Customer Impact Statement - Energex · 2015 preliminary decision on Energex’s forecast distribution revenue for the 2016-17 to 2019-20 period.1 The figures quoted include adjustments

4 September 2015 Customer Impact Statement 1

Customer Impact Statement Tariff Reform

Energex Limited 2015 - 2020

4 September 2015 Customer Impact Statement i

Version Control

Version Date Description

1.0 04/09/2015 Published

2.0 28/09/2015 Updates to figures on page 27

Contact details

Energex Limited

Andrew Hager

Phone: 13 12 53

Email: [email protected]

GPO Box 1461 Brisbane QLD 4001

26 Reddacliff Street Newstead QLD 4006

Telephone 13 12 53

www.energex.com.au

Energex Limited ABN 40 078 849 055

© Energex Limited 2015

® Energex and Energex Positive Energy are registered trademarks of Energex Limited ABN 40 078 849 055

This work is copyright. Material contained in this document may be reproduced for personal, in-house or

non-commercial use, without formal permission or charge, provided there is due acknowledgement of Energex

Limited as the source. Requests and enquiries concerning reproduction and rights for a purpose other than personal,

in-house or non-commercial use, should be addressed to the Group Manager Corporate Communications, Energex,

GPO Box 1461 Brisbane QLD 4001.

4 September 2015 Customer Impact Statement ii

Contents

1 Introduction .............................................................................................................. 1

1.1 Network cost categories .............................................................................................. 2

1.2 How you can respond .................................................................................................. 2

2 Indicative revenue and forecasts ............................................................................ 3

2.1 Forecast revenue .......................................................................................................... 3

2.2 From revenue to network prices ................................................................................. 4

2.3 Indicative prices for 2017-20 period............................................................................ 4

3 Standard Asset Customers residential .................................................................. 5

3.1 Proposed tariff structure .............................................................................................. 5

3.2 Preliminary decisions ................................................................................................... 6

3.2.1 Single peak or average of four peaks ................................................................ 7

3.3 Indicative forecast prices ............................................................................................. 8

3.4 Customer load profiles ................................................................................................. 8

3.5 Customer impact......................................................................................................... 13

3.5.1 Estimated annual bill ........................................................................................ 16

3.6 Bill protection .............................................................................................................. 18

3.7 Load control ................................................................................................................ 20

3.7.1 Scenario ........................................................................................................... 21

4 Standard Asset Customers Small to medium businesses ................................. 22

4.1 Proposed tariff structure ............................................................................................ 22

4.2 Proposed prices .......................................................................................................... 22

4.3 Customer load profiles ............................................................................................... 23

4.4 Preliminary decisions ................................................................................................. 25

4.5 Bill impact .................................................................................................................... 25

4.5.1 Scenario ........................................................................................................... 27

4.6 Bill protection .............................................................................................................. 27

5 Standard Asset Customers large .......................................................................... 28


5.2 Indicative forecast prices ........................................................................................... 29

5.3 Bill Impact .................................................................................................................... 29

5.3.1 Scenario ........................................................................................................... 31

6 Connection Asset Customers ............................................................................... 32


6.2 Preliminary decisions ................................................................................................. 33

6.3 Indicative forecast prices ........................................................................................... 33

4 September 2015 Customer Impact Statement iii

6.4 Bill impact .................................................................................................................... 33

7 Individually Calculated Customers ....................................................................... 34


7.2 Proposed prices .......................................................................................................... 35

7.3 Bill impact .................................................................................................................... 35

8 Glossary .................................................................................................................. 36


1 Introduction

This Customer Impact Statement has been prepared to provide information to customers and

stakeholders that quantifies the financial impact of Energex’s proposed new cost reflective network

tariffs. These tariffs form part of the tariff reform package that will be submitted to the Australian

Energy Regulator by 27 November 2015.

In developing its proposed tariff reform package for the 2017-20 period, Energex has been engaging

with its customers, customer advocacy groups, retailers and any interested stakeholders. As part of

the engagement process, Energex released a consultation paper for residential and small business

customers in July 2015, and a consultation paper for large customers in August 2015. These papers

can be found at www.energex.com.au/influencingtariffs.

The analysis provided in this Customer Impact Statement is intended to complement the Customer

Consultation Papers and applies to the tariff classes detailed in table 1.1.

Table 1.1: Cost groups and tariff charging parameters used to recover revenue

Tariff Class Usage Customer type and engagement program Document section

Standard Asset Customers

Customers connected to the low voltage network

Under 100MWh per annum

Residential customers

(CSIRO report relates to residential customers only) 3

Small to medium business customers 4

Engagement program information: www.energex.com.au/yournetworkyourchoices

Over 100MWh per annum

Large business customers 5

Engagement program information: www.energex.com.au/tariffsbeyond2015

Connection Asset Customers

Customers connected to the 11kV network.

- Large commercial and industrial loads 6

Engagement program information:

www.energex.com.au/lctariffreform

Individually Connected Customers

Individually Calculated customers connected at 33kV and 110kV


Engagement program information: www.energex.com.au/lctariffreform

Customers should note that the financial implications of the tariff reform included in this Customer

Impact Statement are based on a set of assumptions and forecasts and therefore, should be treated

as indicative only and not be relied on for financial advice.


1.1 Network cost categories

Energex is proposing to apply the new pricing principles contained in the Rules in the following

manner

Table 1.2: Cost groups and tariff charging parameters used to recover revenue

Cost group Tariff charging parameter used to recover costs

Connection assets Costs associated with the assets required to connect a customer to the network. Connection assets are used by only one customer.

Common and non-system costs

Costs associated with running a network business that are not directly attributable to network assets.

Shared network

Forward signal component

Shared network refers to the assets that multiple customers use.

The forward signal component of shared network costs signals to customers the cost of building new network.

Shared network

Residual component

Shared network refers to the assets that multiple customers use.

The residual component of shared network costs are the remainder left over after the forward signal component is subtracted from the shared network costs.

1.2 How you can respond

Energex is seeking customer and other interested stakeholder responses to its proposed tariff reform

program by 2 October 2015. In providing comments, customers should consider this Customer Impact

Statement in conjunction with the Residential and Business Customer Consultation Paper and the

Large Customer Consultation Paper available on Energex’s website. The analysis in this Customer

Impact Statement is limited to the data available. Energex acknowledges that this may not provide

comprehensive answers to all customer concerns.

The consultation period for the tariff reform program is open until 2 October 2015 and responses can

be submitted to the Customer Engagement Team [email protected].


2 Indicative revenue and forecasts

This chapter outlines Energex’s methodology applied when allocating allowed revenue to network tariff

classes and setting forecast network prices.

2.1 Forecast revenue

There are three primary sources of revenue that Energex recovers through network tariffs:

Distribution revenue, set and approved by the Australian Energy Regulator;

Solar PV Feed-in-Tariff – Jurisdictional Scheme, as determined by the Queensland

Government; and

Transmission revenue as set by Powerlink.

Table 2.1 below shows the total revenue estimated for collection through network tariffs per year

during the 2016-20 period. These figures have been based on the Australian Energy Regulator’s April

2015 preliminary decision on Energex’s forecast distribution revenue for the 2016-17 to 2019-20

period.1 The figures quoted include adjustments such as under and over recoveries, Service Target

Performance Incentive Scheme and capital contributions. Energex will update its forecast revenue

based on the final decision by the Australian Energy Regulator when submitting the Tariff Structure

Statement in November 2015.2

Table 2.1: Total revenue 2015-16 to 2019-20

Revenue source 2016-17

($M) 2017-18

($M) 2018-19

($M) 2019-20

($M)

Distribution 1,516.5 1,430.5 1,393.6 1,372.0

Solar PV feed-in tariff 192.1 182.1 172.0 162.0

Transmission 457.2 468.8 480.8 493.1

Total 2,165.8 2,081.4 2,046.5 2,027.0

The Queensland Government’s Solar Bonus Scheme is a jurisdictional scheme. Solar Bonus Scheme

payments are passed through to customers via network tariffs.

Powerlink (transmission) revenue figures for 2016-17 to 2019-20 are not yet available. The above

forecasts for 2016-20 has estimated Powerlinks revenue figures based on 2015-16 approved

revenues.

1 Refer https://www.aer.gov.au/node/20187

2 The final decision by the Australian Energy Regulator is expected in October 2015.


2.2 From revenue to network prices

Energex allocates its forecast revenue to its tariff classes using a Distribution Cost of Supply model

which is explained in Energex’s 2015-16 Pricing Proposal.3

Figure 2.1: Energex allocation of revenue requirement to the tariff classes and tariffs.

2.3 Indicative prices for 2017-20 period

The indicative forecast prices for the current and newly developed demand based network tariffs

covering the period from 1 July 2016 to 30 June 2020 are presented in Appendix A.

3 Energex, Annual Pricing Proposal 1 July 2015 to 30 June 2016, Appendix 3 – Revenue

allocation process

Tariff Structure

Tariff classes have a number of different tariffs and each tariff has the following structure.

Residual

Volume (c/kWh)

Forward Signal

Peak demand

($/kVA or kW/month)

Connection assets

Fixed charge ($/day)

Tariff Classes

Tariff classes are groups of like customer based on their energy usage and connection to the network.

For each tariff class, revenue is recovered through network tariffs which are a combination of network charges (distribution and transmission) and Solar Bonus Scheme charges.




Customers connected at 11kV

Individually Calculated Customers

Customer connected at 33kV and 110kV

Revenue

Energex’s revenue is calculated using a building block approach and is approved by the Australian Energy Regulator.

Energex cannot recover more than what the Australian Energy Regulator has approved.


3 Standard Asset Customers

residential

This section specific relates to residential Standard Asset Customers as detailed in table 3.1.

Table 3.1: Details of residential Standard Asset Customers





Residential customers

(CSIRO report relates to residential customers only) 3


3.1 Proposed tariff structure

The tariff structure for the proposed residential tariff is presented in table 3.2 below. Energex is

proposing to change the residential tariff structure to include a demand component. This will signal the

cost of building the distribution network.

Table 3.2: Proposed tariff structure for residential customers

Network cost category Existing tariff structure NTC7000

Connection assets Fixed charge

($/day)

No change

Forward signal None Peak demand ($/kW/month)

Residual Tariff 8400:

Anytime volume

(c/kWh)

Tariff 8900:

Energy time of use

(c/kWh peak and off-peak periods)

Anytime volume

(c/kWh)

Further details on Energex’s proposed tariff structure for residential customers are provided in the

Residential and Business Customer Consultation Paper available on Energex’s website at

www.energex.com.au/yournetworkyourchoices.

Energex’s tariff strategy for residential customers over the 2015-20 regulatory control period is

presented in Table 3.3 below.


Table 3.3: Proposed tariff offerings for residential customers

Network tariff

Description 2015-16 2016-17 2017-18 2018-19 2019-20

NTC8400 Residential flat Default tariff

NTC8900 Residential Time of Use Optional tariff Grandfathered

NTC7000 Residential demand Initial offering (voluntary)

3.2 Preliminary decisions

In order to assess the impacts on residential customers, Energex has applied its tariff option

preferences based on customer feedback to the tariffs (see consultation paper). The applied options

are presented in table 3.4 below.

Table 3.4: Elements of the residential demand tariff

Tariff component Energex’s preference Alternative

Peak Period 4-8pm 3-9pm

Weekdays Everyday

Peak Single maximum Average top 4 peaks

Bill protection One year demand cap No protection

As shown in figure 3.3, Energex’s analysis of residential customer load profile supports Energex’s

preference for the peak period to be set between 4pm and 8pm.

Figure 3.1: Residential half-hourly demand profile (weekdays, maximum MW)


Energex’s low voltage peak demand is illustrated in Figure 3.2, a heat map of heat levels on the low

voltage network at every half hour each day between July 2014 and June 2015

Figure 3.2: Energex’s network heat map

Figure 3.2 clearly shows that most of the network heat caused by network peaks is particularly

significant between 4pm and 8pm (the area between the dotted lines). It should be noted that peak

network usage after 8pm is controlled through Energex’s load switching program.

Energex considers that residential customers are familiar with the 4-8pm window and existing

messaging ‘can it wait ‘til after 8?’ campaign, and this time period in the residential demand tariffs will

be supported by customers’ existing knowledge.

Energex is also of the view that the peak period should be limited to weekdays, this view is supported

by customers who have been engaged to date. Energex’s analysis shows that, while there are peaks

that occur on weekends, these peaks are not critical. As Energex continues to expand its load control

program it is anticipated that weekend peaks can be managed through the load control tariff. Charging

customers for weekend peak demand will limit customers’ ability to make behavioural change in

response to tariffs

3.2.1 Single peak or average of four peaks

Energex’s preference is to set the demand measurement on a single maximum demand in a billing

period. In the Residential and Business Customer Consultation Paper, Energex noted customers’

preference for the average of the top four demand measurements in the billing period. This approach

was perceived to be less punitive and would result in greater stability in charges.


While acknowledging customer feedback on this issue, Energex is concerned that the complexity in

deriving an average demand may result in confusion among residential customers and impact their

ability to understand their electricity bill. Electricity retailers have conveyed their lack of support for an

averaging of the peaks as this approach was not operationally viable. Given these considerations the

current preference is for a single peak demand measurement.

3.3 Indicative forecast prices

The indicative forecast prices for the 2016-20 period for residential tariffs are presented in Appendix A.

3.4 Customer load profiles

To determine the impact of demand tariff on different residential customer types, Energex requires

interval data which can only be obtained through the use of half hourly interval meters (also known as

smart meters).

Energex is currently responsible for the management and maintenance of 2.2 million meters which

includes over 607,000 advanced meters. However, very few meters have communication functions,

and therefore Energex has limited interval data for residential and business customers connected to

the low voltage network.

To address the data limitations, Energex commissioned the Commonwealth Scientific and Industrial

Research Organisation (CSIRO) to undertake a load profile data collection study for residential

customers.

As part of this study, CSIRO collected residential load profiles and demographic data to provide an

understanding of consumption behaviours for distinct residential market segments. Statistically

significant and representative samples of Energex’s population of residential customers were derived

by considering geographic location, demographics, load control and solar installations. In deriving the

residential customer load profiles, CSIRO used half-hourly interval data provided by Energex:

Peel-off data – Peel-off metering captures the load behaviour of Energex customers with load

control secondary tariffs and is used for calculating the net system load profile for the Energex

network. This dataset is free from opt-in bias but lacks specific demographic diversity.

Smart grid trial data – This dataset is drawn from a targeted improvement technology that

focused on intensive metering of the Newmarket distribution supply area. This dataset

provides deep longitudinal insight into the behaviour of a small sample of residential

customers in South East Queensland, but does not contain any specific demographic

information.

Rewards-based Trial data – the RBT trial was an initiative conducted by Energex and Ergon

Energy from January 2011 whose objective was to better understand residential customer’s

behaviour in relation to price signals. The RBT dataset is rich and offers deep demographic

and load profile information. It also contains an intrinsic bias as the trial focussed on new

stand-alone properties built after 2,000 and the participants were expected to respond to the

price signal on event days.


In addition, CSIRO used interval data from 1,200 probed residential customer meters.

The study concluded in June 2015 and the results have been used to quantify the financial impact of

tariff reform in this Customer Impact Statement.

It is worth noting that the CSIRO work is not intended to be a complete representation of Energex’s

residential customer base. Rather, it is a concise set of profiles that describe broad residential load

behaviours at half-hourly resolution. Energex intends to further develop its understanding of the impact

of tariff reform on customers over the next two years through the implementation of a Real Time Tariff

Study (further information is available in the Residential and Business Customer Consultation Paper).

Energex would also like to invite stakeholders to provide comments about whether there is any

specific information they would want Energex to provide in the future.

Table 3.5 summarises the load profiles developed by CSIRO, the characteristics of each market

segment.

The residential customer cohorts identified by CSIRO include:

Customers living in detached homes with low income ($0-$799 per week).

Customers without children living in detached home with lower-middle income ($800-$1,999

per week).

Customers with children living in detached homes with lower-middle income ($800-$1,999 per

week).

Customers living in detached homes with upper-middle income ($2,000-$2,999 per week).

Customers living in detached homes with high income ($3,000 and above per week).

Single parent customers living in detached homes.

Customers living in semi-detached homes and units.

There is further segmenting within the residential customer cohorts listed above to account for

differences in behavioural patterns that emerge.

Further information on the customer profiles developed by CSIRO is included in the Energex customer

load profile market segmentation and clustering report available on Energex’s website at

www.energex.com.au/influencingtariffs.

Table 3.5 summarises the attributes of each customer cohort. The naming convention of the customer

cohorts in this Customer Impact Statement differs from that used in the CSIRO report to enable

simpler communication. For those who wish to refer to the CSIRO report, a mapping table of the

naming convention used by CSIRO and Energex is provided in Appendix C.


Table 3.5: Summary of customer groups and likely bill impact

Cohort Property type

Bedrooms Household income

Ownership Occupant type

Children Solar Demand Average energy consumption

Customer Impact

Cohort 1 Detached house

3 to 4 Low income Very high rate of ownership

Mostly couples Low numbers with children

Low number of households with solar installed

High afternoon and evening peaks in summer

Moderate consumption

Refer to Appendix D for further details


3 to 4 Low income Very high rate of ownership

Mostly couples Mostly no children

Very high number of household with solar installed

High evening peaks in summer and winter

Low consumption



3 Low income Very high rate of ownership

Mostly couples Mostly no children


Low afternoon peaks in summer and winter

Low consumption



4 Upper middle income

Very high rate of ownership

Mostly couples Mostly with children


Early afternoon and evening peaks particularly in summer

High consumption





Nearly all couples

Mostly with children


Lower daytime load. Evening peaks in summer and winter

High consumption





Mostly couples Mix of people with and without


Small evening peaks in summer and winter

Low consumption







Customer Impact

Cohort 7 Semi-detached houses (townhouses exclusively)

3 Lower middle income to Upper middle income




Greater afternoon and evening peaks in summer

Low consumption


Cohort 8 Semi-detached houses and units

2 Low to Lower middle

Moderate level of ownership



Relatively small winter demand

Low consumption



3 to 4 Lower middle income


Mostly couples No children Low number of households with solar installed

Moderate daytime peaks in summer

Low consumption





Half are couples

No children Low number of households with solar installed

Moderate evening peak in summer and winter

Low consumption



4 Lower middle income

High rate of ownership

All couples Children Low number of households with solar installed

Significant summer peaks in the afternoon and early evening

Moderate to high consumption




High rate of ownership

All couples Children Low number of households with solar installed

Moderate afternoon and evening peaks in summer and winter

Moderate to low consumption



4 High income Very high rate of ownership



High daytime load in summer and winter








Customer Impact


4 High income Very high rate of ownership



High evening peaks in summer and winter




4 High rate of ownership




Relatively flat load




3 Mixture of people with low to lower middle income


Singles No children Low number of households with solar installed

Relatively flat load. Small evening peak in summer and winter




3.5 Customer impact

Using the CSIRO load profiles, Energex has analysed the difference in annual charges between flat

tariff NTC8400 and the proposed new demand tariff NTC7000. It is important to note that the customer

impact assessment in this section is a point in time snapshot when customers switch from their current

energy based tariff to a demand based tariff. It does not account for behavioural changes resulting

from price signals over time.

Figure 3.3 shows annual bill impact for the customer sample, expressed in percentage increase

(orange and red dots) and decrease (yellow to green dots) considering yearly maximum demands (the

y axis) and annual energy consumption (the x axis). The black line represents the break-even point

where customers are neither better off nor worse off.4

Figure 3.3: Annual customer bill impact by energy and demand

Energex’s analysis reveals that, based on the customer profiles developed by CSIRO, the majority of

customers (58 per cent) would be better off when on a demand tariff.

4 It can be noted that the customer impact analysis on residential customers does not

account for adoption or non-adoption of load control tariffs.


Table 3.6: Annualised bill impact for all sample customers

Better off Worse off

Customer cohorts Greater

than 10% Between

5 and 10% Between 0 and 5%

Between 0 and 5%

Between 5 and 10%

Greater than 10%

All customer sample 31% 15% 12% 13% 10% 20%

For the purposes of this assessment a Financial Risk Reduction Mechanism was applied to customer

bills used in the above analysis. Energex is currently proposing Financial Risk Reduction Mechanisms

to mitigate the impact of tariff reform on residential customers. The details of Energex’s proposed

approach are discussed in Section 3.8 below.

Comparing the overall financial impact to customer cohorts listed in table 3.6 above, it is estimated

that four customer cohorts could be worse off as a result of switching from a flat residential tariff to a

demand based tariff.

The average bill impact for the various residential customer groups is illustrated in figure 3.4 below.

The negatively impacted customer cohorts include:

1. Low income couples typically without children, living in a three to four bedroom detached

house and with solar system installed (Customer Cohort 2). This customer cohort is likely to

experience a 3 per cent increase under a demand tariff.

2. Low income couples typically without children, living in a three bedroom detached house, and

unlikely to have solar system installed (Customer Cohort 3). This customer cohort is likely to

experience a 1 per cent increase under a demand tariff.

3. Couples living in semi-detached homes or units, with a low to lower middle income, and

unlikely to have children (Customer Cohort 8). This customer cohort is likely to experience an

8 per cent increase under a demand tariff. This might be related to their low load factor,

indicating a high demand peaks relative to their average consumption.

4. Customers (half of them couples) without children, living in large detached houses, and

earning lower to middle incomes (Customer Cohort 10). This customer cohort is not

significantly impacted with a 0.4 per cent increase in their annual charges under a demand

tariff.


Figure 3.4: Average bill impact for each customer cohort

Table 3.7 below provides more detailed information in relation to the percentage of individual

residential customers in each customer cohort who have been negatively or positively impacted by the

tariff reform up to 5 per cent, between 5 and 10 per cent or greater than 10 per cent.

Table 3.7: Annualised bill impact by customers and magnitude



than 10% Between


Between 0 and 5%

Between 5 and 10%

Greater than 10%

Cohort 1 46% 18% 14% 14% 7% 0%

Cohort 2 18% 10% 15% 18% 10% 30%

Cohort 3 21% 16% 8% 16% 14% 24%

Cohort 4 64% 24% 8% 4% 0% 0%

Cohort 5 41% 7% 19% 11% 11% 11%

Cohort 6 35% 9% 13% 9% 14% 19%

Cohort 7 17% 33% 17% 17% 17% 0%

Cohort 8 11% 7% 14% 14% 7% 46%

Cohort 9 47% 16% 12% 14% 6% 6%




than 10% Between


Between 0 and 5%

Between 5 and 10%

Greater than 10%

Cohort 10 27% 13% 13% 13% 9% 25%

Cohort 11 77% 8% 0% 8% 8% 0%

Cohort 12 26% 22% 13% 13% 9% 17%

Cohort 13 71% 29% 0% 0% 0% 0%

Cohort 14 57% 14% 7% 7% 7% 7%

Cohort 15 44% 8% 12% 4% 12% 20%

Cohort 16 27% 13% 17% 13% 10% 20%

Note: Due to rounding, individual components may not sum to 100 per cent.

This shows that a significant number of customers in each customer group might be facing an

increase in their annual electricity bill of 10 per cent or more. These results highlight the need to

develop tools, such as education material, that will enable customers to mitigate some of the negative

impact they might experience from demand tariffs.

Load profiles and bill impacts for each CSIRO customer cohort are provided in Appendix D.

3.5.1 Estimated annual bill

Energex has developed tools to enable stakeholders to estimate the average annual bill a residential

customer may be charged in 2016-17 and 2019-20 based on their network tariffs, estimated annual

energy level and load factor. These tools are provided in figures 3.1 and 3.2 below.

Load factor is used to measure the efficiency in network usage and is calculated by dividing a

customer’s total average hourly energy divided by the average maximum demand. A high load factor

is considered to be efficient while a low figure is a sign of poor network usage. A load factor of 0.25 is

considered to be typical, a load factor of 0.125 is considered below average while a load factor of

0.075 is considered to be a sign of poor network use.

Assuming an average efficiency in network usage (load factor = 0.25), figures 3.5 and 3.6 provide a

comparison between existing and proposed new tariffs.

The existing residential tariffs used in this analysis include:

NTC8400 – Residential Flat

NTC8400 – Residential Flat and NTC9000 – Load control Super Economy

NTC8400 – Residential Flat and NTC7300 – Load control Economy tariff

The proposed new residential tariffs used in this analysis include:

NTC7000 – Residential Demand (proposed new demand tariff for residential customers)

NTC7000 – Residential Demand and 7300 – Smart Control load control.


Figure 3.5: Estimated annual charges for residential tariffs in 2016-17

Figure 3.6: Estimated annual charges for residential tariffs in 2019-20


Scenario

Using the bill estimation tools provided in Appendix B, it is estimated that residential customers with an

estimated average efficiency in network usage (load factor = 0.25) and typical annual energy

consumption of 4,053kWh5, who are considering switching from NTC8400 – Residential Flat to

NTC7000 – Residential Demand, could be better off by $115 in 2016-17. Under NTC8400, this

particular customer will be charged $661 while on NTC7000 they will be charged $546. Assuming the

same energy levels and efficient use of the network (load factor of 0.25), the same customer will be

expected to save $140 in 2019-20 by moving to a demand tariff.

Residential customers with a load control tariff (NTC8400+NTC9100) with a typical annual energy

consumption of 4,319 kWh6 and a typical network efficiency usage are expected to save $323 in 2016-

17 and $305 in 2019-20 if they adopt the demand based tariff in conjunction with the new Smart

Control secondary tariff (NTC7000 – Residential Demand and NTC7300 – Smart Control).

Customers and stakeholders may conduct their own analysis under various load factors, energy

levels, and network tariffs by using the tools provided in Appendix B.

3.6 Bill protection

Energex is proposing to introduce a Financial Risk Reduction Mechanism or bill protection as it is

called in the consultation papers to mitigate the negative financial impact of demand based tariffs to

residential customers. The Financial Risk Reduction Mechanism will place a cap on the chargeable

quantity of demand (kW) in customers’ first year of the new NTC7000 – Residential Demand. For

customers whose metered monthly maximum demand is less than the cap, their network bill is

calculated without any adjustments. For customers whose metered monthly maximum demand is

greater than the cap, the customers will be charged the cap rate rather than their actual metered

monthly maximum demand.

The idea of bill protection was developed from engagement with customers and retailers. Through this

engagement stakeholders discussed the risk of introducing demand tariffs that will not be adopted by

customers due to the bill impact. Customers and stakeholders recommended the offering of bill

protection to support a 12 month transition for customers who adopt demand tariffs.

Having conducted modelling based on the CSIRO residential load data, Energex proposes that the

cap be set at 5kW. Energex is also proposing to limit access to the Financial Risk Reduction

Mechanism to those customers consuming less than 10MWh/year.

Energex estimates that the proposal will result in mitigating the chargeable demand of approximately

25 per cent of customers during summer months, and 15 per cent of customers in all other months.

This mechanism aims to provide the appropriate balance between mitigating the risk of bill shock and

sending cost reflective price signals.

5 Queensland Competition Authority, Regulated retail electricity prices for 2015-16, Final

determination, June 2015, page 111.

6 Ibid


Figures 3.7 and 3.8 below illustrate the mitigation effect the Financial Risk Reduction Mechanism has

on customers with a maximum demand greater than 5 kW.

Figure 3.7: Customer financial impact of tariff reform without the Financial Risk Reduction Mechanism


Figure 3.8: Customer financial impact of tariff reform with the Financial Risk Reduction Mechanism

Based on the CSIRO customer load profiles, Energex estimates that 353 out of a total of a sample of

907 customers (or nearly 39 per cent) would benefit from the Financial Risk Reduction Mechanism.

These customers would be expected to avoid an average of $30.95 in annual charges during the 12

month period of bill protection.

3.7 Load control

As part of its tariff reform package, Energex is proposing to introduce a new secondary load control

tariff: NTC7300 – Smart Control. The new load control tariff will be offered from 1 July 2016 and will be

used in conjunction with NTC7000 – Residential Demand and available only to customers with smart

meters.

A new load control tariff is required because of:

The increased focus on emerging technologies such as batteries and electrical vehicles.

Currently Energex does not have tariffs that would encourage customers in investing in new

technologies in a way that is beneficial to Energex and its customers.

The existing secondary load control tariffs which are priced relative to NTC8400 – Residential

Flat and are not economically appealing to customers on NTC7000 – Residential Demand.

Under this new load control tariff, electrical equipment such as water heating, pool pumps, air

conditioning units, electric vehicles and smart batteries will be accessed by Energex’s load control

devices. To increase benefits to the low voltage network, the proposed tariff will offer flexible and

targeted operation times, and may make use of domestic solar energy exports during the day.


The indicative prices for NTC7300 from 2016-17 to 2019-20 are provided in Appendix A.

Energex is intending to retain over the 2016-17 to 2019-20 period the current load control tariffs

NTC9000 – Super Economy, and NTC9100 – Economy that are to be used in conjunction with

NTC8400 – Residential Flat. The financial impact of the current and proposed primary tariffs combined

with a load control tariffs (NTC7000+NTC7300, NTC8400+NTC9000, NTC8400+NTC9100) can be

estimated using tools included in Appendix B.

3.7.1 Scenario

Using the bill estimation tool provided in Appendix B, residential customers are estimated to save

$323 in 2016-17 and $305 in 2019-20 if they adopt a demand based tariff in conjunction with the new

Smart Control secondary tariff (NTC7000+NTC73000). This scenario is based on customers with:

Flat tariff in conjunction with load control tariff NTC9100 (Economy);

Typical annual energy consumption of 4,319 kWh7; and

Typical network efficiency usage.

7 Queensland Competition Authority, Regulated retail electricity prices for 2015-16, Final

determination, June 2015, page 111


4 Standard Asset Customers

Small to medium businesses

This section specific relates to small to medium business customers in the Standard Asset Customer

tariff class as detailed in table 4.1.

Table 4.1: Details of small to medium business Standard Asset Customers





Small to medium business customers 4



The tariff structure for the proposed SAC business tariff is presented below:

Table 4.2: Proposed tariff structure for SAC business customers



($/day)

No change

Forward signal None Peak demand ($/kVA/month)

Residual Tariff 8500:

Anytime volume

(c/kWh)

Tariff 8800:

Time of use volume

(c/kWh))

Anytime volume

(c/kWh)

Further details on Energex’s proposed tariff structure for small business customers are provided in the

Residential and Business Customer Consultation Paper.

4.2 Proposed prices

The indicative forecast prices for the 2016-20 period for small to medium business tariffs are

presented in Appendix A. The indicative prices for the newly developed time of use demand tariff

(NTC7100 – Business Demand) are provided from 1 July 2016, which is when it will be offered.


4.3 Customer load profiles

Currently, due to metering issues, half hourly interval load data on small businesses is very limited.

Therefore Energex is not able to accurately quantify the financial impact of the proposed tariff reform

on small business customer segments.

To address this issue, Energex is aiming to collect load profile and small business information to

enable comprehensive customer impact analysis. The objective is to provide Energex with small

business customer load profiles at high, medium and low usage scenarios to capture representative

profiles in identified market segmentation groups. Such information will not be available until 1 May

2016. Energex acknowledges that it will be too late for engagement prior to the submission of its

proposed Tariff Structure Statement on 27 November 2015. To address this Energex is proposing that

NTC7100 – Business Demand as a voluntary tariff and Energex will not proceed with any mandatory

or opt out assignment of customers to tariffs until sufficient data is available to ensure customer

impacts and network impacts have been adequately considered.

In the meantime, Energex has conducted a preliminary analysis of small to medium businesses as

part of this consultation process. A high level load profile for small businesses was derived by taking

the system demand level and removing the estimated CSIRO residential load profile and large

customer interval metered data. The resulting profile was scaled by the month to match the total

energy billed for all NTC8500 and NTC8800 customers.

The small business median demand load profiles for weekdays and weekends are presented in

figures 4.1 and 4.2 below. These profiles were created by taking the maximum or median value for

each 30 minute period over 12 months, as such these profiles don’t represent a single day but the

extreme/typical demand for each period.

Figure 4.1: Derived small business load profile – weekdays


Figure 4.2: Derived small business load profile – weekends

The observations that can be drawn from the above analysis include:

The profile of small to medium business customers is different to the residential customer

profile;

Demand peak period should be limited to weekdays – figure 4.2 demonstrates that the load

profile for small to medium business customers is flat during weekends making it unnecessary

to extend the demand peak period beyond weekdays; and

The proposed peak period 9am and 9pm aligns with when small to medium businesses use

the network.



In calculating customer impacts on small to medium business customers, Energex has applied the

option of setting the peak period between 9am to 9pm weekdays. As shown in Figures 4.1 and 4.2

above, this decision appears to be supported by Energex’s analysis conducted thus far.

Energex will conduct further analysis when a more comprehensive load profile dataset for small

businesses is available and will work with customers to understand the impacts derived from the

comprehensive analysis.

4.5 Bill impact

To inform stakeholders as part of this consultation process, Energex has included in this Customer

Impact Statement a number of business case studies that are intended to illustrate the impact of tariff

reform on small business customers. These business cases, provided in Appendix E, show the

negative impact between a low load factor (ratio between energy and peak demand) and high energy

bills under a demand tariff.

Energex has also developed tools to enable stakeholders to estimate the average annual bill a

residential customer may be charged in 2016-17 and 2019-20 based on their network tariffs, estimated

annual energy level and load factor. Refer to Appendix B.

Load factor is a measure of efficient use of the network and is calculated by dividing a customer’s

annual average hourly energy by the average maximum demand. Figures 4.3 and 4.4 show the

average annual bill amounts small to medium business customers may experience in 2016-17 (date

when demand tariff is first offered) and 2019-20 (final year of the initial Tariff Structure Statement),

depending on the customer’s estimated annual energy levels and load factor. Load factor is a

measure of efficient use of the network that considers a customer’s maximum demand relative to their

average energy consumed within a defined period. A high load factor is considered to be efficient

while a low figure is a sign of poor network use. For a small to medium business customer, a load

factor of 0.4 is considered to be reasonably efficient; a load factor of 0.3 is considered average while a

load factor of 0.2 is considered to be a sign of poor network use.

The existing tariff considered in the analysis includes NTC8500 – Business Flat and the proposed new

tariff NTC7100 – Business Demand.


Figure 4.3: Estimated annual charges for business tariffs in 2016-17

Figure 4.4: Estimated annual charges for business tariffs in 2019-20


4.5.1 Scenario

LV business customers are estimated to save $229 on their annual network charge when the demand

tariff becomes available. Customers with the below load factor and consumption will be charged

$7,453 on NTC8500 – Demand Small compared to $7,224 on NTC7200 – Demand Time of Use (LV)

in 2016-17. This scenario applies to customers with:

A reasonably efficient network usage (Load factor = 0.4);and

A power factor of 0.88 and a assumed annual energy consumption of 60,000kWh.

4.6 Bill protection

Energex is proposing to introduce a Financial Risk Reduction Mechanism to mitigate the negative

financial impact of demand based tariffs to small business customers. The Financial Risk Reduction

Mechanism will place a cap on the chargeable quantity of demand (kW) for the first year of adoption of

the new NTC7100 – Business Demand. For customers whose metered monthly maximum demand is

less than the cap, their network bill is calculated without any adjustments. For customers whose

metered monthly maximum demand is greater than the cap, the customers will be charged the cap

rate rather than their actual metered monthly maximum demand.

The details of the Financial Risk Reduction Mechanism are yet to be developed but will be provided in

the Tariff Structure Statement. As a result, due to insufficient information, Energex is unable to model

the impact of the Financial Risk Reduction Mechanism on small business prices.


5 Standard Asset Customers large

This section specific relates to large business customers in the Standard Asset Customer tariff class

as detailed in table 5.1.

Table 5.1: Details of large Standard Asset Customers




Over 100MWh per annum

Large business customers 5

Engagement program information: www.energex.com.au/tariffsbeyond2015


As of 1 July 2015, customers in the Standard Asset Customer tariff class are charged for demand in

kVA rather than kW. Energex proposes that from 1 July 2018, a new time of use demand tariff

NTC7200 – Demand Time of Use be introduced on a voluntary basis.

Table 5.2: Proposed tariff structure for large customers.



($/day)

No change

Forward signal Anytime maximum demand ($/kVA/month)

Peak demand ($/kVA/month)

Residual Anytime volume

(c/kWh)

Excess demand ($/kVA/month)

Anytime volume

(c/kWh)

Energex proposes that NTC7200 will be made available on 1 July 2018 on a voluntary basis.


Energex’s tariff offering for large customers over the 2015-20 regulatory control period is presented in

Table 5.3 below.

Table 5.3: Proposed tariff strategy for large customers

Network tariff

Description 2015-16 2016-17 2017-18 2018-19 2019-20

NTC8100 Demand Large Optional tariff

NTC8300 Demand Small Default tariff

NTC7200 New tariff Initial offering (voluntary)

Further details on Energex’s proposed tariff structure for large customers can be found in the Large

Customer Consultation Paper and education material for large customer available on Energex’s

website at www.energex.com.au/tariffsbeyond2015.


The indicative forecast prices for the 2016-20 period for large Standard Asset Customers is presented

in Appendix A.

5.3 Bill Impact

Customers in the Standard Asset Customer class may refer to the indicative prices in Appendix B to

understand the impact of the proposed voluntary tariff on their bills.

Energex has also developed tools to enable stakeholders to estimate the average annual bill a

residential customer may be charged in 2016-17 and 2019-20 based on their network tariffs, estimated

annual energy level and load factor. Refer to Appendix B.

Load factor is a measure of efficient use of the network and is calculated by dividing a customer’s

annual average hourly energy by the average maximum demand. Figures 5.1 and 5.2 show the

average annual bill amounts small to medium business customers may experience in 2016-17 (date

when demand tariff is first offered) and 2019-20 (final year of the initial Tariff Structure Statement),

depending on the customer’s estimated annual energy levels and load factor. Load factor is a

measure of efficient use of the network that considers a customer’s maximum demand relative to their

average energy consumed within a defined period. A high load factor is considered to be efficient

while a low figure is a sign of poor network use. For a small to medium business customer, a load

factor of 0.4 is considered to be reasonably efficient; a load factor of 0.3 is considered average while a

load factor of 0.2 is considered to be a sign of poor network use.

The existing tariffs considered in the analysis include:

NTC8100 – SAC Demand Large

NTC8300 – SAC Demand Small

The proposed new tariffs considered in the analysis include:

Tariff 7200 – Demand Time of Use (LV)


Figure 5.1: Estimated annual charges for large customer’s tariffs in 2016-17

Figure 5.2: Estimated annual charges for large customer’s tariffs in 2019-20


5.3.1 Scenario

Large business customers are estimated to save $1,352 on their annual network charge when the

demand tariff becomes available in 2019-20. Customers with the below Load Factor and consumption

will be charged $15,030 on NTC8300 – Demand Small compared to $13,678 on NTC7200 – Demand

Time of Use in 2019-20. This scenario applies to customers with:

A reasonably efficient network usage (Load factor = 0.4);and

A power factor of 0.88 and an annual energy consumption of 135,000 kWh.

Further analysis on business tariff charges under various network use scenarios is provided in

Appendix B.


6 Connection Asset Customers

This section specific relates to large commercial and industrial customers connected to the 11kV

network in the Connection Asset Customer tariff class as detailed in table 6.1.

Table 6.1: Details of Connection Asset Customers



Customers connected to the 11kV network.


Engagement program information:

www.energex.com.au/lctariffreform


Energex’s tariff reform proposal for Connection Asset Customers requires the introduction of a new

tariff, NTC7400 – Demand Time of Use (11 kV). The tariff structure for NTC7400 is presented below:

Table 6.2: Proposed tariff structure for Connection Asset Customer


Connection assets Individually calculated fixed charge

($/day)

Capital rate x non-contributed connection asset value ($/NCCAV/day);

Operating and Maintenance Allowance rate x connection asset value

($/CAV/day)

Forward signal Anytime maximum demand ($/kVA/month)

Peak demand ($/kVA/month)

Residual Time of use volume

(c/kWh)

Excess demand ($/kVA/month)

Anytime volume

(c/kWh)


Table 6.3: Proposed tariff offerings for Connection Asset Customers

Network tariff

Description 2015-16 2016-17 2017-18 2018-19 2019-20

NTC4000 CAC 11kV Bus Offered as is Grandfathered

NTC4500 CAC 11kV Line Offered as is Grandfathered Removed

NTC3000 EG 11kV Grandfathered Removed

NTC8000 HV Grandfathered Removed

NTC7400 New tariff Initial offering Default tariff

Further details on Energex’s proposed tariff structure for Connection Asset Customers can be located

in the Large Customer Consultation Paper which can be found at

https://www.energex.com.au/lctariffreform.


To estimate the impact of tariff reform on customers in the Connection Asset Customer tariff class,

Energex made the preliminary decision to set the peak period for the time of use demand charge

between 7am and 9pm, and the off peak period for the excess demand charge between 9pm and

7am. This preliminary decision was based on the analysis conducted by Energex.


The indicative forecast prices for the 2016-20 period for Connection Asset Customer tariffs are located

in Appendix A.

6.4 Bill impact

Given the confidential nature of the Connection Asset Customer fixed charges, Energex is unable to

include in this Customer Impact Statement the full financial impact of the tariff reform to customers in

the Connection Asset Customer tariff class. However, Energex estimates that Connection Asset

Customer fixed charges will increase by 2.55 per cent annually over the 2016-20 period. Customers in

the Connection Asset Customer tariff class may refer to the indicative forecast prices in Appendix A to

estimate the impact of the proposed changes to the forward signal and residual cost categories.

Customers who believe they will be impacted by the proposed changes to the tariffs should contact

Energex for individual assessment. Energex will assist customers in measuring the impact of tariff

reform upon request. Enquiries can be emailed to the Major Customer Relationship Manager at

[email protected].


7 Individually Calculated Customers

This section specific relates to large commercial and industrial customers connected to the 33kV and

110kV network in the Individually Calculated Customer tariff class as detailed in table 7.1.

Table 7.1: Details of large Individually Calculated Customers


Individually Connected Customers

Individually Calculated customers connected at 33kV and 110kV


Engagement program information: www.energex.com.au/lctariffreform

Given the confidentiality and complexity of large customer prices, the financial impact of tariff reform

will be calculated and reported on an individual basis.


All customers in the Individually Calculated Customer tariff class are assigned to NTC1000. Energex

does not propose any changes to the tariff structure for NTC1000. The NTC1000 tariff structure is

summarised in table 7.2 below:

Table 7.2: Proposed tariff structure for Individually Calculated Customer customers

Network cost category Existing tariff structure Proposed tariff structure

Connection assets Site specific fixed daily charge ($/day)

No change

Forward signal Capacity charge ($/kVA/month)

Anytime maximum demand ($/kVA/month)

No change

Residual Time of use volume

(c/kWh)

No change

Customers who moved to the Individually Calculated Customer tariff class from the EG tariff class

(NTC2000 and NTC2500) do not currently receive a Designated Pricing Proposal Charges (previously

known as TUoS) fixed charge. These EG customers will gradually be exposed to transmission

charges gradually to align with the current NTC1000 from 2017-18.


7.2 Proposed prices

The charges for Individually Calculated Customers are site specific and confidential.

7.3 Bill impact

Given the confidentiality of Individually Calculated Customer prices, customers who believe they will

be impacted by the proposed tariff reform should contact Energex for individual assessment. Energex

also intends to develop a network charge calculator which will assist customers in measuring the

impact of tariff reform. The calculator will be available upon request to the Major Customer

Relationship Manager at [email protected].

To provide Individually Calculated Customers with a high level indication of the impact of the tariff

reform, Energex has provided in table 7.3 indicative revenue trends for energy and demand for the

period 1 July 2016 to 30 June 2020.

Table 7.3: Indicative revenue trends for Individually Calculated Customers

Year 2016-17 2017-18 2018-19 2019-20

Network revenue ($M) 1,2 $46.15 $45.69 $46.15 $47.60

AMMD (MVA) 459.21 462.87 467.95 532.96

Network revenue per unit of demand ($/kVA)

$100.51 $98.70 $98.61 $89.31

Network revenue per unit energy (c/kWh)

2.17c 2.13c 2.13c 1.93c

Note:

1. Network revenue comprises distribution revenue (DUoS) and transmission revenue (TUoS).

2. Network revenue includes Queensland Government Jurisdictional Solar Bonus Scheme.

It is important to note that these are not actual prices and are included in this Customer Impact

Statement to represent the trend in allocated revenues.


8 Glossary

Table 8.1: Acronyms and abbreviations used through this document

Abbreviation Description

CAC Connection Asset Customer

CAV Connection asset valuation

DUoS Distribution Use of System

HV High voltage

kV Kilovolt

kVA Kilovolt ampere

NCCAV Non-contributed connection asset valuation

Table 8.2: Units of measurement used throughout this document

Basic Unit Unit name Multiples

h hour GWh, kWh, MWh

V volt kV, kVA, MVA

VA volt ampere kVA, MVA

W watt W, kW, kWh

Table 8.3: Definitions of terminology used throughout the document

Term Abbreviation/Acronym Definition

Australian Energy Market Commission

AEMC A national, independent body that exists to make and amend the detailed rules for the National Energy Market to ensure efficient, reliable and secure energy market frameworks which serve the long term interests of consumers.

Australian Energy Regulator

AER The economic regulator of the National Electricity Market established under section 44AE of the Competition and Consumer Act 2010 (Commonwealth).

Charging parameter

The charges comprising a tariff. Parameters include demand, capacity, fixed and volume (flat or ToU) charges.

Connection asset (contributed or non-contributed)

Related to building connection assets at a customer’s premises as well as the connection of these assets to the distribution network. Connection assets can be contributed (customer funded, then gifted to Energex) or non-contributed (Energex funded).


Term Abbreviation/Acronym Definition

Customer impact statement

Study which explores the impact that the proposed tariff reform package may have on customers.

Demand The amount of electricity energy being consumed at a given time measured in either kilowatts (kW) or kilovolt amperes (kVA). The ratio between the two is the power factor.

Designated Pricing Proposal Charge

DPPC Refers to the charges incurred for use of the transmission network; previously referred to as Transmission Use of System (TUoS).

Distribution Use of System

DUoS This refers to the network charges for the use of the distribution network.

Large customer classification

As per tariff class assignment process for customers with consumption greater than 100 MWh per year.

Load factor LF Load factor is a measure of efficient use of the network and is calculated by dividing a customer’s annual average energy by the average maximum demand (or AMMD).

Long run marginal cost

LRMC An estimate of the cost (long term variable investment) of augmenting the existing network to provide sufficient capacity for one additional customer to connect to the network or an additional MW of demand.

Low voltage LV Refers to the sub-11 kV network

Network Use of System

NUoS The tariff for use of the distribution and transmission networks. It is the sum of both Distribution Use of System (DUoS) and Designated Pricing Proposal Charge (DPPC).

Power factor PF Power factor is the ration of kW to kVA, and is a more accurate measure of the use of the network infrastructure as it takes into account reactive power. The closer to one (1), the more efficiently the network assets are utilised as reactive power is minimised.

Power factor = kW/kVA

Regulatory control period

A standard Regulatory Control Period for DNSPs is a period of not less than 5 regulatory years. Energex’s current Regulatory Control Period is 2015-20, commencing 1 July 2015.

Time of use ToU Refers to tariffs that vary according to the time of day at which the electricity is consumed.

Tariff Structure Statement

TSS Document prepared in accordance with Part I of chapter 6 of the National Electricity Rules, setting out Energex’s network price structures and indicative tariffs that will apply over each year of the regulatory control period.

Documents

Customer Impact Statement - Energex · 2015 preliminary decision on Energex’s forecast distribution revenue for the 2016-17 to 2019-20 period.1 The figures quoted include adjustments