Non-network providers are encouraged to regularly check the website as it will be updated with frequently asked questions (FAQs) during the submission period.

All requests for additional information and lodgement of submissions should be directed to:

35 Page 10 of Evoenergy Demand Side Engagement Strategy, 2018, available from https://www.evoenergy.com.au/- /media/evoenergy/documents/demand-management/demand-side-engagement- strategy.pdf?la=en&hash=FA65B91E871F114D009C3C26468AE3EF4B6D7E38

Email: [email protected] The period for requests for additional information closes on 5 June 2020 at 5pm. Submissions must be lodged by 23 June 2020 at 5pm.

All submissions will be published on the Evoenergy website unless otherwise requested. Please indicate if you do not wish to have your submission published in part or in full.

8.2 Information from non-network providers

Each submission must provide sufficient information and detail for Evoenergy to determine that the proposed non-network solution is feasible. To be considered feasible, any non-network solution must be technically feasible, commercially feasible and able to be implemented in sufficient time for deferral of the network investment. In the absence of any viable solutions, the preferred network solution is to be commissioned by summer 2021/22.

Evoenergy is seeking proposals that provide sufficient detail about the type and likely scale of non-network solutions offered by market providers. Respondents are not required to provide detailed costing of proposed solutions in response to this report, however, proposals should include as much information as possible.

Non-network providers must make a submission using the Special Connection Request form.36 This includes the following information as a minimum:

1. Non-network provider name and contact details, 2. Overview of the proposal and the extent to which it addresses the identified need, 3. A technical description, including but not limited to: a) Location(s), site plan, and specifically if the non-network solution is contained within the target area, b) Size of the peak load reduction (including any standards/methodologies relied upon to determine the load reductions) or additional supply capacity (temporary or permanently connected generators) offered c) Electrical layout schematics/single line diagram (if applicable), d) Network connection requirements (if applicable), e) Contribution to power system security or reliability, f) Contribution to power system fault levels and load flow and stability studies (if applicable), g) Operating profile, h) How each of these matters is consistent with applicable technical standards, and i) A backup plan in the event of a battery failure (if applicable). 4. Implementation timeline, estimated lifespan and key milestones, 5. Measurement and verification procedures, 6. Proposed operational and contractual commitments, including financier commitments, 7. Planning application information (where required), 8. List of services and prices to be provided which may include: a) Availability payment (payment which guarantees availability of the non-network option regardless of whether it is required or not); b) Demand reduction in terms of maximum power ($/kVA) and/or energy delivered ($/kWh); or c) Total cost to provide services to meet identified need d) Other more detailed/complex service offerings and price schedules 9. Required notice time for availability (and any impact on prices for services where this notice time is not provided),

36 Evoenergy Special Connection Request form, available from https://www.evoenergy.com.au/emerging- technology/embedded-generation/special-connection-request

10. Potential risks associated with the proposal and a comparison with the risks associated with the deferred network augmentation option, and any actions that can be taken to mitigate these risks. This assessment should address the risk of not meeting the demand requirement and the compensation arrangements that would apply in such circumstances, and 11. Testimonials.

Non-network providers may be invited to present their proposals to Evoenergy as part of the evaluation process.

8.3 Next steps Following the publication of the NNOR, non-network providers will have a period of 3 months to collate the information required and provide submissions to Evoenergy for non-network solutions to achieve or partially achieve the identified need.

The RIT-D process from this point involves the following upcoming activities:

1. A public briefing session is held to provide answers to non-network providers’ questions about the NNOR content. 2. Submissions close for non-network providers to submit non-network option proposals. 3. A draft project assessment report37 is released. 4. Consultation with the preferred non-network provider(s) is undertaken. 5. A final project assessment report38 is released. 6. Contracts with non-network providers is confirmed (where applicable) or a network option is progressed. Evoenergy strongly recommends that non-network providers also commence engaging in the connection process early, to optimise alignment of timing with the identified need as well as with processing times.

8.3.1 Timeline An overview of the timeline, from the publication of this NNOR to when the preferred option is required to be operational, is provided in Table 17 below.

37 As per NER clause 5.17.4(i)-(n) 38 As per NER clause 5.17.4(o)-(s)

TABLE 17: TIMELINE ACTIVITIES DATES Publish NNOR and request for submissions39 27 March 2020 27 March 2020 - 25 Consultation period40 for non-network providers to provide submissions June 2020 Public briefing session during consultation period – Details to be confirmed April 2020 Evoenergy review of submissions received (non-network proposals) June 2020 – July 2020 Draft project assessment report41 is released August 2020 August 2020 – Consultation period for preferred option and request for submissions42 September 2020 September 2020 – Evoenergy review of submissions received October 2020 Publish final project assessment report43 November 2020 Prepare draft contract(s) with preferred non-network provider(s) (where a non- November 2020 – network option or options are preferred) December 2020 Preferred option operational November 2021

8.3.2 Documents Documents that are intended to be released include:  FAQs document,  Draft project assessment report, and  Final project report.

39 Evoenergy will notify registered parties on DSE-RIP form As per NER clause 5.17.4(g), available from https://www.evoenergy.com.au/emerging-technology/demand-management 40 Not less than 3 months in duration from notifying registered parties on DSE-RIP as per NER clause 5.17.4(h) 41 Within 12 months of end of consultation period on NNOR as per NER clause 5.17.4(i) 42 Not less than 6 weeks in duration from publication of the draft assessment report as per NER clause 5.17.4(m) 43 As soon as practicable after the end of the consultation period on draft project assessment report as per NER clause 5.17.4(o), unless NER clause 5.17.4(p) applies

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DOCUMENT OWNER PUBLISH DATE REVIEW DATE Strategy & Operations 27/03/2020 N/A