Appendix A - Australian Energy Regulator · 27 November 2015 7 Figure 1 – Indicative Tariff Formulation Process under New Pricing Rules 2.3.1 Efficient tariffs Ausgrid’s starting

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Appendix A

Revised Tariff Structure Statement

October 2016

27 November 2015

Contents

1 INTRODUCTION ......................................................................................................... 4

2 FURTHER BACKGROUND INFORMATION .............................................................. 5 2.1 What is a Tariff Structure Statement? ............................................................... 5 2.2 Regulatory and legal requirement for Tariff Structure Statement ...................... 5 2.3 Ausgrid’s approach to setting tariffs .................................................................. 6 2.4 Overview of developments in our regulatory environment ................................ 9 2.5 Overview of developments in our volume environment .................................. 12 2.6 Overview of the AER Issues Paper, Public Hearing and Draft Decision on

our initial TSS .................................................................................................. 13

3 FURTHER INFORMATION ON TARIFF CLASSES .................................................. 15 3.1 Rule requirement ............................................................................................. 15 3.2 Background ...................................................................................................... 15 3.3 Tariff classes.................................................................................................... 16 3.4 Future issues to consider ................................................................................ 17

4 FURTHER INFORMATION ON LONG RUN MARGINAL COST .............................. 18 4.1 Rule Requirements .......................................................................................... 18 4.2 Economics of network pricing .......................................................................... 18 4.3 Role of marginal cost ....................................................................................... 19 4.4 Methodologies for estimating marginal cost of electricity distribution ............. 20 4.5 Methodology for estimating long run incremental costs of electricity

distribution ....................................................................................................... 20

5 FURTHER INFORMATION ON RESIDUAL COST RECOVERY ............................. 30 5.1 Rule Requirements .......................................................................................... 30 5.2 Economic rationale of residual cost recovery .................................................. 30 5.3 Principles for residual cost recovery ................................................................ 32 5.4 Potential approaches to residual cost recovery ............................................... 33 5.5 Methodology for allocating residual costs ....................................................... 33 5.6 The economic desirability of Ausgrid’s approach to residual cost recovery .... 46

6 FURTHER INFORMATION ON DEPARTURE FROM EFFICIENT PRICING PRINCIPLES ........................................................................................................... 48

6.1 Rule Requirement ............................................................................................ 48 6.2 The role of efficient tariffs in the indicative price-setting process .................... 48 6.3 Efficient pricing outcomes ................................................................................ 49 6.4 Is there a need to vary indicative tariffs from efficient outcomes? .................. 62 6.5 Key reforms ..................................................................................................... 64

7 ASSESSMENT OF CROSS SUBSIDIES .................................................................. 69 7.1 Rule Requirement ............................................................................................ 69 7.2 Economic Concept of Subsidy ......................................................................... 69 7.3 Efficiency bounds test at tariff class level ........................................................ 70 7.4 Inherent cross subsidies at the individual tariff level ....................................... 72

8 FURTHER INFORMATION ON INDICATIVE PRICES ............................................. 73 8.1 Rule Requirement ............................................................................................ 73 8.2 Ausgrid’s approach to developing indicative prices........................................ 73

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8.3 Overview of Ausgrid’s indicative price-setting process under the first stage of the network pricing process ........................................................................ 75

8.4 Summary of the indicative pricing outcomes at the NUOS level under stage one of the network pricing process ................................................................. 76

9 CUSTOMER IMPACTS FOR BUSINESS CUSTOMERS ......................................... 77

10 COMPLIANCE CHECK LIST ..................................................................................... 80

11 STAKEHOLDER ENGAGEMENT ............................................................................. 88 11.1 Rule requirement ............................................................................................. 88 11.2 Ausgrid’s process for engaging with stakeholders .......................................... 88 11.3 Key issues raised by stakeholders .................................................................. 93

12 DESCRIPTION OF TARIFF STRUCTURE AND CHARGING PARAMETERS ...... 105 12.1 Residential Non-TOU (EA010) Tariff (Closed from 1 July 2018) .................. 105 12.2 Residential Transitional TOU (EA332) Tariff (Open from 1 July 2018) ......... 106 12.3 Residential Time of Use (TOU) (EA025) Tariff .............................................. 107 12.4 Controlled Load (EA030/EA040) Tariffs ........................................................ 108 12.5 Small Business Non-TOU (EA050) Tariff (Closed from 1 July 2018) ............ 109 12.6 Small Business Transitional TOU (EA333) Tariff (Open from 1 July 2018) .. 110 12.7 Small Business Time of Use (EA225) Tariff .................................................. 111 12.8 Low Voltage (LV) TOU Capacity 40-160 MWh (EA302) Tariff ...................... 112 12.9 Low Voltage TOU Capacity 160-750 MWh (EA305) Tariff ............................ 113 12.10 Low Voltage TOU Capacity >750 MWh (EA310) Tariff ................................. 114 12.11 High Voltage TOU Capacity (System) (EA370) Tariff ................................... 115 12.12 High Voltage TOU Capacity (Substation) (EA380) Tariff .............................. 116 12.13 Sub-transmission Voltage TOU Capacity (System) (EA390) Tariff ............... 118 12.14 Sub-transmission Voltage TOU Capacity (Substation) (EA391) Tariff .......... 119 12.15 Transmission Connected TOU Capacity (EA501) Tariff ............................... 121 12.16 Individually Calculated Network Tariff ........................................................... 122 12.17 LV Connection (Stand-by) (EA325) Tariff (Closed) ....................................... 124 12.18 HV Connection (Stand-by) (EA360) Network Tariff (Closed) ........................ 125 12.19 Unmetered Network (EA400/EA401/EA402) Tariffs...................................... 126

13 GLOSSARY ............................................................................................................. 127

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1 Introduction

This appendix is an important element of Ausgrid’s tariff structure statement (TSS) and provides further information on particular aspects of Ausgrid’s tariff strategy, as required by the National Electricity Rules (NER). In particular:

section 2 provides further background information;

section 3 sets out further information on Ausgrid’s tariff classes;

section 4 explains in more detail Ausgrid’s approach to estimating long run marginal cost;

section 5 provides further information on Ausgrid’s approach to allocating residual costs;

section 6 elaborates on Ausgrid’s approach to departing from purely efficient tariffs;

section 7 contains Ausgrid’s assessment of cross-subsidies, as required by the NER;

section 8 provides further detail on Ausgrid’s approach to setting prices;

section 9 contains enlarged versions of the business customer impact results presented in the main TSS document;

section 10 presents a compliance checklist against the requirements of the NER;

section 11 explains in detail how Ausgrid engaged with customers throughout the preparation of its TSS;

section 12 contains a description of each of Ausgrid’s tariffs.

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2 Further background information

2.1 What is a Tariff Structure Statement?

Our revised TSS provides a description of how we applied the pricing principles under the NER to develop our tariff structures and indicative pricing schedule. The AER will assess our revised TSS for compliance with the pricing principles. Once approved, the TSS will apply from 1 July 2017 to 30 June 2019. The details on our annual prices will be set out in our annual pricing proposal, and will be consistent the methodology set out in our approved TSS.

The new pricing framework represents a significant change from previous arrangements. In the past, DNSPs were allowed to set network tariffs to achieve a broader range of objectives than economic efficiency. As a consequence, our current tariffs could better reflect economic principles. The new framework seeks to improve the efficiency of tariffs, which will in turn benefit all customers over time by potentially leading to a lower overall cost of supplying electricity.

The TSS requires all Distribution Network Service Providers (DNSPs) to review their current tariffs and develop plans to implement efficient tariffs with regard to customer impacts. We have worked closely with a broad range of stakeholders to develop a tariff reform program and transitional arrangements to deliver these reform outcomes over a reasonable time-frame.

Our TSS covers network tariffs for direct control services. The Australian Energy Regulator (AER) sets the prices for our alternative network services as part of its regulatory proposal. Our tariffs for metering, public lighting and ancillary services are set out in Appendix G to J, and replicate the prices set by the AER. Accordingly, the focus of this TSS is on describing our process for developing our tariffs and indicative prices for general distribution network services. The Rules require us to provide the following information in our TSS:

our approach for setting tariffs in each pricing proposal in accordance with the pricing principles in the Rules;

the tariff classes in to which Ausgrid will divide its retail customers.

Ausgrid’s structure and charging parameters for each tariff.

the policies and procedures that Ausgrid will apply in assigning or re-assigning retail customers from one tariff to another.

an indicative price schedule of prices for each tariff within a tariff class from 1 July 2017 to 30 June 2019 to provide customers and retailers with greater certainty around the intended price path of direct control services.1

Our TSS also demonstrates how we have sought to incorporate feedback from our stakeholders when developing our TSS. We have summarised the issues raised by our stakeholders in the Overview paper, and provided further information as part of this document.

2.2 Regulatory and legal requirement for Tariff Structure Statement

On 1 December 2014, the National Electricity Rules (NER) were amended to include new distribution network pricing arrangements. This was part of the reform program initiated by the Council of Australian Governments (COAG) Energy Council, following the Australian Energy Market Commission’s (AEMC’s) Power of Choice recommendations to help consumers participate more effectively in energy markets.

1 The indicative and efficient prices presented in the TSS have been rounded to two decimal places.

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The new pricing arrangements include:

new pricing objectives and principles mandating the use of cost-reflective tariffs;

more transparency about how distributors develop network tariffs;

greater consultation with consumers and retailers;

new process with network tariffs determined as part of a 5-yearly revenue reset process; and

within-period amendments to the TSS which are only allowed due to unforeseen events.

Ausgrid is required under Section 6.8.2 of the National Electricity Rules (NER) to submit to the Australian Energy Regulator (AER) a TSS. This document provides stakeholders with a comprehensive understanding on our potential approach to setting our tariffs and an indication of how the structure and level of our tariffs may change over the regulatory control period. This document:

Provides a simple explanation of our network tariffs and other key concepts discussed in this document;

Outlines our indicative tariff structures and new tariffs for the regulatory control period;

Explains our approach to developing our indicative tariff schedule and how we will update tariffs annually over the regulatory control period; and

Outlines how our network tariffs are expected to change over the regulatory control period (both the tariff structure and prices).

2.3 Ausgrid’s approach to setting tariffs

In developing our approach to setting tariffs, the Rules require us to take into account the pricing principles in the Rules. The principles set out a number of factors that we are required to consider when developing efficient tariffs. The pricing principles also require us to consider the impact to customers from moving from current tariffs to efficient tariffs.

Ausgrid’s approach to set tariffs reflects the pricing principles in the Rules. Figure 1 shows that Ausgrid’s approach to develop indicative prices from 1 July 2017 was to:

Identify a reference ‘efficient tariff’ – Our starting point is to design a network tariff or tariffs solely with the objective of promoting economic efficiency, in the absence of any metering constraints or consideration of customer impact. We term the term ‘efficient tariff’ – a concept that serves as a reference point, allowing us to identify the manner in which we have departed from this notion in setting our tariffs, and the rationale for doing so.

Consider the impacts to customers – We then assessed the extent to which we should vary from efficient tariffs with regard to network bill impacts to our customers and the prevailing metering constraints.

In developing our methodology we have sought to engage with our customers and stakeholders on key issues of tariff reform and the potential impact of any changes. In particular, our decision to depart from the efficient level of tariffs reflects the concerns raised by stakeholders on the potential bill impact from such reform.

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Figure 1 – Indicative Tariff Formulation Process under New Pricing Rules

2.3.1 Efficient tariffs

Ausgrid’s starting point has been to establish the level and structure of an efficient tariff. This process is highly theoretical as it ignores customer impacts and practical constraints such as whether a meter can collect the information required to set efficient prices.

The pricing principles in the Rules provide a framework for establishing an efficient tariff.2 While many of these concepts are technical in nature, the underlying basis for an efficient tariff is that each customer receives a price signal that reflects the costs they impose on the network. In turn, this is related to the current and future costs of supplying energy to that customer.

Economic cost of supplying network services to a customer

A key principle behind efficient prices is the concept of long run marginal cost. In simple terms, this is the cost to the network of an incremental change in demand for our services. If prices accurately reflect the marginal cost of increasing demand, then consumers will make appropriate decisions on whether to consume more. In the case of an electricity network, there is generally excess capacity during non-peak periods meaning there is little additional cost from consuming more energy at these times. However, if the electricity network is congested, the cost of consuming greater amounts of electricity at peak times will be high – for example, running the air conditioner on a very hot summer day.

In our current environment, costs are less influenced by the need to augment the network to meet increasing demand. However there may be localised areas of congestion for which dynamic peak prices would reflect the long run marginal cost.

2 In particular, pricing principles in clause 6.18.5(e), (f) and (g) provide economic criteria for establishing efficient tariffs.

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Our analysis suggests that the fixed (residual) component of our costs is very high. In this case, efficient tariffs would include a high proportion of revenue recovery from the fixed charge (or charging parameter with similar efficiency properties). Less revenue would be collected from variable charges given that there is little or no increase in costs associated with increased network usage.

Factors we considered in developing efficient tariffs

We examined a number of factors or principles that could be used to derive a set of efficient tariffs. These include:

Efficient peak period definition – tariffs with a Time of Use structure should only signal LRMC via charges during the peak period. The peak period should be dynamic, applying between 12pm and 8pm on business days, for at most 12 days per year. These 12 days would be determined based on demand reaching some predefined level, at which point the demand places a strain on network assets.

Efficient peak prices – the price applied to network usage during the efficient peak period (hereafter the ‘dynamic peak price’) should be based on the LRMC of providing electricity distribution network services by location. The dynamic peak price should therefore differ based on whether Ausgrid’s network faces congestion over medium term at a given location.

Efficient allocation of residual costs to tariffs – the allocation of residual costs across tariffs is efficient, provided that it does not distort the price signals for efficient usage of the network. In particular, the allocation of residual costs should not discourage customers from switching tariffs when it is not economically desirable to do so. Ausgrid’s residual cost methodology satisfies this requirement, in a manner that strikes an appropriate balance between the twin objectives of economic efficiency and equity.

Efficient allocation of residual costs with a tariff – residual costs should be allocated to the fixed charge of each tariff (or charging parameter with similar properties) to ensure an efficient outcome. Although there may be other ways to recover these costs efficiently, Ausgrid cannot currently support such an approach without more robust empirical evidence on the price elasticities of different customer groups.

Efficient assignment and re-assignment of customers to tariffs – new customers should be assigned to the efficient tariff on the basis of the metering installed in their premise and the level of voltage and size of connection. If an existing customer is no longer eligible to remain assigned to their existing network tariff, they should be re-assigned to another network tariff in accordance with their new metering and/or network connection characteristics.3

An understanding of how our efficient tariffs over the regulatory control period compare against our current tariffs at the NUOS level is provided in Tables 1.1 and 1.2 at the end of this Executive Summary.

Basic meters

As noted above, the reference ‘efficient’ tariffs have not considered practical impediments to setting an efficient price. In reality metering infrastructure limits the extent to which we can achieve efficiencies in our tariffs. For example, a basic meter does not provide information on the amount of energy used by a customer during peak periods, and does not allow us to charge on that basis. Many of these customers cannot be subject to time of use pricing.

For this reason, we have not included the primary (non-Time of Use) tariff for residential and small business customers in our efficient tariffs. However, we have considered what the ‘second best’ efficient price could look like for these customers.

Our process has been to consider the tariffs that least distorts the price signals customers receive for using electricity. For instance, we considered the structure that would ensure that customers do not have lower prices during times of peak demand on the network. In the absence of peak pricing signals, it would

3 Ausgrid proposes to only rely upon an extent of network usage criteria in respect to the eligibility criteria for a site-

specific individually calculated tariff for a customer connected to the high and sub-transmission voltage level of Ausgrid’s electricity distribution network.

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be more efficient to apply a fixed charge (or other charging parameters with similar efficiency properties) to collect revenue rather than variable charges.4

2.3.2 Customer impacts

The second stage of our approach for setting tariffs was to compare the reference efficient tariffs with the current tariffs paid by customers.

The pricing principles explicitly require us to consider the impact to customers from moving to efficient tariffs relative to the tariffs customers faced in the previous regulatory year (ie, 2015-16). We must vary our efficient prices to the extent that we reasonably consider necessary. In doing so, we , and must consider the need for transition, extent to which customers can choose the tariff to which they are assigned, and the extent to which customers can mitigate the impact of changes in tariffs through their usage decisions.

Our analysis indicates that the reference ‘efficient tariffs’ would result in unacceptable bill shocks for our customers. A key reason is that the structure and price levels of the reference tariffs are substantially different from the network tariffs we currently have in place. Our view was that customers could not mitigate the impact of moving to an efficient tariff by changing their usage decisions, and that a reasonable period of transition would be required.

In developing our TSS we also engaged extensively with stakeholders on the issue of bill impacts. Ausgrid has traditionally engaged with customers, consumers, the community and stakeholders via face-to-face briefings, meetings, letters and presentations. New consumer engagement guidelines established by the AER gave Ausgrid the opportunity to expand and improve on this two-way communication.

By giving customers more opportunities to communicate with us, we can learn more about what they want and align our operations with their long-term interests. To help provide greater transparency, Ausgrid has included in our TSS document a summary of the key findings from our engagement.

The majority of our customers considered that a three to five year timeframe was most appropriate to effectively introduce substantial changes to tariff structure. In their view, a shorter timeframe would result in a bill shock that was inequitable and that longer term planning would allow for greater consultation and the ability for consumers to change their behaviour. Some of our stakeholders considered that a shorter timeframe was appropriate but only if changes were marginal.

As a result of our analysis of bill impacts and the concerns of our stakeholders, we considered that there was a strong basis for varying our tariffs from the efficient level. From a practical perspective we examined the reasonable extent to which we could move from our current tariffs to the reference ‘efficient’ tariffs, having regard to the customer impact factors in the Rules. This involved assessing the potential bill impact to existing customers and options for transition to efficient prices over time.

We have also developed an easy to read summary of this TSS to help customers understand the key areas and how it will impact them. This plain English customer overview paper accompanies the TSS.

2.4 Overview of developments in our regulatory environment

The Australian Energy Regulator (AER) regulates Ausgrid by setting the annual revenue requirement it may recover from customers through distribution network charges.

The AER Final decision allows Ausgrid to recover $6576.4 million ($nominal) from its customers over the 2015–19 regulatory control period, which is around 33 per cent less revenue than Ausgrid’s proposal, as shown in the figure below.

4 It may also be in the long-term interest of electricity users in this situation to pursue a complimentary demand

management strategy in areas that are expected to face critical network congestion in the near future.

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Figure 2 – Ausgrid's past total revenue, proposed total revenue and AER total revenue allowance – distribution and transmission

Source: AER analysis.

Ausgrid successfully appealed to the Tribunal a number of aspects of the AER’s final determination. The Tribunal’s decision was to set aside the AER’s final decision, however, the AER subsequently applied to the Federal Court for judicial review of the Tribunal’s decision. The judicial review is still underway at the time of preparing this TSS.

It follows that, at the time of preparing this TSS, there is considerable uncertainty as to the outcome of this judicial review, and the potential form of any remade decision by the AER for the current regulatory period. It follows that there is present uncertainty as to the target revenue requirement used by Ausgrid to set prices.

Two components of our final decision explain most of the difference between Ausgrid’s proposed revenue and our final decision: rate of return and operating expenditure. The major underlying components of Ausgrid’s revenue allowance for the regulatory control period to 2018/19 are discussed below.

(i) Rate of return

Significant investment is required to build a distribution network. The return Ausgrid must pay lenders and investors is referred to as the rate of return. Even a small difference in the rate of return can have a big impact on revenues.

The AER’s final decision sets the allowed rate of return (or ‘cost of capital’) at 6.68 per cent in 2015–16, which is significantly lower than the AER’s decision on this matter in the previous regulatory control period.

The investment environment has improved since the AER’s previous decision, which was made during the height of uncertainty surrounding the global financial crisis. This improved investment environment translates to lower financing costs necessary to attract efficient investment.

(ii) Operating expenditure

Operating expenditure (opex) includes forecast operating, maintenance and other non-capital costs incurred in the provision of network services. It includes labour costs, maintenance costs, and other non-capital costs that Ausgrid is likely to require during the 2014–19 period for the efficient operation of its network.

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The following figure shows the AER final decision compared to Ausgrid's past and proposed operating expenditure allowance.

Figure 3 – AER final decision compared to Ausgrid's past and proposed opex

Source: AER analysis.

The AER substantially reduced Ausgrid’s opex allowance in the regulatory control period to 2018/19 on the basis of their assessment that Ausgrid’s distribution services could be provided at a substantially lower cost while still maintaining safety and complying with reliability obligations.

(iii) Capital expenditure

Capital expenditure (capex) refers to the cost of building new facilities or replacing existing infrastructure. Factors that influence the required level of capex include the age and condition of existing assets. Capital expenditure (capex) refers to the capital expenses incurred in the provision of network services. The return on and of forecast capex for standard control services are two of the building blocks used by AER to determine Ausgrid’s annual revenue allowance.

The following figure shows the difference between Ausgrid's initial proposal, its revised proposal and our final decision for the 2014–19 period, as well as the actual capex that Ausgrid spent during the 2009–14 regulatory control period.

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Figure 4 – Ausgrid's forecast capex, AER draft decision Vs actual capex 2009–19

Source: AER analysis

2.5 Overview of developments in our volume environment

Unprecedented annual take up rates of air conditioning appliances in residential households occurred during the 2000’s decade, which drove the need for growth-related capital expenditure to ensure that network capacity was adequate to meet peak demand.

Annual energy consumption in Ausgrid’s network area declined markedly in the previous regulatory control period as seen in the figure below. The key reason behind the expected slowdown in declining consumption trends is that the rate of increase in retail electricity prices is projected to moderate after 2015/16, following the high and sustained price growth, which has been experienced in recent years. The projected electricity price path together with expected moderate uptake of electric vehicle usage adds positive stimulus to growth trends compared with recent years. However, these positive stimuli are to a large degree offset by independently projected energy conservation outcomes associated with ongoing solar PV penetration, the NSW Energy Savings Scheme (NSW ESS) and ongoing building shell and electrical end-use efficiency improvements.

Figure 5 – Historical and Forecast Energy Sales

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Air conditioning penetration in NSW households appears to have stabilised at around 65% and the average electrical efficiency of air conditioning appliances in households is substantially better than a decade ago due to Commonwealth Government initiatives including Mandatory Performance Efficiency Standards (MEPS) and the household insulation scheme. As a result, the need for future growth-related capital expenditure to cater for summer peak demand growth is now much lower than in the past.

While there is a degree of uncertainty associated with the outlook for these drivers, it is considered highly likely that their impact on network tariffs over the regulatory control period to 2018/19 will be orders of magnitude lower than was the case in the regulatory control period 2009-2014.

The following figure shows the historical and forecast trends in annual system-wide peak demand in Ausgrid’s network on a weather corrected basis.

Figure 6 – Historical and Forecast Trends – Ausgrid’s System-wide Summer Peak Demand

It is clear that the weakness in peak demand growth in recent years combined with significant investment in network capacity in the 2009-2014 regulatory control period means that many areas of Ausgrid’s electricity network are expected to have significant excess capacity for many years into the future.

2.6 Overview of the AER Issues Paper, Public Hearing and Draft Decision on our initial TSS

Ausgrid submitted its initial proposed TSS to the AER on 27 November 2015. Our initial TSS set out our proposed methodology for the allocation of residual cost, the estimation and application of Long Run Marginal Cost and a comprehensive suite of network tariff reforms that would deliver improvements in the efficiency of our network price signals and contribute towards the efficient recovery of our substantial residual costs in a manner that promotes stable revenue and pricing outcomes, without imposing unacceptable bill shocks on our customers.

In March 2016, the AER released an Issues paper outlining its preliminary position on the TSS proposals submitted by Ausgrid and the other NSW DNSPs. The AER held a public forum in April 2016 to seek feedback from stakeholders on its Issues paper. Ausgrid submitted a comprehensive submission to the AER Issues paper and actively participated in this public forum by addressing concerns over whether the DBT encouraged inefficient network usage and investment and whether the design of our tariffs is undermining the voluntary take-up our TOU tariff, as well as explaining our gradual approach to tariff re-balancing away from inefficient energy charges.

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Ausgrid actively engaged with the AER during their assessment of our proposed TSS by providing more detailed explanations of our TSS proposal and additional evidence to support of our position that what we have proposed complies with the National Electricity Rules.

The AER released its draft decision not to approve Ausgrid’s proposed TSS on 2 August 2016. The key areas of feedback provided by the AER in the draft decision are summarised in the table below

AER feedback Ausgrid’s response in revised TSS

In assigning customers to tariffs, it is not appropriate to distinguish between new residential and small business customers by reference to whether or not they have embedded generation installed. Ausgrid could consider assigning all new residential and small customers to a TOU tariff.

Ausgrid is comfortable assigning all new residential and small business customers to a TOU tariff, not just

those with embedded generation installed.

In the absence of empirical support for a declining block tariff, a flat tariff structure is more appropriate.

Ausgrid is comfortable replacing the DBT with a flat tariff.

Further support is required to justify the use of current transformer connection as a basis for allocating medium and large business customers with a low voltage connection to tariffs.

There was insufficient time to undertake further and sufficient analysis prior to submitting the revised TSS.

Therefore, Ausgrid has reverted to the previous usage based eligibility criteria and will consider the scope for using ‘size of the electrical connection’

eligibility criteria as part of the next TSS.

Further evidence is required in support of Ausgrid’s charging windows, namely that for the peak period and the weekend shoulder for residential and small business customers. The AER considered that a 3-5pm and 5-7pm peak period was appropriate, respectively, in the summer and winter months

Ausgrid undertook a first-principles analysis of its peak periods and, on this basis, is reforming the

winter peak period for residential customers. Further, Ausgrid is removing the weekend shoulder period for

business customers.

Source: Ausgrid, 2016

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3 Further information on Tariff Classes

3.1 Rule requirement

Under Chapter 10 of the NER, tariff classes are defined as representing ‘a class of customers for one or more direct control services, who are subject to a particular tariff or particular tariffs.

Section 6.18.1A(a)(1) of the NER requires that a TSS includes the tariff classes into which retail customers for direct control services will be divided during the relevant regulatory control period.

Section 6.18.3(d) of the NER requires that each tariff class must be constituted with regard to the need to group retail customers together on an economically efficient basis to the extent that this is desirable to do given the need to avoid unnecessary transaction costs.

3.2 Background

In theory, economic welfare is maximised when DNSPs set their prices to reflect the marginal cost of providing individual customers with electricity network services according to the time of day, time of year and by location. Unfortunately, the presence of high transaction cost means that it is not practical for a DNSP to design their tariffs to signal to individual customers the marginal cost of their network usage, particularly for the large number of customers with relatively small electrical loads. As a result, it is necessary for a DNSP to set prices on the basis of highly averaged marginal costs. This implies that some customers pay above marginal cost, while other customers pay less than their marginal costs, but this approach to setting tariffs is still efficient if the cost of differentiating tariffs outweighs the benefits to economic welfare of further de-averaging of tariffs.

The challenge for Ausgrid is to ensure that the grouping of customers into tariff classes results in minimal loss to economic welfare. In practice, this will be achieved when customers with similar marginal cost of supply are grouped together.5

In response to this challenge, Ausgrid recently reviewed its Cost Reflective Network Price (CRNP) tariff class to assess whether assigning all customers that satisfied an extent of usage criteria (i.e greater than 40 GWh pa or 10 MW) to a separate tariff class represented the most economically efficient way to group these customers.6

The key finding of this review is that economic welfare can be approved by changing the eligibility criteria for the CRNP tariff class from an extent of usage basis to a connection characteristic basis. As a consequence of this change, the following re-assignments were put into effect in early FY 2015/16, as summarised below:

Re-assigning customers connected to the high voltage level of Ausgrid’s electricity distribution network, as measured at the metering point, from the CRNP tariff class to the high voltage tariff class. The efficiency gain arises because this re-assignment result in these customers being grouped with other high voltage connected customers that have a similar economic cost to serve.

Re-assigning the customers connected to the sub-transmission voltage level of Ausgrid’s electricity distribution network, as measured at the metering point, from the CRNP tariff class to the sub-transmission voltage tariff class. The efficiency gain arises because this re-assignment result in these customers being grouped with other sub-transmission voltage connected customers that have a similar economic cost to serve.

Customers connected to Ausgrid’s electricity transmission network remaining assigned to the CRNP tariff class. This tariff class has been renamed the “Transmission connected” to reflect that only transmission-connected customers are eligible to be assigned to this tariff class.

5 NERA 2014, Economic Concepts for Pricing Electricity Network Services, A report for the Australian Energy Market Commission, 21 July, P.10 6 Ausgrid 2015, Initial Pricing Proposal, For the Financial Year ending June 2016, May, p.7.

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Ausgrid notes that the above-mentioned is generally consistent with current practice in the industry with DNSPs assigning all customers connected to the high or sub-transmission voltage level of the electricity network to a separate tariff class, regardless of whether they are assigned to a published tariff or an individually calculated tariff.

Ausgrid notified customers impacted by this change in the eligibility criteria for the CRNP tariff class in accordance with the process set out in the Attachment 14 of AER”s Final Decision. While there were concerns raised over the level of individually calculated network tariffs, Ausgrid recognised there was a general agreement amongst the large business customers consulted during this process that this change in the eligibility criteria for the CRNP tariff class resulted in a more appropriate grouping of customers from an economic welfare perspective.

3.2.1 Purpose of tariff classes

The purpose of tariff classes under the NER arises from their role in:

implementing price limits – there are restrictions on DUOS price increases at the tariff class level, and so the degree of flexibility afforded to a DNSP to re-balance DUOS tariffs is to some extent determined by the number of tariff classes; and

avoiding economic subsidies – the revenue expected to be recovered from each tariff class must lie on or between the standalone and avoidable cost of providing the relevant services.

The diminished importance of the concept of tariff class under the recently amended distribution pricing principles is highlighted by the comments made by AEMC in their Rule Determination:

“[However] it is unclear that there are efficiency benefits in having a larger number of tariff classes. A single tariff class can contain several tariffs... Each of those different tariffs can send customised network cost signals to different customers even if all of those consumers are in the same tariff class. Accordingly, rather than focusing on how tariff classes are determined, it is more important that DNSPs develop tariffs that are cost reflective and assign consumers to a tariff that sends the right pricing signals about the network costs caused by their usage.”7

3.3 Tariff classes

Ausgrid will group retail customers into the following tariff classes, ie:

Low voltage tariff class

High voltage tariff class

Sub-transmission voltage tariff class

Transmission connected tariff class

Unmetered tariff class

Ausgrid considers that the tariff classes set out above will deliver acceptable economic efficiency outcomes without imposing unnecessary transaction costs on Ausgrid, retailers and retail customers.

7 AEMC 2014, Rule Determination, National Electricity Amendment (Distribution Pricing Arrangements) Rule 2014,

Rule Proponents, COAG Energy Council, Independent Pricing and Regulatory Tribunal, 27 November, page 181-182.

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Table 1 – Ausgrid’s Tariff Class Descriptions

Tariff Class Definition Network Tariffs

Low Voltage Applicable to separately metered low voltage (400V or 230V) connections, as measured at the metering point.

EA010 – Residential Non TOU

EA025– Residential Time of Use

EA030 – Controlled load 1

EA040 – Controlled load 2

EA050– Small Business Non TOU

EA225– Small Business Time of Use

EA302 – LV TOU capacity (40-160 MWh pa)

EA305– LV TOU capacity (160-750 MWh pa)

EA310 – LV TOU capacity (>750 MWh pa)

EA325 – LV Connection (Standby - Closed)

EA332 – Residential transitional TOU

EA333 – Small business transitional TOU

High Voltage Applicable to any connection at high voltage (11kV) level, as measured at the metering point.

EA360 – HV Connection (Standby - Closed)

EA370 – HV Connection (System)

EA380 – HV Connection (Substation)

Individually calculated tariffs

Sub-transmission

Applicable to any connection at a sub-transmission voltage (132/66/33kV), as measured at the metering point.

EA390 – ST Connection

EA391 – ST (Substation)

Individually calculated tariffs

Unmetered Applicable to any LV connection that is defined as an unmetered supply by Ausgrid in consultation with AEMO as per clause S7.2.3 (Item 5) of the NER.

EA401 – Public Lighting

EA402 – Constant Unmetered

EA403 – EnergyLight

Transmission Applicable to any site that is connected to the electricity transmission network.

Customer Specific Prices

EA501 –Transmission Tariff

3.4 Future issues to consider

Ausgrid notes that there may be scope to disaggregate our tariff classes in the future. This may include consideration of whether it is desirable to group customers by reference to their locations (eg. regional pricing), or even by reference to their connection characteristics or network usage patterns (eg. air conditioning). However, Ausgrid believes that in the presence of widespread excess network capacity, there is unlikely to be strong economic justification for further disaggregating tariff classes.

Nevertheless, Ausgrid will consult with stakeholders and explore these issues as part of the next TSS.

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4 Further information on Long Run Marginal Cost

4.1 Rule Requirements

Section 6.18.5(f) of the National Electricity Rules requires that each tariff must be based on the long run marginal cost of providing the service to which it relates to the retail customers assigned to that tariff with the method of calculating such cost and the manner in which that method is applied to be determined having regard to:

the costs and benefits associated with calculating, implementing and applying that method;

the additional costs likely to be associated with meeting demand from retail customers that are assigned to that tariff at times of greatest utilisation of the relevant part of the distribution network; and

the location of retail customers that are assigned to that tariff and the extent to which costs vary between different locations in the distribution network.

It is also important to note that setting prices based on long run marginal cost is an important step towards achieving the network pricing objective set out in section 6.18.5(a) of the National Electricity Rules, which states that the tariffs that a Distribution Network Service Provider charges in respect of its provision of direct control services to a retail customer should reflect the Distribution Network Service Provider's efficient costs of providing those services to the retail customer.

4.2 Economics of network pricing

In simple terms, there are two economic challenges associated with setting network prices. The first challenge is to decide how best to signal the economic cost of network congestion.8 From an economic perspective, this decision involves the following key considerations:

Should the same peak price apply to all customers on a given network tariff, regardless of where they are located?

What charging parameter should be used to convey this signal to customers?

What time peak period definition should be adopted?

What level should the peak price be?

The second economic challenge is to decide how best to recover residual network costs from customers. From an economic perspective, this decision involves the following key considerations:

To what extent can the residual costs be recovered through charging parameters with stable or growing volumes, such as the fixed charge?

To what extent can these costs be recovered from customers with stable and price inelastic network usage patterns?

To what extent is it possible to re-assign customers on an inefficient network tariff with declining and elastic network usage patterns to a more efficient tariff where residual costs are recouped through the fixed charge or charging parameters with similar attributes?

In the situation where practical constraints exist (such as insufficient metering functionality) and it is not possible to signal LRMC in a meaningful manner, the economic challenge in relation to setting network prices relates to how best to recover residual network costs from customers.

This section relates to the first challenge of setting network use of system tariffs to convey efficient price signals to customers in respect to the economic cost associated with network usage, where possible to do so, given metering functionality.

8 This assumes that there are no practical constraints (such as insufficient metering functionality) to the application of the concept of LRMC to the setting of peak prices.

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4.3 Role of marginal cost

The concept of Long Run Marginal Cost (LRMC) has a central place in the economic theory of pricing. It is only by setting prices according to marginal cost that consumers will take into account future costs of meeting demand when making consumption and investment decisions. Efficient price signals also provide incentives for optimal investment in the network and its alternatives – demand side responses and distributed generation.

In a perfect world, economic efficiency is promoted by a marginal price of electricity distribution that reflects short run marginal cost – which consists almost exclusively of congestion costs (given that energy losses are dealt with in the energy market). Ideally, every individual consumption decision, at every point in time, should be undertaken by reference to a price signal based on the marginal cost of supply at that location, at that point in time.

This means, in a perfect world, marginal prices for distribution network services at a particular location and at a particular time of use would be close to zero where there is no capacity constraint. As demand grows, then marginal prices would increase above zero in order to clear the market (and properly affect the short run marginal costs of congestion). The higher the demand grows, the higher would marginal distribution prices grow. This process would continue until it became economic to augment the system, at which time marginal prices would again fall to close to zero (assuming the augmentation resulted in excess distribution capacity at a marginal distribution price of zero). This would tend to give a “saw tooth” profile to marginal prices over time.

However, it is not appropriate to put in place a perfectly efficient marginal cost pricing given that the transaction costs involved in administering such an approach would be considerable – for the DNSP, retailer and customer. Such costs stem from the burden of estimating, monitoring and billing prices that adjust instantaneously by the type of service, type of customer, and by time and location. It is also relevant to note that this form of pricing is also unlikely to be sufficient to recover the revenue requirement, except where widespread network capacity constraints exist. However, this is not to suggest that prices must always be equal to marginal cost, but rather that there should always be good reasons for departing from this rule in order that consequential economic losses can be set against other gains. In other words, the marginal cost pricing principles should always be applied with the aim of minimising the expected efficiency losses subject to other objectives, such as providing customers with more stable and certain pricing outcomes over time.

The pricing of network services is a practical exercise that takes place in an environment of limited cost information, technical complexity and uncertainty.

It is important to recognise that the setting of distribution prices is a broader function than signaling economic costs. This is because the presence of economies of scale means that supplying distribution network services at marginal cost will not be financially sustainable. This gives rise to a tension between economic efficiency and revenue adequacy. In such circumstances, economic efficiency requires that the DNSP recover these residual network costs with minimal distortion to efficient usage of the network, such as through the fixed charge. In practice, the extent that DNSPs can rely on fixed charges to recover sunk costs is likely to be limited by equity issues.

On the other hand, the inefficient recovery of these costs through usage charges is likely to expose the DNSP to unacceptable revenue risk, particularly in the environment where many customers are better placed to respond to these inefficient price signals by investing in solar PV systems, switching to gas and upgrading to more energy efficient appliances. In this type of pricing environment, it is important that DNSPs continue to have significant discretion under the distribution pricing arrangements as to how they recover residual network costs.

In the short run, when capacity is fixed, marginal costs will be made up of energy losses and the cost of network congestion. At present, congestion costs are incurred by customers in the form of reduced quality of supply and interruptions, rather than through increased prices. In the long run when capacity is variable, the marginal cost is the investment in additional capacity that is required to meet an increase in demand on the network.

27 November 2015 20

In theory, the most efficient tariff structure possible would be a fixed charge to recover residual network costs and a peak charge set at LRMC that applies to network usage only during periods when the network is most likely to be congested.

4.3.1 Long run marginal cost versus short run marginal cost

Marginal cost can be estimated by reference to either the short or long run change in costs arising from a specified change in output. The distinction between short run and long run marginal cost rests on the timeframe over which the postulated increase in output – and the corresponding change in costs – is estimated. In economics, generally:

the short run is taken to be a timeframe over which capital inputs (eg, plant and machinery), ie:

– physical capacity cannot be changed, and so SRMC measures only the change in operating costs arising from a change in demand; whereas

the long run is taken to be a timeframe sufficient for all factors of production – both capital and operating – to be varied.

An important distinction between SRMC and LRMC arises when there are physical capacity constraints. In these circumstances, SRMC also incorporates the cost to consumers of taking whatever measures are necessary to curtail demand such that it does not exceed available capacity. Therefore, SRMC can be very high when there is a network constraint whereas, when there is excess capacity, SRMC may be very low. Owing to the fluctuating nature of SRMC, in the context of infrastructure services it is often not practicable to set prices on this basis.

On the other hand, LRMC does not fully reflect the short term cost of capacity constraints. Instead, it reflects the cost of infrastructure necessary to alleviate any congestion, and so provides signals to both infrastructure users and providers as to the long term cost of changing capacity. Setting prices equal to LRMC provides strong signals to consumers to make medium to long term investments to manage demand, while ensuring that a network business receives the correct signals for capacity changes.

4.4 Methodologies for estimating marginal cost of electricity distribution

4.4.1 Overview of methodologies for estimating marginal cost of electricity distribution

A number of different methodologies have been traditionally used to estimate the LRMC of providing network services. Some of the more common methodologies include:

Average Incremental Cost methodology (AIC). This methodology estimates LRMC by identifying the stream of capital, operations and maintenance expenditure needed to satisfy projected demand growth, typically over 10 years, and then dividing this by projected demand growth. It then calculates the present value of the expenditure required and divides this by the present value of incremental demand growth to estimate the LRMC.

Common Distribution Charging methodology. This methodology is used by DNSPs in the United Kingdom and estimates the capital, maintenance and operating costs of supplying a hypothetical increment of 500 megawatt (MW) of demand at the system peak on the distribution network.

Perturbation or 'Turvey' methodology. This methodology involves a number of steps. First a small increment or decrement "shock" is applied to a known demand forecast. Then, a change is calculated in the present value of costs over the investment planning period resulting from this shock compared to the base case. Finally, this result is divided by the demand increment or decrement to arrive at the LRMC estimate.

4.5 Methodology for estimating long run incremental costs of electricity distribution

Ausgrid uses the Average Incremental Cost (AIC) approach to estimating the long run marginal cost by tariff class level, which involves the following steps:

1. Identify forecast average annual growth in kVA demand by voltage level;

2. Forecast average annual growth in network augmentation capital expenditure by voltage level to meet this increased demand;

27 November 2015 21

3. Estimate incremental and recurrent operating expenditure as a result of network augmentation identified;

4. Annualise capital expenditure costs identified; and

5. Calculate LRMC on an average incremental cost per kVA per annum.

Figure 7 – Conceptual Overview of LRMC estimation process

4.5.1 Ausgrid’s estimates of LRMC by tariff class at a system-wide level

Ausgrid has developed a model based on the AIC methodology (as illustrated in the figure above) to produce an estimate of LRMC at a system-wide level, assessed over a 15 year horizon.

Table 2 – Ausgrid’s LRMC Estimates by Tariff Class

Tariff Class

LRMC estimate

($/kW, FY2015/16 to FY 2029/30)

Low Voltage 164

High Voltage 53

Sub-transmission Voltage 8

Unmetered 164

Ausgrid considers that its estimate of LRMC presented in table 6.1 above is sufficiently reliable for pricing purposes.

However, Ausgrid notes that the application of the AIC approach over alternative time-frames can produce non-positive estimates in some circumstances. This reflects Ausgrid’s economic circumstances, namely the existence of excess capacity in its network. In the presence of a sufficient level of excess capacity, a postulated change in demand may not necessitate a material change in costs, which would give rise to a LRMC estimate equal to approximately zero.

This mismatch between demand and supply has complicated the LRMC estimation process, particularly under an AIC methodology.

Rather than exploring alternative LRMC methodologies, Ausgrid believes that it is more worthwhile to investigate this issue to obtain valuable insights into the underlying reality of our economic circumstances and how these circumstances influence the LRMC estimation process. A better understanding of these

1. Forecast average annual growth in kVA by tariff class

2. Estimate network augmentation expenditure to accommodate kVA

growth by tariff class

3. Estimate operating costs caused by network augmentation

4. LRMC = PV (augmentation capex + opex)/PV (growth in kVA)

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issues may also influence our thinking on the efficient tariff proposition (see section 6 of this appendix) and facilitate informed decisions being made about the extent that this model can be used (in conjunction with other analysis) in the efficient tariff-setting process.

To develop a better understanding of the underlying issues, Ausgrid has used a conceptual economic framework to illustrate the underlying nature of our economic circumstance and the impacts that these circumstances are likely to have on our LRMC-based pricing outcomes, see figure below.

Figure 8 – Conceptual Understanding of the Shortcoming of Ausgrid’s LRMC model

The hypothetical DNSP in the figure above is satisfying the level of demand in period t-4 in a least cost manner, which is denoted by point A on the LRMC curve in figure above. At this point in time, the hypothetical DNSP expects the level of demand to increase over the regulatory control period, denoted by increase from Qt-4 to QE(t) in figure above. On the basis of this expectation, the hypothetical DNSP decides:

To invest its regulatory allowance in supplying additional network capacity over the regulatory control period, which is denoted by the movement along the LRMC curve from point A to point B in the figure above.

To set prices over the regulatory control period equal to its forecast LRMC estimate, which is denoted by PE in figure above.

As a consequence of the marked increase in the level of price (denoted by increase from Pt-4 to P(E) in figure above and the influence of non-price factors (denoted by downward shift in the demand curve from Dt-4 to Dt), the actual level of demand in period t (denoted by Q(t) in figure above) turns out to be materially less than the original expectation formed in period t-4. This situation is characterized in economic theory as a disequilibrium in the sense that the hypothetical DNSP has invested in supplying a level of network capacity (denoted by Q(E) in figure above) that is in excess of what is required to efficiently satisfy current levels of demand(denoted by Qt in figure above).

There are two aspects to the restoration of equilibrium (denoted by point E in the figure above) where the level of demand for capacity is being satisfied under least cost conditions, as discussed below:

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Movement along demand curve - The hypothetical DNSP would in response to the unanticipated change in circumstance reduce the level of prices to reflect the latest LRMC estimate. The lower prices result in an increase in demand, which is denoted by the movement along the demand curve from point C to point D in the figure above. The increase in demand over time results in some of the excess capacity being utilised.

Movement along LRMC curve - The hypothetical DNSP would factor in the latest expectations of future demand in their decision-making around the capital replacement program, which in turn may lead to future replacement-related costs being lower than what they would been otherwise. The impact of this reduction in the supply of capacity is denoted by a movement along the LRMC curve from point D to point E in the figure above. Eventually, the efficient replacement of capital also contributes to the restoration of an equilibrium state.

In light of the insights gained from the conceptual analysis above, Ausgrid believes that it is reasonable to assume that the LRMC at a system-wide level is approximately zero if calculated on the basis of a reasonable forecasting horizon, say 10 years. Ausgrid also believes that it is reasonable to use our LRMC estimate at a system level based on a 25 year forecasting horizon as a proxy for the LRMC outcome under conditions that are more reflective of an equilibrium state. Ausgrid has used this estimate to calculate the level of the dynamic peak price charging parameter in our efficient tariff outcome.

4.5.2 Ausgrid’s insights into the potential LRMC outcomes at a localised level

Ausgrid has adopted the localised dynamic peak tariff structure as the basis of our efficient tariff proposition, as discussed in more detail in section 8 of the TSS and in section 6 of this appendix. As a result, the relevant basis for the dynamic peak price charging parameter is an estimate of LRMC on a localised, rather than a system-wide level.

To provide the AER and other stakeholders with an understanding of the potential range of outcomes for LRMC at a localised level, Ausgrid has referenced below the illustrative case studies developed by NERA for the AEMC.9

NERA Case Study 1: Kogarah Zone Substation

As a consequence of anticipated load growth within the St George load area, Ausgrid (formerly EnergyAustralia) investigated the construction of new zone substation at Kogarah (the Kogarah Zone Substation). At the time the area was serviced by seven zone substations, each of which had loads that either currently exceeded firm capacity or was expected to exceed firm capacity within the previous two to three years, given expectations about future growth.

Importantly, the observed growth in demand reflected the construction of a number of significant high density residential developments, and increasing numbers of commercial developments. Overall, Ausgrid was anticipating a combined zone capacity deficit of between 7.9 MVa and 35 MVa over the period 2008 to 2013.

In addition to the demand growth, asset condition assessments of the existing zone substations had identified Carlton zone substation as being of need of replacement in the near future. However, because of the lack of spare capacity at the surrounding zone substations, the load from Carlton could not be shared across those zone substations.

The proposed construction of the Kogarah zone substation was therefore designed to address two objectives, namely:

to replace the Carlton zone substation; and

to address an anticipated capacity deficit given continuing load growth.

9 NERA 2014, Economic Concepts for Pricing Electricity Network Services. A report for the Australian Energy

market Commission, July p.27

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In estimating the LRMC for the Kogarah zone substation, it was therefore important to distinguish between that expenditure that was caused by incremental changes in maximum demand, as compared to expenditure that was needed to provide ongoing reliable network services by replacing the Carlton zone substation. In practice, this required consideration to be given to what expenditure would have been incurred absent the anticipated additional growth in demand.

This highlights the importance of distinguishing the costs that are caused by changes in demand within the St George supply area. In this example, increases in demand were leading to:

expenditure from the construction of the Kogarah zone substation;

expenditure associated with the decommissioning of the Carlton zone substation; and

avoided expenditure from replacing the Carlton zone substation.

It follows that to estimate the LRMC, both the expenditure associated with the new Kogarah zone substation needs to be considered, less any expenditure that would have been avoided by replacing the Carlton zone substation. The incremental benefit of changes in demand is therefore the difference between the two expenditure streams.

The table below sets out the NERA’s estimates of LRMC for the Kogarah zone substation applying an AIC and a perturbation methodology.

Table 3 – NERA’s Illustrative estimates of Long Run Marginal Cost –St George Supply Area

Methodology LRMC estimate

Average Incremental Cost $363/kW/year

Perturbation $157/kW/year

Source: Ausgrid 2016

NERA believe that the difference in the results reflects the different emphases implicit within the two LRMC methodologies. The AIC approach is significantly higher in this case reflecting the planned size of the investment needed to meet reliability requirements within the St George supply area. The relatively small associated change in maximum demand means that this leads to a high LRMC estimate.

In contrast, the relatively lower LRMC estimate applying the perturbation methodology reflects the modest cost of capital applied (5 per cent in NERA’s illustrative case study) and so the benefits of avoiding these costs for a period of two years.

The Hornsby zone substation was constructed as a three transformer zone substation, which at the time of the proposed upgrade was equipped with two 50 MVA 132/11kV transformers. As a consequence of load growth, the Hornsby zone substation was exceeding its firm capacity in both summer and winter and so it was proposed to upgrade the zone substation through the construction of a third transformer.

The following table sets out the estimates of LRMC for the Hornsby zone substation upgrade applying an AIC and a perturbation methodology.

Table 4 – NERA’s Illustrative estimates of Long Run Marginal Cost –Hornsby Zone Substation

Methodology LRMC estimate

Average Incremental Cost $163/kW/year

Perturbation $23/kW/year


As for the Kogarah illustrative case study, the estimate of the LRMC is lower applying the perturbation approach compared to the AIC approach. In this case, the result reflects the relatively modest cost of the upgrade ($7.4m) relative to the size of the capacity expansion. The higher AIC reflects the decrease in

27 November 2015 25

maximum demand observed in year six, which greatly reduces the assumed incremental load growth, thereby increasing the LRMC estimate.

NERA believe that the results for both Kogarah and Hornsby highlight the sensitivity of both methodologies to the forecast of maximum demand. Relevantly, the AIC is strongly influenced by any fluctuations in the demand profile, which can offset the incremental demand increase and so increase the resultant LRMC estimate.

Similarly, NERA believe that the AIC methodology cannot be applied if demand is falling because the denominator is undefined, but can be used to estimate the LRMC in circumstances where declining demand leads to the avoidance of asset replacement costs.

It is clear from the NERA case studies that LRMC varies considerably between locations within an electricity network and is significantly influenced by the choice of methodology used to estimate LRMC. Therefore, Ausgrid believes that it is more appropriate to treat the concept of LRMC in practice as a range of outcomes, rather than a point estimate. Given that Ausgrid does not expect to face critical congestion at a localised area in the foreseeable future, Ausgrid has set the dynamic peak charging parameter in our efficient tariff proposition on the basis of the following LRMC estimates to provide the AER and other stakeholders with a better understanding of what this form of network pricing would look like in practice.

Table 5 – Ausgrid’s illustrative estimates Long Run Marginal Cost at a localised level

Tariff Class Illustrative Range of LRMC estimate ($/kW)

Lower range* Upper range

Low Voltage 0 164

High Voltage 0 53

Sub-transmission Voltage 0 8

Unmetered 0 164

*These estimates reflect Ausgrid’s expectation that there will be no critical congestion at a localised area in the foreseeable future.


Ausgrid wishes to inform stakeholders that the robust estimation of LRMC at specific locations facing critical congestion will be a key focus for the draft TSS document and related engagement process that will accompany Ausgrid’s regulatory proposal for the next regulatory control period.

4.5.3 Application of long run incremental costs of electricity distribution to tariffs

The application of LRMC to the setting of efficient network tariffs for large customers is a two-step process, as summarised below:

1. Select the charging parameter to use to signal LRMC to customers; and

2. Convert of long run marginal cost estimate from $/KW to cents per kWh.

These steps are explained in detail below.

4.5.3.1 Selection of charging parameter to use to signal LRMC

A review of Ausgrid’s existing tariffs indicates that there are number of charging parameters that could be individually or jointly used to convey LRMC signals to customers with an interval meter installed in their premise, as summarised below:

• Peak energy charge: This charging parameter involves applying a price per kWh to energy consumption recorded during the peak period.

27 November 2015 26

• Peak maximum demand charge; this charging parameter involves applying a price per KW or kVA to the highest maximum half hourly demand recorded during the peak period.

While there is considerable debate within the industry on how best to signal LRMC cost to customers, Ausgrid considers that these two types of charging parameters have similar efficiency properties if the underlying peak period definition was sufficiently narrowed to cover only the small number of time periods of the year when the electricity network is highly likely to experience critical congestion. In this context, Ausgrid considers that that it is reasonable to rely on peak energy charge to signal LRMC to customers and to focus on reforming the peak-period definition applying to this charging parameter.

A secondary issue to resolve is to decide the extent that Ausgrid’s capacity charge should be used to signal LRMC to customers. Ausgrid believes that the design of this capacity charge, particularly the historical 12 month basis, results in this charging parameter having weaker efficiency properties than the peak energy charge.

To understand this issue, consider the following illustrative figure that relates to a customer that has installed maximum demand management equipment. In the illustrative example below, a hypothetical customer’s maximum demand within the peak period is shown for each month over a three year period. In this illustrative example the two features of Ausgrid’s capacity charge are shown:

Monthly review of capacity charge (ratcheting)

A reset of capacity value where the maximum demand in the peak period of a month has been reduced for 12 continuous months.

The bold line shows the capacity value to which the capacity charge has been applied. During the financial year, when a monthly maximum demand in the peak period exceeds the capacity value, the line ratchets up (these months are labelled ratchet up in the figure below. Where a reduction in the maximum demand in the peak period is sustained over a twelve month period, the capacity value is reset to the maximum demand in the peak period over that twelve month period, (these months are labelled ratchet down in the figure below.

Figure 9 – Illustration of Ausgrid’s capacity charge reset

Ausgrid has undertaken empirical analysis to better understand the efficiency properties of Ausgrid’s capacity charge. On the basis of 4-years of historical data, Ausgrid has compared the timing of the actual maximum demand that underlies the capacity charge with periods of likely congestion on the electricity network. The results of this analysis suggest that there is generally a poor correlation – in other words that capacity charge is linked to network usage at times when the network is unlikely to be constrained – refer to figure below.

ratchet down

J F M A M J J A S O N D J F M A M J J A S O N D J F M A M J J A S O N D

2008 2009 2010

ratchet up

27 November 2015 27

Figure 10 – Timing of underlying maximum demand basis of Capacity Charge – Sub-transmission Voltage TOU Capacity (EA390) Tariff

While it is clear that the efficiency properties of the capacity charge charging parameter can be improved from the perspective of signaling economic costs by reforming the peak period definition, it would not be appropriate to do so if the role of this charging parameter is to efficiently recover residual costs, rather than signalling LRMC. Ausgrid believes that it is more appropriate to use the capacity charge to recover residual costs in a more equitable manner than what would be the case if these costs were only recovered through the fixed charge. Ausgrid notes that there is some support within the industry for Ausgrid’s position on the role of the capacity charge.

The key reform issue in relation to Ausgrid’s capacity charge is how to reform this charging parameter to ensure that it can be relied upon to recover residual costs without distorting the efficient usage of the electricity network. Ausgrid is considering a number of long-term reform options for the capacity charge in future TSSs, including:

• broadening the peak period definition (i.e adopt anytime maximum demand); and

• increasing the historical period use to calculate the capacity charge from 12 months to 24 months.

4.5.3.2 Conversion of LRMC to a peak energy charge

Ausgrid converts estimates of LRMC by tariff class into a peak energy charge using the below formula, ie:

ii

LRMCkWhcLRMC

)/(

Where:

LRMC is the estimate of LRMC, expressed on $/kW basis;

i is the probability that the quantities in respect to charging parameter i correlating with

network congestion; and

i is the peak hours per annum in respect to charging parameter i .

The theoretically Efficient Peak Energy Charge

The framework established by the NER requires Ausgrid to develop theoretically efficient tariffs, and then to assess the need to transition to these theoretically efficient tariffs over one or more regulatory control periods so as to account for, among other things, unacceptable customer impacts.

0%

5%

10%

15%

20%

5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35

Daily Average Temperature (°C)

Billed Capacity Value vs Daily Average Temperature

27 November 2015 28

Ausgrid considers that a fully cost-reflective tariff may involve a localised dynamic peak energy charge. The efficient properties of such a tariff draw from the resulting application of peak prices on only the few days when peak events occur and to only customers using elements of the network that are constrained. The theoretically efficient tariff is discussed in more detail in section 6.

The illustrative LRMC-based peak energy charge that would arise from the implementation of a dynamic peak charging parameter is presented in Table 6.5 below. 10

Table 6 – LRMC estimates for dynamic peak charging parameter

Tariff

LRMC Conversion Parameters Illustrative LRMC

DUOS Price

$/kW Alpha () No. of peak

hours c/kWh

Low Voltage 164 1 72 227

High Voltage 53 1 72 73

Sub-transmission Voltage

8 1 72 11.6


However, Ausgrid has not introduced a dynamic peak pricing in the next regulatory control period because the costs are likely to outweigh the associated economic benefits.11 Further, the implementation of such a tariff would impose unacceptable bill impacts on our customers, as discussed later in section 6.

The seasonal peak energy charge

Ausgrid is applying seasonal peak energy charges and is reforming the residential winter peak period from 1 July 2018. These reforms are discussed in detail in section 6 of the main TSS document and the resulting peak periods are presented in Table 7 – below.

Table 7 – Time periods for seasonal peak charging parameter, from 1 July 2018

Season Time Period Definition

Summer peak period From 2pm to 8 pm on working weekdays during 1 November and 31 March (inclusive)

Winter peak period (residential)

From 5pm to 9pm on working weekdays during 1 June to 31 August (inclusive)

Winter peak period (business)

From 2pm to 8pm on working weekdays during 1 June to 31 August (inclusive)

For the purpose of guiding its decisions on the peak energy charge for Ausgrid’s TOU tariffs, Ausgrid calculated the illustrative LRMC-based peak energy charge for each tariff class under its peak period definition to apply from 1 July 2018. These illustrative estimates are presented in Table 8 – below

10 Note – Note: To satisfy the efficiency criteria, the design of the dynamic peak tariff, such as the duration of the

peak period, the criteria for triggering an event and the number of events allowed to be called each year, must be determined for each specific area of network congestion.

11 Due to wide-spread excess capacity and the limited penetration of interval metering in Ausgrid’s network area.

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Table 8 – LRMC estimates for seasonal peak charging parameter

Tariff


DUOS Price

$/kW Alpha () No. of peak hours c/kWh

Low Voltage (residential)

164 1 879 18.7

Low Voltage (business)

164 1 1,005 16.3

High Voltage 53 1 1,005 5.3


8 1 1,005 0.8


An illustrative LRMC-based anytime charge

It is important to bear in mind the limited ability of non-time-variant tariffs to send efficient price signals to customers. Nevertheless, for illustrative purposes only, Ausgrid has also produced illustrative LRMC estimates for the anytime peak definition for customers connected to the low voltage level of our electricity distribution network, see the table below.

Table 9 – LRMC estimates for usage charging parameters under non-TOU tariff

Tariff


DUOS Price)

$/kW Alpha () No. of peak hours c/kWh

Residential non-TOU tariff

164 1 8760 1.9

Small business non-TOU tariff

164 1 8760 1.9


27 November 2015 30

5 Further information on Residual Cost Recovery

5.1 Rule Requirements

Section 6.18.5(g) of the National Electricity Rules requires that the revenue expected to be recovered from each tariff must:

reflect the Distribution Network Service Provider's total efficient costs of serving the retail customers that are assigned to that tariff;

when summed with the revenue expected to be received from all other tariffs, permit the Distribution Network Service Provider to recover the expected revenue for the relevant services in accordance with the applicable distribution determination for the Distribution Network Service Provider; and

comply with sub-paragraphs (1) and (2) in a way that minimises the distortion to the price signals for efficient usage that would result from tariffs based on long run marginal cost, as required under Section 6.18.5(f) of the National Electricity Rules.

5.2 Economic rationale of residual cost recovery

A significant proportion of a DNSP’s revenue requirement is made up of the fixed capital costs of previous investments in network assets – so-called sunk costs. Sunk costs are not affected by current and future consumption decisions. Therefore, from an economic perspective, sunk costs do not provide a basis for signalling the costs of further network use. The relevant costs for this purpose are marginal (forward looking) costs. When there is spare capacity network marginal costs, and hence efficient usage prices, will be low. Alternatively, as capacity is more fully used, efficient usage prices will increase. However, only in rare cases will these fully recover allowed (or required) revenues. This leaves a residual revenue requirement that must be recovered by other means.

The following conceptual representation provides an understanding of the inherent tension between the need for a DNSP to provide efficient price signals by setting prices on the basis of LRMC and the need for a DNSP to recover sufficient revenue to earn a normal return and to fund the efficient provision of distribution network services. Economic welfare is maximised by setting prices on the basis of Marginal Cost (denoted by PMC). At this level of price, customers will consume an efficient level of distribution network service (denoted by QMC). Unfortunately, the DNSP will not earn sufficient revenue by setting prices in this manner given that at the efficient level of distribution network service supplied (denoted by QMC) , the DNSP earns a level of revenue (PMC multiplied by QMC) that is below its efficient cost to supply (AC multiplied by QMC).

Figure 11 – Simple Illustration – Economic Welfare Implications of Departure from LRMC prices

Average Cost

PMC

QMC

Demand

Quantity

Price

QR

Marginal Cost

PR=AC (Q

MC)

27 November 2015 31

It is clear from the illustrative figure above that the maximisation of economic welfare requires that the DNSP should recover residual revenues from customers in a manner that has the least impact on the current and future level of network use. The economic literature suggest that this can be achieved in theory by adopting a two-part tariff structure where the usage charge is set equal to LRMC and residual costs are recovered through a fixed charge. In practice, the efficiency properties of a multi-part tariff are influenced by a range of factors, such as the functionality of the metering installed in the customer’s premise. This issue is explored in in the following section.

5.2.1 Economic challenge of setting network prices

The challenge faced by Ausgrid and many other DNSPs to efficiently set prices is particularly evident where limitations on the functionality of metering installed in the customer’s premise prevent time of use price signals from being conveyed to retail customers. This is a significant issue for Ausgrid given that there are currently around 1.2 million retail customers with basic accumulation metering in Ausgrid’s network area. The limited functionality of these meters means that Ausgrid cannot record the energy consumption of these customers during the periods when the electricity network is most likely to be constrained. As a consequence, it is not possible in practice to charge these customers for their energy consumption on the basis of LRMC. However, it is possible to set the energy consumption charge reflective of a highly averaged estimate of long run marginal cost. While this represents a practical pricing solution to the limitations of basic accumulation metering, the price signals that arise under this approach are not likely to significantly enhance economic welfare given the following, ie:

given that the price is below LRMC during the periods when the electricity network is likely to be constrained, it is likely that retail customers assigned to this tariff will overconsume network capacity during peak periods; and

given that the price is above LRMC during the periods when the electricity network has an abundance of capacity, it is likely that retail customers assigned to this tariff will under-consume network capacity at these times.

The loss of economic welfare that arises in this situation where metering constraint result in the same price being applied to energy consumption on anytime basis has both consumption and capacity effects, as discussed below:

Figure 12 – Simple Illustration – Efficiency Loss of Over-pricing of non-peak network usage

Economic loss to Society from over‐charging kWh use (shaded area)

P=LRMC

Q*

Demand for energy kWh

Quantity Energy (kWh) Supplied

Price

P1

Q1

Long Run Marginal Cost for energy kWh

27 November 2015 32

Figure 13 – Simple Illustration – Efficiency Loss of Under-pricing of peak network usage

In practice, the economic welfare consequences of not being able to effectively signal LRMC to retail customers with a basic accumulation meter installed in their premise are addressed in a number of ways, such as:

to improve the efficiency of the energy consumption and investment decisions of retail customers with basic accumulation metering by providing demand management incentives based on long run avoidable costs; and

minimise the extent that prices are set above LRMC during periods when the network is not likely to be constrained, such as by recovering a greater share of residual network costs from:

– the fixed charge or other charging parameters with similar properties; and

– charging parameters with volumes that are forecast to be stable or growing over time.

5.3 Principles for residual cost recovery

Ausgrid developed an approach to the recovering of residual costs from customers in accordance with the following principles:

Economic Efficiency: residual costs should be recovered in a way that is consistent with the promotion of economic efficiency and does not distort efficient LRMC based network prices, as required under Section 6.18.5(g)(3) of the National Electricity Rules.

Fairness: there is no single accepted interpretation of fairness, but the concept typically involves the desire for customers to contribute towards the recovery of costs in proportion to the extent that their network usage has caused these costs to be incurred.

Gradualism: Prices should change gradually to avoid shocking and inconveniencing consumers, as required under Section 6.18.5(f) of the National Electricity Rules.

Q1

P=LRMC

Price for capacity

P1

Quantity of Network capacity supplied

Demand for capacity

Marginal Cost of Capacity Supply

Economic loss to Society from over‐consuming peak capacity

Q2

27 November 2015 33

5.4 Potential approaches to residual cost recovery

There are a number of approaches that Ausgrid could adopt to recover residual costs. Importantly, some of these approaches are designed pre-dominantly to promote economic outcomes, while other approaches promote fairness outcomes, but often at the expense of economic welfare. All of these approaches could be argued to be consistent with the gradualism principle if implemented on a transitional basis. These approaches are summarised below:

to efficiently recover residual costs from customers by only applying a mark-up above long run marginal cost to charging parameters where the volumes are expected to show little if any response to changes in the price level, e.g. fixed charges and capacity charges; and

to equitably recover residual costs by applying a mark-up above long run marginal cost that results in:

– all customers in total or for a given class paying the same average mark-up above long run marginal costs, expressed in cents per kWh, $ per kW, or some combination thereof; and

– all customers contributing to the recovery of these costs to the extent that their network usage has caused these costs to be incurred.

Ausgrid agrees with the Brattle Group that there is no single “best” approach to recovering residual costs.12 It is for this reason that Ausgrid will allocate residual costs using a range of parameters to ensure that the recovery of residual costs from customers in a manner that reflects an appropriate balance between the often conflicting objectives of economic efficiency, fairness and gradualism.

5.5 Methodology for allocating residual costs

Ausgrid’s approach to recovering residual costs from customers involves a number of steps, as illustrated in the figure below:

12 Brattle Group 2014, Structure of Electricity Distribution Network Tariffs: Recovery of Residual Costs, prepared for

Australian Energy Market Commission, August, p.46

Figure – Simple representation of Ausgrid’s proposed residual cost allocation methodology

TARIFF CLASS A

TARIFF D

TARIFF E

USAGE

STEP 1: CALCULATE TOTAL RESIDUAL COST

DESIGNATED PRICING PROPOSAL COST

RESIDUAL DUOS COST CCF COST

STEP 2: ALLOCATE TOTAL RESIDUAL COST TO TARIFF CLASS

FIXED

FINAL STEP: ALLOCATE RESIDUAL COST TO CHARGING PARAMETERS

STEP 3: ALLOCATE RESIDUAL COST TO TARIFFS

USAGE FIXED USAGE FIXED USAGE

TARIFF CLASS B TARIFF CLASS C

TARIFF A

TARIFF B

TARIFF C

27 November 2015 34

A detailed explanation of each of the steps in Ausgrid’s methodology for allocating residual costs is provided in the sections below.

5.5.1 Approach to the calculation of total residual cost

Ausgrid will calculate the residual cost in a given financial year in the following manner:

Residual costs at the DUOS level – this is calculated by subtracting the revenue expected to be earned from marginal cost based prices from the expected total DUOS revenue calculated in accordance with the AER Final Decision.13

Plus other residual costs - expected revenue for a given financial year in respect to designated pricing proposal charges and climate change fund contribution, as calculated in accordance with the AER Final Decision. 14

The total residual cost in each financial year as calculated in accordance with Ausgrid’s methodology is shown in the following table.

13 AER 2015, Final Decision – Ausgrid distribution determination 2015/16 to 2018/19 – Attachment 14, April,

Appendix A, p. 22 14 AER 2015, Final Decision – Ausgrid distribution determination 2015/16 to 2018/19 – Attachment 14, April,

Appendix A p.22 and B p.24

27 November 2015 35

Table 10 – Indicative Total Residual Cost ($,000) – Ausgrid – FY 2017 to FY 2019

2017 2018 2019

Expected Revenue 2,193,640 2,237,512 2,293,450

Less revenue from LRMC component of peak charges 508,529 505,410 343,804

Total Residual Cost 1,685,110 1,732,102 1,949,645


The total residual cost figures shown in the table above have been calculated on the basis of formula below:

RC R R MC

Where:

RC Total residual cost in year t

R Expected revenue in year t

R MC Expected revenue from LRMC-based component of prices in year t

The expected revenue figures shown in the table above have been calculated on the basis of the following formula:

R P Q

Where:

R Expected revenue in year t

Network Use of System Price for charging parameter i in year t

Q Volume for charging parameter i in year t

For the purpose of calculating the expected revenue requirement for the 2018 and 2019 years, Ausgrid set the expected revenue equal to the sum of the revenue expected to be derived from distribution use of system (DUOS) network charges, transmission use of system (TUOS) network charges and jurisdictional scheme target revenue amounts in the previous year, multiplied by the Reserve Bank of Australia’s most recent estimate of consumer price inflation for that year.15

5.5.2 Approach to the allocation of total residual cost to tariff classes

An understanding of Ausgrid’s methodology to allocate residual cost to individual tariff classes in each financial year is provided by the figure below.

15 Reserve Bank of Australia, Statement on Monetary Policy, August 2016. Since there was no precise estimate for FY19, Ausgrid used the mid-point of the RBA’s long-term inflation target of two to three per cent for the FY19 year, ie, 2.5 per cent.

27 November 2015 36

Figure 14 – Overview of Ausgrid’s Method for Allocating Residual Cost to Tariff Class

The annual allocation outcomes for residual cost under Ausgrid’s approach are shown at the tariff class level in the following table.

Table 11 – Indicative Total Residual Cost ($,000) – Ausgrid – FY 2017 to FY 2019

Tariff Class 2017 2018 2019

Low voltage 1,529,600 1,571,938 1,774,544

High voltage 49,374 52,008 60,504

Sub-transmission voltage 86,259 88,032 93,580

Unmetered 15,172 15,343 16,116

Transmission 4,705 4,783 4,903

Total Residual Cost 1,685,110 1,732,102 1,949,646


It is important to note that there is a risk that the residual cost allocation outcome for a particular tariff class under Ausgrid’s methodology may contravene the requirement under section 6.18.5 (e) of the National Electricity Rules that the expected revenue for a tariff class may lie or on between the upper bound of standalone cost and the lower bound of avoidable cost for that particular tariff class.

To eliminate this compliance risk, Ausgrid will apply the following rules to the allocation of residual cost to the tariff class level, as set out below:

if the residual DUOS cost allocation for a particular tariff class exceeds Ausgrid’s estimate of the standalone cost for that particular tariff class, Ausgrid will instead use the standalone cost estimate less the expected DUOS revenue based on LRMC prices for that particular tariff class; and

TRANSMISSION CONNECTED

METERING

LOW VOLTAGE

HIGH VOLTAGE

SUB‐TRANSMISSION

VOLTAGE

SUMMATION OF TARIFF LEVEL ALLOCATION

SUMMATION OF TARIFF LEVEL ALLOCATION

EXPECTED PROPOSED DESIGNATED PRICING PROPOSAL CHARGES

EXPECTED CCF REVENUE

EXPECTED NUOS

RESIDUAL COST

EXPECTED DUOS

REVENUE FROM LRMC BASED PRICES

EXPECTED RESIDUAL DUOS COST

EXPECTED DUOS

REVENUE PEAK DEMAND

CUSTOMER NUMBERS

27 November 2015 37

if the residual DUOS cost allocation for a particular tariff class falls below Ausgrid’s estimate of the avoidable cost for that particular tariff class, Ausgrid will instead use the avoidable cost estimate less the expected DUOS revenue based on LRMC prices for that particular tariff class.

The following formulae provide a clear understanding of the operation of this rule under Ausgrid’s methodology for the allocation of residual costs to individual tariff class:

If then:

Alternatively, if then:

Where:

R MC P MC Q

RC Residual cost for tariff class k in year t

R MC Expected DUOS revenue from LRMC-based prices for tariff class k in year t

SC Estimated standalone cost for tariff class k in year t

AC Estimated avoidable cost for tariff class k in year t

P MC Long Run Marginal Cost Price for charging parameter i in year t

Q Volume for charging parameter i in year t

Q Volume for charging parameter i in year t-2

It is also important to note that Ausgrid has not included a residual cost allocation rule covering the application of the side constraint mechanism. This is because Ausgrid believes that the appropriate role of the side constraint is to limit the annual movement in DUOS revenue at the tariff class (i.e. transition), as opposed to the allocation of residual cost to ultimately calculate the total efficient cost at the individual tariff level (i.e. end-point).

5.5.3 Approach to the allocation of total residual cost to tariff level

An understanding of Ausgrid’s methodology for allocating annual residual cost to individual tariffs with a tariff class is provided in the figure below.

27 November 2015 38

Figure 15 – Overview of Ausgrid’s Method for Allocating Residual Cost to Tariff Level

The key point from the figure above is that Ausgrid will use a range of approaches to allocate annual residual costs to individual tariffs within a given tariff class. The rationale for using different approaches is to ensure that the residual cost allocation outcomes at the individual tariff level reflect an appropriate balance between the often, conflicting principles of economic efficiency, commerciality and fairness.

The different approaches that underpin Ausgrid’s methodology for allocating residual costs to individual tariffs within a tariff class are discussed below:

(i) Ausgrid’s approach to allocating residual DUOS cost to individual tariffs within a tariff class

Ausgrid believes that it is in collective interests of all of our stakeholders for Ausgrid to recover residual DUOS costs from customers on the basis of sound revenue management principles. This is because recovering residual costs in this manner will deliver more stable pricing outcomes by minimising the extent that unanticipated developments in our volume environment flow through to actual revenue outcomes.

It is important to note that recovering residual costs in a manner that promotes price stability is in the long-term interests of electricity users, regardless of whether the DNSP is subject to a price cap or a revenue cap control mechanism. This is because a DNSP’s failure to effectively manage revenue risk will result in unstable pricing outcomes within the regulatory control period under a revenue cap or across regulatory control periods under a price cap as a consequence of the AER re-setting the X-factor to realign overall tariff revenues and underlying efficient costs.

It should also be noted that more stable pricing outcomes over the longer term are likely to improve economic welfare by ensuring that our customers can base their network usage and investment decisions on more certain price expectations.

ANNUAL CONTRIBUTION

WEIGHTED AVERAGE VOLUME FORECAST

EXPECTED DUOS REVENUE FROM LRMC BASED

PRICES

EXPECTED RESIDUAL DUOS COST

EXPECTED DUOS

REVENUE

EXPECTED PROPOSED DESIGNATED PRICING PROPOSAL CHARGES

EXIT CHARGE FIXED CHARGE

NON‐LOCATION CHARGE

HISTORICAL ENERGY CONSUMPTION

PEAK DEMAND DEMAND CHARGE

VOLUME FORECAST ERROR

UNDER/OVER RECOVERY

ENERGY CONSUMPTION

UNDER/OVER RECOVERY

EXPECTED CCF REVENUE

VOLUME FORECAST ERROR

27 November 2015 39

Ausgrid believes that the achievement of stable pricing outcomes in practice requires that Ausgrid allocate residual costs based on sound revenue management principles. It is for this reason that Ausgrid will allocate the annual residual DUOS cost to each tariff on the basis of relative forecast volume growth rate for the purpose of calculating the efficient tariff outcome.

To assist stakeholders understand Ausgrid’s approach to allocating residual DUOS cost to the individual tariff level within a given tariff class consider the following illustrative example involving two hypothetic tariffs within a tariff class.

Table 12 – Illustrative Example: Annual volume by Tariff and Charging Parameter

Charging Parameter

Year t-1 Year t+4 Forecast

Volume Growth Rate

Tariff A

Number of Customers

10,000 11,000 10%

kWh consumption 500,000 800,000 60%

Tariff B

Number of Customers

5,000 4,500 -10%

Consumption (kWh) 500,000 400,000 -20%


In the simple example in the above table, the volumes associated with Tariff A are forecast to increase markedly over the regulatory control period in response to an expected increase in the penetration of an energy-intensive appliance. In contrast, the volumes associated with Tariff B are forecast decrease markedly over the regulatory control period in response to an expected increase in customers switching to an alternative energy source.

Under Ausgrid’s approach, the efficient Tariff A would be based on a higher allocation of residual DUOS cost than Tariff B because Tariff A has a higher weighted average growth rate compared to Tariff B.

The mathematical representation of Ausgrid’s methodology for allocating annual residual DUOS costs is shown below:

Where:

1

1

27 November 2015 40

0

Share of total residual cost for tariff k in year t

RC DUOS Residual DUOS cost for tariff k in year t

RC DUOS Total Residual DUOS cost for a given tariff class in year t

R Estimated residual DUOS cost for charging parameter type i for tariff k in year t-1

R Estimated residual DUOS cost for tariff k in year t-1

Q Forecast volume in year t+4 for charging parameter type i for tariff k

Q Historical volume in year t for charging parameter type i for tariff k

Ausgrid will assign more or less residual DUOS cost to a particular tariff for the purpose of calculating the efficient tariff outcome in accordance with the allocation factors shown in the table below.

Table 13 – Residual Cost Allocation Factor

Relative growth Rate Allocation Factor

Highest +10%

Medium Residual

Lowest -5%


It is important to note that the residual cost allocation factor in the table above is applied to the overall annual growth rate of total residual cost. For example, where the total residual cost is expected to fall by 5% for a given tariff class, this approach will result in the highest volume growth tariff receiving no change in their residual cost allocation from the previous year, and the lowest volume growth tariff receiving a 10% reduction in their residual cost allocation from the previous year.

Finally, it is important to note that it is Ausgrid’s intention to allow the outcome of the modelling process to be replaced with a value based on professional judgement where Ausgrid believes it is necessary to make this adjustment to ensure a sensible allocation of residual cost to a particular tariff, such as where the allocation process for a particular tariff has been distorted by tariff transfers or abnormal temperature events. The exercise of professional judgement may also be required in the situation where limitations on the degrees of freedom in practice result in the strict application of this methodology in practice results in perverse pricing outcomes for customers, such as in the case of a tariff class containing relatively few tariffs. Allowing Ausgrid to exercise professional judgement and expertise in this aspect of our price-setting process ensures that we retain ownership of our network tariffs, which is compliant with Chapter 6 of the NER, as evident from the following quote:

“it is important that DNSPs retain ownership of their network prices so that they face an incentive and obligation to set network prices that reflect the efficient costs of providing network services to consumers.”16

16 AEMC 2014, Rule Determination, National Electricity Amendment (Distribution Network Pricing Arrangements) Rule, November, p.16.

27 November 2015 41

(ii) Ausgrid’s approach to allocating residual TUOS-related costs to individual tariffs within a tariff class

Ausgrid will allocate TUOS-related residual costs to tariffs for the purpose of calculating efficient tariffs in a manner that preserves the TransGrid transmission price signal, to the extent that it is desirable to do so given the prevailing pricing and metering limitations.

The following figure provides an overview of our methodology for allocating TUOS costs to individually calculated site-specific tariffs.

Figure 7.7: Relationship between TransGrid Transmission Charges and Ausgrid’s TUOS Tariffs

The methodology for allocating TUOS costs to the published network tariffs is similar to the approach in the figure above, except that the postage stamp basis of these tariffs means that the allocation of TUOS will be highly averaged, particularly for the basic metered tariffs. Nevertheless, Ausgrid believes that allocating TUOS costs in this manner is in the long-term interests of our customers because it will result in a better alignment between TUOS revenue and TransGrid transmission cost outcomes, which will benefit our customers by reducing the risk of overs and unders, which in turn will deliver more stable TUOS pricing outcomes compared to other approaches to the allocation of residual costs.

It is important to note that it is Ausgrid intention to allow the outcome of the modelling process to be replaced with a value based on professional judgement where Ausgrid believes it is necessary to make this adjustment to ensure a sensible allocation of residual cost to a particular tariff, such as where the allocation process for a particular tariff has been distorted by historical tariff transfers or abnormal temperature events.

(iii) Ausgrid’s approach to allocating residual CCF-related costs to individual tariffs within a tariff class

Similarly, the methodology for allocating our contribution to NSW Government Climate Change Fund (CCF) is also based on the principle of fairness given that under this approach all residential customers pay the same CCF price per kWh and all business customers pay the same CCF price per kWh, regardless of whether they are assigned to a published or individually calculated tariff.17

Ausgrid’s methodology for allocating annual residual CCF-related costs is based on the following formula:

.

17 Note Ausgrid is unable to apply a uniform CCF price to all customers given that Ausgrid is required to limit the

recovery of the annual CCF contribution from residential customers to no more than 25%.

Network Access (Fixed) Charge

Demand charges at applicable transmission

connection point Capacity charge

TransGrid Transmission Charge Ausgrid TUOS Tariff

Share of exit charge at applicable transmission

connection point

Share of general and common service charges

(Non-location)

27 November 2015 42

.

0.25 oversandunders

0.75 oversandunders

0.25

Where:

The share of the overs and unders attributed to residential tariff k for year t The share of the overs and unders attributed to business tariff k for year t

Ausgrid’s contribution to the Climate Change Fund for year t

oversandunders The over or under-recovery of Climate Change Fund revenue in yeart‐1,including an interest component, calculated in accordance with the AER Final Decision

Ausgrid’s expected total Climate Change Fund revenue for yeart

Ausgrid’s expected Climate Change Fund revenue relating to residential tariff k for year t

Ausgrid’s expected Climate Change Fund revenue relating to business tariff k for year t

Ausgrid’s expected energy consumption for residential customers for yeart

Ausgrid’s expected energy consumption for business customers for yeart

The following table provides the indicative annual residual cost allocation outcomes for each published tariff based on Ausgrid’s methodology over the regulatory control period.

27 November 2015 43

Table 14 – Indicative Total Residual Cost ($,000) – Published Tariff Level – FY 2017 to FY 2019

Tariff Class Code Tariff Name 2017 2018 2019

Low Voltage EA010 Residential non-TOU 699,636 721,061 746,095

EA025 Residential TOU 170,174 167,396 189,981

EA030 Controlled Load 1 13,187 12,921 12,706

EA040 Controlled Load 2 22,038 21,859 21,627

EA050 Small Business non-TOU 96,521 96,806 99,746

EA225 Small Business TOU 93,079 91,838 99,161

EA302 LV TOU Capacity 119,571 129,425 157,835



Unmetered EA401 Public Lighting 10,789 10,805 11,193

EA402 Constant Unmetered 4,014 4,175 4,529

EA403 EnergyLight 369 363 394

High Voltage EA360 HV Connection (standby) Closed 75 122 133

EA370 HV Connection (System) 36,520 38,994 45,509

EA380 HV Connection (Sub-station) 2,148 2,262 2,727


EA390 ST Connection (System) 15,308 16,421 17,905

EA391 HV Connection (Sub-station) 0 0 0

27 November 2015 44

5.5.4 Allocating total residual cost to charging parameter level

There are a number of methodologies that Ausgrid could adopt to allocate the residual cost from the tariff level to each individual charging parameter according to economic principles. The key options available to Ausgrid, as identified by the Brattle Group18 are:

Postage Stamp approach;

Setting volumetric charges equal to LRMC and recovering residual costs through the fixed charge;

Introducing LRMC demand-based charges and sharing residual cost recovery between fixed and usage charging parameters; and

Recovering residual costs through charging parameters with stable or growing volumes.

The economic desirability of each of these methodologies for allocating residual cost is explored in the following section.

The postage stamp approach recovers residual costs by applying a uniform mark-up to LRMC-based prices. This approach could be argued to be consistent with the principle of fairness because the same mark-up is applied to all customers. As the Brattle Group correctly points out that the simple uniform mark-up approach does not result in efficient tariffs to the extent that customers are responsive to change in the level of price (i.e. price elasticity of demand is non-zero), and to the extent that this price responsiveness varies across different types of customers.19 For this reason, Ausgrid does not support this approach.

The second option involves recovering all of the residual costs from the fixed charge to enable the volumetric charge to be set at LRMC. While this approach is consistent with economic principles, it will result in very large increases to fixed charges even if implemented in accordance with the gradualism principle.

The third option involves introducing a demand charge parameter and recovering residual costs from both the fixed charge and the new demand charge. This approach is likely to be consistent with economic principles if the demand charge parameter is designed to have similar properties to a fixed charge.20 It could also be argued that this approach is consistent with the principle of fairness given that the customer’s contribution to the recovery of common costs of network service provision is a function of their peak demand, which in turn is a key driver of long-run network costs. Despite these advantages, Ausgrid does not support this approach at this stage because:

Limited scope - it is not possible to introduce a demand charge parameter for the 1.2 million customers in Ausgrid’s network area with a basic accumulation meter installed in their premise.

Knowledge gaps – Ausgrid has not undertaken sufficient customer research into demand-based tariffs to understand the responsiveness of different types of residential and small business customers to kVA or KW-based charging parameters.

Uncertainty over tariff design – Ausgrid has not undertaken any analysis on the optimal design of a demand charge in light of our expected trends in network usage, e.g. up-take of electric vehicles, investment in solar PV, switch to gas for cooking and heating, etc.

The final approach is consistent with economic principles because it aims to allocate residual cost in a manner that minimise the mark-up to LRMC-based prices and, hence, the distortion to efficient network usage. This approach is also consistent with the principle of gradualism if prices are transitioned to more efficient levels over time. It is for these reasons that Ausgrid supports this approach, but only if

18 Brattle Group 2014, Structure of Electricity Distribution Network Tariffs; Recovery of Residual Costs, Report

prepared for the Australian Energy Market Commission, Page 46 19 Brattle Group 2014, Structure of Electricity Distribution Network Tariffs; Recovery of Residual Costs, Report

prepared for the Australian Energy Market Commission, Page 41 20 For example, Ausgrid’s capacity charge for business customers is based on the highest maximum demand in a

half hour interval during the peak period in the previous 12 months.

27 November 2015 45

implemented in a manner that does not involve large and sudden changes in the level of individual charging parameters.

5.5.5 The allocation of residual cost to charging parameters

Ausgrid’s approach to the allocation of residual cost to each individual charging parameter for the purpose of calculating the efficient tariff aims to recover these costs from customers in a manner that minimises the distortion to the level and pattern of network usage under LRMC-based price signal.

Ausgrid believes that the achievement of this economic objective requires that residual costs are recovered in a manner that minimises the economic deadweight loss by:

Preserving the efficiency of price signals – ensuring that customers receive marginal price signals that reflect the economic cost of network service provision.

Delivering stable pricing outcomes – ensuring that the risk of revenue over/under recovery is minimised to the extent necessary to deliver stable pricing outcomes over the longer term.

While preserving the efficiency of the price signal is clearly important from an economic efficiency perspective, Ausgrid believes that economic welfare is also enhanced by ensuring that our customers receive stable pricing outcomes. A failure to recover residual costs in a manner that effectively mitigates volume risks will produce unstable prices, which undermine efficient network usage and investment decisions by creating uncertainties over future pay-offs.

It is important to note that a failure to effectively mitigate risks of recovering residual costs will result in unstable prices in the long-term, irrespective of the form of control mechanism applying to the DNSP:

Revenue Cap – a failure to actively manage revenue risk will flow through to price instability within the regulatory control period via the operation of the overs and unders account mechanism. In practice, it is also clear that the perverse incentives under a revenue cap have the potential to create cumulative overs and unders that result in price instability across regulatory control periods.

Price Cap – a failure to actively manage revenue risk will flow through to price instability across regulatory control periods due to the misalignment of the revenue earned from tariffs in the final year of the existing regulatory control period and the building block revenue requirement in the next regulatory control period.

To promote the long-term interests of electricity users, Ausgrid will deliver stable pricing outcomes and preserve the efficiency of the usage prices by allocating residual cost from the tariff level to the individual charging parameter level on the basis of the following formula:

Where:

Residual cost for charging parameter i of tariff k in year t

Residual cost for tariff k in year t

Risk measure for charging parameter i of tariff k in year t

The application of the approach to allocation residual cost to each charging parameter for the purpose of calculating the efficient tariffs varies across different tariffs according to the number of charging parameters, the value of the risk measure () coefficient and the extent that the allocation has been influenced by the exercise of professional judgement. Nevertheless, a high summary of the key allocation outcomes is provided below.

27 November 2015 46

In the case of the TOU and TOU Capacity tariffs:

Significant increase in the share of residual DUOS cost recovered through the fixed charge and capacity charge

Significant reduction in the share of residual DUOS cost recovered through the energy charge, particularly for the shoulder and off-peak periods.

In the case of the non-TOU tariffs:

Significant increase in the share of residual DUOS cost recovered through the fixed charge for both residential and business non-TOU tariffs.

Significant reduction in the share of residual DUOS cost recovered through energy charges under the residential and business non-TOU tariff.

5.6 The economic desirability of Ausgrid’s approach to residual cost recovery

Ausgrid believes that the methodology for allocating residual costs to tariffs and charging parameters set out in section 7 of the TSS and section 5 of this appendix comply with the requirements of section 6.18.5(g)(3) of the National Electricity Rules. This is because Ausgrid’s methodology is designed to enhance economic welfare by allocating residual costs to tariffs and charging parameters in a manner that minimises the distortion to the level and pattern of electricity network usage that would arise under LRMC based prices.

Ausgrid notes that the methodology used to recover residual costs impacts economic welfare to the extent that the tariff outcomes distort network usage and investment decisions. In this regard, the following considerations are relevant:

To what extent are decisions to connect to (or disconnect from) Ausgrid’s electricity network likely to be distorted by the approach taken to recover residual costs.

To what extent are decisions to consume network capacity during the peak period likely to be distorted by the approach taken to recover residual costs.

To what extent are decisions to consume network capacity outside the peak likely to be distorted by the approach taken to recover residual costs.

To what extent are decisions to invest in electrical appliances or substitutes (e.g. gas heating and cookers) likely to be distorted by the approach taken to recover residual costs.

Ausgrid has assessed the methodology for the recovery of residual costs against the above factors, as discussed in detail below.

5.6.1 Efficiency implications of Ausgrid’s methodology for residual cost recovery on network connection decisions

The approach to recovering residual costs from customers will have implications for economic welfare in the following situations:

If it results in existing customers disconnecting from the electricity network in the situation where it is not economically desirable for these customers to do so.

If it discourages new customers from connecting to the electricity network in the situation where it is not economically desirable for these customers to do so.

Ausgrid believes that the methodology will not result in inefficient decision-making in relation to connecting or disconnecting to Ausgrid’s electricity network over the regulatory control period. This is because the risk of the tariff outcomes resulting in inefficient network by-pass or connection will be minimised given the methodology will have the following characteristics: The allocation of total residual costs to individual tariff classes will be required to comply with the requirement under section 6.18.5(e) of the National Electricity Rules. Therefore, in the event the strict application of Ausgrid’s methodology results in the residual cost allocation to a particular tariff class:

27 November 2015 47

Exceeding the standalone cost estimate for that tariff class, the allocation will be reduced to ensure the expected revenue for that particular tariff being equal to the upper bound representing the stand cost of serving the retail customers who belong to that class.

Falling below the avoidable cost estimate for that tariff class, the allocation will be increased to ensure that the expected revenue for that particular tariff being equal to the lower bound representing the avoidable cost of serving the retail customers who belong to that class.

5.6.2 Efficiency implications of Ausgrid’s methodology for residual cost recovery on electricity network usage decisions

The approach to recovering residual costs from customers will have implications for economic welfare in the following situations:

If it results in customers consuming more or less electricity network capacity during the peak-period compared to what would be the case under efficient prices. In practice, the magnitude of the efficiency loss in respect to this issue can be gauged by the extent that the peak-period price is different to our estimate of long marginal cost and the extent that it can be reasonably expected that customers on this tariff will respond to changes in the price level of individual charging parameters by changing their network usage (i.e. elasticity is non-zero).

If it results in customers consuming more or less electricity network capacity outside the peak-period compared to what would be the case under efficient prices. In practice, the magnitude of the efficiency loss in respect to this issue can be gauged by the extent that the shoulder and off-peak-period prices are different to the LRMC-based prices and the extent that it can be reasonably expected that customers on this tariff will respond to these marginal prices by changing their network usage (i.e. elasticity is non-zero).

Ausgrid believes that the methodology will not result in inefficient decision-making in relation to network usage over the regulatory control period because the allocation of total residual costs to individual charging parameters aims to minimise the extent that residual costs are recovered through the peak period price charging parameter. In the event that the strict application of Ausgrid’s methodology results in the residual costs being allocated to the peak period price charging parameter in such a manner that it would result in the peak period price level that is inconsistent with the preferred transitional path to LRMC-based prices, the recovery of residual costs from the peak-period charging parameter would be constrained to no more than the level recorded in the previous financial year.

5.6.3 Efficiency implications of Ausgrid’s methodology for residual cost recovery on electrical appliance investment decisions

Ausgrid believes that the methodology will not result in inefficient investment decision-making over the regulatory control period because the allocation of total residual costs to individual charging parameters aims to minimise the extent that residual costs are recovered through the charging parameter that are designed to convey the economic cost of network usage, except where volumes are reasonably believed to be inherently stable i.e. price inelastic.

Given that investment decisions are made by weighing up the future benefits from a new appliance against the up-front (and on-going) costs associated with that investment, it is important that prices are stable over time. Ausgrid’s approach to residual cost recovery is likely to deliver stable pricing outcomes in the long-term given that it is underpinned by sound revenue management principles.

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6 Further information on departure from Efficient Pricing Principles

6.1 Rule Requirement

Section 6.18.5(c) of the National Electricity Rules allows a Distribution Network Service Provider's tariffs to vary from tariffs which would result from complying with the pricing principles set out in paragraphs (e) to (g) only:

To the extent permitted under Section 6.18.5 (h) of the National Electricity Rules; and

To the extent necessary to give effect to the pricing principles set out below:

– The structure of each tariff must be reasonably capable of being understood by retail customers that are assigned to that tariff, having regard to the type and nature of those retail customers and the information provided to, and the consultation undertaken with, those retail customers.

– A tariff must comply with the Rules and all applicable regulatory instruments.

Section 6.18.5(h) of the National Electricity Rules requires that a Distribution Network Service Provider must consider the impact on retail customers of changes in tariffs from the previous regulatory year and may vary tariffs from those that comply with paragraphs (e) to (g) of section 6.18.5 to the extent the Distribution Network Service Provider considers reasonably necessary having regard to:

The desirability for tariffs to comply with the pricing principles, albeit after a reasonable period of transition (which may extend over more than one regulatory control period);

The extent to which retail customers can choose the tariff to which they are assigned; and

The extent to which retail customers are able to mitigate the impact of changes in tariffs through their usage decisions.

6.2 The role of efficient tariffs in the indicative price-setting process

Ausgrid’s starting point has been to establish what an efficient tariff looks like, in the absence of metering constraints or consideration of customer impact. This idealized notion of an efficient tariff serves as an important reference point to guide the tariff reform process. The following figure provides an understanding of the role played by the efficient tariff in the indicative price-setting process in the new distribution pricing framework under Chapter 6 of the NER:

Figure 16 – Overview of Ausgrid’s Indicative Price-Setting Framework

Customer impact principle

Long Run Marginal Cost

Residual Cost Allocation

Economic subsidy Test

Side Constraints

Revenue entitlement under

AER Determination

Efficient Tariffs

Transitional Arrangements

Price Response

Tariff Opt-out

Indicative Pricing

Schedule

Economic principles

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6.3 Efficient pricing outcomes

Ausgrid has developed a set of tariffs in strict adherence to the economic principles set out in Chapter 6 of the NER. It is important to note that these “efficient tariffs” are highly theoretical in nature and are only used by Ausgrid to guide the tariff reform process. Nevertheless, Ausgrid is required to demonstrate that it is necessary to depart from these efficient tariffs in practice to comply with the customer impact principle set out in Section 6.18.5(c) of the National Electricity Rules.

Ausgrid has developed the “efficient” tariffs on the basis that an improvement in economic welfare is likely to arise under the following circumstances:

By using the peak energy charging parameter to signal LRMC to our customers, which is based on our analysis set out in section 5 of the TSS and section 4 of this appendix;

By applying the peak energy charge to energy consumption occurring at times that are highly likely to coincide with periods when the network is critically congested, which is based on our analysis set out in section 4 of this appendix;

By applying the dynamic peak price only to customers in areas of Ausgrid’s electricity network that are expected to face critical congestion over the medium term.

By allocating annual residual costs to tariffs in accordance with economic principles where it is reasonable to do on an equitable grounds, as set out in section 7 of the TSS and section 5 of this appendix;

By recovering residual costs through only the fixed charge, in accordance with the requirement in section 6.18.5(g)(3) of the NER to minimise the distortion to efficient usage patterns, refer to our historical variance analysis at the individual charging parameter level, as discussed in section 7 of the TSS and section 5 of this appendix;

By assigning or re-assigning customers to the efficient tariff given the metering installed in their premise, the nature of their usage, and the level of voltage and size of connection (as measured at their metering point), as set out in section 4 of the TSS; and

By offering voluntary tariffs that are set at a discount to the default tariff where that discount is justified on an economic cost to serve basis, such as in the case of Controlled Load 1 tariff where supply is only available under this tariff outside the peak period.21

6.3.1 Ausgrid’s position on the basic metered non-TOU tariff structure

It is important to note that Ausgrid has excluded the primary (non-TOU) tariff for residential and small business customers from our efficient tariff outcome. This is because Ausgrid believes that the inherently poor efficiency properties of this type of tariff means that it is not possible to satisfy the requirement set out in Section 6.18.5(f) of the NER.

As explained below, Ausgrid has adopted the dynamic peak period definition as the underlying basis for the efficient signalling of LRMC. As a consequence, it is cannot be argued that it is possible to signal LRMC though the energy charges under the non-TOU tariff structure given that it not possible to measure the consumption of energy during dynamic peak events for a customer with this type of metering installed in their premise.

Ausgrid is of the view that this approach satisfies Chapter 6 of the National Electricity Rules given that it is consistent with the AEMC’s position on this matter:

“…the Commission's policy intent that in basing tariffs on LRMC, DNSPs are to send efficient future cost signals to individual consumers or groups of consumers with similar cost characteristics within their networks. For example, if the LRMC of serving consumers in different parts of the

21 AEMC 2014, Rule Determination, National Electricity Amendment (Distribution Network Pricing Arrangements)

Rule, 27 November, page 216.

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network varies significantly a DNSP is unlikely to comply with this principle if it simply calculates a single average LRMC for its entire network. Similarly, if the LRMC of serving consumers is driven by peak demand on a few hours of a few days of the year and the consumers assigned to the relevant tariff have interval or advanced meters, a DNSP is unlikely to comply with this principle if it simply applies its LRMC estimate to a non-time varying tariff structure.”22

It is important to design the non-TOU tariff to achieve a second-best outcome by minimising the potential loss of economic welfare associated with being unable to signal LRMC due to the severity of the metering constraints. Ausgrid believes that the most appropriate way to achieve this outcome under a basic accumulation metering environment is by setting the usage prices equal to a blunt system-wide estimate of LRMC and recovering all of the residual costs from the fixed charge, as well as by pursuing complimentary demand management strategy in areas facing critical network congestion.

To understand the important inter-relationship between demand management and pricing in a basic accumulation metering environment consider the following illustrative figure. The figure below shows the demand and supply situation for a congested area of the network under different network tariffs. The efficient outcome (point A) is based on a dynamic peak tariff with dynamic peak price set at LRMC (denoted by PMC), which resulted in an efficient level of peak network usage by non-TOU customers (denoted by QMC). The non-TOU tariff is based on a lower than LRMC price level (denoted by PFLAT), which results in a higher than efficient level of peak network usage (denoted by QFLAT). The red shaded area denotes the loss of economic welfare under the non-TOU tariff.

Figure 17 – Simple Illustration – Role of Demand Management to minimise Economic Deadweight Loss under non-TOU tariffs

Given that it is not possible under the non-TOU tariff to completely eliminate the economic deadweight loss by changing the level and structure of the tariff, the only option available to the DNSP is to pursue complementary demand management strategy (e.g air condition cycling, peak rebates, etc) to reduce the level of peak network usage in this area from QFLAT to QMC. This will be an efficient outcome if the pursuit of demand management is able to achieve this outcome by paying incentives to customers in this specific network area that are no more than the value of the economic deadweight loss (denoted by red shaded area).

22 AEMC 2014, Sending efficient network price signals, p.139

PFLAT

QFLAT

Demand

Quantity

Price

QMC

Marginal Cost

PMC

A

B

C

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The key point from the discussion above is that an efficient outcome for the non-TOU tariff is dependent upon the design of the non-TOU tariff and the efficacy of the DNSP’s proposed demand management strategy to address the inefficiencies of non-TOU price signals in areas of critical network congestion. For the purpose of the TSS, Ausgrid will adopt as a second-best solution the following non-TOU tariff design:

To set the level of the energy consumption charge equal to zero, which approximately corresponds to the LRMC outcome produced using Ausgrid’s LRMC methodology based on an anytime peak period definition

To recover the residual costs for this tariff through the fixed charge to minimise the distortion to efficient network usage and related investment decisions.

The following table provides our second-best efficient outcome for the non-TOU tariffs for residential and small business customers in each remaining year of the regulatory control period.

Table 15 – Ausgrid Second Best Efficient Outcome- NUOS (Excl. GST) non-TOU Tariffs by Charging Parameter– Remaining 3 Years of Regulatory Control Period

Tariff

FY 2017/18 FY 2018/19

Network Access Charge

Anytime Energy Price



c/day c/kWh c/day c/kWh

Residential non-TOU (EA10) Tariff

154.51 1.74 159.08 1.74

LV Business non-TOU (EA50) Tariff

377.1 1.74 356.41 1.74


6.3.2 Overview of Ausgrid’s efficient tariff outcomes

The following table shows a comparison between the actual NUOS prices for Ausgrid’s major published tariffs for FY 2015/16 and the efficient prices for these tariffs on a revenue neutral basis.

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Table 16 – Ausgrid Current NUOS Tariffs by Charging Parameter– Major Published Tariffs – FY 2016/17

Tariff Code Tariff Name

Actual NUOS Prices (Excl. GST) – FY 2016/17



Peak Energy Price/

Block 1 Energy Price

Shoulder Energy Price/


Off-peak Energy Price/


Daily Peak Capacity Charge

c/day c/kWh c/kWh c/kWh c/kWh c/KW c/KVA

EA010 Res non-TOU 33.24 – 10.97 10.68 10.42 – –

EA050 Bus non-TOU 41.45 – 26.47 5.48 2.79 – –

EA030 Controlled Load 1 0.14 1.77 – – – – –

EA040 Controlled Load 2 10.04 4.69 – – – – –

EA225 LV Business TOU 119.78 – 10.79 10.48 – – –

EA025 LV Res TOU 118.21 – 21.78 6.91 2.11 – –

EA302 LV TOU Capacity 40-160 MWh pa 580.35 – 5.42 2.75 1.66 35.19 –

EA305 LV TOU Capacity 160-750 MWh pa 1748.48 – 4.94 2.42 1.61 – 35.19

EA310 LV TOU Capacity >750 MWh pa 2184.66 – 4.37 2.17 1.46 – 35.19

EA370 HV Connection 4372.54 – 3.19 2.13 1.46 – 18.88

EA390 ST Connection 5465.67 – 2.57 1.87 1.26 – 6.01


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Table 17 – Summary of Ausgrid’s Efficient NUOS Tariffs by Charging Parameter– Major Published Tariffs – FY 2017/18 and FY2018/19

Tariff Code Tariff Name

FY 2017/18 FY 2018/19


Dynamic Peak Energy Price


Dynamic Peak Energy Price

c/day c/kWh c/day c/kWh

EA225 LV Business TOU* 377.10 227.12 356.41 227.12

EA025 LV Res TOU* 154.51 227.12 159.08 227.12

EA302 LV TOU Capacity 40-160 MWh pa 2,129.03 227.12 2,011.99 227.12

EA305 LV TOU Capacity 160-750 MWh pa 7,597.57 227.12 7,195.06 227.12

EA310 LV TOU Capacity >750 MWh pa 28,460.77 227.12 27,160.45 227.12

EA370 HV Connection 51,920.96 73.55 51,488.97 73.55

EA390 ST Connection 92,777.89 11.59 92,105.18 11.59


Note1: Illustrative prices have been rounded and exclude GST.

Note2: The efficient tariff outcomes shown above are based on the assumption that all customers in Ausgrid’s network area have Type 5 or better metering installed in their premise. Ausgrid has produced a second-best efficient outcome for our non-TOU tariffs for the purpose of the TSS.

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6.3.3 Overview of customer impacts under efficient tariffs

An understanding of the bill impacts (positive or negative) under the efficient tariffs is provided in the following figures, which show the% difference in annual NUOS bill outcomes by annual energy consumption level for customers on Ausgrid’s major published tariffs between the revenue-neutral efficient tariff in FY17/18 and the tariffs at the start of the regulatory control period, on a constant volume basis.

(i) Customer impact under efficient second-best non-TOU tariffs

The following figures provide an understanding of the potential NUOS bill impacts under efficient second-best non-TOU tariffs for FY 2017/18.

Figure 18 – NUOS % bill impact under efficient tariffs - Residential non-TOU tariff – FY 2017/18

Figure 19 – NUOS % bill impact under efficient tariffs – Small Business non-TOU tariff – FY 2017/18

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(ii) Customer impact under efficient residential TOU tariffs

The following figures provide an understanding of the potential NUOS bill impacts of the efficient tariffs in FY 2017/18 for individual customers currently assigned to Ausgrid’s residential TOU tariff.

Figure 20 – NUOS % bill impact- efficient tariffs – Congested area- Residential TOU tariff – FY 2017/18

Figure 21 – NUOS % bill impact- efficient tariffs – Non-congested area- Residential TOU tariff – FY 2017/18

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(iii) Customer impact under efficient small business TOU tariffs

The following figures provide an understanding of the potential NUOS bill impacts of the efficient tariff in FY 2017/18 for individual customers currently assigned to Ausgrid’s small business TOU tariff.

Figure 22 – NUOS % bill impact- efficient tariffs – Congested area- Small Business TOU tariff – FY 2017/18

Figure 23 – NUOS % bill impact- efficient tariffs – Non-congested area- Small Business TOU tariff – FY 2017/18

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(iv) Customer impact under efficient LV TOU capacity tariffs

The following figures provide an understanding of the potential NUOS bill impacts of the efficient tariff in FY 2017/18 for individual customers currently assigned to Ausgrid’s LV TOU Capacity (EA302) tariff.

Figure 24 – NUOS % bill impact- efficient tariffs – Congested area- LV TOU Capacity tariff (EA302) – FY 2017/18

Figure 25 – NUOS % bill impact- efficient tariffs – Non-congested area- LV TOU Capacity tariff (EA302) – FY 2017/18

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(v) Customer impact under efficient HV TOU capacity tariffs

The following figures provide an understanding of the potential NUOS bill impacts of the efficient tariff in FY 2017/18 for individual customers currently assigned to Ausgrid’s HV TOU Capacity (EA370) tariff.

Figure 30 – NUOS % bill impact- efficient tariffs – Congested area- HV TOU Capacity tariff (EA370) – FY 2017/18

Figure 31 – NUOS % bill impact- efficient tariffs – Non-congested area- HV TOU Capacity tariff (EA370) – FY 2017/18

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(vi) Customer impact under efficient STV TOU capacity tariffs

The following figures provide an understanding of the potential NUOS bill impacts of the efficient tariff in FY 2017/18 for individual customers currently assigned to Ausgrid’s STV TOU Capacity (EA370) tariff.

Figure 32 – NUOS % bill impact- efficient tariffs – Congested area- STV TOU Capacity tariff (EA390) – FY 2017/18

Figure 33 – NUOS % bill impact- efficient tariffs – Non-congested area- STV TOU Capacity tariff (EA390) – FY 2017/18

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6.3.4 Key insights from customer impact analysis under efficient tariffs

The key insights gained from Ausgrid’s analysis of the NUOS bill impact under efficient tariffs are summarised below:

The recovery of all of the residual costs from the fixed charge results in a significant re-balancing of residual cost recovery from relatively larger energy users to relatively small energy users at the individual tariff level. Ausgrid’s view is that the NUOS bill increase under efficient tariffs for relatively small energy users is contrary to the customer impact principle under Chapter 6 of the NER.

The setting of the peak price equal to LRMC under an efficient dynamic peak period results in higher than otherwise NUOS bills for customers that are either unwilling or unable to respond to dynamic peak price signals by reducing their energy consumption during dynamic peak events receiving. Ausgrid’s view is that the NUOS bill increase under efficient tariffs for relatively small energy users with inelastic dynamic peak energy consumption is unacceptable.

Allocating residual cost in accordance with Ausgrid’s methodology results in a significant shift in residual cost recovery from business to residential customers, which is reflected in the level of fixed charge.

6.4 Is there a need to vary indicative tariffs from efficient outcomes?

Ausgrid notes that a departure from the tariffs that comply with the economic principles set out in Chapter 6 of the National Electricity Rules is only allowed to the extent that it is necessary to do so to give effect to the following principles:

It is reasonable to assess that structure of the efficient tariff will not be understood by retail customers assigned to that tariff given the type and nature of customer and the information provided to, and the consultation undertaken with, those retail customers.

It is reasonable to assess that the introduction of efficient tariffs will result in unacceptable customer impact outcomes having regard to the extent these impacts can be mitigated by adopting transitional pricing arrangements, the responsiveness of customers to efficient price signals and the opportunities to switch to another tariff.

Ausgrid believes that there is grounds for a significant departure from the efficient tariffs set out in section 6 of this appendix, given the evidence and logic presented below.

6.4.1 Assessment of whether retail customers understand efficient tariff structures

Ausgrid believes that a large proportion of our customer base will understand the structure of the efficient tariffs set out in section 6 of this appendix, particularly if supported by a well targeted education campaign over several years. This belief is based on the insights gained from undertaking a dynamic peak pricing trial. A survey undertaken prior to the commencement of the trial found that many of the respondents saw the DPP tariff structure as being simple and easy to understand. This result was supported by the findings of a survey conducted at the end of the pricing trial that found that a very high percentage of customers that participated in the trial understood the structure of their trial tariff and had sufficient information to respond to the incentives under the trial tariffs. There is also empirical evidence available that supports the view that large businesses are reasonably capable of understanding the DPP tariff structure.

Ausgrid notes that recent research by CSIRO suggests that at least some customers may not be able to understand the dynamic peak tariff structure. It is unclear from this research whether the survey participants that were repelled by the perceived complexity of dynamic pricing were objecting to complexity of the tariff design because they had difficulty understanding the DPP structure or were objecting to having to incur the transaction costs of actively managing their energy consumption during the DPP events, when they would prefer to “simply sign a contract & pay”.

Given the insights gained from research undertaken and the feedback received from our stakeholders, Ausgrid believes that it is reasonable to adopt the position that our customers are capable of understanding the dynamic peak tariff structure, but given the concerns of our stakeholders over the potential bill shocks to be imposed on particular customer groups Ausgrid will limit the extent of reform to

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the peak energy charge over the remainder of the regulatory control period. Ausgrid’s reforms to the peak period are discussed in section 6 and 8 of the main TSS document.

6.4.2 Desirability of efficient tariffs

Ausgrid believes that the tariffs that comply with the pricing principles set out in paragraphs (e) to (g) of Section 6.18.5 of the National Electricity Rules are undesirable because they will result in unacceptable bill shocks for small energy users, particularly if they are unwilling or unable to mitigate the impact under the efficient tariff by responding to dynamic peak price signals. Ausgrid believes that these bill shocks will be unacceptable even if efficient tariffs are implemented on the basis of a 10 year transition period, which Ausgrid considers is a reasonable period of transition.

It is also relevant to note that the actual severity of annual bill impacts under efficient tariffs at the network level may differ from the impacts presented in section 6 of this appendix given that retailers may not necessarily pass through the network price signal to end-customers.

6.4.3 The extent that customers are able to mitigate the bill impact under the efficient tariff by voluntarily opting-out to another tariff

There are limited opportunities for customers to mitigate the bill impacts under the efficient tariffs set out in section 6 of this appendix by switching to another tariff. This situation reflects that there is little if any scope under Chapter 6 of the NER for Ausgrid to offer voluntary network tariffs set at a discount unless it can be demonstrated that the discount reflects the efficient cost of network service provision.23

6.4.4 The extent that customers are able to mitigate bill impact by changing their network usage under the efficient tariff

Ausgrid believes that there is a material financial incentive for customers in congested areas of our electricity network to mitigate the bill impacts under the efficient dynamic TOU tariff by changing their network usage.24 To illustrate consider the example of a residential customer using 5,000 kWh pa located in a congested area of our electricity network with dynamic peak energy consumption of 125 kWh per annum. The NUOS bill for this customer is around $910 pa in the absence of a response to the dynamic peak price, which is around 40% higher than what they currently pay under the current residential tariffs. If it is assumed that this customer are willing and able to reduce their dynamic peak energy consumption by a quarter through sustainable behavioural change and investment in energy efficient appliances, the customer will realise a NUOS bill saving of only around $86 per annum.

The responsiveness of customers to marginal price signals is influenced by a plethora of factors, such as the magnitude of the price change, time, appliance holdings, discretionary consumption, substitutability of electricity and, information. The empirical evidence gained from pricing trials indicates that residential customers will on average reduce their energy consumption during the dynamic peak period by between 12.5% and 23%. However, these pricing trials found little if any evidence that business customers are willing and able to respond to dynamic peak price signals in the short-run.

There is reason to believe that customers will not respond to this extent in practice given that the potential bill savings from each marginal reduction in dynamic peak consumption is small relative to the cost of upgrading electrical appliances and permanently changing behaviour on extreme hot and cold days when our customers are most likely to assign a very high utility value to their network usage.

Ausgrid also believes that it is reasonable to assume that the responsiveness of customers to efficient marginal price signals may be less than observed in the pricing trials undertaken a decade ago due to the significant efforts by customers in the previous regulatory control period to eliminate wastage, invest in more efficient electrical appliances and to switch to substitutes, eg, gas and solar hot water.

23 AEMC 2014, Rule Determination, National Electricity Amendment (Distribution Network Pricing Arrangements)

Rule, 27 November, p. 216. 24 Note that the dynamic peak price does not apply to customers in unconstrained areas of the network. For these

customers the efficient NUOS tariff is a fixed charge.

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6.5 Key reforms

Given the need to vary tariffs from efficient outcomes in order to comply with the customer impact principles, Ausgrid has developed tariff reforms that makes clear progress towards the theoretical efficient outcome, but that achieve this progress in a manner that does not undermine the needs of our stakeholders for prices to be fair and reasonable.

Ausgrid will be implementing a number of reforms in the current regulatory control period that are directed at transitioning to efficient tariffs without imposing on customers unacceptable bill impacts. In other words, the below reforms are directed at striking an appropriate balance between the often conflicting principles and efficiency, equity and gradualism.

The key reforms include:

replacing the declining block tariff with a flat tariff;

voluntarily applying a re-balancing constraint to limit increases in fixed charges;

introducing seasonality into TOU tariffs;

reforming the winter peak period for residential customers;

changing the assignment and reassignment process;

introducing new transitional tariffs to prevent unacceptable customer impacts;

removing the shoulder period on weekends for small business customers; and

introducing a new tariff for transmission-connected customers.

Each of these reforms is discussed briefly below, however, where the relevant reform is discussed in detail in the main body of the TSS, or elsewhere in this appendix, we have not repeated the discussion below.

6.5.1 Replacing the DBT with a flat tariff

This reform is discussed in section 8 of the TSS, and so that discussion is not replicated in this appendix.

6.5.2 The rebalancing constraint for fixed charges

Ausgrid’s proposal to apply a rebalancing constraint for fixed charges in the current regulatory control period is a central component of this TSS, and one of the principal means by which Ausgrid is able to avoid adverse bill impacts and provide certainty to customers.

The NER requires Ausgrid to transition to more cost reflective tariffs, which necessitates some degree of rebalancing away from inefficient charges and towards more efficient fixed charges (or similar charging parameters).

Ausgrid is concerned that a rebalancing towards fixed charges has the potential to impose on some customers adverse bill impacts. For this reason, Ausgrid has voluntarily elected to provide certainty and comfort to customers by voluntarily imposing on itself a rebalancing constraint that limits the extent to which fixed charges may increase from year-to-year during this regulatory control period.

In essence, the rebalancing constraint acts to limit the annual change in fixed charges to the greater of consumer price inflation or the annual change in the network costs in that year. Ausgrid considers that, in a stable volume environment, the application of this rebalancing constraint is in the long term interests of consumers.

Specifically, in each year of the remainder of the current regulatory control period Ausgrid will limit the increase in the fixed charge component of each tariff to:

thegreaterof%∆CPI or%∆P

Where:

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%∆P %∆DUOS %∆TUOS %∆CCF

%∆DUOS is the % change in allowed DUOS revenue allocated to tariff k in year t, including approved pass through amounts

%∆TUOS is the % change in TUOS costs allocated to tariff k in year t, including approved pass through amounts

%∆CCF is the % change in CCF costs allocated to tariff k in year t, including unders and overs

CCF Ausgrid’s contribution to the NSW Government Climate Change Fund in year t

%∆ 1]

2,2,3,3,

1,1,2,2,[

tDecCPItSepCPItJunCPItMarCPI

tDecCPItSepCPItJunCPItMarCPI

tCPI

CPI means the all groups index number for the weighted average of eight capital cities as published by the ABS, or if the ABS does not or ceases to publish the index, then CPI will mean an index which the AER considers is the best estimate of the index.

6.5.3 Seasonality in TOU tariffs


6.5.4 Reforms to the winter peak period for residential customers


6.5.5 Improving the assignment and reassignment of customers

This reform is discussed in section 4 and section 8 of the main TSS document.

6.5.6 The introduction of transitional tariffs

The implementation of transitional tariffs is a cornerstone of our approach to protecting customers from adverse bill implications. Ausgrid identified a number of reforms that would materially improve the efficiency of Ausgrid’s tariffs, but that would also result in unacceptable customer impacts.

Given this tension between cost reflectivity and customer impacts, Ausgrid will apply transitional tariffs as a means of striking a better balance between these factors, consistent with the requirements of the NER.

Ausgrid will introduce a transitional NUOS tariff in FY2019 to ensure that residential and small business customers with an interval meter installed in their premise that are currently on the non-TOU tariff do not receive an unacceptable NUOS bill shock from being re-assigned to a TOU tariff in FY2019. This transitional tariff has been designed so that the fixed charge aligns with the applicable non-TOU tariff and the same energy charge applies across the peak, shoulder and off-peak periods. The level of the energy charge reflects the applicable non-TOU energy charge so as to ensure the customer does not experience an unacceptable bill impact.

Ausgrid has designed this approach so as to afford customers time to understand their energy use patterns, while preventing unacceptable customer bill impacts. Further, customers assigned to a transitional tariff may opt-in to a more cost reflective TOU tariff. Ausgrid intends to transition customers on the transitional TOU tariffs to the standard TOU tariffs within a reasonable time frame.

The following table compares the indicative NUOS prices (excl. GST) in FY 2018/19 for the residential TOU tariff (EA225) with the indicative NUOS prices (excl. GST) for the residential transitional TOU tariff (EA332).

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Table 18 – Ausgrid’s Indicative TOU and Transitional TOU NUOS Tariffs for FY 2018/19

Charging parameter

Unit

Residential Customers

FY 2018/19

TOU NUOS tariff Transitional TOU NUOS

Tariff

Fixed Charge c/day 43.33 34.76

Peak Energy Charge

c/kWh 30.69 11.20

Shoulder Energy Charge

c/kWh 6.32 11.20

Off-peak Energy Charge

c/kWh 3.24 11.20

6.5.7 Removing the weekend shoulder period for small business customers

This reform is discussed in section 8] of the TSS, and so that discussion is not replicated in this appendix.

6.5.8 New tariff for transmission-connected customers

Following a thorough review of tariffs, Ausgrid identified scope to improve the economic and equity outcomes for new customers connected to Ausgrid’s electricity transmission network. At present, new transmission-connected customers are assigned to the published sub-transmission TOU capacity (EA390) tariff.

Ausgrid also proposes to introduce a transmission-connected default tariff in FY2019 to ensure that new customers connected to our electricity transmission network from 1 July 2018 are initially assigned to a more efficient tariff. Ausgrid believes that this is both an efficient and equitable outcome than current practice that results in these customers paying DUOS charges when they do not contribute to the cost of providing electricity distribution network services.

The following table compares the indicative NUOS prices (excl. GST) for the default transmission-connected NUOS tariff with the actual NUOS prices (excl. GST) for sub-transmission voltage TOU capacity tariff in FY 2018/19.

27 November 2015 67

Table 19 – Ausgrid’s Potential New Default Transmission-Connected NUOS Tariff

Charging parameter Unit

Sub-transmission Voltage (System) NUOS

Tariff (EA390)

Default Transmission-connected NUOS Tariff

(EA501)25

FY 2018/19 FY 2018/19

Fixed Charge c/day 5714.36 0

Peak Energy Charge c/kWh 2.79 1.25

Shoulder Energy Charge

c/kWh 2.16 1.25

Off-peak Energy Charge

c/kWh 1.37 1.25

Capacity Charge c/KVA/d 6.28 3.10


It is important to note that it is Ausgrid’s intention to apply the default tariff to all new transmission-connected customers (i.e no historical load data) from 1 July 2018, regardless of where these customers are located in Ausgrid’s network area. As a result, the annual bill outcomes for these customers are likely to vary (positive or negative) from what they would if they were assigned to an individually calculated tariff based on TransGrid’s transmission charges applying to their specific transmission connection point. This issue is addressed to an extent by our intention to re-assign these customers once sufficient historical load data is available to a site-specific individually calculated network tariff if the extent of their network usage exceeds the eligibility criteria of 10 MW or 40 GWh pa, refer to section 4 of the TSS for a more detailed explanation. Nevertheless, Ausgrid believes that this default tariff delivers a more equitable outcome compared to the current approach of assigning these customers to the sub-transmission voltage TOU capacity tariff (EA390) because it will result in these customers no longer being required to contribute to the costs of owning, maintaining and expanding the electricity distribution network.

To provide the AER and our stakeholders with a better understanding of the extent that new transmission-connected customers will benefit under this reform, Ausgrid has undertaken network bill impact analysis using the network usage characteristics of existing transmission-connected customers, see figure below:

25 Price levels may vary to those presented here due to changes in TransGrid’s transmission pricing methodology.

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Figure 34 – Indicative NUOS impact – Default Transmission-connected Tariff – FY 2018/19

It is clear from the figure above that new transmission-connected customers are likely to receive a lower network bill under our new default tariff compared to the sub-transmission voltage TOU capacity (EA390) tariff. On this basis, Ausgrid believes that our new default tariff for transmission-connected customers satisfies the customer impact principle set out in Chapter 6 of the NER. As a result, Ausgrid does not propose to introduce transitional tariff arrangements in respect to this element of our tariff reform agenda.

6.5.9 Other comments

Finally, it is important to note that Ausgrid does not propose to introduce a tariff over the regulatory control period that is specifically designed to meet social, rather than economic objectives. Ausgrid believes that there is no need at this stage to introduce this type of tariff because the interests of vulnerable customers is already safeguarded by our gradual approach to re-balancing our tariffs away from inefficient energy charges towards fixed charges.

Ausgrid also wishes to point out that a social tariff cannot be effectively designed to safeguard the interests of vulnerable customers until there is greater clarity over the transition path to efficient tariffs. The optimal design of a social tariff is dependent on the transition path adopted. For example, a transition path based on recovering residual costs through a capacity charge (rather than fixed charge) will require that the social tariff safeguard the interests of vulnerable customers with relatively high peak demand, whereas a transition path based on increasing the reliance on fixed charges will require that the social tariff be designed to shield vulnerable low energy users.

Ausgrid intends to research innovative approaches to recovering residual costs and to share the findings of this research with all stakeholders to develop a robust position on the social tariff in the next few years.

27 November 2015 69

7 Assessment of Cross Subsidies


Ausgrid is required under Section 6.18.5(a) of the National Electricity Rules to develop annual indicative prices over the regulatory control period that are free of economic subsidy at the tariff class level. Ausgrid proposes to satisfy this obligation by demonstrating that these prices are expected to produce DUOS revenue at the tariff class level in each year that lies on or between:

an upper bound representing the stand alone cost of serving the retail customers who belong to that class; and

a lower bound representing the avoidable cost of not serving those retail customers.

This section also aims to provide our stakeholders with an understanding of the broader issue of cross subsidy at the individual tariff level using the total economic cost concept from Chapter 6 of the National Electricity Rules. While estimating cross subsidies at the individual tariff level is a highly subjective exercise given that residual costs typically account for a very high proportion of total efficient costs in a given year, Ausgrid believes that it may provide some insights into this issue and assist stakeholders to better understand the complexities associated with estimating cross subsidies at the individual tariff level.

7.2 Economic Concept of Subsidy

The purpose of applying standalone and avoidable cost bounds on expected tariff revenues is to ensure that the distribution business is not pricing each tariff class outside the bounds defined by economic efficiency. These bounds, standalone and avoidable costs, are the highest and lowest theoretical prices that a distributor could charge a customer class without imposing costs on other classes or having the customer pursue alternative forms of supply. In other words, pricing outside these efficient bounds implies cross subsidisation between tariff classes if the business is recovering its costs.

It was noted in a NERA Economic Consulting report for the Ministerial Council on Energy (MCE) that the Rule aims to achieve “the economic objectives of ensuring that the revenue expected to be recovered from each tariff class is calibrated so as to discourage inefficient bypass and to avoid customer subsidies”. 26

This was also articulated by John Vickers who stated that the standalone cost test has been argued to result in ‘subsidy-free’ prices because consumers of each product at least cover the extra costs that their consumption causes, so no financial burden is placed on others, and no consumers pay more than they would pay if they broke away and went to an alternative supplier with access to the same technology.27

7.2.1 Definition of standalone cost

Standalone cost represents the cost that would be required to replicate or bypass the network. It follows that if customers were charged above standalone costs it would be beneficial for that group of customers to bypass the network or be provided by a new entrant. Therefore, these costs are comprised of the assets and operating costs that would be required to provide services to that tariff class on a dedicated basis (i.e. without sharing costs with other tariff classes).

7.2.2 Definition of avoidable cost

Avoidable cost represents the cost that would be avoided if the network business no longer provided services to that group of customers. If the business charges less than avoidable cost to that group of

26 NERA Economic Consulting, Distribution Pricing Rule Framework, Network Policy Working Group, December 2006

27 Vickers, John (1997), “Regulation, Competition and the Structure of Prices”, Oxford Review of Economic Policy, 13:1.

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customers it follows that it would be beneficial for it to not provide services to those customers since the costs would be greater than the expected revenues.

Short run avoidable costs represent the costs that the business should be recovering in the short run, where only variable costs, predominantly operating costs, can vary. This is differentiated from long run avoidable costs where planned capital investments should be included. Given that tariffs are to be designed with regard to long run marginal cost it follows that the lower bound for efficient tariffs should be long run avoidable costs.

7.3 Efficiency bounds test at tariff class level

To satisfy our obligations under Chapter 6 of the National Electricity Rules to demonstrate that the pricing outcomes set out in the TSS are free of economic subsidy, Ausgrid proposes to demonstrate that these prices are expected to produce DUOS revenue at the tariff class level in each year that lies on or between an upper bound representing the stand alone cost of serving the retail customers who belong to that class and a lower bound representing the avoidable cost of not serving those retail customers.

7.3.1 Methodology for estimating standalone and avoidable costs for each tariff class

Ausgrid has estimated the annual standalone and avoidable costs of electricity distribution service provision at the tariff class level over the regulatory control period on the basis of a detailed disaggregated analysis of our annual cost to serve. While it is clear that our approach will need to rely to a large extent on the exercise of professional judgment in relation to the allocation of costs, Ausgrid believes that our approach is acceptable at this stage given the prohibitive cost of obtaining more robust engineering estimation of the costs is likely to outweigh the benefits of doing so.

A high level understanding of our methodology for estimating standalone and avoidable costs at the tariff class over the regulatory control period is provided by the figure below:

7.3.2 Are our efficient tariffs free of economic subsidy at the tariff class level?

Ausgrid is satisfied that our efficient tariff outcomes are free of economic subsidy since the revenue outcomes based on these prices lie on or within the bounds of standalone and avoidable cost at the individual tariff class level.

7.3.3 Are our indicative tariffs free of economic subsidy at the tariff class level?

Ausgrid is satisfied that the indicative prices are free of economic subsidy given that our analysis in Table 20 shows that the revenue outcomes based on these prices lie on or within the bounds of standalone and avoidable cost at the individual tariff class level.

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Table 20 – Annual Comparison of Ausgrid’s expected DUOS outcome Vs Standalone and Avoidable Cost by Tariff Class – Indicative Pricing Schedule ($)

Tariff Class

FY 2017/18 FY 2018/19

Avoidable Cost

Expected DUOS Revenue

Stand Alone Cost

Avoidable Cost

Expected DUOS Revenue

Stand Alone Cost

Low Voltage 250.05 1367.37 1,397.45 261.37 1356.91 1,387.79

High voltage 5.97 37.04 467.92 6.23 37.81 464.68

Sub-transmission voltage

3.08 26.88 452.89 3.26 26.83 449.75

Unmetered 0.28 8.95 440.60 0.29 8.71 437.56

27 November 2015 72

+

Figure – Underlying relationship between economic cost concepts

=

=

Total Residual cost

Expected Network Revenue

LRMC based Network Tariffs

Annual Volume Forecast by charging parameter

Expected Network Revenue from

LRMC based Tariffs

Annual Volume Forecast by

charging parameter

Mark‐up to LRMC Network Tariffs

Total Efficient Cost

Annual Volume Forecast by

charging parameter

Network Use of System Tariffs

7.4 Inherent cross subsidies at the individual tariff level

This section explores the issue of inherent cross subsidies at the individual tariff level. While the estimation of inherent cross subsidies at a disaggregated level is clearly a highly subjective exercise given the presence of significant residual costs, Ausgrid hopes that this analysis may provide our stakeholders with some insights into this matter.

There is no commonly accepted approach to estimating inherent cross subsidies at the individual tariff level. Ausgrid is aware of the following approaches:

Distribution Cost of Supply Model – this approach involves a detailed cost allocation process using engineering and accounting concepts. These models typically rely upon the method of intercepts.28

Economic Cost to Serve Analysis – this approach involves estimating the marginal cost of satisfying the peak demand requirements associated with a particular group of customers. This analysis typically relies upon a LRMC model.

Total efficient Cost Analysis – this approach involves calculating the efficient level of cost to be recovered from the customers on a given tariff on the basis of LRMC-based prices and an efficient mark-up to these prices to recover residual cost.

To illustrate the concept of inherent cross subsidy at the tariff level, Ausgrid has decided to use the third approach given that the concept of total efficient cost is an element of the new distribution pricing arrangements under Chapter 6 of the National Electricity Rules.

7.4.1 Definition of total efficient costs

The concept of total efficient cost is not defined under the National Electricity Rules. Ausgrid’s interpretation of this concept is that it relates to the expected NUOS revenue for a given tariff in a given regulatory year derived on the basis of the efficient tariffs set and our baseline forecast of the volumes associated with this tariff, as illustrated in the figure below:

28 Energy International 1969, Allocating fixed costs, A new method of rationally distinguishing between consumers so that each contributes according to his technical responsibility, H. Christopher; H, Armstead (Consultant), p.20-25.

+

=

==

=

27 November 2015 73

8 Further information on indicative prices

This section provides further background on the indicative prices presented in the main TSS document.


Ausgrid is required under Section 6.18.1A (5) of the National Electricity Rules to include in our TSS document a description of the approach that the Distribution Network Service Provider will take in setting each tariff in each pricing proposal of the Distribution Network Service Provider during the relevant regulatory control period in accordance with the pricing principles set out in clause 6.18.5 of the NER.

Ausgrid is required under Section 6.8.2(d1) of the National Electricity Rules to prepare an indicative pricing schedule that shows the indicative annual prices of our tariffs calculated in accordance with the approach set out in the TSS for each year of the regulatory control period.

This section satisfies these obligations by describing our approach to setting tariffs over the remainder of the current regulatory control period and providing a summary of the indicative pricing outcomes at the NUOS level produced by this approach.

8.2 Ausgrid’s approach to developing indicative prices

The setting of network tariffs under new distribution pricing framework is a two stage process:

First Stage: This stage of the network pricing process involves the DNSP undertaking consultation on their tariff reforms, development of a TSS document and an indicative pricing schedule. The DNSP must submit both of these documents to the AER for assessment against the requirements of Chapter 6 of the National Electricity Rules.

Second Stage: This stage of the network pricing process involves the DNSP developing an annual pricing proposal and submitting this proposal to the AER for assessment against the requirements of Chapter 6 of the National Electricity Rules. The DNSP is required as part of the annual pricing process to update the price levels in their indicative pricing schedule and to explain any material variations between their prices and the indicative prices shown in the updated schedule.

8.2.1 First stage of the network pricing process

The figure below illustrates the stage one process that Ausgrid has followed to produce an indicative pricing schedule to accompany our TSS document.

27 November 2015 74

Figure 35 – Overview of indicative price-setting process

To assist stakeholders understand how we have developed our indicative price schedule under stage one of the network pricing process, Ausgrid has provided the rule requirements and the relevant references in our TSS document for each of the steps in our indicative price-setting process.

Table 21 – Ausgrid’s Approach to Developing Indicative Prices

Step Description NER Requirement

Reference

1 Group customers into tariff classes in an economically efficient manner

6.18.1A(a)(1) 6.18.3(d

TSS – section 3

Appendix A – section 3

2 Develop procedures for assigning or re-assigning retail customers to tariffs.

6.18.1A(a)(2) TSS – section 4

3 Develop a methodology for estimating Long Run Marginal Cost and apply this estimate to tariffs

6.18.5(g) TSS – section 5


4 Develop a methodology for allocating residual cost and use this method to apply a mark-up to LRMC-based prices to recover these costs.

6.18.5(g) TSS – section 7


5 Develop “efficient tariffs” by summing the outputs of step 3 and 4.

TSS – section 8


6 Assess whether it is necessary to depart from “efficient tariffs” in order to comply with the customer impact principle.

6.18.5(h) Appendix A – section 6

7 Develop a tariff strategy that makes progress towards efficient outcomes, but in a manner that complies with the customer impact principle.

TSS – section 8


8 Develop indicative prices covering the regulatory control period in accordance with the tariff strategy (step 6)

6.18.5 TSS – section 9


27 November 2015 75

It is important to note that our TSS must also provide indicative prices for the alternative control distribution network services that we provided to our customers. Given that these services are subject to a price cap control mechanism and that Ausgrid has little if any scope to reform the level and structure of these tariffs, Ausgrid has adopted the forecast prices for these services set out in the AER Determination. The detailed indicative pricing information and commentary for these services is provided in Appendices F to J.

8.2.2 Second stage of the network pricing process

Ausgrid proposes to update the indicative pricing schedule as part of the annual pricing process by updating the key inputs in Ausgrid’s indicative pricing model. Ausgrid believes that there is merit in allowing the DNSP some discretion over the extent that the inputs to this model are updated each year to ensure that the DNSP does not incur transaction costs where there is little if any economic benefit for the consumer. For example, Ausgrid does not at this stage foresee any longer term benefit to electricity users from annually updating the estimates of economic cost used in the indicative pricing model given that these costs are not expected to change materially over the regulatory control period. Nevertheless, Ausgrid accepts that updating these inputs to the indicative pricing model could be justified during the regulatory control period in the event of unanticipated changes in our demand and cost conditions, such as in the case of a rapid and widespread uptake of electric vehicles or solar PV systems.

Allowing Ausgrid to exercise professional judgement and expertise in this aspect of our price-setting process ensures that we retain ownership of our network tariffs, which is compliant with Chapter 6 of the NER, as evident from the following quote:

“it is important that DNSPs retain ownership of their network prices so that they face an incentive and obligation to set network prices that reflect the efficient costs of providing network services to consumers.”29

At this stage Ausgrid believes that the following inputs to the indicative pricing model should be updated as part of the annual pricing process during the regulatory control period:

• The expected annual revenue allowance for our standard control distribution and transmission services;

• The annual contribution to the NSW Government’s Climate Change Fund;

• The assumptions made in respect to the future increases in the TransGrid share of our transmission cost to serve;

• The closing balance in year t-1 of the overs and unders account for DUOS, TUOS and CCF; and

• Most of the inputs used in Ausgrid’s methodology for allocating residual cost to individual tariffs and charging parameters.

8.3 Overview of Ausgrid’s indicative price-setting process under the first stage of the network pricing process

Ausgrid’s has developed a schedule of indicative prices to satisfy the requirement under Section 6.18.1A(e) of the National Electricity Rules with the aim of providing our stakeholders with an understanding of the potential pricing outcomes under the pricing approach set out in this document on the basis of our current forecasts for the various inputs to our indicative pricing model.

29 AEMC 2014, Rule Determination, National Electricity Amendment (Distribution Network Pricing Arrangements) Rule, November, p.16.

27 November 2015 76

Figure 36 – Overview of indicative price-setting process

8.4 Summary of the indicative pricing outcomes at the NUOS level under stage one of the network pricing process

Ausgrid has developed indicative prices to recover our forecast revenue entitlements under the AER Final Decision over the regulatory control period on the basis of our baseline volume forecast. It is important to note that Ausgrid has varied these tariffs from the efficient tariffs to extent necessary to comply with the customer impact principle set out in Chapter 6 of the NER.

The indicative prices and customer impacts under Ausgrid’s indicative prices for our major published tariffs are discussed below at the NUOS level. The underlying indicative DUOS, TUOS and CCF prices for Ausgrid’s published tariffs are provided in Appendices B to D.

The following table compares the current NUOS prices in FY 2015/16 and indicative NUOS prices for Ausgrid’s network use of system tariffs for residential and small business customers over the regulatory control period to FY 2018/19.

Calculate the forecast annual revenue entitlement under AER Final Determination over the regulatory control period

Prepare annual volume forecasts at the charging parameter level

Estimate Long Run Marginal Cost and apply this estimate to the relevant charging parameter s in accordance with Ausgrid's proposed methodology

Estimate residual cost and allocate this estimate to the relevant charging parameters in accordance with Ausgrid's proposed methodology

To adjust prices at the charging parameter level to comply with side constraints and efficiency bounds test

Adjust prices at the charging parameter level to depart from efficient outcomes to the extent necessary to deliver acceptable customer impact over the regulatory control period

Step 1

Prepare indicative annual pricing outcomes over the regulatory control period based on a feasible range of volume forecasting scenarios

Step 2

Step 3

Step 4

Step 5

Step 6

Step 7

27 November 2015 77

9 Customer Impacts for business customers

This section contains enlarged versions of the customer impact analysis for business customers presented in section 10.2 of the main TSS document. The results for the customer impact study for residential customers is presented in section 10.1 of the main TSS document.

The figures below illustrate the indicative business customer bill impacts arising from the indicative prices for Ausgrid’s major published tariffs, as presented in the main TSS document. In particular, these figures show that business customers will either realise a reduction in their bill or an annual change in their bill that is on average in line with the rate of consumer price inflation, as measured by the Reserve Bank of Australia’s most recent estimates for the relevant period. Figure 37 – FY17-FY19 customer impacts EA050 (small business non-TOU)

Figure 38 – FY17-FY19 customer impacts EA225 (small business TOU)

0.0%

0.5%

1.0%

1.5%

2.0%

2.5%

0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000

Average

Annual Bill Im

pact

kWh

FY17‐FY19 Customer Bill Impact ‐ EA050 (Small Business Flat Tariff)

‐14%

‐12%

‐10%

‐8%

‐6%

‐4%

‐2%

0%

2%

4%

6%

8%

0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000

Average Annual Bill Im

pact kWh

FY17‐FY19 Customer Bill Impact ‐ EA225 (Small Business TOU)

27 November 2015 78

Figure 39 – FY17-FY19 customer impacts EA302 (LV TOU Capacity)



0.0%

1.0%

2.0%

3.0%

4.0%

5.0%

6.0%

40,000 60,000 80,000 100,000 120,000 140,000 160,000

Average

Annual Bill Im

pact

kWh

FY17‐FY19 Customer Bill Impact ‐ EA302 (LV TOU Capacity)

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0.5%

1.0%

1.5%

2.0%

2.5%

3.0%

3.5%

4.0%

160,000 260,000 360,000 460,000 560,000 660,000

Average

Annual Bill Impact

kWh


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0 5000000 10000000 15000000 20000000 25000000 30000000 35000000 40000000

Average

Annual Bill Im

pact

kWh


27 November 2015 79

Figure 42 – FY17-FY19 customer impacts EA370 (HV TOU Capacity)

Figure 43 – FY17-FY19 customer impacts EA390 (STV TOU Capacity)

0.0%

0.5%

1.0%

1.5%

2.0%

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0 5,000,000 10,000,000 15,000,000 20,000,000 25,000,000 30,000,000 35,000,000 40,000,000 45,000,000

Average

Annual Bill Impact

kWh

FY17‐FY19 Customer Bill Impact ‐ EA370 (HV TOU Capacity)

0.0%

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0 20,000,000 40,000,000 60,000,000 80,000,000 100,000,000

Average

Annual Bil Im

pact

kWh

FY17‐FY19 Customer Bill Impact ‐ EA390 (STV TOU Capacity)

27 November 2015 80

10 Compliance Check List

To assist the AER and stakeholders in understanding how the tariffs in our revised TSS comply with the requirements of Chapter 6 of the NER, Ausgrid has provided a detailed compliance checklist in the tables below.

27 November 2015 81

Table 22 – Regulatory proposal and proposed tariff structure statement – 6.8.2 – Submission of tariff structure statement

Rule Provision Amending Clause

Requirement Section in main TSS

Other documents

6.8.2(a) 11.73.2(a) A Distribution Network Service Provider must, whenever required to do so under paragraph (b), submit to the AER a regulatory proposal and a proposed tariff structure statement related to the distribution services provided by means of, or in connection with, the Distribution Network Service Provider's distribution system.

Entire Document All appendices

6.8.2(b) 11.73.2(a) A regulatory proposal and a proposed tariff structure statement must be submitted: by 27 November 2015.

Entire Document All appendices

6.8.2(c) 11.73.2(a) A proposed tariff structure statement must be accompanied by information that contains a description (with supporting materials) of how the proposed tariff structure statement complies with the pricing principles for direct control services.

Entire document

Appendix A, section 10

6.8.2(c1a) 11.73.2(a) The proposed tariff structure statement must be accompanied by an overview paper which includes a description of how the Distribution Network Service Provider has engaged with retail customers and retailers in developing the proposed tariff structure statement and has sought to address any relevant concerns identified as a result of that engagement

Overview Paper

6.8.2(d1) The tariff structure statement must be accompanied by an indicative pricing schedule. Section 9 Appendix B to E

6.8.2(d2) The tariff structure statement must comply with the pricing principles for direct control services.

Entire Document Appendix A

6.8.2(e) If more than one distribution system is owned, controlled or operated by a Distribution Network Service Provider, then, unless the AER otherwise determines, a separate tariff structure statement are to be submitted for each distribution system.

Not applicable

6.8.2(f) If, at the commencement of this Chapter, different parts of the same distribution system were separately regulated, then, unless the AER otherwise determines, a separate tariff structure statement are to be submitted for each part as if it were a separate distribution system.

Not applicable

27 November 2015 82

Table 23 – Distribution Pricing Rules – 6.18.1A –Tariff Structure Statement

Rule Provision Amending

Clause Requirement

Section in main TSS

Other documents

6.18.1A(a)(1) The tariff structure statement must include the tariff classes into which retail customers for direct control services will be divided during the relevant regulatory control period.

Section 3 Appendix A, section 3

6.18.1 A(a)( 2) The tariff structure statement must include the policies and procedures the Distribution Network Service Provider will apply for assigning retail customers to tariffs or reassigning retail customers from one tariff to another (including any applicable restrictions).


6.18.1A(a)(3) The tariff structure statement must include the structures for each proposed tariff. Section 9

Appendices A, Section 12

Appendices B to E

6.18.1A(a)(4) The tariff structure statement must include the charging parameters for each proposed tariff.

Section 9

Appendices A, Section 12

Appendices B to E

6.18.1A(a)(5) The tariff structure statement must include a description of the approach that the Distribution Network Service Provider will take in setting each tariff in each pricing proposal during the relevant regulatory control period in accordance with clause 6.18.5 (pricing principles).

Section 5 to 9


6.18.1A(b) The tariff structure statement must comply with the pricing principles for direct control services.

Entire document

All appendices

6.18.1A(e) A tariff structure statement must be accompanied by an indicative pricing schedule which sets out, for each tariff for each regulatory year of the regulatory control period, the indicative price levels determined in accordance with the tariff structure statement.

Section 9

Appendix B to E

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Table 24 – Distribution Pricing Rules – 6.18.1A –Tariff Classes

Rule Provision Amending Clause

Requirement Section in main TSS Other documents

6.18.3(b) Each customer for direct control services must be a member of 1 or more tariff classes.


6.18.3(c) Separate tariff classes must be constituted for retail customers to whom standard control services are supplied and retail customers to whom alternative control services are supplied (but a customer for both standard control services and alternative control services may be a member of 2 or more tariff classes).


6.18.3(d) A tariff class must be constituted with regard to:

(1) the need to group retail customers together on an economically efficient basis; and

(2) the need to avoid unnecessary transaction costs.


27 November 2015 84

Table 25 – Distribution Pricing Rules – 6.18.1A – Principles governing assignment or re-assignment of retail customers to tariff classes and assessment and review of basis of charging

Rule Provision


Other documents

6.18.4(a) In formulating provisions of a distribution determination governing the assignment of retail customers to tariff classes or the re-assignment of retail customers from one tariff class to another, the AER must have regard to the following principles:

Section 4

6.18.4(a)(1) retail customers should be assigned to tariff classes on the basis of one or more of the following factors:

(i) the nature and extent of their usage;

(ii) the nature of their connection to the network;

(iii) whether remotely-read interval metering or other similar metering technology has been installed at the retail customer's premises as a result of a regulatory obligation or requirement;

Section 3 and 4 Appendix A, section 3

6.18.4(a)(2) retail customers with a similar connection and usage profile should be treated on an equal basis; Section 3 and 4 Appendix A, section 3

6.18.4(a)(3) however, retail customers with micro-generation facilities should be treated no less favourably than retail customers without such facilities but with a similar load profile;

Section 3 and 4 Appendix A, section 3

6.18.4(a)(4) a Distribution Network Service Provider's decision to assign a customer to a particular tariff class, or to re-assign a customer from one tariff class to another should be subject to an effective system of assessment and review.

Note: If (for example) a customer is assigned (or reassigned) to a tariff class on the basis of the customer's actual or assumed maximum demand, the system of assessment and review should allow for the reassignment of a customer who demonstrates a reduction or increase in maximum demand to a tariff class that is more appropriate to the customer's load profile.

Section 3 and 4

6.18.4(b) If the charging parameters for a particular tariff result in a basis of charge that varies according to the usage or load profile of the customer, a distribution determination must contain provisions for an effective system of assessment and review of the basis on which a customer is charged.

Section 3 and 4

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Table 26 – Distribution Pricing Rules – 6.18.1A – Network Pricing Objective and Pricing Principles

Rule Provision


Other documents

6.18.5(a)

The network pricing objective is that the tariffs that a Distribution Network Service Provider charges in respect of its provision of direct control services to a retail customer should reflect the Distribution Network Service Provider's efficient costs of providing those services to the retail customer.

Entire document All Appendices

6.18.5(b) Subject to paragraph (c), a DNSP’s tariffs must comply with the pricing principles set out in paragraphs (e) to (j).

Sections 3 to 10

Appendix A, sections 3 to 9

6.18.5(c) A Distribution Network Service Provider's tariffs may vary from tariffs which would result from complying with the pricing principles set out in paragraphs (e) to (g) only:

(1) to the extent permitted under paragraph (h); and

(2) to the extent necessary to give effect to the pricing principles set out in paragraphs (i) to (j).

Sections 3 to 10


6.18.5(d) A Distribution Network Service Provider must comply with paragraph (b) in a manner that will contribute to the achievement of the network pricing objective.

Sections 3 to 10


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Table 27 – Distribution Pricing Rules – 6.18.1A –Application of the Pricing Principles

Rule Provision


Other documents

6.18.5(e) For each tariff class, the revenue expected to be recovered must lie on or between:

(1) an upper bound representing the stand alone cost of serving the retail customers who belong to that class; and

(2) a lower bound representing the avoidable cost of not serving those retail customers.


6.18.5(f) Each tariff must be based on the long run marginal cost of providing the service to which it relates to the retail customers assigned to that tariff with the method of calculating such cost and the manner in which that method is applied to be determined having regard to:

(1) the costs and benefits associated with calculating, implementing and applying that method as proposed;

(2) the additional costs likely to be associated with meeting demand from retail customers that are assigned to that tariff at times of greatest utilisation of the relevant part of the distribution network; and

(3) the location of retail customers that are assigned to that tariff and the extent to which costs vary between different locations in the distribution network.


6.18.5(g) The revenue expected to be recovered from each tariff must:

(1) reflect the Distribution Network Service Provider's total efficient costs of serving the retail customers that are assigned to that tariff;

(2) when summed with the revenue expected to be received from all other tariffs, permit the Distribution Network Service Provider to recover the expected revenue for the relevant services in accordance with the applicable distribution determination for the Distribution Network Service Provider; and

(3) comply with sub-paragraphs (1) and (2) in a way that minimises distortions to the price signals for efficient usage that would result from tariffs that comply with the pricing principle set out in paragraph (f).

Sections 7, 8 and 9

Appendix A, section 5 and 6

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Table 28 – Distribution Pricing Rules – 6.18.1A –Application of the Pricing Principles (Continued)

Rule Provision


Other documents

6.18.5(h) A Distribution Network Service Provider must consider the impact on retail customers of changes in tariffs from the previous regulatory year and may vary tariffs from those that comply with paragraphs (e) to (g) to the extent the Distribution Network Service Provider considers reasonably necessary having regard to:

(1) the desirability for tariffs to comply with the pricing principles referred to in paragraphs (f) and (g), albeit after a reasonable period of transition (which may extend over more than one regulatory control period);

(2) the extent to which retail customers can choose the tariff to which they are assigned; and (3) the extent to which retail customers are able to mitigate the impact of changes in tariffs through

their usage decisions.

Section 8 and 10 Appendix A, section 6 and 9

6.18.5(i) The structure of each tariff must be reasonably capable of being understood by retail customers that are assigned to that tariff,

having regard to:

(1) the type and nature of those retail customers; and

(2) the information provided to, and the consultation undertaken with, those retail customers.

Sections 3 and 4 Appendix A, Section 11 and 12

6.18.5(j) A tariff must comply with the Rules and all applicable regulatory instruments. Entire Document All Appendices

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11 Stakeholder Engagement

11.1 Rule requirement

The National Electricity Rules require Ausgrid to prepare an Overview document summarising our proposed TSS in plain English. The overview must include a description of how Ausgrid engaged with electricity consumers in developing the TSS and the manner in which it sought to address any relevant concerns. The Overview document provides a useful summary of the issues raised by stakeholders, and how we addressed their concerns when developing this TSS document.

The purpose of this section is to set out detailed information on our engagement process with stakeholders including details on workshops, interviews and consultations on our joint issues paper, prepared with electricity distribution networks Endeavour Energy and Essential Energy. We also provide detailed information on key comments we received from our stakeholders, and the manner in which we considered these issues when developing our revised TSS.

Further supporting information is contained in the other appendices referenced throughout this section.

11.2 Ausgrid’s process for engaging with stakeholders

Ausgrid engaged with a diverse range of stakeholders when developing our TSS, including customers, consumer representatives, community organisations, and electricity retailers. Over recent years, Ausgrid has sought to better engage with our stakeholders and to provide more accessible information concerning our industry and operations. Many of these processes influenced the manner in which we have conducted tariff reform. Figure 14.1 sets out the phases of our engagement process on the TSS and tariff reform more broadly.

Figure 44 – Ausgrid’s TSS Stakeholder Engagement

In the sections below we provide more information on these engagement activities such as workshops, issue papers, meetings with local Government, and feedback we received via the NSW Government’s Have Your Say portal.

11.2.1 Stakeholder Roundtables and Forum

A number of stakeholders approached Ausgrid to be involved in discussion groups. In other cases, Ausgrid was able to identify relevant stakeholders with an interest in the discussions, such as large customers. The stakeholders were invited to participate in a number of joint forums and roundtable discussions, including:

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a TSS Vulnerable Customers Forum hosted by the Energy Networks Association;

a Stakeholder Roundtable for Electricity Retailers;

a Stakeholder Roundtable for Food and Fibre Stakeholders;

a Stakeholder Roundtable for Consumer and Environment Stakeholders;

a Second Stakeholder Roundtable for Consumer and Environment Stakeholders on tariff options for (at the request of consumer advocates); and

a Third Second Stakeholder Roundtable for Consumer and Environment Stakeholders on the economic and financial assumptions and evidence base used by the network businesses to assess tariff options (at the request of consumer advocates)

The Stakeholder Roundtables were facilitated by ACIL Allen Consulting30 and involved senior executives from Ausgrid, Endeavour Energy, Essential Energy, and Networks NSW (NNSW). The Chief Executive Officer of NNSW presented at the Retailer Stakeholder Roundtable, and participated in discussions. Senior representatives from HoustonKemp Economists also attended each workshop.

Discussions about tariff structures at the ENA Vulnerable Customers Forum were facilitated by ACIL Allen, following a presentation by the CEO of NNSW, the Energy Networks Association, and the NSW Energy and Water Ombudsman.

A summary of each of the Roundtables and the ENA Forum discussion is provided in Attachment B in Appendix R. These tables list the stakeholders that were invited to the Forum and the Roundtables, and stakeholders who were able to participate (we note some stakeholders were unable to participate because of scheduling conflicts).

The following table lists a number of Ausgrid’s stakeholders who were engaged on the TSS separate from the Roundtable and one-on-one interviews and discussions.

Table 29 – Ausgrid TSS Engagement with Key Stakeholders represented on Customer Council

Engaged Member Organisation Stakeholder engagement

Armanda Scorrano Council of Social Service of NSW

Stakeholders received a briefing on different tariff options and the submission of the TSS.

Stakeholders were presented with an Issues brief.

Each stakeholder was Invited and encouraged to provide feedback on the Networks NSW Issues Paper.

Annie Kiefer Country Women’s Association

Cristina Fica The Smith Family

James Ryan Nature Conservation Council

Morris Mansour Ethnic Communities Council

Sarah Davidson Council of the Ageing NSW (COTA)

Tina Jelenic Public Interest Advocacy Centre (PIAC)


30 In August 2015, Ausgrid, Endeavour Energy and Essential Energy contracted economics, public policy and stakeholder strategy firm ACIL Allen Consulting to assist with facilitating TSS stakeholder engagement. The ACIL Allen team also comprised Ogilvy Public Relations Australia, which was involved in assisting NNSW and each network business to communicate the TSS engagement process and opportunities to stakeholders (including customers and the general public), and conduct one-on-one interviews with interest group stakeholders around questions raised in the NNSW TSS Issues Paper)

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11.2.2 Issues Paper

Ausgrid, in conjunction with Endeavour Energy and Essential Energy, published an issues paper inviting feedback on tariff reform, and how to engage on the tariff structure statements. The paper was distributed to a wide group of stakeholders via email, posted on the websites of Ausgrid, Endeavour Energy and Essential Energy, and made available via the Have Your Say online consultation portal.

A group of stakeholders identified by the network businesses as having a specific interest in network tariffs and the 2017 – 2019 TSS were invited to discuss their insights, issues and ideas during one-to-one interviews with a senior stakeholder consultation practitioner from Ogilvy Public Relations. Details of stakeholders interviewed, and those invited to attend in October but who could not participate, are in the following Table:

Table 30 – Initial Stakeholder Engagement Conducted by Acil Allen Consulting Around Preferences on Engaging the NSW Network Businesses on TSS Issues, September 2015

Contact Organisation Participation

Randall Brown Energy Australia Participated

Martin Jones (Replacing Mercedes Lentz)

Consumer Utilities Advocacy Centre

Participated

David Calder Origin Energy Participated

Mandy Gilmour Cotton Growers Association

Participated

Patrick Whish-Wilson AGL Participated

Gavin Dufty St Vincent de Paul Participated

Chris Dodds EWON Participated

Stefanie Shulte NSW Irrigators Council Participated

Note: These interviews were arranged and conducted by Ogilvy Public Relations Australia, part of the ACIL Allen Consulting consortia contracted by the NSW network businesses via NNSW to assist with TSS stakeholder engagement

Source: ACIL ALLEN CONSULTING, 2015

The discussion guide and summary of stakeholder comments and answers during the stakeholder engagement underpinning the initial TSS is included Attachment A of Appendix R.

11.2.3 Engagement with large customers

Ausgrid issued a comprehensive consultation paper to large customers connected to our electricity network seeking their feedback on a broad range of issues in respect to our TSS. This consultation paper is provided in Appendix M.

Ausgrid received a number of submissions from large customers in response to our invitation to comment on our consultation paper. We appreciated the efforts made by these customers to provide us with detailed feedback in the compressed time frame available. This has provided us with an important lesson about commencing timeframes earlier in cases where there is significant complexity and modelling to be undertaken. Nevertheless, we have carefully considered the feedback from our large customers, and present in Appendix N a summary of the questions posed to large customers, their views on those questions and Ausgrid’s response.

11.2.4 Engagement with local Government

The Australian Energy Regulator has previously set price levels and structures for street lighting. However, all the NSW network businesses including Ausgrid invited feedback from local government about street lighting pricing structures.

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As part of TSS consultation, Ausgrid wrote to all local government areas in its operational footprint advising them of the stakeholder engagement process. Telephone discussions were held between some local government areas and Ausgrid about the TSS process and street lighting charges. The Southern Sydney Regional Organisation of Councils (representing 35 local government areas) submitted a response to the NNSW Issues Paper via the Have Your Say consultation web portal.

11.2.5 “Have Your Say” online portal

The views and insights of customers around the TSS and other tariff issues were sought through the Have Your Say consultation portal, and via Ausgrid’s Facebook page. The portal was open from September 30, 2015, to November 4, 2015. A summary of the submissions and comments via the Have Your Say portal is in Appendix Q.

Figure 45 – Have Your Say Public Consultation Portal – Customer and General Public TSS Engagement

Note: Fragment from Ausgrid’s Facebook page, Source: Ausgrid, 2016

11.2.6 Consultation after the submission of Ausgrid’s initial TSS

The AER released an issues paper on Ausgrid’s initial TSS and held a public forum to gather stakeholder feedback in March and April 2016, respectively. Ausgrid was actively involved throughout this process, submitting a comprehensive submission to the AER’s issues paper and actively participating in the AER’s public forum. A high-level summary of stakeholder submissions to the AER’s issues paper on Ausgrid’s TSS is included at Appendix V.

In the week after the AER published its draft decision, Ausgrid held a briefing session for stakeholders to outline the key issues and implications arising from the AER’s feedback in the draft decision.

Ausgrid then issued and invited submissions on a short discussion paper that was circulated to stakeholders, this discussion paper is included at Appendix S. After undertaking further analyses and considering stakeholder’s submissions, Ausgrid again met with stakeholders in mid-September to discuss Ausgrid’s preferred approach for the revised TSS and, importantly, to understand stakeholder views on that approach. The presentation from that workshop is included at Appendix T.

Stakeholders that attended this workshop included:

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Chris Dodds – EWON;

David Havyatt - Energy Consumers Australia;

Keith Besgrove - Energy Consumers Australia;

Douglas McCloskey – NCOSS;

Iain Maitland - Ethnic Communities' Council;

Jane Leung – PIAC;

Deirdre Moor – PIAC;

Mark Byrne – TEC;

Jay Whelan - Energy Australia;

Joseph Caruana - Endeavour Energy; and

Lisa Beckmann – AER/ACCC.

A key focus in this session was on what further reforms could practically be included in the revised TSS and, with these practicalities in mind, Ausgrid and stakeholders agreed on a number of key areas of focus for the next TSS.

Stakeholders continued to support the introduction of seasonal peak periods. However, a number of stakeholders indicated a preference for a narrower summer peak period for residential customers and encouraged Ausgrid to ‘experiment’ with a different shoulder period on the weekends for residential customers. Ausgrid discussed these matters at length in this forum.

In the days after the mid-September stakeholder workshop, Ausgrid sent stakeholders a follow-up communication reflecting on the views provided by stakeholders in the workshop and how Ausgrid proposed to take those views into consideration, bearing in mind the short timeframe for submission of the revised TSS.

Specifically, Ausgrid explained to stakeholders that, owing to the diversity in the timing of peak demand across our network, the network-cost implications of an inappropriately defined peak period and the tight time frame for submission of the revised TSS, Ausgrid proposes to retain the 2pm to 8pm peak period in the summer months. Ausgrid plans to make this a key area of focus in the next TSS, which will enable it to undertake the research, detailed analysis and consultation necessitated by a reform of this magnitude.

Similarly, Ausgrid outlined to stakeholders that Ausgrid’s preferred position is to retain the weekend shoulder period in the current regulatory control period due to the material price and customer impacts that would arise from removing the weekend shoulder period. Removing the weekend shoulder would necessitate a substantial increase in the shoulder price (in the order of 66 per cent increase), with corresponding adverse bill impacts on customers with usage in the shoulder period on weekdays.

Similarly, Ausgrid is hesitant to ‘test new weekend shoulder periods’ over the remainder of the current regulatory control period – as was suggested by some stakeholders – since this may risk confusion amongst customers. Ausgrid is mindful of the potential confusion and inconvenience of adopting a changed position on the charging windows for the 2017-19 period, where further analysis as part of the next TSS may indicate that further changes are again required.

Against the backdrop of the substantial reforms to be implemented as part of this TSS, Ausgrid proposes to consider reforming the weekend shoulder period for residential customers in the next TSS, ie, once Ausgrid has successfully mitigated the customer impacts of the reforms in this TSS.

To this end, we will work closely with stakeholders to help build an overall research and engagement program on future tariff structures that would include a review of existing knowledge and research on electricity tariffs to help inform this overall approach. This will include discussion on the merits of future trials or pilots on tariffs, including changes to charging windows and the impacts on customers or likely customer response. This work can begin very soon after the 2017-19 Revised TSS is submitted. Indeed,

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Ausgrid is already working with CitySmart to undertake a review of existing knowledge and to conduct further market research.

Ausgrid considers that it is in everyone's interest to build a considered engagement program with our stakeholders before making changes to tariff designs. This includes the potential for a demand charge for residential customers and the merits of an inclining block tariff, as raised by stakeholders.

Our stakeholders generally acknowledged Ausgrid’s practical response to what can prudently be achieved in the timeframe for the revised TSS, and on the matters for which it would be prudent to delay consideration until the next TS, which will be submitted to the AER in just over 12 months’ time.

Our engagement with stakeholders identified the following key areas of focus for the consideration as part of the consultation for the next TSS, including:

the future of the non-TOU tariff for residential and small business customers;

the potential to implement a demand charge for residential customers;

the scope to reform the peak periods and the weekend shoulder period; and

how best to mitigate customer bill impacts for low-income and vulnerable householders.

Ausgrid looks forward to further consultation with stakeholders on these matters and continuing to work together in developing and implementing Ausgrid’s transition to efficient tariffs.

11.3 Key issues raised by stakeholders

In our Overview of the TSS we provided a comprehensive summary of the key issues raised by our stakeholders during the engagement process. In the sections below, we set out these issues and provide a table of detailed comments and responses.

11.3.1 Customer Education

A number of stakeholders noted that the community’s understanding of network electricity tariffs was low – including representatives from retailers, environment, consumer, and vulnerable groups. In particular, environment and consumer advocates considered that culturally and linguistically diverse (CALD) groups have particular difficulty understanding their bills. A related point was that consumers find tariffs confusing. This means they are unable to make informed decisions that can reduce their electricity costs.

We acknowledge that we can do more to provide an understanding of our network tariffs. We accept that we have to work with retailers and other stakeholders to address this important issue. One of our key objectives in preparing an overview was to provide a plain English description of our charging structures, and how this impacts the electricity bills of our customers. We also wanted to provide a clear summary of the reasons for changes that customers may see in the future under our tariff reform. We hope that providing the information in a non-technical way makes it useful for our stakeholders

We also recognise that the transition to more efficient tariff structures has the potential to increase complexity. We have sought to address this concern by pursuing a transitional approach, rather than moving to the most efficient structure immediately. For instance, our tariff structure statement incorporates transitional tariffs so that customers have adequate time to understand and respond to the changes.

Further, we are mindful of the risk of confusing stakeholders by frequent changes to tariff structures. Therefore, our approach to tariff reform is founded on the implementation of carefully considered reforms. This is reflected in our decision to exclude from the reform package in this TSS, potentially meritorious reforms, for which Ausgrid considers it would be our customers interest to consider further as part of the consultation for the next TSS, ie, so as to afford Ausgrid time to undertake the requisite analysis.

11.3.2 Declining block tariffs

Some of our stakeholders indicated concerns with the previous declining block tariff (DBT). In particular, there was a view that declining block tariffs provide incentives for consumers to use more electricity, which in turn would have an adverse impact on the environment. There was also a view from vulnerable

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customer advocates that a declining block tariff would disadvantage low income households who in general consume lower amounts of electricity.

We have taken this feedback from stakeholders, as well as feedback from the AER, on board in our revised TSS by removing the DBT and replacing it with a flat tariff.

11.3.3 Time of Use Tariffs

A small proportion of our customers considered that time of use tariffs are fair and reflective of network infrastructure use, and provide a good lever to change consumption behaviour. However, the majority of stakeholders considered that time of use tariffs were complicated and difficult for customers to understand.

We have carefully considered the views of our stakeholders when developing the tariff structure statement. We have made key changes to our time of use tariffs by changing the times at which we charge peak rates. In our view our new definition is more closely aligned to the timing of peak demand that drives our forward looking costs.

Some stakeholders also indicated a preference for alternative, narrower peak periods for residential customers in the summer months, and for refinements to the weekend shoulder. We discuss our response to these views in section 11.2.6 above.

We recognise that some customers lack the ability or information to change their energy use at peak times. We have sought to address these equity concerns by adopting a cautious approach to implementing tariff reforms and by ensuring there is a staged transition to the changes.

Some stakeholders – such as food and fibre producers, environmental advocates, some retailers and customer groups – considered that a specific demand tariff could provide more choice on when to use electricity to suit their budget. Such a tariff gained further support when there was the opportunity to opt-in. Other stakeholders did not support such a tariff, particularly one vulnerable customer stakeholder who considered it to be problematic for low income families.

We note the support from some stakeholders for an opt-in demand charge, and agree that it is likely to play an important role in future tariff reform. For this TSS we have not chosen to implement a demand charge as we wanted to methodically consider design options for such a charge, so that we could quantify the potential impact on each customer. Nevertheless, we have agreed with stakeholders that this will be a key area of focus in the next TSS.

11.3.4 Specific tariffs

Stakeholders made a number of suggestions on alternative types of tariffs. For example, a stakeholder representing vulnerable customer groups was strongly in favour of social tariffs, stating that further analysis is required to understand the impact that electricity bills have on specific vulnerable groups. However, many stakeholders disagreed, and considered social policy to be a government issue.

This view is consistent with a statement made in 2007 by the then Minister of Energy in relation to the interpretation of the National Electricity Objective, ie:31

“It is important that the National Electricity Objective does not extend to broader social and environmental objectives”

Some stakeholders suggested the possibility of a specific tariff for irrigators but, for the most part, stakeholders considered that such tariffs should not be offered. Most stakeholders considered that while regional customers should not pay more than urban customers, and that concessional tariffs should not be provided for regional customers.

Some stakeholders considered that consumer generators should pay a tariff for the benefits they receive from exporting to the network, however, environmental advocates were strongly opposed to such a tariff.

31 Hansard, South Australia House of Assembly, Sep 2007.

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At this stage, we consider that there has not been sufficient analysis of the issues and implications stemming from the tariff suggestions identified above. For example, there is limited data on how the tariffs would affect network usage, or how such tariffs would impact on different customer groups. In relation to the concept of a social tariff we note that the transitional arrangements together with our goal to gradually rebalance tariffs over time will ensure no customer receives an unacceptable bill increase over the regulatory period. We also note the considerable concerns raised by stakeholders opposed to these tariffs. As a result, we have not proposed these tariffs in our TSS.

11.3.5 Timeframe for implementing new tariffs

The majority of stakeholders considered that a three to five year timeframe was most appropriate to effectively introduce a new tariff structure. Importantly, short term implementation would most likely result in bill shock that was both inequitable and not ‘politically palatable’. Further, longer term planning allows greater consultation and communication on upcoming tariff changes. Providing more certainty over the future direction of tariffs will drive changes in consumer behaviour. However, a few stakeholders believed that if the changes were marginal, they could be implemented in a shorter timeframe.

We have listened very carefully to the concerns of our stakeholders on a rapid implementation of tariff reform. While some reform is not likely to cause bill shock, we have nevertheless adopted a cautious approach by developing transitional tariffs to help gradually rebalance tariffs over time. Ausgrid expands on its view of the transition to efficient tariffs in section 8 of the main TSS document.

Table 14.3 below identifies the issues raised by stakeholders, and how we have addressed these issues in developing our revised TSS.

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Table 31 – What have our stakeholders said?

Issue Feedback Our response

Consumer understanding of tariffs

A number of stakeholders commented that the community’s understanding of network electricity tariffs was low – (including representatives from retailers, environment, consumer, and vulnerable groups).

Environment and consumer advocates perceived that culturally and linguistically diverse (CALD) groups have particular difficulty understanding their bills; and that one third of SMEs do not read their bills.

“I suppose most customers wouldn’t even understand there is an underlying network tariff, let alone how they relate.”

A related point made was that consumers find tariffs confusing. This means they are unable to make informed decisions that can reduce their electricity costs.

“I’d imagine a lot of consumers are still struggling with the difference between a retailer and a distributor, let alone understanding that a distributor has a network tariff and a retailer can choose to reflect that or not in their retail tariff.”

Stakeholders perceived that the complexity of network and retail tariffs – rather than a lack of information about them – contributes to consumer confusion (many noted tariff information provided by networks was generally considered to be good.

Stakeholders interviewed concluded that customers are unware of the complexity of the electricity distribution system, and the elements that contribute to network charges – or that the complexity of the system produces “white noise”, or a low will to want to understand the system.

“When you get to the general public they glaze over fairly quickly, and as soon as you talk about those particular issues, network tariffs, all they want to know is how much are they going to pay from a retail perspective, how they pay it, how often they are going to pay it... most of them don’t know even know the network exists, except when they have an outage.”

Ausgrid notes that community understanding and awareness of network tariff structures is poor.

Ausgrid accepts that educating customers on network tariff structures is important and recognises that addressing this issue will require that network businesses work proactively with Retailers.

Declining block tariff

Most stakeholders interviewed indicated they did not support a declining block tariff for NSW customers.

Although a flat tariff reduces the flexibility for Ausgrid to manage the bill impact of transitioning to a usage charge that reflects long run marginal cost (LRMC), Ausgrid supports stakeholder’s and the AER’s view on this matter and is comfortable replacing the DBT with a flat tariff in the revised TSS.

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Environmental issues

Some stakeholders flagged that declining block tariffs provide incentives to consumers to use more electricity, which would have an adverse impact on the environment. Environmental and vulnerable customer representatives felt that a move to declining block tariffs would send a contradictory signal to previous messages about reducing consumption.

Some stakeholders felt maintenance of a declining block tariff could be “unfair” to customers encouraged to invest in energy-saving and alternative energy generation devices.

“(DBTs are) reward increased consumption. So some people who are into energy efficiency would not like that because it sends a contradictory message.”

See response above.

Impact on low-income households

Vulnerable customer and environment advocates stated a declining block tariff is likely to disadvantage low-income households, who in general consume lower amounts of electricity than other households.

“Low consumption consumers will not benefit from the declining cost of energy in the subsequent consumption blocks, and high prices will be maintained for non-discretionary energy consumption required to support a basic standard of living.”

See response above.

Impact on primary producers

Food and fibre groups perceive that a declining block tariff would disadvantage them, as their energy use can be very high at some times of the year, and significantly lower during others.

“We are forced to schedule the start of our irrigation program with the billing cycle for electricity, rather than when our crops need the water.”

See response above.

Implementation Some stakeholders supported a DBT as an interim measure to manage a transition to a long-term tariff structure - while NSW “catches up” with other States to install more smart meters.

Environmental advocates requested that long run marginal cost calculations be made available to support the rationale for a declining block tariff, It was noted Networks NSW agreed to share these calculations in the coming weeks.

Stakeholders who supported smart meters felt that they should be introduced by retailers in NSW, and paid for by consumers, as long as they were not imposed upon them.

“Ultimately the customer should pay, but hopefully the meters will be creating some efficiencies that can be incorporated into the final cost of the unit making it a very, very modest cost. Otherwise people will be very much getting up in arms.”

Ausgrid provided Environmental advocates with our LRMC calculation and underlying analysis, how we propose to apply this estimate to the calculation of the “efficient” tariff proposition and its linkage to the indicative price schedule.

Ausgrid notes the feedback from stakeholders on the DBT as a transitional strategy, the role and importance of smart meters.

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Inclining block tariff

Some stakeholders indicated support for an inclining block tariff for customers with basic meters. These stakeholders consider that an inclining block structure reinforces the concept of ‘higher use equals higher cost’ for customers and that it would benefit low income and vulnerable customers.

Nevertheless, stakeholders were receptive to Ausgrid’s decision to replace the DBT with a flat tariff in the revised TSS, and to earmark further consideration of its non-TOU tariffs as part of the next TSS.

Ausgrid supports the AER and stakeholders’ view that, for the purpose of this TSS, it is appropriate to replace the DBT with a flat tariff, and to delay further consideration of the structure of Ausgrid’s non-TOU tariffs until the next TSS.

Demand tariff This tariff was supported by food and fibre producers, environmental advocates, and some retailers and consumer groups. They considered a demand tariff provided consumers with more choice about when to use electricity to suit their budget. This type of tariff was particularly supported if it could be opt-in.

Environmental stakeholders stated NSW has more smart meters than Queensland or South Australia, yet network businesses in both those states still offer a demand tariff. They feel that the low take-up of smart meters in NSW should not prevent network businesses offering a demand tariff.

Other stakeholders did not support this tariff. One vulnerable customer stakeholder was strongly opposed to it because it was considered to be problematic for low income families:

“They hate it, they’ve got kids that all come home from school right at the peak. They switch on the TV because it occupies the kids while they’re cooking – there’s no way in the world that this demand tariff is friendly, it’s not family friendly, because they’re terrified that it’s going to be loaded up because 60 per cent of an annual bill turns up in the summer time.”

Some stakeholders stated they would be more supportive of demand tariffs if smart meters were rolled out in NSW, because these meters would enable customers to be more aware of, and monitor, their electricity consumption.

Ausgrid notes the support amongst stakeholders for the introduction of an optional demand tariff.

Ausgrid believes that demand charges are likely to play an important role in future tariff reforms, but at this stage has decided not introduce an optional demand tariff or to reform existing TOU tariffs to incorporate a demand charging parameter.

The key reason for this decision is that Ausgrid wishes to delay this matter until it has:

Explored the potential design options for a demand charging parameter.

Better understood the potential impacts on customers of each option.

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Time of use tariff

Only a small number of stakeholders supported this tariff. They considered it was fair, reflective of network infrastructure use, and a good lever to change consumption behaviour:

“Our understanding is always that the network was built for peak times, so cost reflectivity wise, and equity wise, customers who use more at the peak than customers who manage to avoid the peak.”

However, most stakeholders were not supportive of time of use tariffs:

“The tariff doesn’t work for my 80 year old mother, because she’s scared to put on an air conditioner at 4pm in the afternoon because she’s terrified, on a 40 degree day.”

“You can’t adjust family life to make the kids have their baths at 9pm and lessen the power bill.”

“We are on 24/7 usage for our business… I know people who turn all the lights and appliances off in their homes at night or when away to reduce their power consumption and bill. We can’t do that. Much as we’d like, the pumps need to run 24/7, or else our crops die.”

This tariff was perceived also to be complicated, and difficult for customers to understand.

A number of stakeholders stated this tariff was unpopular in Victoria, where customers did not understand it, and feared it would lead to ‘bill shock’.

Ausgrid believes that a TOU component to tariffs is required to efficiently signal LRMC.

Ausgrid understands and accepts that conveying more efficient peak price signals has the potential to cause unacceptable bill impacts for particular groups of customers.

Ausgrid believes that it is important to address these equity concerns by adopting a cautious approach to the implementation of tariff reforms as well as ensuring that these reforms are accompanied by appropriate transitional tariff arrangements.

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Social tariff The NSW Council of Social Services (NCOSS) was happy to be quoted, and is strongly in favour of social tariffs.

It presented some key data to support its position: in 2014 about 33,000 households had their electricity supply disconnected for failure to pay an electricity bill, a figure that has increased by 100 per cent over five years.

NCOSS stated further analysis is required to understand the impact that electricity bills have on specific vulnerable groups, such as carers, large families, people with medical heating or cooling needs, and people with low incomes:

“Low income consumers vary greatly by household size, inefficient housing and household appliances, and sometimes lack of understanding about energy consumption.”

However, most stakeholders opposed social tariffs for the following reasons:

• networks are better placed to focus on overall cost reduction rather than the development of a complicated discount system;

• multiple tariffs create higher levels of administration, and ultimately costs for the consumer;

• there is no guarantee that retailers would pass on social tariffs to the consumer;

• social tariffs distort the market and do not address underlying issues of affordability

• the cost of social tariffs needs to be met elsewhere – ‘cost-shifting’ in effect - and other customers may not be willing to meet these costs;

• network businesses should not be responsible for making value judgments about who should receive a discount and who should not. Most stakeholders felt strongly that government was best placed to make those decisions, and had responsibility to do so.

“We don’t want a multitude of different tariffs across the nation. It’s expensive for the industry, it’s expensive for everyone, and it creates an enormous amount of cross-charging”.

“Social policy is a government issue. It is a broad ranging issue that affects more than just vulnerability and affordability of energy... the network (business) should strive to deliver an efficient network tariff, and then any other social policy arrangements are up to other parties to facilitate”.

Ausgrid has decided at this stage not to introduce a social tariff.

While Ausgrid is aware that tariff structure reforms have the potential to impose unacceptable bill impacts on particular customers groups, our careful approach to the implementation of reforms, including transitional tariff arrangements and rebalancing constraint, will ensure that no customer will receive an unacceptable bill increase over the remainder of the current regulatory control period.



Food and fibre tariff

Most stakeholders interviewed considered that a food and fibre tariff should not be offered by the NSW network businesses.

“If those industries (food and fibre) need some kind of subsidy to be cost-effective then that should come by different means, government subsidies or other means.”

Food and fibre representatives supported the network businesses considering a specific tariff for irrigators in particular (although one stakeholder feared this would end up costing irrigators the same in the long run).

“Growers have seen power bills increase by up to 300 per cent over the last few years. Growers are thinking seriously about going off the grid because of costs.”

Ausgrid has decided not to introduce a food and fibre tariff. Nevertheless, Ausgrid accepts that it is critically important to understand the extent that different tariff reform options impact different customer groups.

To ensure that the interests of our customers are safeguarded, Ausgrid proposes to delay the introduction of our key tariff reforms until the final year of the regulatory control period and to supplement these reforms with comprehensive transitional tariff arrangements.

Location and regional tariff

No stakeholders wanted to see rural consumers charged more for electricity than urban consumers, even though the actual costs of electricity distribution may be higher in regional and remote areas of NSW.

“That would probably take the concept of cost-reflection a step too far. Rural people would lose out. You need to remember that NSW is more than just Sydney/Newcastle… In Australia people strongly believe that everyone should have equal access to essential services. This idea doesn’t match social and political reality”.

“There is a social element in people having the right to access services regardless of where they choose to live”.

Concurrently, there was no appetite for concessional tariff pricing for regional consumers based on their location.

In light of the feedback from stakeholders Ausgrid has decided not to introduce location or region-based published network tariffs for residential and business customers.

Ausgrid accepts that tariff reform needs to balance economic and equity outcomes, but intends to investigate the extent that economic costs vary within our network area for the purpose of refining our ‘efficient’ tariff proposition for the next TSS.



Consumer electricity generation

A small group of stakeholders interviewed felt strongly that consumer generators should make a corresponding contribution in light of the benefits they gained from exporting to the network, and so there should be an export tariff.

Environmental advocates were less supportive of this option, citing the following arguments:

solar users will perceive an export tariff as another cost imposed on them, which would encourage them to leave the grid entirely in the long term;

a solar export tariff would send a contradictory, even hypocritical, message compared to communications about the environmental and financial benefits of alternative energy sources;

no other network nationally has found it necessary to introduce a solar export tariff in the TSS process;

if the rationale is that the average load profile of solar customers is less favourable, this will be taken care of by demand tariffs; and

there is disagreement that solar power production is a cost to networks.

Environmental advocates argued that consumers who invested in solar generation should be brought “down” a block along the three blocks of declining block tariffs. They posited that net solar customers (as opposed to gross solar customers) have invested so they can save energy, with the expectation of a consistent price. Shifting some of the cost to an earlier block means they receive less of the savings anticipated.

Ausgrid has decided at this stage not to introduce a network tariff specifically for customers with a small scale electricity generation unit connected to our electricity network.

This decision reflects a number of considerations, such as to provide more time for Ausgrid to undertake additional economic analysis to better understand:

1. The extent that the economic cost to provide distribution network services to these customers varies from similar customers without small scale electricity generation. This will form the basis of a decision on whether to assign customers with small scale electricity generation units to a specific tariff class in the next regulatory control period.

2. The impacts of more efficient tariffs on network usage and electricity generation behaviour of customers with small scale electricity generation units; and

3. The role of the LRMC-based incentives on customers that both consume energy and export energy.

Ausgrid accepts that changes in the level and structure of network tariffs have the potential to impact the financial returns from historical investments, such as investments in Solar PV systems and energy-efficient appliances. Ausgrid’s position is that these issues are best addressed by adopting appropriate transitional pricing arrangements, rather by than modifying the efficient tariff proposition.



Timeframe for introducing new tariffs

Most stakeholders felt a three to five year timeframe was most appropriate to effectively introduce a new tariff structure, because:

• consistency in tariff arrangements is required over three to five years to drive any changes in consumer behaviour;

• short-term implementation would most likely result in ‘bill shock’, which would be inequitable, and would “not be politically palatable”;

• a shorter timeframe would not be effective to consult, discuss and communicate tariff changes with consumers.

Two stakeholders, however, suggested the appropriate timeframe to introduce new tariff structures would depend on the predicted bill increases: if these were likely to be marginal, the timeframe could be much shorter:

“All of these things should be measured in quantum. If you’re talking an extra $30 a year, I don’t think we need a three year window to introduce this”.

“Changes happen all the time and no-one lets us know they are coming, we just see the change reflected in the bill. It seems the companies are a law unto themselves, so I have no idea why they are bothering to ask this question.”

Ausgrid accepts that the introduction of a new tariff has the potential to create unacceptable bill shocks for some customer groups.

Ausgrid also accepts that the risk of unacceptable bill shocks is dependent on the particular circumstances, such as whether the new tariff is offered on an opt-in basis only.

Nevertheless, Ausgrid has adopted a careful approach in our TSS by delaying the introduction of new default tariffs until the final year of the current regulatory control period.

Further, Ausgrid has introduced transitional tariffs to ensure that customers do not receive an unacceptable bill impact as a result of being reassigned to a different tariff.

CPI-based constraint

Stakeholders were asked if they felt consumers would support a CPI cap being placed on any tariff changes to reduce ‘bill shock’.

Stakeholders were divided evenly in their support for such a cap.

Consistency and long-term tariff planning

Most stakeholders supported emphasised the importance of consistency, and long-term thinking around tariff changes. These stakeholders perceive customers want certainty and simplicity, not volatility and complexity.

Two stakeholders flagged the importance of not sending mixed signals to consumers, as tariffs are designed to stimulate behaviour change.

“I understand this strategy statement only applies for two years. So I’d like to see some comments about the next one (TSS period) to at least highlight at this stage, because all the other networks have a longer period. If we’re not going to get anything more than just declining block (the network businesses) should at least highlight what they’ll be looking at next time.”

“Whatever Networks NSW does, whatever tariff structure it decides, it can’t keep chopping and changing it once every five years in a regulatory period. People need certainty.”

Ausgrid notes the mixed feedback on our CPI pledge.

Ausgrid believes that the application of a CPI-based rebalancing constraint is an important element of our revised TSS.

It is important to note that while increases to bill outcomes will be constrained to CPI, our proposed tariff reforms, such as the proposed reductions in shoulder and off-peak energy charges, will result in our customers receiving stronger signals to use our electricity network more efficiently over time.

Ausgrid accepts that it is critically important to provide stakeholder with pricing certainty. This is the reason why Ausgrid has explained in detail the efficient tariff proposition and the underlying rationale for our tariff reform options in our revised TSS.



Tariff education Several stakeholders emphasised the importance of consumer and broader stakeholder education around introducing new tariff structures.

The understanding of ‘the why’, or the ‘back story’, is considered essential to the success of introducing a new tariff – particularly if the messaging is shifting away from ‘reduce consumption’:

“If you’re having a tariff conversation to bring people along, you need to explain why the declining block tariff is going to be introduced, given the conversation we’ve been having before (saying Ausgrid is going to introduce time of use meters) ... It’s like “oh all of a sudden the past 10 years have disappeared”.

Ausgrid accepts that it is important to educate stakeholders on new tariff structure.

Ausgrid proposes to work with the AER and other stakeholders to ensure that a clear and consistent message is conveyed in respect to our tariff reforms.

The consultation process

Some stakeholders wanted to see a longer TSS consultation and engagement period.

Food and fibre stakeholders were disappointed that most of the Phase Two consultation was taking place during harvesting season and school holidays, which they indicated limited their capacity to be involved.

A consumer advocate requested that network businesses share information with environment stakeholders so that advocates can support the final TSS decision. This information could include: load profiles for individual types of customers, as well as long run marginal costs (LRMC) for different tariff and customer classes.

Some environment and consumer advocates expressed scepticism about NNSW’s commitment to consider other tariff options, and felt a decision to implement declining block tariffs had already been made. Advocates noted networks in other states had included optional demand tariffs in their recent tariff changes.

Ausgrid accepts that some stakeholders were disappointed with the short time frame of the TSS consultation process.

Ausgrid is committed to providing stakeholders with additional information and analysis to facilitate a broader discussion on tariff reform and to assist stakeholders to better understand our economic circumstance, and its influence on the tariff reform process.

Ausgrid is open to additional ideas and thinking around the options for reforming our network tariffs.

Ausgrid has already agreed with stakeholders key areas of focus for the next TSS.

Acknowledgement of the difficulty of consultation

Despite some criticism of the timeframe for stakeholder engagement, some stakeholders acknowledged that there was no ‘right’ answer when it came to the most appropriate network tariffs for NSW; and that the tariff preference of individuals would differ at different stages of their lives depending on age, household arrangements, their business or employment circumstances, energy preferences, financial circumstances, and the area in which they lives or worked.

Ausgrid notes the acknowledgement of the difficulty of consulting on complex tariff issues.


12 Description of Tariff Structure and Charging Parameters

This section provides a description of Ausgrid’s network use of system tariffs to apply over the remainder of the current regulatory control period.

12.1 Residential Non-TOU (EA010) Tariff (Closed from 1 July 2018) Ausgrid’s network use of system Residential non-TOU Tariff is currently the default primary network use of system tariff for new residential customers without a solar photo voltaic system connected to Ausgrid’s electricity network.

From 1 July 2018 onwards, no residential customers (either existing or new) will be assigned or reassigned to this tariff. Further, from 1 July 2018 residential customers on this tariff that have a Type 5 or better meter (including customers that get a meter upgrade) will be reassigned to the transitional TOU tariff (EA332), with the option to opt-in to a more cost reflective TOU tariff (EA025).

Metering requirements

The Residential non-TOU Tariff is only available to distribution customers in Ausgrid’s network area with Type 6 or better metering installed in their premise; please refer to our ES3 Metering Installations document for more information on this matter.32

Network Use of System Tariff Components

The Residential non-TOU Network Tariff is comprised of the following tariff components:

Network Access Charge – This tariff component is a fixed charge per day; and

Flat rate Energy Consumption Charge – This tariff component is a network use of system charge applying to all energy consumed per standard quarterly billing cycle (being 91 days).

32 This document is available to be downloaded from www.ausgrid.com.au


12.2 Residential Transitional TOU (EA332) Tariff (Open from 1 July 2018) From 1 July 2018, existing residential customers on the non-TOU tariff (EA010) that have a Type 5 (or better) meter – including due to a meter upgrade – will be reassigned to this tariff. Further, from 1 July 2018 new residential customers can opt-in to this tariff from the more cost reflective TOU tariff (EA025).


The Residential TOU Tariff is only available to distribution customers in Ausgrid’s network area with Type 5 or better metering installed in their premise; please refer to our ES3 Metering Installations document for more information on this matter.33


This tariff has a TOU structure with the same per unit energy charge applied across the peak, shoulder and off peak periods and is comprised of the following tariff components:

Network Access Charge – This tariff component is a fixed charge per day;

Seasonal Peak Energy Consumption Charge – This tariff component is a network use of system charge for energy consumed during the peak period;

Shoulder Energy Consumption Charge – This tariff component is a network use of system charge for energy consumed during the shoulder period; and

Off-peak Energy Consumption Charge – This tariff component is a network use of system charge for energy consumed in off-peak period.

Definition of Time of Use Periods (from 1 July 2018)

The time period definitions applicable to Ausgrid’s Residential Time of Use Network Tariff from 1 July 2018 are shown in the table below, and that applying prior to 1 July 2018 can be found in section 6 of the TSS.

Time Period Network Definition

Summer Peak From 2 pm – 8 pm on working weekdays during 1 November to 31 March (inclusive)

Winter Peak From 5 pm – 9 pm on working weekdays during 1 June to 31 August (inclusive)

Shoulder In the summer months, from 7am to 2pm and from 8 pm to 10pm on working weekdays

In the winter months, from 7am to 5pm and from 9pm to 10pm

In the non-summer and non-winter months, from 7am to 10pm on working weekdays.

From 7am to 10pm on weekends and public holidays.Off-Peak All other times.

Note: All times take into account daylight saving during the period gazetted by the NSW Government, generally from 3am on the first Sunday in October to 2am on the first Sunday in April.



12.3 Residential Time of Use (TOU) (EA025) Tariff Ausgrid’s Residential Time of Use Network Tariff is only available to residential distribution customers in Ausgrid’s electricity network area. This network tariff is currently the default primary network use of system tariff for all new residential distribution customers with a small scale embedded generator connected to Ausgrid’s electricity network.

From 1 July 2018 all new residential customers will be assigned to this tariff, with the option to opt-in to the residential transitional TOU tariff (EA332).


The Residential TOU Tariff is only available to distribution customers in Ausgrid’s network area with Type 5 or better metering installed in their premise; please refer to our ES3 Metering Installations document for more up to date information on Ausgrid’s metering policy.34


The Residential Time of Use Network Tariff is comprised of the following tariff components:






The time period definition applicable to Ausgrid’s Residential Time of Use Network Tariff from 1 July 2018 are shown in the table below, and that applying prior to 1 July 2018 can be found in section 6 of the TSS.




Shoulder In the summer months, from 7am to 2pm and from 8 pm to 10pm on working weekdays

In the winter months, from 7am to 5pm and from 9pm to 10pm

In the non-summer and non-winter months, from 7am to 10pm on working weekdays.

From 7am to 10pm on weekends and public holidays.Off-Peak All other times.




12.4 Controlled Load (EA030/EA040) Tariffs Ausgrid’s Controlled Load Network Tariffs are secondary network use of system tariffs that apply to separately metered loads used for operating storage water heaters, thermal storage space heaters and other approved appliances, which are controlled or interrupted by Ausgrid. For a full list of equipment that Ausgrid allows to be under a control load tariff; please refer to our ES7 Network Use of System Tariff – Terms and Conditions. 35

Ausgrid’s controlled load network tariffs are only available to distribution customers in Ausgrid’s network area assigned to one of the following primary network use of system tariffs:

Residential non-TOU (EA010) Tariff.

Small Business non-TOU (EA050) Tariff.

Residential TOU (EA025) Tariff.

Small Business TOU (EA225) Tariff.

Low Voltage 40–160 MWh (EA302) Tariff.

Low Voltage Transitional 40-160 MWh Closed (EA316)Tariff.

Please note that Ausgrid currently only allows a distribution customer in Ausgrid’s network area to be assigned to one controlled load network tariff.

(i) Time Period Definitions

The time periods where supply is available under Ausgrid’s controlled load network tariffs are shown below:

Network Use of System Tariff Tariff Code Time period

Controlled load 1 EA030 Supply is usually available for six hour duration between 10.00 pm and 7.00 am.

Controlled load 2 EA040

Supply is usually available for sixteen hours per day including more than six hours between 8pm and 7am and more than four hours between 7am and 5pm.



12.5 Small Business Non-TOU (EA050) Tariff (Closed from 1 July 2018) Ausgrid’s Small Business non-TOU Network Tariff is currently the default primary network use of system tariff for all business distribution customers that satisfy the criteria to be assigned to the low voltage network tariff class without a small scale embedded generator connected to Ausgrid’s electricity network.

From 1 July 2018 onwards, no small business customers (either existing or new) will be assigned or reassigned to this tariff. Further, from 1 July 2018 small business customers on this tariff that have a Type 5 or better meter (including customers that get a meter upgrade) will be reassigned to the small business transitional TOU tariff (EA333), with the option to opt-in to a more cost reflective TOU tariff (EA225).

Metering Requirement

Ausgrid requires that a distribution customer assigned or re-assigned to the Small Business non-TOU Network Tariff have a Type 4, Type 5 or Type 6 meter installed in their premise; please refer to our ES3 Metering Installations document for more up to date information on Ausgrid’s metering policy.36

Network Tariff Components

The small business non-TOU Network Tariff is comprised of the following tariff components:


Flat rate Energy Consumption Charge – This tariff component is a network use of system charge applying to all energy consumed per standard quarterly billing cycle (being 91 days);



12.6 Small Business Transitional TOU (EA333) Tariff (Open from 1 July 2018) From 1 July 2018, existing small business customers on the non-TOU tariff (EA050) that have a Type 5 (or better) meter – including due to a meter upgrade – will be reassigned to this tariff. Further, from 1 July 2018 new small business customers can opt-in to this tariff from the more cost reflective small business TOU tariff (EA225).


The small business TOU Tariff is only available to distribution customers in Ausgrid’s network area with Type 5 or better metering installed in their premise; please refer to our ES3 Metering Installations document for more information on this matter.37


This tariff has a TOU structure with the same per unit energy charge applied across the peak, shoulder and off peak periods. The Residential TOU Network Tariff is comprised of the following tariff components:






The time period definitions applicable to Ausgrid’s small business Time of Use Transitional Network Tariff from 1 July 2018 are shown in the table below, and that applying prior to 1 July 2018 can be found in section 6 of the TSS.




Shoulder In the summer and winter months, from 7 am – 2 pm and 8 pm – 10pm on working weekdays

In the non-summer and non-winter months, from 7am – 10 pm on working weekdays

Off-Peak All other times.




12.7 Small Business Time of Use (EA225) Tariff Ausgrid’s Small Business Time of Use Network Tariff is currently the default primary network use of system tariff for all business distribution customers that satisfy the criteria to be assigned to the low voltage network tariff class with a solar photo voltaic system connected to Ausgrid’s electricity network.

Please note that existing distribution customers assigned to the small business time of use tariff that do not have a small scale embedded generator connected to Ausgrid’s electricity network are allowed to be re-assigned to the Small Business non-TOU network tariff.

From 1 July 2018 all new small business customers will be assigned to this tariff, with the option to opt-in to the small business transitional TOU tariff (EA333).


The Small Business Time of Use Network Tariff is only available to customers in Ausgrid’s network area with Type 5 or Type 4 metering installed in their premise; please refer to our ES3 Metering Installations document for more up to date information on Ausgrid’s metering policy.38


The Small Business Time of Use Network Tariff is comprised of the following tariff components:


Peak Energy Consumption Charge – This tariff component is a network use of system charge for energy consumed during the peak period;



Proposed Definition of Time of Use Periods (from 1 July 2018)

The time period definitions applicable to Ausgrid’s Small Business Time of Use Network Tariff from 1 July 2018 are shown in the table below, and that applying prior to 1 July 2018 can be found in section 6 of the TSS.










12.8 Low Voltage (LV) TOU Capacity 40-160 MWh (EA302) Tariff Ausgrid’s Low Voltage 40-160 MWh (EA302) Tariff is the default primary network use of system tariff for all business distribution customers that satisfy the criteria to be assigned to the low voltage network tariff class with a low voltage connection with 40-160 MWh per annum.


The Low Voltage 40-160 MWh (EA302) Tariff is only available to business customers in Ausgrid’s network area with Type 5 or better metering installed in their premise; please refer to our ES3 Metering Installations document for more up to date information on Ausgrid’s metering policy.39


The Low Voltage 40-160 MWh Network Tariff is comprised of the following tariff components:



Shoulder Energy Consumption Charge – This tariff component is a network use of system charge for energy consumed during the shoulder period;

Off-peak Energy Consumption Charge – This tariff component is a network use of system charge for energy consumed in off-peak period; and

Peak kW Capacity Charge– This tariff component is a network use of system charge applied to the maximum kW demand recorded in any half hour interval during the peak period in the previous 12 months.


The time period definitions applicable to Ausgrid’s Low Voltage 40-160 MWh Network Tariff from 1 July 2018 are shown in the table below, and that applying prior to 1 July 2018 can be found in section 6 of the TSS.










12.9 Low Voltage TOU Capacity 160-750 MWh (EA305) Tariff Ausgrid’s Low Voltage 160-750 MWh (EA305) Tariff is the default primary network use of system tariff for all business distribution customers that satisfy the criteria to be assigned to the low voltage network tariff class with a Low Voltage 160-750 MWh.


The Low Voltage 160-750 MWh (EA305) Tariff is only available to business customers in Ausgrid’s network area with Type 3 or better metering installed in their premise; please refer to our ES3 Metering Installations document for more up to date information on Ausgrid’s metering policy.40


The Low Voltage 160-750 MWh (EA305) Tariff is comprised of the following tariff components:





Peak kVA Capacity Charge– This tariff component is a network use of system charge applied to the maximum kVA demand recorded in any half hour interval during the peak period in the previous 12 months.


The time period definitions applicable to Ausgrid’s Low Voltage TOU Capacity CT 400 to 1600 Amps Network Tariff from 1 July 2018 are shown in the table below, and that applying prior to 1 July 2018 can be found in section 6 of the TSS.










12.10 Low Voltage TOU Capacity >750 MWh (EA310) Tariff Ausgrid’s Low Voltage >750 MWh (EA310) Tariff is the default primary network use of system tariff for all business distribution customers that satisfy the criteria to be assigned to the low voltage network tariff class with a CT connection of greater than 1600 Amps.


The Low Voltage >750 MWh (EA310) Tariff is only available to business distribution customers in Ausgrid’s network area with Type 3 or better metering installed in their premise; please refer to our ES3 Metering Installations document for more up to date information on Ausgrid’s metering policy. 41


The Low Voltage >750 MWh (EA310) Tariff may be comprised of the following tariff components:





Peak kVA Capacity Charge– This tariff component is a network use of system charge applied to the maximum kVA demand recorded in any half hour interval during the peak-period in the previous 12 months.


The time period definitions applicable to Ausgrid’s Low Voltage >750 MWh (EA310) Network Tariff from 1 July 2018 are shown in the table below, and that applying prior to 1 July 2018 can be found in section 6 of the TSS.










12.11 High Voltage TOU Capacity (System) (EA370) Tariff Ausgrid’s High Voltage TOU Capacity (System) (EA370) Network Tariff is the default network use of system tariff for all new business distribution customers in Ausgrid’s network area that satisfy the eligibility criteria to be assigned to the high voltage network tariff class.


The High Voltage TOU Capacity (System) (EA370) Tariff is only available to business distribution customers in Ausgrid’s network area with Type 3 or better metering installed in their premise; please refer to our ES3 Metering Installations document for more information.42


The High Voltage TOU Capacity (System) (EA370) Tariff may be comprised of the following tariff components:







The time period definitions applicable to Ausgrid’s High Voltage TOU Capacity (System) (EA370) Network Tariff from 1 July 2018 are shown in the table below, and that applying prior to 1 July 2018 can be found in section 6 of the TSS.










12.12 High Voltage TOU Capacity (Substation) (EA380) Tariff The HV TOU Capacity (Substation) (EA380) Tariff is an optional primary network use of system tariff available to all distribution customers in Ausgrid’s network area that satisfy the eligibility criteria to be assigned to the high voltage network tariff class and which have an exclusive dedicated feeder connection(s) to a Transmission Node Identity (TNI) transmission substation, see figure below:

Figure 46 – Transmission, Sub Transmission and High Voltage tariff assignment


The High Voltage Capacity (Substation) (EA380) Tariff is only available to business distribution customers in Ausgrid’s network area with Type 3 or better metering installed in their premise; please refer to our ES3 Metering Installations document for more up to date information on Ausgrid’s metering policy.43


The High Voltage Capacity (Substation) (EA380) Tariff is comprised of the following tariff components:









The time period definition applicable to Ausgrid’s High Voltage TOU Capacity (Substation) (EA380) Network Tariff from 1 July 2018 are shown in the table below, and that applying prior to 1 July 2018 can be found in section 6 of the TSS.









12.13 Sub-transmission Voltage TOU Capacity (System) (EA390) Tariff The Sub-transmission Voltage TOU Capacity (System) (EA390) Tariff is the default primary network use of system tariff for all new distribution customers in Ausgrid’s network area that satisfy the eligibility criteria to be assigned to the sub-transmission network tariff class.


The Sub-transmission Voltage TOU Capacity (System) (EA390) Tariff is only available to business customers in Ausgrid’s network area with Type 3 or better metering installed in their premise; please refer to our ES3 Metering Installations document for more up to date information on Ausgrid’s metering policy.44


Ausgrid’s Sub-transmission Voltage TOU Capacity (System) (EA390) Tariff may be comprised of the following tariff components:







The time period definitions applicable to Ausgrid’s Sub-transmission Voltage TOU Capacity (System) (EA390) Network Tariff from 1 July 2018 are shown in the table below, and that applying prior to 1 July 2018 can be found in section 6 of the TSS.










12.14 Sub-transmission Voltage TOU Capacity (Substation) (EA391) Tariff The Sub-transmission Voltage TOU Capacity (Substation) (EA391) Tariff is an optional primary network use of system tariff available to all distribution customers in Ausgrid’s network area that satisfy the eligibility criteria to be assigned to the Sub-transmission network tariff class and which have an exclusive dedicated feeder connection(s) to a Transmission Node Identity (TNI) transmission substation, see the figure below.

Figure 47 – Transmission, Sub Transmission and High Voltage tariff assignment


The Sub-transmission Voltage TOU Capacity (Substation) (EA391) Tariff is only available to distribution customers in Ausgrid’s network area with Type 3 or better metering installed in their premise, please refer to our ES3 Metering Installations document for more up to date information on Ausgrid’s metering policy.45


The Sub-transmission Voltage TOU Capacity (Substation) (EA391) Tariff is comprised of the following tariff components:









The time period definitions applicable to Ausgrid’s Sub-transmission Voltage TOU Capacity (Substation) (EA391) Network Tariff from 1 July 2018 are shown in the table below, and that applying prior to 1 July 2018 can be found in section 6 of the TSS.









12.15 Transmission Connected TOU Capacity (EA501) Tariff From 1 July 218, the Transmission Connected TOU Capacity (EA501) Tariff will be a default primary network use of system tariff available to all new transmission connected customers in Ausgrid’s network area that satisfy the eligibility criteria to be assigned to the transmission connected tariff class. Transmission connected customers do not use any Ausgrid distribution assets. The connection point is at a TNI’s Transmission Connection Point (TCP).


The Transmission Connected TOU Capacity (EA501) Tariff is only available to transmission connected customers in Ausgrid’s network area with Type 3 or better metering installed in their premise; please refer to our ES3 Metering Installations document for more up to date information on Ausgrid’s metering policy.46


The Transmission Connected TOU Capacity (EA501) Tariff may be comprised of the following tariff components:







The time period definitions applicable to Ausgrid’s Transmission Connected TOU Capacity (EA39X) Network Tariff from 1 July 2018 are shown in the table below, and that applying prior to 1 July 2018 can be found in section 6 of the TSS.










12.16 Individually Calculated Network Tariff Ausgrid’s individually calculated tariffs are an individually calculated network use of system tariff. This network tariff is available to all existing customers in Ausgrid’s network area that either:

Satisfy the eligibility criteria to be assigned to the transmission connected tariff class, please refer to section 8 of this document; or

Satisfy the eligibility criteria to be assigned to the high voltage tariff class or sub-transmission voltage tariff class and consume more than 40 GWh pa or have a maximum demand in excess of 10 MW.


The individually calculated tariff is only available to distribution customers in Ausgrid’s network area with Type 3 or better metering installed in their premise; please refer to our ES3 Metering Installations document for more up to date information on Ausgrid’s metering policy.47

Eligibility Criteria

The eligibility criteria to be assigned or re-assigned to an individually calculated network tariff are:

Distribution Customer - To be re-assigned from a published network use of system tariff to an individually calculated tariff a customer currently assigned to the high or sub-transmission voltage network tariff class must have at least 12 months of load data available under their current network use of system tariff and must satisfy the following eligibility criteria:

o Have a recorded demand history of 10 MW or more in at least three months over the 12 month period prior to the assessment.

o Have a recorded annual consumption that exceeds 40 GWh over the 12 month period prior to the assessment.

Transmission Customer - an existing customer that satisfies the following criteria to be assigned to the transmission voltage tariff class, namely:

o A site that is directly connected to a TNI substation Transmission Connection Point (TCP) in Ausgrid’s network area.48


Ausgrid’s individually calculated tariff may be comprised of the following tariff components:






47 This document is available to be downloaded from www.ausgrid.com.au 48 Note: To be eligible for the transmission voltage tariff class, the site must not require the use of any distribution assets.



The time period definitions applicable to Ausgrid’s individually calculated tariffs from 1 July 2018 are shown in the table below, and that applying prior to 1 July 2018 can be found in section 6 of the TSS.









12.17 LV Connection (Stand-by) (EA325) Tariff (Closed) The LV Connection (Stand-by) (EA325) Tariff is closed to customers in Ausgrid’s network area. This network use of system tariff is currently being transitioned to align with Ausgrid’s LV >750 MWh (System) Network Tariff.

Standby supplies are loads not normally connected to the electrical supply system but increase the capacity requirements on the upstream system that must be capable of supplying the standby load in addition to normally supplied loads. In accordance with the current AEMO National Metering Identifier Procedure (NMI) document, the standby connection point must be assigned a separate NMI to the normal supply point.


The existing distribution customers assigned to the Low Voltage Connection (Stand-by) (EA325) Tariff are required to have Type 4 or better metering installed in their premise, please refer to our ES3 Metering Installations document for more up to date information on Ausgrid’s metering policy.49


The Low Voltage Connection (Stand-by) (EA325) Tariff is comprised of the following tariff components:







The time period definitions applicable to Ausgrid’s Low Voltage Connection (Stand-by) (EA325) Tariff from 1 July 2018 are shown in the table below, and that applying prior to 1 July 2018 can be found in section 6 of the TSS.










12.18 HV Connection (Stand-by) (EA360) Network Tariff (Closed) The HV Connection (Stand-by) (EA360) Network Tariff is closed to distribution customers in Ausgrid’s network area. This network use of system tariff is currently being transitioned to align with Ausgrid’s HV (System) Network Tariff.

Standby supplies are loads not normally connected to the electrical supply system but increase the capacity requirements on the upstream system which must be capable of supplying the standby load in addition to normally supplied loads. In accordance with the current AEMO National Metering Identifier Procedure (NMI) document, the standby connection point must be assigned a separate NMI to the normal supply point.


The High Voltage Connection (Stand-by) (EA360) Tariff is only available to business distribution customers in Ausgrid’s network area with Type 3 or better metering installed in their premise; please refer to our ES3 Metering Installations document for more up to date information on Ausgrid’s metering policy.50


The High Voltage Connection (Stand-by) (EA360) Tariff is comprised of the following tariff components:







The time period definitions applicable to Ausgrid’s High Voltage Connection (Stand-by) (EA360) Tariff from 1 July 2018 are shown in the table below, and that applying prior to 1 July 2018 can be found in section 6 of the TSS.










12.19 Unmetered Network (EA400/EA401/EA402) Tariffs A business customer in Ausgrid’s network area assigned to the unmetered network tariff class is required under Chapter 6 of the National Electricity Rules to be assigned to one of the following primary network use of system tariffs:

Public Lighting (EA401) Tariff

Constant Unmetered (EA402) Tariff

EnergyLight (EA403) Tariff


The Unmetered network use of system tariffs are only available to business distribution customers in Ausgrid’s network area with Type 7 metering installed in their premise, please refer to ES3 for more up to date information on Ausgrid’s metering policy.

Eligibility Criteria for Unmetered Tariffs

Ausgrid allows a new distribution customer in Ausgrid’s network area to be assigned to an unmetered network use of system tariff if they satisfy the eligibility requirements of the unmetered tariff class, please refer to section 3 of our TSS.


13 Glossary

Ancillary network services Non-routine services provided to individual customers on an “as needs” basis. Examples of these services include providing design related information for connections to be made to our network, special meter reads and site establishment fees.

AEMC Australian Energy Market Commission

AEMO Australian Energy Market Operator

AER Australian Energy Regulator

Basic accumulation metering Accumulation meters keep track only of the total accumulated electricity usage. Customers are charged the same amount regardless of when the electricity is used.

Block Tariff A tariff with a structure that applies a different price for energy consumption beyond specified energy consumption threshold or thresholds.

CCF Climate Change Fund

Charging parameter Pricing component that makes up a tariff.

CRNP Cost Reflective Network Price. An individually calculated “customised” tariff that is available to transmission-connected sites or certain large loads.

Current Transformer (CT) connection A connection where the transformer for use with meters and/or protection devices in which the current in the secondary winding is, within prescribed error limits, proportional to and in phase with the current in the primary winding.

Customer class Refer to Tariff class

Determination A decision by the AER that determines the revenue allowance for network service providers under the National Electricity Rules.

Distribution Network Service Providers A person who engages in the activity of owning, controlling or operating a transmission or distribution system and who is registered by AEMO as a Network Service Provider.

Distribution-connected sites Customers that are connected to the electricity distribution network.

DUOS Distribution Use of System

Dynamic peak prices This is a charging parameter that applies a price, expressed on a cents per kWh basis to energy consumption during a dynamic peak event.

Dynamic peak event The dynamic peak energy charge is applied to consumption during the specific peak period (e.g. 1pm to 8pm) during the dynamic peak event. There are typically only around 12 dynamic peak events called in a financial year.

Efficiency Signifies a level of performance that describes a process that uses the lowest amount of inputs to create the greatest amount of outputs.

Fixed charge A charging parameter expressed in cents per day. Also known as Network Access Charge.


High voltage tariff A tariff that applies to connections that are connected at high voltages 5kV, 11kV or 22kV (as measured at the metering point) that is neither a Sub-transmission nor a CRNP tariff.

Interval meter A meter that records how much electricity is used every 30 minutes.

Low voltage tariff A tariff that applies to connections that are connected at low voltages 230V or 400V (as measured at the metering point).

LRMC Long Run Marginal Cost

Metering point The physical point of connection between the Consumers Mains and the electrical network. Each separate overhead or underground service is a separate connection point. Each separate busbar or direct cable supply from a single substation is a separate connection point, e.g. two busbar supplies equal two connection points.

Metering services Services that measure the customers’ energy consumption and can assist customers to better understand and manage their energy usage.

National Electricity Law The National Electricity Law set out in the schedule to the National Electricity (South Australia) Act 1996 (SA) and applied in each of the participating jurisdictions.

National Electricity Rules Refers to the National Electricity Rules (NER) which governs the operation of the National Electricity Market. The Rules have the force of law, and are made under the National Electricity Law.

Network services Transmission service or distribution service associated with the conveyance, and controlling the conveyance, of electricity through the network.

NUOS Network Use of System price, which is composed of DUOS, TUOS and CCF prices.

Phase As defined in the Service and Installation Rules of New South Wales August 2012.

Price cap A price control mechanism

Primary tariff A network use of system tariff payable by a customer that relates to the principal load of a Distribution Customer

Public lighting services Services that involve maintaining and improving the standards of streetlights on behalf of local councils, community associations and statutory authorities across Ausgrid’s network.

Single phase connection Refer to Phase

Sub-transmission voltage tariff A tariff that applies to connections that are connected at sub-transmission voltages 33kV or greater (as measured at the metering point).

Tariff The monetary value assigned to individual charging parameters (i.e. cents per kVA or cents per day).

Tariff class A class of retail customers for one or more direct control services who are subject to a particular network tariff or particular network tariffs as defined in the National Electricity Rules.

Tariff code A unique code that identifies each different network tariff.

TSS Tariff Structure Statement referred to in clause 6.18.1A in the


National Electricity Rules that has been approved by the AER for that Distribution Network Service Provider.

Three phase connection Refer to Phase

Time of Use (TOU) tariff A tariff with a structure that applies a different price for energy consumed at times of the day.

Transitional tariff A tariff that may be available for a defined period following changes in the network pricing structures.

Transmission-connected sites Customers that are connected to the electricity transmission network.

TUOS Transmission Use of System

Type 5 meter A metering installation containing an electronic meter, or meters, capable of recording electrical energy consumption in 30 minute market intervals in accordance with the NER. Such meters are read manually by meter readers. Data is down-loaded via probes into a hand-held data collection device carried by Ausgrid meter readers. Also known as an MRIM, ToU or interval meters.

Type 6 meter A metering installation containing a meter, or meters, (electronic or electromechanical) capable of recording cumulative electrical energy consumption only. Such meters are read manually by Ausgrid meter readers who record the total cumulative consumption readings displayed on the Type 6 meter register. All meters can support a Type 6 Installation, but they are predominantly installed with mechanical meters or simple electronic meters. Also known as BASIC, Flat Rate or accumulation meters.

Unmetered tariff A tariff for unmetered supply

Documents

Appendix A - Australian Energy Regulator · 27 November 2015 7 Figure 1 – Indicative Tariff Formulation Process under New Pricing Rules 2.3.1 Efficient tariffs Ausgrid’s starting