Default market
offer prices
2022–23
Final determination

May 2022

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Default market offer prices 2022–23: Final determinationii

Contents
1

Executive summary ....................................................................................................... 1

2

DMO 2022–23 final prices ............................................................................................. 6

3

4

5

6

7

8

2.1

DMO final prices ............................................................................................... 6

2.2

Analysis of DMO prices against the policy objectives ........................................ 8

Background to the DMO.............................................................................................. 12
3.1

Policy context for the DMO ..............................................................................12

3.2

DMO regulatory framework ..............................................................................13

3.3

DMO regulations review ...................................................................................14

Network costs .............................................................................................................. 16
4.1

Overview..........................................................................................................16

4.2

Draft determination ..........................................................................................16

4.3

Stakeholder submissions .................................................................................16

4.4

Final determination ..........................................................................................17

Wholesale energy costs .............................................................................................. 19
5.1

Overview..........................................................................................................19

5.2

Draft determination ..........................................................................................20

5.3

Stakeholder submissions .................................................................................21

5.4

Wholesale methodology review........................................................................23

5.5

Final determination ..........................................................................................24

Environmental costs ................................................................................................... 30
6.1

Overview..........................................................................................................30

6.2

Draft determination ..........................................................................................30

6.3

Stakeholder submissions .................................................................................30

6.4

Final determination ..........................................................................................31

Retail costs and allowances ....................................................................................... 32
7.1

Overview..........................................................................................................32

7.2

Overall approach to retail costs and allowances ..............................................32

7.3

Retail costs ......................................................................................................34

7.4

DMO retail allowance .......................................................................................42

7.5

Retail allowance analysis .................................................................................46

7.6

Final determination on overall approach, retail costs and retail allowance .......48

Model annual usage .................................................................................................... 51
8.1

Draft determination ..........................................................................................51

8.2

Stakeholder submissions .................................................................................51

8.3

Final determination ..........................................................................................52

Appendices ......................................................................................................................... 53

Default market offer prices 2022–23: Final determination

iii

A

List of submissions to the DMO 4 Draft Determination ............................................ 54

B

Market offer analysis for each distribution region .................................................... 55

C

Nominal price movements from draft determination to final determination ........... 65

D

Advanced meter costs ................................................................................................ 67

E

Legislative instrument................................................................................................. 69

F

DMO 3 to DMO 4 price movements ............................................................................ 80

G

Analysis of DMO 4 final retail costs and margins ..................................................... 82

Default market offer prices 2022–23: Final determinationiv

1 Executive summary
This is our final determination for retail electricity default market offer (DMO) prices to apply
from 1 July 2022 to 30 June 2023, known as DMO 4.
The DMO is the maximum price an electricity retailer can charge a standing offer customer
each year. A customer might be on a standing offer if they have never switched to a retailer’smarket offer or for a range of other reasons.1
The objectives of the DMO price2 are to:•reduce unjustifiably high standing offer prices and continue to protect consumers fromunreasonable prices•

allow retailers to recover their efficient costs of providing services, including areasonable retail margin and costs associated with customer acquisition and retention•

maintain incentives for competition, innovation and investment by retailers, andincentives for consumers to engage in the market.

To meet these objectives, we base the DMO price on the costs that retailers incur to supply
customers. These include the costs to purchase electricity (wholesale costs), costs totransport that electricity to customers (network costs), the costs to comply with government
environmental schemes (environment costs) and costs associated with serving retail market
customers, such as billing and provision of hardship services (retail costs).
Recognising that the DMO must allow retailers to make a reasonable profit and enable
competition and market engagement, the price also includes an allowance for these factors.
Our draft determination, released in February 2022, set out our intention to:•

Adopt a cost build-up approach for all elements of the DMO determination – our view
was that this provides greater transparency on the cost drivers in a market in which thepace of change continues to accelerate and helps ensure costs are reasonable.

•

Transition to a consistent 10% retail allowance for residential customers and a 15% retailallowance for small business customers – these allowances encompass a retailer profit
margin and an allowance to meet the DMO objectives, which were previously part of the‘residual’ component of the DMO.
This shift ensures that, looking forward, the policy objectives can be met consistently
across regions. This is important in addressing the very low retail margins in someregions and very high margins in others, which were in place previously.
To minimise potential impacts of a sudden change on retailers and customers, we
intended to transition to these targets over the next 3 years, so that they were in placeby the 2024–25 (DMO 6) determination.

1

See section 3.1.
The DMO objectives are set out in several sources including: Treasurer’s and Minister for Energy’s
request to the AER to develop a DMO, 2018; the ACCC Retail Electricity Pricing Inquiry final report, 2018; theExplanatory Statement accompanying the DMO Regulations, 2019.
2

Default market offer prices 2022–23: Final determination

1•

Adjust the usage benchmark we use to calculate the annual price for small businesscustomers. The available information suggested 10,000kWh per year better represented
these customers than the previous 20,000kWh per year benchmark.

•Adjust elements of the wholesale cost methodology – while we continue to assume thatretailers will adopt risk management strategies that minimise their exposure to thevolatile spot market, we proposed adjusting elements of the forecast settings to reduce
the likelihood of overestimating retailers’ wholesale costs. Our draft determination view
was that reducing the margin for error in our estimates balanced the risks to retailers
with the need to protect customers from unnecessarily high prices.

While wholesale prices were rising in the forecasts used for the draft determination, this has
accelerated since then. Factors contributing to increases in the draft forecasts included a
reduction in thermal generation resulting from unplanned outages and higher coal and gas
costs, slowing of investment in new capacity, and increasingly ‘peaky’ demand driving up thecost of hedging for retailers. These conditions have persisted and been compounded by theongoing war in Ukraine, which has led to significant pressure on coal and gas prices globally;
extreme weather in NSW and Queensland, which has affected coal supplies and electricity
demand; and further unplanned outages at multiple generators. As a result, there have beenvery significant increases in wholesale futures prices for all DMO regions but in particular
NSW and Queensland.
A number of retailers told us that these factors have elevated their wholesale market financial
risk. Additionally, some saw parallels between the current Australian market conditions andrecent events in the United Kingdom’s (UK) retail market, where wholesale price surges andthe retail price cap were among factors contributing to the collapse of several retailers.
We have reviewed the UK events and market conditions. Our view is that some key factorsthat contributed to the UK issues, specifically the difference in business models adopted byretailers and some of their hedging strategies, are not prevalent in the Australian market. We
recognise the increased risk environment, but consider our DMO approach adequately takesthese risks into account. In particular, we note:•even in a period of higher uncertainty, the forecast settings provide a significant marginof error against underestimating wholesale costs – particularly in light of the other riskaverse assumptions embodied in the forecast methodology•

the change to the final DMO publication date to 26 May means that the wholesale cost
takes into account the current risk assumptions as foreseen by the market•

the DMO allowances for residential and small business customers are set high enoughthat even a retailer with higher than average costs will be able to make a reasonableprofit.

Taking into account the long-term interests of consumers, as well as the current market risks,
our view is that the approach outlined above is fair and balances the DMO objectives.
Consequently, we have not changed our position on the key issues set out above since thedraft determination. However, we have made adjustments to:•use AEMO’s fee proposals for the coming year instead of the past year

Default market offer prices 2022–23: Final determination2

•take into account legacy costs retailers incur following the removal of someaccumulation meters.

The draft determination noted that we would seek a peer review of ACIL Allen’s wholesalecost forecasting approach. This was to examine how well it performs given changes in themarket, such as increased uptake of rooftop and grid-scale solar. These are having a large
impact on spot prices and challenging the extent to which standard contracting products
enable retailers to manage risk.
We engaged Frontier Economics to undertake this review.3 Frontier’s review reassures usthat ACIL Allen’s market-based methodology meets the DMO objectives and is practical,
transparent and provides price stability compared with other approaches.
However, Frontier also notes that multiple assumptions within the methodology tend to resultin wholesale costs being overestimated relative to what the most efficient retailers could
expect to achieve. In our view, this affirms our decision to adjust some settings to reduce therisk of overestimation while still providing a significant risk margin against underestimation.
Frontier identified a range of forecasting approaches that could potentially be used tostrengthen the methodology as the market evolves. These require careful consideration andwe will work with stakeholders to examine these over the coming year.
DMO 4 prices
Compared with last year, standing offer customers will face price increases in real terms.
•

NSW residential customers will see increases of 2.9% to 12.1% above expected
inflation,4 depending on whether they have controlled load (8.5% to 18.3% increases innominal terms).

•

Residential customers in south-east Queensland will see increases above expected
inflation of 5.5% to 6.8% (11.3% to 12.6% increases in nominal terms).

•

Residential customers in South Australia face increases above expected inflation of
1.7% to 3.8%, depending on whether they have controlled load (7.2% to 9.5% increases
in nominal terms).

For small business customers, DMO 4 prices are not directly comparable with DMO 3 prices
due to the new usage benchmark. However, when compared using the previous benchmark:•prices for NSW customers will see increases of 4.3% to 13.5% above expected inflation(10% to 19.7% increases in nominal terms)•

south-east Queensland prices would be 6.9% above expected inflation (12.8% in
nominal terms)•

South Australian prices would be 0.2% above expected inflation (5.7% in nominal
terms).

3

Frontier Economics, Review of retail wholesale energy cost estimation methodology: Final Report for theAustralian Energy Regulator, 31 March 2022.
4
We have used the RBA’s forecast inflation for 2021-22 of 5.5%, Reserve Bank of Australia, Statement on
Monetary Policy, May 2022.

Default market offer prices 2022–23: Final determination

3

Factors influencing DMO prices
Rising wholesale costs are the main cause of the increase in the DMO price. In addition to
the drivers described above, in DMO 4 wholesale costs will also be impacted by:•in south-east Queensland, increased frequency control ancillary service (FCAS)
charges, as well as costs relating to the activation of the Reliability and Emergency
Reserve Trader (RERT) scheme in February 2022•

the inclusion of AEMO directions costs in South Australia.

Network costs have fallen slightly for the Ausgrid (NSW) region and more significantly for the
Energex (south-east Queensland) region. Return of over-recovered revenue was a key factor
in both regions, while reduced costs for transmission and the Queensland Government’s
Solar Bonus Scheme contributed to Energex’s larger reductions.
Cost pass-throughs, efficiency incentive payments and higher transmission costs are among
the factors driving higher network costs in the Essential (NSW), Endeavour (NSW) and
SAPN (South Australia) regions.
Higher demand for large-scale generation certificates (LGCs) and Small-scale Renewable
Energy Scheme certificates has seen environment costs for NSW increase slightly since lastyear, but this has had a negligible impact on the DMO price.
The transition to consistent retail allowances across regions moderates the price increases in
NSW, where the effective retail allowances were previously higher. The shift to standardised
allowances contributes a small amount to price rises in South Australia and south-east
Queensland but this effect is moderated by the transitional pathway for allowances.
DMO policy objectives
The adjusted methodology and the resulting DMO 4 prices deliver on the DMO policy
objectives:•

The DMO price protects standing offer customers against unreasonable prices in anenvironment of rising living costs. In particular, in NSW, the retail allowance componentof many standing offer customers’ bills will be significantly lower than previous years as it
moves towards a consistent level across all jurisdictions.
The lower forecast error margin reduces the likelihood the wholesale estimate willoverstate retailers’ costs. We considered that the previous setting resulted in higher thannecessary prices, given the other cautious forecast settings.

•

The retail allowances are above those set by jurisdictional regulators aiming to determine
an efficient retail margin, ensuring that retailers can recover their costs and make areasonable profit margin.
In South Australia, the retail allowance will be higher than the low level of previous years,
which we were concerned may not allow retailers to achieve a reasonable profit margin.
We have carefully considered retailers’ operating and other underlying costs andreflected these in setting the DMO price. Our later wholesale data also ensures that thecurrent market outlook is factored into the wholesale estimates.

Default market offer prices 2022–23: Final determination

4•The retail allowances ensure the DMO remains a ‘fall back’ price well above market
offers. It means retailers can continue to offer discounts and compete on price under thecap, while the large savings available for switching to market offers provide goodincentives for customers to engage in the market.

Customers who shop around will continue to save on their bills. Based on offers available in
May 2022, residential customers switching from the DMO 4 price to the median market offer
could save between $294 and $443 depending on their network region, while small businesscustomers could save between $733 and $1,308.

Default market offer prices 2022–23: Final determination

5

2 DMO 2022–23 final prices
2.1 DMO final prices
DMO prices for 2022–23 for each customer type in each distribution region are set out inTable 2.1. The table also shows the changes from DMO 3 in both real terms (that is, adjusted
for forecast inflation) and nominal terms.
The final DMO prices are based on the most recent data available. Since the draft
determination, higher contract prices have flowed through to the DMO wholesale costcalculations, resulting in higher prices than the draft determination.
The small business DMO prices in the table are based on our new annual usage benchmark
of 10,000 kWh per year. Due to this change, DMO 3 and DMO 4 prices are not directlycomparable. However, to provide an indication of the year-on-year change, we havecompared the DMO 3 small business price with a nominal DMO 4 price calculated at
20,000 kWh per year.

Default market offer prices 2022–23: Final determination

6

Table 2.1 DMO 2022–23 final determination prices, including changes from DMO 3 innominal and real terms*
Distribution zone

Ausgrid(NSW)

Endeavour(NSW)

Essential(NSW)

Energex (SE
QLD)

SAPN (SA)Residential without
CL

DMO price$1,512for annual
usage of3,900 kWh

Residential with
CL

$2,122

Small businesswithout CL$4,360Change y-o-yChange y-o-y(real)+$119 (8.5%)

Flat rate 4,800
kWh+ CL 2,000 kWh+$210 (11.0%)+$42 (2.9%)+$105 (5.2%)+$310 (4.3%)

DMO price$1,836$2,383$3,782for annual
usage of4,900 kWh

10,000 kWh+$690 (10.0%)

Change y-o-yChange y-o-y(real)+$227 (14.1%)

Flat rate 5,200
kWh+ CL 2,200 kWh+$369 (18.3%)+$139 (8.2%)+$258 (12.1%)+$815 (13.5%)

DMO price$2,092$2,490$4,901for annual
usage of4,600 kWh

10,000 kWh+$1,130 (19.7%)

Change y-o-yChange y-o-y(real)+$185 (9.7%)

Flat rate 4,600
kWh+ CL 2,000 kWh+$219 (9.6%)+$80 (4.0%)+$94 (3.9%)+$717 (8.7%)

DMO price$1,620$1,961$3,446

for annual
usage of4,600 kWh

10,000 kWh+$1,146 (14.7%)

Change y-o-yChange y-o-y(real)+$165 (11.3%)

Flat rate 4,400
kWh+ CL 1,900 kWh+$220 (12.6%)+$85 (5.5%)+$124 (6.8%)+$402 (6.9%)

DMO price$1,840$2,275$4,539for annual
usage of4,000 kWhChange y-o-yChange y-o-y(real)

10,000 kWh+$705 (12.8%)+$124 (7.2%)

Flat rate 4,200
kWh+ CL 1,800 kWh+$198 (9.5%)+$459 (5.7%)+$30 (1.7%)+$84 (3.8%)+$17 (0.2%)

10,000 kWh* Real comparisons with DMO 3 are based on RBA 2021–22 inflation forecast of 5.5% in its May 2022 Statement
on Monetary Policy.
Note: DMO 3 and 4 prices for small business are not directly comparable due to the new usage benchmark.
Percentage and dollar changes in this table are based on a comparison of the DMO 3 small business price and anominal DMO 4 price calculated at 20,000 kWh per year.

Default market offer prices 2022–23: Final determination

7

The Regulations require that the DMO prices are indicative prices based on a set model
annual usage. They are not a ‘maximum bill’. Individual customers’ bills will vary depending
on how much electricity they use, their distribution region and how their retailer has set the
fixed and variable charges on their standing offer. As required under the Regulations, wehave specified DMO prices as annual prices, based on the model annual usage (which is
discussed in Chapter 8 of this report).5 Under the Regulations, retailers must structure theirtariffs to not exceed the DMO annual price for the model annual usage.6
Figure 2.1 illustrates the change in DMO price components between DMO 3 and DMO 4 forresidential customers without controlled load. Appendix F contains the full set of thesefigures for each customer type.
Figure 2.1 Change in DMO price components for DMO 4, residential without controlled
load, nominal

2.2 Analysis of DMO prices against the policy objectives
Ensuring the DMO price balances the objectives is our primary goal in setting the price. Our
analysis, set out below, indicates that the adjusted methodology and the resulting DMO 4
prices continue to do so.
Objective – Protect consumers from unjustifiably high prices
Consumers in DMO regions will continue to receive protection from unjustifiably high pricesthat existed before the DMO came into effect in 2019. In DMO 4 we are making additionalchanges to protect customers from high retail allowances in a way that is fair across all
regions.

5
6Regulations s. 16.
Regulations s. 10.

Default market offer prices 2022–23: Final determination

8

Under previous DMO determinations, the residual component varied widely across theregions and in some regions was very high. For instance, in DMO 3:•

The DMO price for most residential standing offer customers in NSW regions included
effective retail allowances of around 13%.

•

For most small business standing offer customers in NSW, the DMO price included
effective retail allowances of 20% to 29%. For those in south-east Queensland’s
Energex region the effective allowance was 18%.

We were concerned that these allowances provided a return to retailers that was notproportionate to the risks they faced in those markets, were higher than needed to facilitatecompetition and engagement, and resulted in customers paying more than necessary tomeet the DMO objectives.
The move to 10% and 15% retail allowances, for residential and small business customers
respectively, addresses these concerns.
In the longer term, consistency in the margin across all customer types and regions will
ensure retailers cannot make unreasonable profits from different sets of customers.
In addition, the move to a full cost build-up methodology allows for greater scrutiny on all
retailer costs. This will ensure cost drivers can be analysed and assessed so only reasonable
costs are passed on to consumers.
Objective – Retailers can recover their efficient costs
The careful consideration given to each cost driver and the approach to the retail allowancemeans retailers can recover the costs they incur to serve customers, including costs they
incur for advanced meters, and bad and doubtful debt.
The move to a later DMO publication date should increase stakeholder confidence that theDMO price will accurately reflect retailers’ underlying costs because we have used:•

more current wholesale data than previous years, meaning the wholesale estimates
better capture the expected market outlook for 2022–23•

approved network pricing as the basis for the DMO 4 network cost component, removing
any risk associated with our use of proposed prices.

The new methodology also means any changes in retail costs over time will be reflected infuture DMO prices due to our use of annually updated ACCC data.
Objective – Retailers can make a reasonable profit
The retail allowances that we have set – 10% of the DMO bill for residential customers and
15% for small business customers – will enable retailers to make a reasonable profit.
These allowances are well above:•the 5% to 6% range allowed as a reasonable profit margin by other Australian regulatorsthat aim to set prices that reflect the efficient costs of a retailer

Default market offer prices 2022–23: Final determination9•

the 3% and 5% reported by the ACCC as the average profit margin across the national
electricity market’s competitive markets for residential and small business customers
respectively.7

The retail allowance will initially be 6% in DMO 4 for residential customers in South Australia
and 8.4% in south-east Queensland, as the first step in the transition to a 10% retailallowance by DMO 6. These initial lower allowances enable retailers to make a reasonableprofit, noting that the 6% retail allowance in South Australia is significantly higher than:•

the nominal equivalent allowance under previous DMO determinations for South
Australia (1.3% to 4% in DMO 3)•

the −1% profit available in the competitive South Australian market.8

Objective – Retailers have incentives to compete, innovate and invest
The gap between the DMO price and market offer prices, as well as the new products andservices marketed by retailers, remains significant and shows that retailers have incentives
to compete on price and offer discounts, innovate and invest.
Our analysis suggests that the DMO price will provide retailers with significant flexibility tohave different pricing strategies and offer discounts below the DMO price.
While this ability is more constrained for retailers in South Australia in DMO 4 and 5, due tothe incremental transition to a higher retail allowance, competition has been reasonably
strong in South Australia despite the historically low profit margins available to retailers there.
The move to a consistent 10% retail allowance over the next 3 determinations should
increase the capacity for retailers to compete, innovate and invest in this market.
The 10% and 15% allowances are lower than what has been historically available to retailers
in NSW, but these will not impact retailers’ capacity to offer substantial discounts below theDMO price and compete for market share. As of May 2022 the median market offer:•in the Ausgrid (NSW) region is 22% below the DMO 4 price, while the lowest offer is
34% below•

in the Endeavour (NSW) region is 24% below the DMO price, while the lowest offer is
33% below•

in the Essential Energy (NSW) region is 21% below the DMO price, while the lowest
offer is 30% below•

in the Energex (south-east Queensland) region is 20% below the DMO price, while thelowest offer is 28% below•

in the SAPN (South Australia) region is 16% below the DMO price, while the lowest offer
is 30% below.

7

ACCC media release, 13 December 2021 - https://www.accc.gov.au/media-release/cost-of-supplyingelectricity-to-households-at-an-eight-year-low
8
ACCC, Inquiry into the National Electricity Market November 2021 report, Appendix E.

Default market offer prices 2022–23: Final determination10

Objective – Consumers have incentives to engage in the market
The substantial gap between DMO 4 and market offer prices in each area, and the range ofretailers and services on offer, indicates there are still strong incentives for DMO customers
to shop around and switch to a market offer.
When switching from the DMO 4 price to the lowest market offer (as of May 2022),
residential customers would stand to save annually:•in NSW, between $508 (Ausgrid) and $624 (Essential)•

in south-east Queensland, $456•

in South Australia, $554.

When switching from the DMO 4 price to the lowest market offer, small business customers
would stand to save:•in NSW, between $1,366 (Endeavour) and $1,767 (Ausgrid)•in south-east Queensland, $1,134•

in South Australia, $1,428.

Default market offer prices 2022–23: Final determination11

3 Background to the DMO
The AER is the independent regulator for Australia’s national energy market. Our functions
include regulating electricity networks and covered gas pipelines in all jurisdictions except
Western Australia. We enforce the laws for the National Electricity Market (NEM) and spot
gas markets in southern and eastern Australia. We monitor and report on the conduct ofmarket participants and the effectiveness of competition.
We protect the interests of household and small business consumers by enforcing the
National Energy Retail Law (NERL). Our retail energy market functions cover
New South Wales (NSW), South Australia, Tasmania, the Australian Capital Territory (ACT)and Queensland.
Our objectives include:•

protecting vulnerable consumers, while enabling consumers to participate in energy
markets•

effectively regulating competitive markets, primarily through monitoring and reporting,and enforcement and compliance.

Under the Competition and Consumer (Industry Code – Electricity Retail) Regulations 2019(the Regulations), our role is to set the DMO price each year for regions that have no retailprice regulation – NSW, south-east Queensland and South Australia.

3.1 Policy context for the DMO
The purpose of the DMO as identified by the ACCC at its conception is to act as a fallback
for those who are not engaged in the market and should not be a low-priced alternative to amarket offer.9 The policy objectives of the DMO are that it should:•

reduce unjustifiably high standing offer prices and continue to protect consumers fromunreasonable prices•

allow retailers to recover their efficient costs of providing services, including areasonable retail margin and costs associated with customer acquisition and retention•

maintain incentives for competition, innovation and investment by retailers, andincentives for consumers to engage in the market.

Customers on standing offers
The Australian Energy Market Commission (AEMC) and ACCC have identified that
customers on standing offers (Table 3.1) are those who:•

have not taken up a market offer since the introduction of retail competition in thatjurisdiction•

are supplied under a retailer’s ‘obligation to supply’ (for example, if a poor credit history
means other retailers will not supply them)10910ACCC, AER Default market offer, Submissions to the draft determination, 20 March 2019, p.1–2.
Unlike other retailers, under s. 22 of the NERL Local Area Retailers cannot refuse to supply customers.

Default market offer prices 2022–23: Final determination

12

•have moved into a premise and receive supply from the existing retailer supplying thepremises but are yet to contact the retailer11•

have defaulted to a standing offer following the expiry of a market contract.12

The majority of customers on standing offers are served by ‘Tier 1’ retailers – AGL Energy,
EnergyAustralia and Origin Energy.
Table 3.1 Customers on standing offers in DMO areas
RegionResidential customers(number and %)Small business customers(number and %)NSW

331,070 (9.8%)

57,411 (17.8%)

South-east Queensland

158,113 (10.7%)

21,686 (19.8%)

South Australia

62,198 (7.8%)

13,631 (15.7%)

Total standing offer customers

551,381 (9.8%)

92,728 (17.9%)

Note: South-east Queensland figures extrapolated from all Queensland by excluding Ergon customers. Other
retailers have customers in regional Queensland so figure is approximate. Standing offer customers calculated bysubtracting market offer customers from total customers.
Source: AER Retail Market Performance update, Quarter 3 2021–22.

The Regulations also prescribe a mandatory industry code with DMO provisions requiring:13•

standing offer prices for small customers not to exceed a price determined by the AER14•

small customers be told how a retailer’s prices compare with the AER determined annual
price15•

the most prominent price related feature in an advertisement is not a conditional
discount, and any conditions on other discounts are clearly displayed.16

Under these requirements, the DMO price acts as ‘reference price’, against which customers
can easily compare market offers. The ACCC is responsible for enforcement and compliancewith these provisions.

3.2 DMO regulatory framework
The legislative framework for implementing DMO prices is contained in the Competition andConsumer (Industry Code—Electricity Retail) Regulations 2019.

11
AEMC, Advice to COAG Energy Council: Customer and competition impacts of a default offer, 20
December 2018, p. 15.
12
Section 10 of the Regulations makes clear the DMO price only applies to customers on an electricity
retailer’s standing offer. It does not apply to customers who are on ongoing market contracts where discounts
have expired. In practice these customers may be paying a retailer’s standing offer prices. We do not know how
many customers may be in this situation.
13
The Code for the purposes of Part IVB of the Competition and Consumer Act 2010.
14
Regulations s. 10.
15
Regulations s. 12.
16
Regulations s. 14.

Default market offer prices 2022–23: Final determination

13

Part 3 of the Regulations confers price setting functions on the AER. Specifically, we are
required to determine:•

how much electricity a broadly representative small customer of a particular type in aparticular distribution region would consume in a year and the pattern of that
consumption17 (the model annual usage)18•

a reasonable total annual price for supplying electricity (in accordance with the model
annual usage) to small customers of a type in a region (the DMO price).19

The DMO price applies to residential and small business customers on standing offers in
NSW, South Australia and south-east Queensland.20
The Regulations set out that we must determine DMO prices for:•residential customers – on flat rate or time of use (TOU) tariffs•

residential customers with controlled load – these are separately metered tariffs used for
appliances such as electric hot water storage systems, pool pumps or underfloor heating•small business customers – on flat rate tariffs.21

Each category includes customers with solar tariffs.22
The Regulations require us to consider a range of specific factors in determining areasonable annual price. These include wholesale electricity, network and retail costs, costs
to acquire, retain and serve customers, the principle that a retailer should be able to make aprofit, and other matters we consider relevant.23

3.3 DMO regulations review
The Australian Government commenced a review of the DMO Regulations in September
2021.
The review has now concluded with outcomes including:24•

amending the regulations to change the date for the DMO determination from 1 May tothe first business day after 25 May to provide more time for the AER to include the mostrecent network costs in the final price determination

17
The AER is not required to determine the pattern of consumption in the case of small businesscustomers.
18
Regulations, s. 16(1)(a).
19
Regulations, s. 16(1)(b).
20
Section 8 of the Regulations specifies that the instrument would not apply in a distribution region if any
standing offer prices, or maximum standing office prices, for supplying electricity in the year in the region to asmall customer are set by or under a law of a State or Territory.
21
Small business customers are those who use less than 100 MWh per annum.
22
We are not required to determine an annual price and usage for customers on other tariff types, such as,
tariffs with a demand charge, small business controlled load and TOU tariffs, tariffs offered in embedded
networks.
23
Regulations, s. 16(4).
24
See https://www.energy.gov.au/government-priorities/energy-programs/price-safety-net

Default market offer prices 2022–23: Final determination14

•

to further consult on amending the name of the reference price and how best to extend
price cap protection provided by the DMO to customers in embedded networks•

undertaking another review of the Code 2 years after the implementation of theConsumer Data Right for Energy for initial retailers, in 2024.

While most of the changes are relevant to DMO 5 and beyond, the amended final dateapplies to our DMO 4 determination.
The main impacts of this change on our DMO 4 determination are:•

We have used approved network prices, meaning the DMO network component willreflect actual network costs retailers will face in 2022–23. Many retailers have been
concerned about our use of proposed prices in previous years.

•

Our wholesale and environment forecasts are based on a later cut-off for wholesalemarket data (13 May). This means our estimates will reflect more current market trends
and developments that will impact prices in the forecast period.

3.4 Our consultation process
In making our final determination we have undertaken a consultation process consistent withsection 17(1) of the Regulations.
•

On 25 October 2021 we published a Position Paper and received 16 submissions.

•

On 10 November 2021 we held an online stakeholder forum attended by approximately
80 stakeholders. Presentations from the forum were published on our website.

•

On 18 February 2022 we published a draft determination and received 18 submissions.
A list of submitters is included at Appendix A.

•

On 9 March 2022 we held an online stakeholder forum attended by about 80
stakeholders. Presentations from the forum were published on our website.

•

We published our consultant ACIL Allen’s wholesale forecasting methodology report on
our website.

We have had regard to the submissions and information received through our consultations
and the advice from our consultants in making our determination.

Default market offer prices 2022–23: Final determination

15

4

Network costs

4.1 Overview
Network costs in a retail electricity bill represent the cost of transporting electricity throughtransmission and distribution networks.
Under the National Electricity Rules (NER), the AER regulates network charges, approving
network tariffs the distribution network businesses annually set for customer use of the
network. Network tariffs are typically constituted of 2 components:•

Network Use of System (NUOS) charges, which largely recover the costs of providing
transmission and distribution of electricity through network infrastructure. These include
the costs of jurisdiction-specific schemes recovered across the entire customer base.

•Metering charges, which relate to the distribution network businesses’ installation andmaintenance of type 5 manually read interval meters and type 6 accumulation meters.

4.2 Draft determination
For the draft DMO 4 prices we used indicative network tariffs for 2022–23 submitted by
distributors as part of their 2021–22 annual pricing proposals. We considered these the best
available information at the time.
Our draft determination position was to use approved network tariffs for 2022–23 for the final
DMO 4 price calculations, if available. Otherwise, we would use submitted network prices
included in 2022–23 annual pricing proposals.
We decided in the draft determination to continue to base the DMO network costs on flat rate
tariffs only, and not to extend our analysis to capture costs under TOU tariffs for residential
customers. We considered our previous approach was reasonable given most customers areon flat rate tariffs, while altering our approach would add complexity and reduce transparency
without providing major benefits to stakeholders.
We also said we would not adjust (‘true up’) network costs to reflect differences between
estimated and actual network tariffs in previous periods. This change would also reducetransparency in the annual price calculation.

4.3 Stakeholder submissions
A number of retailers raised issues about the risks they face when we do not use approved
tariffs, which were consistent with those raised in previous years. Origin, Red/Lumo andAlinta considered it was reasonable that the DMO price reflect actual network costs, and thatany resulting underestimation should be addressed through a true up in the subsequentdecision.25

25

Origin, Submission to DMO 4 draft determination, 17 March 2022, p. 7-8; Red Energy and Lumo Energy,
Submission to DMO 4 draft determination, 17 March 2022, p. 4; Alinta, Submission to DMO 4 draft determination,
17 March 2022, p. 1-2.

Default market offer prices 2022–23: Final determination

16

Origin considered that our draft determination to continue to use flat rate network tariffs only
in our calculation of the DMO network component was reasonable. No submissions opposed
this approach.

4.4 Final determination
The AER approved network pricing for the 5 DMO distribution regions between late April andearly May 2022. Consistent with our draft position, we have used the approved flat rate
network tariff prices to calculate the DMO network component in each region.
We note that these have varied from the indicative tariffs that were the basis of the draft
network component. Final networks costs in DMO 4 are:•in the Ausgrid (NSW) region, 0.5% lower to 2.1% higher than our draft estimates,
depending on the customer type.

•in the Endeavour (NSW) region, 6.1% to 8.5% higher•

in the Essential (NSW) region, 5.6% to 5.7% higher•

in the Energex (south-east Queensland) region, 6.4% to 7.3% lower•

in the SAPN (South Australia) region, 1.8% to 2% higher.

Return of over-recovered revenue was a key factor in the decreases in the Ausgrid andEnergex regions, while reduced costs for transmission and the Queensland Government’s
Solar Bonus Scheme contributed to Energex’s larger reductions.
Cost pass-throughs, efficiency incentive payments and higher transmission costs are among
the factors driving higher network costs in the Essential, Endeavour and SAPN regions.
The use of approved tariffs means the DMO 4 prices will reflect retailers’ actual network
costs for 2022–23, addressing retailers’ concerns about the risks of using proposed prices.
While the use of approved prices means true ups are not relevant for DMO 4, our position
remains not to use true ups. As we have set out in previous DMO decision documents, thiswould reduce transparency in the DMO calculation each year.
The revised DMO date of late May (discussed in section 3.3) means we will be able to use
approved prices in the DMO every year other than in reset years.
The network tariffs that will be used to assess network costs are set out in Table 4.1 andnetwork cost estimates resulting from this are included in the DMO charts in Appendix F, as
well as the DMO price calculation model, published alongside the final determination.

Default market offer prices 2022–23: Final determination

17

Table 4.1 Network tariffs (with network codes) to assess the change in network costs
Distribution region

Residential flat rate

Residential controlled load

Small business flat rate

Ausgrid (NSW)Residential Non TOU EA010

EA030 – Controlled load 1
EA040 – Controlled load 2

EA050 Small business
non-TOU

Endeavour (NSW)Residential Energy(anytime) N70

Controlled load 1 N50
Controlled load 2 N54

General Supply N90

Energex (NSW)Residential Flat
NTC8400

Super Economy NTC9000
Economy NTC9100

Business Flat NTC8500

Essential (NSW)Residential Anytime
BLNN2AU

Energy Saver 1 BLNC1AU
Energy Saver 2 BLNC2AU

Small Business Anytime
BLNN1AUSAPN (NSW)Residential Single Rate
RSR (SR)

Residential Single Rate RSR(controlled load)Business Single Rate
BSR

Total network costs for the 2022–23 DMO 4 are set out in Table 4.2, together with the costs
used for the 2021–22 DMO 3 for comparison.
Table 4.2 Total network costs for 2021–22 and 2022–23, $ (incl. GST, nominal)
Distribution region

TariffAusgrid (NSW)

Endeavour (NSW)

Essential (NSW)

Energex (SE QLD)SAPN (SA)2021–222022–23

Changeyear-on-year

Flat rate

557

538

-3.3%

Controlled load

730

707

-3.1%

Small business

2,303

2,259

-1.9%

Flat rate

623

654

5.0%

Controlled load

728

770

5.8%

Small business

2,132

2,239

5.0%

952

980

2.9%

Controlled load

1,069

1,100

2.9%

Small business

3,756

3,839

2.2%

Flat rate

677

627

-7.4%

Controlled load

767

708

-7.6%

Small business

2,303

2,120

-7.9%

819

827

1.0%

Controlled load

1,008

1,016

0.8%

Small business

3,549

3,587

1.1%

Flat rate

Flat rate

Total network costs contain a fixed and variable component and are a function of usage.
Small business comparison is at 20,000kWh

Default market offer prices 2022–23: Final determination18

5 Wholesale energy costs
Wholesale energy costs (WEC), the costs retailers incur to purchase electricity, represent asignificant proportion of customers’ electricity bills – typically 30% to 40% depending on theregion. Therefore, these costs have a major influence on the DMO price.
This section sets out how we have taken into account WEC in setting the DMO 4 price.

5.1 Overview
To calculate WEC, our consultant (ACIL Allen) simulates the costs a retailer incurs whenbuying energy in the NEM for a given year.26 The costs combine hedging and spot market
costs (WEC) and other fees related to participation in the NEM (other energy costs).
We refer to this as a ‘market-based’ forecast approach. Under the approach, WEC are
influenced by energy supply and demand forecasts, an assumed strategy to manage
exposure to the spot market (hedging strategy), and any residual exposure to forecast spot
market prices.
The hedging strategy we seek to model is for a risk-averse retailer that has reduced its
exposure to the possibility of very high spot market prices. We acknowledge that different
retailers will use a range of hedging strategies, depending on their size, generation assets
and market conditions, and that our strategy may not represent any specific retailer.
However, in the absence of information about retailers’ actual strategies, we consider anominal risk-averse retailer is reasonable because, other than in unusual market conditions,most retailers would seek to reduce exposure to risk.
The strategy assumes that hedging occurs from the first trade recorded by ASX Energy for agiven product (contract), with the risk-averse retailer progressively accumulating contracts
over time to develop its final portfolio.
The supply-side forecast, which is broadly aligned with AEMO’s Integrated System Plan,
takes into consideration announced new investments, retirements, fuel costs and simulated
thermal power generation availability.
The demand-side forecast is a function of AEMO’s Electricity Statement of Opportunities
central scenario, an estimated uptake of rooftop solar photovoltaic (PV) systems and weather
simulations in respect to their impact on demand and availability of renewable resources.
ACIL Allen takes the above demand-side and supply-side forecasts to produce a distributionof around 500 simulated spot market price outcomes, representative of volatility in the spot
market. The cost of implementing the hedging strategy in each scenario is then calculated.
The hedging strategy is the same for all scenarios.

26

The AER contracts ACIL Allen to provide consultancy services relating to the wholesale andenvironmental cost elements of the DMO. ACIL Allen produces a companion report discussing its wholesale andenvironmental cost forecasting approach in more detail, that is published alongside the draft and final DMO
determinations.

Default market offer prices 2022–23: Final determination

19

Distribution loss factors (DLF) for each network area and average marginal loss factors(MLF) for transmission losses from the node to major supply points in the distribution
networks are applied to the WEC estimates to incorporate any losses.
Other energy costs include hedging costs, AEMO NEM management fees, Reliability andEmergency Reserve Trader (RERT) costs and ancillary services charges for services tomanage power system safety, security and reliability.
Details of ACIL Allen’s wholesale cost forecasting methodology and resulting wholesale
energy costs forecasts are set out in its Default Market Offer 2022–23 final determination
technical report.27

5.2 Draft determination
Our draft determination was to:•

Retain the previous assumptions in relation to hedge book build and hedging strategy.

•

Adjust the forecast settings to reduce the likelihood of overestimating wholesale costs.
As noted above, ACIL Allen’s methodology simulates around 500 possible spot market
price outcomes and applies the assumed hedging strategy to each of these. The result is
a distribution of possible hedged prices our assumed retailer could face, where prices
around the median represent those that are most likely to eventuate and those at theextreme high and low ends very unlikely to occur.
Therefore, prices above the median (50th percentile) provide a margin for error against
underestimation.
Our draft determination was to adopt the 75th percentile estimate of ACIL Allen’smodelled price outcomes, rather than our previous 95th percentile estimate.
We considered that this balanced the risk of over and underestimating the wholesale
price. While the 95th percentile estimate covered retailers for almost all potential priceoutcomes, the 75th percentile more appropriately balanced the cost to consumers whileproviding a very low risk of underestimating costs to retailers.

•

Include AEMO directions costs in the WEC in South Australia for the first time. These arecosts incurred when AEMO directs generators to operate for system security, which are
passed onto retailers. We considered these are costs a prudent retailer is likely to incur
during the DMO 4 period.

We did not make any changes to our approach in response to feedback from somestakeholders about the South Australian wholesale market or negative prices. Our view wasthat we did not have access to reliable public information on which to base new estimates,
but we noted we were open to considering further information.

27

ACIL Allen, Default Market Offer 2022-23 Wholesale energy and environment cost estimates for DMO 4
Final Determination, May 2022.

Default market offer prices 2022–23: Final determination20

5.3 Stakeholder submissions
Stakeholders held differing views on a number of different components of the wholesale
energy cost component. The following sections group this feedback by issue/component.
Change to the 75th percentile
Retailers and the Australian Energy Council (AEC) indicated in their submissions that they
considered that the change to the 75th percentile was not appropriate given their
expectations of increasing volatility in the wholesale market (both high and low prices) in
2022–23 and in future years, as a result of the energy market transition and expected coal
generation closures.28 Some retailers also stated that the 75th percentile of wholesale market
outcomes is lower than the risk limits prudent retailers have in place and increases aretailer’s spot price risk and the viability of some retailers.29 Other retailer submissions
considered that the wholesale cost component is a significant risk for underforecasting ofcosts and so a return to the 95th percentile should be adopted.
EnergyAustralia stated that the AER had not provided enough evidence to support thechange to the 75th percentile and questioned if this change should be held over until athorough review of the entire WEC component was undertaken.30 It also had concerns that
reducing the percentile of modelled price outcomes may lead to retailer failure.
EnergyAustralia’s submission also discussed the VDO approach of including a volatility
allowance for the cost of holding working capital to meet wholesale costs for the mostextreme scenario.31 While noting the differences in approached for the VDO compared with
the DMO, it considered the volatility allowance still presented a higher risk to retailers
because it only reflected the cost of capital, not a full provision of capital required forhedging.
Wholesale energy cost – methodology approach
Stakeholder submissions made a number of comments on the other aspects of thewholesale energy cost forecast methodology.
Origin requested that the AER and ACIL Allen provide more specific details about themodelling inputs and approach, including details of the proprietary model used by ACIL Allen
to estimate wholesale electricity costs. They also suggested a volatility allowance should be
included if the decision to uphold the move to the 75th percentile remained.32

28

1st Energy, Submission to DMO 4 draft determination, 17 March 2022, p. 1-3; Origin, Submission to
DMO 4 draft determination, 17 March 2022, p. 2; Alinta, Submission to DMO 4 draft determination, 17 March
2022, p. 2-3; ReAmped Energy, Submission to DMO 4 draft determination, 17 March 2022, p. 2; Powershop,
Submission to DMO 4 draft determination, 17 March 2022, p. 3, Red Energy and Lumo Energy, Submission to
DMO 4 draft determination, 17 March 2022, p. 5; Australian Energy Council, Submission to DMO 4 draft
determination, 17 March 2022, p. 3-4; EnergyAustralia, Submission to DMO 4 draft determination, 17 March
2022, p. 9-11; AGL, Submission to DMO 4 draft determination, 17 March 2022, p. 1; Tango Energy, Submission
to DMO 4 draft determination, 17 March 2022, p. 1-2; Simply Energy, Submission to DMO 4 draft determination,
17 March 2022, p 4; Momentum Energy, Submission to DMO 4 draft determination, 17 March 2022, p 2.
29
Alinta, Submission to DMO 4 draft determination, 17 March 2022, p. 2; 1st Energy, Submission to DMO 4
draft determination, 17 March 2022, p. 1.
30EnergyAustralia, Submission to DMO 4 draft determination, 17 March 2022, p. 3.
31
EnergyAustralia, Submission to DMO 4 draft determination, 17 March 2022, p. 10-11.
32
Origin, Submission to DMO 4 draft determination, 17 March 2022, p. 4.

Default market offer prices 2022–23: Final determination

21

EnergyAustralia supported the trade-weighted approach currently used by ACIL Allen, but
considered that the AER should extend the cut-off date to late May for contract prices used in
the WEC modelling. 33 Alinta supported retaining the 24 to 36-month hedge book build
period, which is approximately the length that ACIL Allen used, based on an ‘as trades occur’approach to the book build.34
Powershop drew attention to the potential retail competition effects due to our wholesale
methodology and whether retailers can or will want to attract customers if they are nothedged effectively in a changing wholesale market. Powershop claimed that the DMO
wholesale methodology discourages retailers from growing because acquiring hedges overthe full 36 months leads to retailers inaccurately hedging against their customer load when
prices move up or down in the DMO year. Powershop also reiterated their previous concerns
about how peak demand and spot prices are factored into the wholesale price modelling.35
Other issues raised
AGL expressed concerns that forward cap contract prices in South Australia do not reflectrealistic market costs because of the low liquidity in that market. AGL argued that moving to
the lower percentile for wholesale prices is particularly problematic in South Australia, which
has more variable peak loads.36 AGL provided the AER with some confidential information toconsider on the issue of prices in South Australia. EnergyAustralia also supported AGL’s
submission to the DMO options paper, which requested consideration of alternative sourcesof data inputs such as prices contracted under offtake agreements with generators, since
ASX energy data is illiquid and limited at best. EnergyAustralia did acknowledge difficulties
that its proposed alternative approach creates in terms of transparency, but believed itshould be considered at some point.37
ReAmped Energy said that the increased wholesale price risk would be borne by nonvertically integrated retailers that cannot access their own generation and rely on thewholesale market to support growth in their retail business.38
Retailers supported the inclusion of directions costs in DMO 4 while the SA Department forEnergy and Mining suggested the AER develop an alternative approach to estimating
directions costs in light of the installation of synchronous condensers in South Australia. It
said that costs have declined as a result of AEMO’s approach to system strength
management in the past year and that the previous 12 months’ costs are not expected tocontinue in 2022–23.39 AGL, Simply Energy and Red/Lumo Energy supported the inclusionof AEMO energy direction costs in the draft determination.
AEMO made a submission requesting its latest fee proposals for the 2022–23 financial year
be included in DMO 4. The fees are collected through retailers and generators, and passed
on to retail customers. AEMO requested the increased forward fees for 2022–23 be included

33

EnergyAustralia, Submission to DMO 4 draft determination, 17 March 2022, p. 11.
Alinta, Submission to DMO 4 draft determination, 17 March 2022, p. 3.
35Powershop, Submission to DMO 4 draft determination, 17 March 2022, p. 2-3.
36
AGL, Submission to DMO 4 draft determination, 17 March 2022, p. 1.
37
EnergyAustralia, Submission to DMO 4 draft determination, 17 March 2022, p. 12-13.
38
ReAmped Energy, Submission to DMO 4 draft determination, 17 March 2022, p. 2.
39
Department of Energy and Mining, Submission to DMO 4 draft determination, Energy and TechnicalRegulation Division, South Australian Government, 17 March 2022, p. 3.
34

Default market offer prices 2022–23: Final determination22

in DMO 4 rather than using the previous 12 months, which has been our practice to date.
They noted that the Essential Services Commission Victoria will include the fee estimates inthe Victorian Default Offer for 2022–23.40
Origin raised the issue of how RERT costs are recovered in the DMO. Origin was concernedthat using total Queensland load in the RERT calculation, which includes commercial andindustrial load, may lead to an under-recovery of costs. Origin suggested removing
commercial and industrial load and costs from the RERT calculation would provide a better
cost representation of residential and small business customers.41 1st Energy also asked us
to include RERT costs for the event in Queensland in 2022 in the DMO.42
Queensland Electricity Users Network (QEUN) made a submission raising concern with the
AER using a single consultant. QEUN stated that the AER should consider other options toaccount for the possibility of inaccurate forecasting, which they noted could become
particularly prevalent in a rapidly changing wholesale market with increasing volatility.
Options they suggested for the AER to undertake included producing its own forecasting or
using additional consultants.43

5.4 Wholesale methodology review
In the draft determination we noted that the electricity market is changing rapidly, with trends
such as the increased uptake of rooftop and grid-scale solar changing demand profiles andhaving a significant impact on spot prices.
These changes are also challenging the extent to which standard contracting products
enable retailers to manage risk, particularly during daylight hours but also moving into theevening peak when maximum demand is not affected by solar and prices can be high.
We committed to undertake a peer review of the wholesale forecast modelling to ensure it
remains able to capture these types of changes in wholesale market outcomes.
In response to the draft determination, both the AEC and Powershop provided feedback on
the wholesale methodology review.
The AEC highlighted a review it commissioned from ACIL Allen in October 2019 to review
Frontier Economics’ wholesale forecasting modelling for the Victorian Default Offer (VDO),
which they consider found Frontier Economics underestimated wholesale costs. AEC statedthey support the methodology used by ACIL Allen in the DMO and consider that it moreaccurately captures costs than the model used for the VDO. Powershop also does notsupport Frontier’s approach to wholesale price modelling for the VDO.
Frontier Economics was engaged to undertake the peer review. Our request focused onreviewing the appropriateness of the wholesale forecasting process that is currently
undertaken by ACIL Allen in terms of how it meets the DMO objectives in the current andpotential future wholesale market scenarios. We also requested Frontier provide options on

40
41
42
43

Australian Energy Market Operator, Submission to DMO 4 draft determination, 17 March 2022, p. 1.
Origin, Submission to DMO 4 draft determination, 17 March 2022, p. 5.
1st Energy, Submission to DMO 4 draft determination, 17 March 2022, p. 3.
Queensland Electricity Users Network, Submission to DMO 4 draft determination, 25 February 2022, p.

1.

Default market offer prices 2022–23: Final determination23

alternative approaches that could be used to undertake this process in the future and how
these approaches do or do not meet the DMO objectives.
Frontier’s report reviews the existing forecasting methodology, and several alternative
options, against the DMO objectives. Frontier also included 3 additional criteria (practicality,transparency and price stability) that they consider need to be assessed when reviewing themerits of all approaches. As the report highlights, there are a number of potential options tochange certain aspects of the current methodology, which may result in a more accurate
wholesale cost forecast. Alternatively, a number of other methodologies could be considered
but are limited by access to publicly available data or other practical considerations.
Frontier found44 that the current approach has some potential to overestimate the WEC for
an efficient retailer but is on par with, or better suited than, most alternative approaches inmeeting the DMO objectives.
We still consider that the changes occurring in the wholesale market, in regards to impacts
from solar on demand profiles and risk management products available to retailers, warrant
further review of the wholesale methodology in the longer term. Based on the work Frontier
has done, the AER will look to engage with stakeholders on this review in the second half of2022, with an aim to include stakeholders views in the DMO 5 process.

5.5 Final determination
Having considered stakeholder feedback, and the Frontier review findings, our final
determination position on the forecasting method is unchanged from the draft determination.
Our reasons are set out below.
Move to the 75th percentile
The 75th percentile estimate of modelled costs has been used to calculate the final WEC in
DMO 4. As stated in the draft determination, we consider that several aspects of the DMO
hedging assumptions are inherently cautious and geared towards minimising the likelihood of
underestimating costs.
Findings from Frontier’s review, which supports the decision to move to the 75th percentile,
was that a number of elements within the current methodology can lead to an overestimationof the WEC. These include:•

The approach only estimates the cost of supplying small customer load in each region
on a standalone basis, which means portfolio benefits available to some retailers
supplying a diversity of customers, such as variable loads, are not accounted for.

•

The approach estimates the cost of hedging small customer load only, based on asubset of hedging products actually available to retailers that can be used to manage
their risks. This results in lower cost risk management products, such as Power
Purchase Agreements or load following hedges, not being accounted for within themodelling.

44

See Frontier Economics, Review of retail wholesale energy cost estimation methodology, Final Reportfor the Australian Energy Regulator, 31 March 2022, Chapter 3.

Default market offer prices 2022–23: Final determination24•

A retailer takes a risk-averse approach when hedging their small customer load.

•

The most efficient retailer could expect to achieve costs lower than the 75th percentile
modelled outcome and the 95th percentile allows for an almost worst-case scenarioeach year.

When reviewing these elements together, we consider that this highlights numerous layers ofconservatism built into the methodology. In reality, a retailer is unlikely to only hedge for a
specific part of its load, taking advantage of diversity across customers and customer types
and acquiring appropriate hedging products for their overall position. A retailer is also likely to
use a number of different products (such as power purchase agreements or load following
contracts) not currently considered within the modelling, which would help them better aligntheir hedging strategy with their actual load profile, resulting in lower costs.
We acknowledge that as the wholesale market transitions over the next few years there will
be uncertainty. Retailers noted issues such as thermal closures as particular sources of
uncertainty that contribute to volatility. The contract market factors in this uncertainty,
assisted by requirements such as the 42-month notice of closure, which gives the market
time to price these changes. ACIL Allen’s model accounts for this by incorporating a mix ofcontracts over the 36-month contract book build period.
We analysed the spread between 75th and 95th percentiles to understand the cost to
consumers, or additional revenue recovery for retailers, that would occur if the 95th
percentile was adopted. This analysis showed that the dollar difference was minimal in NSW
and Queensland distribution zones while it was currently larger in South Australia due to abroader range in demand forecasts and dependence on variable renewables. However, thishas not been the case in previous DMOs and the spread of outcomes appears dependent onmarket conditions in any given year.
We have explored EnergyAustralia’s comments on the volatility allowance included in the
VDO. This allowance acknowledges that retailers face a risk of wholesale purchasing costs
above the median modelled outcome used in the VDO and will be holding working capital tomanage that risk.45 The dollar value provided by the difference between the 50th and 75th
percentiles of the DMO is greater than that a VDO style ‘volatility allowance’ would provide if
applied to the DMO. This is because our methodology enables a full provision of capital,
which will always allow greater cost recovery than an allowance for the cost of holding that
capital.
Having considered stakeholder feedback and the available information, our view remains
unchanged from the draft determination – that the 95th percentile estimate provides too greata margin of error against underestimation and is likely to result in a wholesale cost estimatethat is significantly higher than what a typical retailer would incur, other than in the mostextreme circumstances. In our view, a WEC estimate that eliminated risk for retailers bysystemically overstating most retailers’ wholesale costs would not be consistent with the
DMO objectives of protecting consumers. Our view is that the 75th percentile estimate
provides a significant margin of error against underestimating wholesale costs and ensuresthat in most circumstances the wholesale forecasts will continue to overstate what most45

Frontier Economics calculate the volatility adjustment by calculating the difference between the medianwholesale outcome and the 100th percentile outcome, then apply a WACC of 7.5%.

Default market offer prices 2022–23: Final determination25

retailers incur – particularly in light of the other risk-averse assumptions embodied in theforecast methodology. In our view, this estimate appropriately balances the need to enableretailers to recover their costs, while protecting consumers from higher than necessary
prices. We further note that the later cut-off for wholesale market data means that mostcurrent risk assumptions as foreseen by the market are taken into account in the WEC
estimates through updated contract data.
Hedge book build
Our view remains that the current, longer hedge book build period remains appropriate forthe DMO because it reduces price volatility from year to year. This results in moreconstrained DMO price movements, which we consider is appropriate given the purpose of
the DMO to provide a fallback price protection for consumers.
In response to EnergyAustralia’s submission that a later cut-off date should be used, we will
always try to use the most current prices available in time to deliver the final determination.
As a result of the change to the DMO publication date, we have been able to use
approximately 6 weeks of additional market data, which reduces the gap between our data
cut-off date and pricing implementation.
Hedging strategy
We agree with most stakeholders that our current risk-averse settings remain appropriate to
set the hedging strategy when estimating wholesale costs. Our final decision is not to change
the wholesale forecast settings relating to hedging strategy.
AEMO directions
As set out in the draft determination, we will include AEMO directions costs because they are
costs that a prudent retailer would include and aren’t substantially different to other nonenergy costs we include. Directions costs for SAPN have increased from $5.02/MWh in ourdraft determination to $7.03/MWh for the final determination – an increase of $2.01/MWh(40%).
In response to the SA Department for Energy and Mining, we acknowledge that using thepast 12 months of fees may not accurately forecast future costs. However, AEMO’s costings
are transparent, public and are the most accurate data available. Additionally, in AEMO’s
most recent report, full operation of synchronous condensers saw the costs of systemsecurity directions fall from $37 million in Q4 2021 to an estimated $7.5 million in Q1 202246.
This latest figure was captured in this year’s modelling, while the next iteration of the DMO
will capture the full yearly effect of the synchronous condensers going forward. Therefore, we
maintain that using this data is the most reasonable way to capture directions costs.
AEMO fees
We agree with AEMO that the latest fee proposal should be included in this DMO. This is achange from previous determinations, where the previous year’s fees would be used. We
have made this change to ensure the proposed large increase in AEMO fees for the 2022‫–ؘ‬23
financial year is captured.

46 AEMO, Quarterly Energy Dynnamics – Q1 2022, 29 April 2022, p. 4.

Default market offer prices 2022–23: Final determination

26

South Australian contract prices
We acknowledge that using the relatively illiquid ASX futures markets will not necessarilyreflect how some retailers are choosing to contract energy for the South Australian market.
However, we also consider that it is the most transparent data source currently available.
We have further considered some retailers’ suggestions that a higher forecast risk margin
was needed in South Australia to mitigate the risks associated with that market.
We have tested both the spread between 75th and 95th percentiles and the level of liquidity
in the South Australian market compared with other years and regions. While the data showsthat base contract trade volumes are lower than the previous year, it is not the first time tradevolumes have been this low (2018 levels were similar). Regular trading has still occurred forSouth Australian base futures contracts and the variability of prices for these contracts islower than that for NSW and Queensland contracts for 2022–23. While the spread ofmodelled outcomes is larger for South Australia in DMO 4, historically there have been
similar disparities in other regions.
On balance, our view remains that the 75th percentile estimate of wholesale cost forecasts
appropriately balances wholesale risks for retailers with protecting customers. We consider
the price difference between the 75th and 95th percentile estimates is not sufficiently largethat a DMO price based on the higher estimate would make a material difference to retailers’cost recovery or profit for the roughly 75,000 South Australians on standing offers.
We are open to further discussions on this issue as part of the larger review of the wholesale
methodology, including on mechanisms that would give stakeholders confidence in our useof any confidential data.
RERT costs
Consistent with previous determinations, RERT costs, including the February 2022 event in
Queensland as estimated by AEMO,47 have been included in DMO 4. In regard to Origin’s
submission, we have not changed the way in which RERT costs are recovered in the DMO.
We consider that retailers are free to recover RERT costs from their customer base as they
see appropriate. There would be an additional layer of complexity and decreasedtransparency if we made adjustments to the load and costs on which the calculation isbased.
Final DMO 4 wholesale costs
WEC are forecast to increase across all DMO regions and consumer types following declines
in the past 2 years.
Changes from the draft determination see WEC up around $11–$12/MWh in NSW andQueensland, as a result of large increases in futures contract prices. South Australian costs
are slightly higher (WEC increased by around $3.5/MWh).
Reasons for the increase from the draft are a result of base future and cap contract prices
having increased in all 3 regions. ACIL Allen has identified higher fuel costs as a key factor in

47 https://aemo.com.au/-/media/files/electricity/nem/emergency_management/rert/2022/rert-activation-estimates-

report-for-1-feb-2022.pdf?la=enDefault market offer prices 2022–23: Final determination27

this along with the slowing of large-scale renewables coming online and a reduction inthermal generation (for instance, the anticipated closure of Liddell and Torrens Island A andoutage of Callide C4 now extended to April 2023). Figure 5.1 shows NSW base futures
prices relevant to DMO 3. Lines represent prices the market was expecting to pay to hedge
costs for each of the quarters in 2022–23. They were increasing throughout the second halfof 2021 but experienced significant increases in 2022. Similar increases were also seen in
Queensland and South Australia.
We have recently become aware that the volume of base future contracts resulting from theexercising of options may be overcounted in published ASX data. We are currently working
with the ASX to investigate this. After we became aware of the issue we undertook an initial
review to understand the impacts this may have had on the wholesale modelling forecast. As
a result of options trades occurring throughout the book build process, which occurred whencontract prices were lower but also in more recent high prices, we found this would be
unlikely to cause a material change in wholesale costs and are not making any changes
based on this information at this point in time. We will work with the ASX to confirm treatmentof trades in the data and resolve any issues ahead of DMO 5.
The net system load profile also has an increasingly peaky shape (extremes of high and low
demand), which has become relatively more expensive to hedge. This has been exacerbatedby the continued uptake of rooftop PV, which reduces demand during daylight hours. During
daylight, spot prices are often less than base contract prices while the cap contracts required
to cover high demand peak periods are much more expensive.
In Queensland, increased FCAS costs have also contributed to price rises.
The impact of direction costs on the DMO 4 price is $7.03/MWh in South Australia andtranslates to price elements of approximately:•$28.12 per year for residential customers without controlled load•$42.18 per year for residential customers with controlled load•

$70.30 per year for small business customers.

Default market offer prices 2022–23: Final determination

28

Figure 5.1 NSW base futures contract prices
200
Draft determiantion cut off date
180
160
140

$/MWh

120
100
80
60
40
20
0

Base - Q3 2022

Base - Q4 2022

Base - Q1 2023

Base - Q2 2023

Wholesale costs for the 2022–23 DMO 4 are set out in Table 5.1, together with the costs
used for the 2021–22 DMO 3 for comparison.
Table 5.1 Wholesale costs for 2021–22 and 2022–23, $/MWh (excl. GST, nominal)
Distribution region

Tariff2021–222022–23

Change yearon-year

Ausgrid (NSW)

Flat rate

87.94

122.23

39%

CL1*

60.44

88.62

47%

CL2

57.47

87.26

52%

Flat rate

88.27

124.25

41%

CL1

83.29

114.50

37%

CL2

83.29

114.5037%

Flat rate

80.34

115.97

44%

CL1

67.30

87.48

30%

CL2

67.30

87.48

30%

Flat rate

74.03

110.53

49%

CL1

58.84

86.65

47%

CL2

61.18

93.47

53%

Flat rate

119.47134.53

13%

CL1

72.82

73.52

1%

Endeavour (NSW)

Essential (NSW)

Energex (SE QLD)SAPN (SA)Default market offer prices 2022–23: Final determination

29

6 Environmental costs
6.1 Overview
Environmental schemes at both national and state levels require retailers to procure
electricity supply from renewable sources and improve customer energy efficiency. The costsof these schemes are incurred by retailers and are included as a cost component of the retailprice. Environmental costs broadly fall into two main categories – national schemes or the
Renewable Energy Target (RET), and jurisdictional green schemes.
The majority of environmental costs relate to complying with the RET. Retailers have an
obligation to purchase renewable energy certificates and surrender them to the Clean Energy
Regulator in proportion to the overall amount of energy consumed by their customers.
The RET is made up of the Large-scale Renewable Energy Target (LRET) and the Smallscale Renewable Energy Scheme (SRES). LRET costs are incurred by retailers to acquire
the necessary amount of LGCs.

6.2 Draft determination
In the draft determination we indicated a preference to continue using our market-based
approach from DMO 2 and DMO 3 to forecast environmental costs. The approach provides
consistency between environmental and wholesale cost forecasting.
We made some minor changes to our approach in response to stakeholder feedback. In
particular, we included costs relating to:•South Australia’s Retailer Energy Productivity Scheme (REPS), which will replace theRetailer Energy Efficiency Scheme and has different activity specifications•

NSW’s Demand Peak Reduction Scheme to promote demand management activities.

We flagged our consultant’s intention to use the binding small-scale technology percentage(STP), rather than using the Clean Energy Regulator’s non-binding estimate.48

6.3 Stakeholder submissions
Submissions that commented on environmental cost forecasting generally supported
retaining the existing methodology.
Origin and AGL agreed with our proposed approach to estimating the non-binding STP,
noting that this approach was more accurate than using the Clean Energy Regulator’s nonbinding figure and was consistent with our approach from previous years.49

48

For information about the STP see http://www.cleanenergyregulator.gov.au/RET/Scheme-participantsand-industry/the-small-scale-technology-percentage
49
AGL, Submission to DMO 4 draft determination, 17 March 2022, p. 1; Origin, Submission to DMO 4 draft
determination, 17 March 2022, p. 5.

Default market offer prices 2022–23: Final determination30

6.4 Final determination
Having considered stakeholder submissions, we propose to retain our current approach toenvironmental cost forecasting with updates for new and amended schemes, as set out inthe draft determination.
Environmental cost inputs
The environmental cost inputs for the 2022–23 period are given in Table 6.1, together with
inputs used for the 2021–22 period for comparison.
Table 6.1 Environmental costs for 2021–22 and 2022–23, $/MWh (excl. GST, nominal)
Distribution region

Tariff2021–222022–23

Change yearon-year

Ausgrid (NSW)

Flat rate

19.17

20.68

8%

CL1*

19.22

20.74

8%

CL2

19.22

20.74

8%

Flat rate

19.31

20.82

8%

CL1

19.31

20.82

8%

CL2

19.31

20.82

8%

Flat rate

19.04

20.45

7%

CL1

19.04

20.45

7%

CL2

19.04

20.45

7%

Flat rate

16.75

17.10

2%

CL1

16.75

17.10

2%

CL2

16.75

17.10

2%

Flat rate

20.39

20.38

0%

CL1

20.39

20.38

0%

Endeavour (NSW)

Essential (NSW)

Energex (SE QLD)SAPN (SA)Default market offer prices 2022–23: Final determination

31

7 Retail costs and allowances
7.1 Overview
Retailers incur a number of costs when selling electricity. These costs include:•

costs to serve – these costs include billing, call centres and hardship programs•

costs to acquire and retain customers – these costs include advertising campaigns
and informing new customers of their options, rights and obligations•

advanced meter costs – retailers are responsible for managing the installation andongoing costs of advanced meters•

bad and doubtful debt – retailers may set aside revenue to cover instances where
customers cannot repay their electricity debt•

depreciation and amortisation – retailers may from time to time make up-front
purchases and investments, such as software and IT system upgrades, which are
depreciated over time.

7.2 Overall approach to retail costs and allowances
7.2.1

Draft determination

Our draft determination position was to adopt a cost build-up approach for retail costs,
including estimating retailers’ operating costs, and a retail allowance encompassing retailmargin and an additional amount to meet the DMO objectives.
We considered that a cost build-up approach, incorporating a consistent retail allowanceabove costs regardless of region, best achieved the policy objectives. Reasons for this view
included:•

It provides greater transparency on the cost drivers in a market in which the pace ofchange continues to accelerate and helps ensure costs are reasonable.

•

Continual indexing of the retail ‘residual’ under the previous methodology means theprice would continue to reflect market conditions in 2018, when we set the first DMO
price. As time progresses we are less confident that this approach would continue tomeet the DMO objectives. In particular, we noted:−−•

very low retail margins, such as little over 1% for some residential customers inSouth Australia, are inconsistent with the objectives to allow retailers to cover theirefficient costs and maintain incentives for competition
higher margins for other customers (for example, 13% for some residential
customers and over 28% for some small business customers in NSW) could beinconsistent with the objective to protect customers from unreasonable standing
offer prices.

The new methodology addresses this variance by introducing a transition to 10% and
15% retail margins for residential and small businesses by DMO 6. This provides
transparency and ensures that, going forward, the policy objectives are met through aconsistent allowance for customers regardless of the region in which they are located.

Default market offer prices 2022–23: Final determination

32

7.2.2

Stakeholder submissions

Views on our proposed move to a cost build-up approach for the retail cost and retail margincomponent of the DMO varied between retailers and consumer representatives.
Retailers did not support the change, citing a range of reasons including:•

given the AER has previously stated the DMO index approach was meeting the policy
objectives, we have not provided sufficient evidence to demonstrate a need for change50•

the adoption of a cost build-up approach brings the DMO closer to price regulation
based on efficient costs, which is not consistent with the DMO policy objectives51•

maintaining the residual indexation approach would provide consistency and regulatory
certainty.52

The SA Department for Energy and Mining also preferred our previous price setting
approach, noting concerns about the increase in retail allowances for South Australianresidential customers.
In contrast, the two consumer representatives that made submissions, PIAC and ECA,
considered that separately identifying retail costs and retail allowance would result in positive
outcomes for consumers because it would promote transparency in pricing determinations
and address information asymmetry. They considered the approach would also allow for
more objective analysis and discussion of the separate components within the DMO and how
these components align with the DMO objectives.
7.2.3

Our consideration of stakeholder submissions

Our view remains that issues highlighted in the draft determination provide a strong case tochange approaches. A cost build-up approach, incorporating a consistent retail allowanceabove costs regardless of region, addresses the regional variation in retail margins. It alsoenhances transparency by identifying separate retail cost and allowance components andensures that actual changes in retail costs will be recovered in future DMO prices.
In relation to concerns that the new approach is closer to price regulation based on efficient
costs, our primary consideration is that the DMO price achieves its own policy objectives.
These have not changed under the recent review of the Regulations, and DISER
consultation documents have emphasised the role of the DMO to offer fallback protection.53
As discussed in chapter 2, we consider that the DMO 4 price appropriately balances theseobjectives and that the retail allowances we have set are well above the level set by50

1st Energy, Submission to DMO 4 draft determination, 17 March 2022, p. 1;Australian Energy Council,
Submission to DMO 4 draft determination, 17 March 2022, p. 1; Momentum Energy, Submission to DMO 4 draft
determination, 17 March 2022, p. 1; Origin, Submission to DMO 4 draft determination, 17 March 2022, p. 5-6;
Simply Energy, Submission to DMO 4 draft determination, 17 March 2022, p. 1-2; Tango Energy, Submission to
DMO 4 draft determination, 17 March 2022, p. 1.
51
1st Energy, Submission to DMO 4 draft determination, 17 March 2022, p. 1; Alinta, Submission to DMO 4
draft determination, 17 March 2022, p. 1; Powershop, Submission to DMO 4 draft determination, 17 March 2022,
p. 4; Red Energy and Lumo Energy, Submission to DMO 4 draft determination, 17 March 2022, p. 1.
52
Simply Energy, Submission to DMO 4 draft determination, 17 March 2022, p. 1-2
53
Department of Industry, Science, Energy and Resources, Competition and Consumer (Industry Code –Electricity Retail) Regulations 2019 Post-Implementation Review, September 2021, p.5 – 6; Department ofIndustry, Science, Energy and Resources, Post-implementation review of Competition and Consumer (Industry
Code – Electricity Retail) Regulations 2019 Directions consultation Paper, January 2022 p.6,8.

Default market offer prices 2022–23: Final determination33

jurisdictional regulators seeking to set an efficient margin. This is appropriate for the DMO,
which is not intended to set an efficient price but instead must balance objectives ofprotecting customers, enabling retailers to recover costs and incentivising customers toengage in the market.
We acknowledge that regulatory certainty and consistency is important. Our change inapproach uses independent and publicly available retail cost information that provides
greater certainty and transparency for stakeholders than the step change framework used in
DMO 2 and 3. Additionally, we have been clear that we will use the same information
sources in future determinations.

7.3 Retail costs
7.3.1

Draft determination

Our draft determination used retail operating cost data from the ACCC Inquiry into the
National Electricity Market reports as our base estimate of retail costs. We considered that
ACCC data is transparent and a reliable estimation of retailer costs. Compared withalternative sources, it is:•

publicly available on a yearly basis•

comprehensive, covering retailers that sell to around 90% of small customers in DMO
regions•

obtained under compulsory powers, with serious consequences for misleading the
ACCC.

Because the ACCC does not collect information on some types of costs, we made an
additional allowance for:•advanced meters – we calculated a weighted per-customer price based on the
proportion of advanced meter customers in each region and included this in the retail
operating cost component54•

bad and doubtful debt – we calculated a weighted per-customer cost based on the
3 publicly listed retailers that reported provisions for bad and doubtful debt expenses intheir most recent annual reports covering the 2020–21 year.

Unlike costs for advanced meters and bad and doubtful debt, we did not make any
adjustment to retail costs to account for the costs retailers face for amortisation anddepreciation, which are not captured in the ACCC data. This is because:•

DMO 1 prices were set at the mid-point of the median market and standing offer andallowed recovery of retailer costs including depreciation and amortisation. This was
carried through the indexation of the residual component for DMO 2 and 3.

•

In DMO 4 we have set target retail allowances of 10 and 15%. These are comparable
levels to the overall retail allowances available in previous DMOs.

54

See Appendix D.

Default market offer prices 2022–23: Final determination34

•

Amortisation and depreciation costs are accounted for within the retail allowance asthese categories of expenses were not included in the group of costs deducted from theprevious DMO prices to calculate implicit retail allowances.

This approach makes our retail allowance comparable to an EBITDA measure of retailmargin, which we noted is consistent with that adopted by state economic regulators ESCV,OTTER and ICRC in their electricity pricing decisions and that the total DMO retail allowance
would allow retailers to recover depreciation and amortisation expenses. However, the retailallowance is higher than the EBITDA margins set by state economic regulators in order toreflect the additional DMO policy objectives.
7.3.2

Stakeholder submissions

Retailers raised a number of concerns with our proposed approach for retail operating costs.
Retailers suggested some options to deal with the perceived risks of using the ACCC data,
including:•applying a contingency or uncertainty allowance, either to the retail cost component or
through an increase to the retail allowance55•

deferring the introduction of the cost build-up approach for a year and working withretailers to develop data templates for DMO use.56

However, ECA considered the ACCC data was an accurate and robust basis for estimating
operating costs.57
Depreciation and regulatory costs
Retailers argued that the ACCC information requests and reported data were designed forthe purpose of reporting, not price regulation. As a result, the data did not reflect some key
retailer costs, including depreciation.
Stakeholders noted depreciation costs can be significant. Retailers may invest in IT systems
to meet new regulatory requirements such as Consumer Data Right, 5-minute settlement or
Better Bills guidelines. These investments could be expensed as depreciation costs overtime and would not be captured within the ACCC’s cost reporting template.58 They argued
that the treatment of depreciation is complex and suggested we defer implementation of thecost build-up approach until we had undertaken further investigation and consultation.59
AGL noted its depreciation costs were large due to significant investment in IT systems for its
retail business. It highlighted information from its public financial reports indicating

55

Alinta, Submission to DMO 4 draft determination, 17 March 2022, p. 3; Simply Energy, Submission to
DMO 4 draft determination, 17 March 2022, p. 3.
56
Red Energy and Lumo Energy, Submission to DMO 4 draft determination, 17 March 2022, p. 3.
57
ECA, Submission to DMO 4 draft determination, p. 1.
58
Australian Energy Council, Submission to DMO 4 draft determination, 17 March 2022, p. 2; AGL,
Submission to DMO 4 draft determination, 17 March 2022, p. 2; EnergyAustralia, Submission to DMO 4 draft
determination, 17 March 2022, p. 4-6; Momentum Energy, Submission to DMO 4 draft determination, 17 March
2022, p. 2; Red Energy and Lumo Energy, Submission to DMO 4 draft determination, 17 March 2022, p. 2-3.
59
EnergyAustralia, Submission to DMO 4 draft determination, 17 March 2022, p. 7.

Default market offer prices 2022–23: Final determination

35

depreciation costs of around $134 million in 2020–21 for its retail business (encompassing
gas customers, small business and residential).60
Tier 2 retailer costs
Several retailers noted the ACCC data was a weighted average of retail costs reported by
the 15 largest retailers and did not reflect the generally higher costs to serve faced by smaller
retailers. They considered this could affect the viability of smaller retailers and was notconsistent with the DMO objectives to have incentives for competition.61
Lagged cost recovery adjustment
Several retailers noted that the ACCC retailer costs are backwards looking and will not reflect
all the costs that retailers are likely to face in the DMO 4 period.62 They recommended
including an adjustment to take into account the 2-year lag in cost recovery.63
Precision of ACCC cost allocation
Retailers argued there is a false precision to the ACCC data. Retailers have encountereddifficulties allocating costs among different NEM regions and customer types as required by
the ACCC. There is a risk that retailers will have different interpretations of the line items
within the ACCC’s information request.
Bad and doubtful debt
While some retailers welcomed our consideration of bad and doubtful debt as a retail cost,some considered our estimates were well below what retailers would face in 2022–23. Thiswas due to factors such as the ongoing impact of the COVID-19 pandemic and restrictions
on retailers’ debt recovery activities under the AER’s Statement of Expectations.64
Customer acquisition and retention costs
PIAC argued that we should not include the ACCC’s subset of retailer costs known ascustomer acquisition and retention costs (CARC) because customers on the DMO, unlike
customers engaged in the competitive market, do not require acquiring or retaining by theretailer. PIAC suggest that CARC could be recovered solely through market offers orindirectly through the ‘reinvestment’ of retail margin for the purpose of business growth.

60

AGL reported 4.208m customers and $134m depreciation expenses attributable to Customer Markets in
its 2020-21 Annual Report 2020-21, p. 17, 36. This averages to $32/customer or $35/customer including GST.
61
Simply Energy, Submission to DMO 4 draft determination, 17 March 2022, p. 2.; Momentum Energy,
Submission to DMO 4 draft determination, 17 March 2022, p. 2; 1st Energy, Submission to DMO 4 draft
determination, 17 March 2022, p. 1; Origin, Submission to DMO 4 draft determination, 17 March 2022, p. 6;
Alinta, Submission to DMO 4 draft determination, 17 March 2022, p. 3; Red Energy and Lumo Energy,
Submission to DMO 4 draft determination, 17 March 2022, p. 3.
62Australian Energy Council, Submission to DMO 4 draft determination, 17 March 2022, p. 2; Powershop,
Submission to DMO 4 draft determination, 17 March 2022, p. 2; Red Energy and Lumo Energy, Submission to
DMO 4 draft determination, 17 March 2022, p. 3.
63
Australian Energy Council, Submission to DMO 4 draft determination, 17 March 2022, p. 2; Alinta,
Submission to DMO 4 draft determination, 17 March 2022, p. 3; EnergyAustralia, Submission to DMO 4 draft
determination, 17 March 2022, p. 8.
64
Alinta, Submission to DMO 4 draft determination, 17 March 2022, p. 3.

Default market offer prices 2022–23: Final determination

36

Advanced meter costs
Retailers and Vector, an accredited metering provider, supported our inclusion of meteringcosts.65 In contrast, PIAC did not support any adjustment for metering costs in DMO 4. It
considered there was not sufficient information about how retailers recovered these costs
and said we should wait until the AEMC completes its review of metering.66
EnergyAustralia highlighted that our advanced meter cost calculation did not take into
account retailers’ residual liability for the capital costs of accumulation meters when these
are removed before their ‘end of life’, such as in the case of customer-requested replacement
or solar installation.67
7.3.3

Final determination

Depreciation
We do not consider that a separate allowance for depreciation under our cost build-up
methodology is required to meet the DMO objectives. Our approach sets a retail allowanceon top of costs incurred by the retailer. Depreciation is not added as a retail cost and it isinstead assumed that retailers will recover it out of the allowance. Our approach iscomparable to the approaches adopted by jurisdictional regulators, such as the ESCV, ICRC
and OTTER, which set retail margins on the expectation that retailers will recoverdepreciation costs from this component of the regulated price (in accounting terms, they set
an EBITDA margin).68
The DMO 1 prices were set at the midpoint of the median market and median standing offersin October 2018, and placed above typical market offers.69 The residual component, which
was the amount in the DMO price left after wholesale, environmental and network costs,
captured all relevant retail costs that a retailer would recover, including bad and doubtful
debt, depreciation and margin.
In setting retail allowances in DMO 4 under a cost build-up approach, we estimated the retailallowance as a percentage of the DMO 1 and DMO 3 prices. We did this by subtracting
corresponding ACCC retail and other costs, advanced meter costs and bad and doubtful
debts from the DMO 1 and DMO 3 residuals, leaving retailer earnings, interest costs, tax
liabilities and depreciation. Therefore, these were equivalent to EBITDA retail margins. As
discussed in our draft determination,70 the target retail allowances of 10% and 15% provide
retail allowances that are in aggregate equivalent to the amounts in DMO 1 and 3,
redistributed across DMO regions and customer types so it is more equitable. We consider
these retail allowances allow recovery of depreciation expenses.

65

Alinta, Submission to DMO 4 draft determination, 17 March 2022, p. 3; EnergyAustralia, Submission to
DMO 4 draft determination, 17 March 2022, p. 7; Origin, Submission to DMO 4 draft determination, 17 March
2022, p. 7; Powershop, Submission to DMO 4 draft determination, 17 March 2022, p. 3; Momentum Energy,
Submission to DMO 4 draft determination, 17 March 2022, p 3; Simply Energy, Submission to DMO 4 draft
determination, 17 March 2022, p 3-4.
66
Public Interest Advocacy Centre, Submission to DMO 4 draft determination, 17 March 2022, p. 1-2.
67
EnergyAustralia, Submission to DMO 4 draft determination, 17 March 2022, p. 7.
68
Earnings before Interest, Taxes, Depreciation and Amortisation.
69
AER, Final Determination Default Market Offer Prices 2019-20, April 2019, p. 60-62.
70
AER, Default Market Offer Draft Determination 2022-23, February 2022, p. 45.

Default market offer prices 2022–23: Final determination37

We have tested the impact of depreciation costs on the retail allowance in section 7.5. This
analysis shows that retailers will continue to make a reasonable profit after depreciation istaken into account.
Regulatory costs
We have not made any change to our draft position on retail costs to account for retail
operating costs for regulatory changes. We have confirmed that the ACCC information
request template categories71 are intended to capture retailer operational expenditure tomeet regulatory requirements. For example, the ACCC’s guidance to retailers highlights that:•

The ‘billing’ line item under ’costs to serve’ should include costs incurred by a company
to prepare and send invoices to customers72 and could include future operational costs
for the upcoming Better Bills regulatory requirements.

•

The ‘customer service and IT’ line item under ‘costs to serve’ should include costs
associated with maintaining the company’s information technology systems73 and could
include future operational costs for the upcoming consumer data right regulatory
requirements.

•

The ‘other costs to serve’ should capture any regulatory costs that do not fall into theabove categories.

While we acknowledge there will be a delay for retailers to recover these costs, retailers canhave confidence that these will be recovered in a future DMO determination.
Tier 2 retailer costs
The ACCC has observed that Tier 2 retailers have higher operating costs than Tier 1 retailers
and the overall average ($57 higher than overall average retailer costs).74
This is likely due to achieved economies of scale for the larger retailers. Tier 1 retailers may
make more up-front capital investments in IT infrastructure, which are expensed as
depreciation and not captured in ACCC retail costs. In contrast, smaller retailers may have agreater reliance on contracting out to service providers, which would appear as retailer
operating costs.
As with the issue of depreciation expenses, we have conducted further analysis in
section 7.5 to test what impact a $57 increase in retail costs would have on the available
retail allowance. This shows that retailers with this level of costs could still receive anallowance similar to or exceeding the margins allowed by other regulators, particularly once
the transitional allowance pathway is complete. Therefore, we are satisfied that the DMO
objectives will be met for a retailer with operating costs that are higher than average.
We further note that:‘costs to serve’, ‘costs to acquire and retain’ and ‘other retailer costs.
ACCC, Inquiry into the National Electricity Market November 2021 report, Appendix C, p. 50.
73
Appendix C ACCC November 2021 report, p. 51-52.
74
ACCC, Inquiry into the National Electricity Market November 2021 report, Appendix E, Tables E8.1B,
E8.7A and E8.10A.
71
72

Default market offer prices 2022–23: Final determination

38

•

Tier 1 retailers have 90% of standing offer customers75 and are significantly more
impacted by the DMO in its role as a price cap for these customers than Tier 2 retailers.

•

The retail operating costs included in the DMO are similar to or higher than that allowedby other regulators. Our allowance for retail costs (excluding advanced meters) of $175
to $177 for residential and $197 to 254 for small business customers are comparablewith that set by ESCV ($206). They are higher than those allowed by ICRC ($128) and
OTTER ($156).

•

Tier 2 retailers have mostly market offer customers, who are not subject to the DMO
price cap. In DMO regions, 96% of residential and 90% of small business Tier 2
customers are on market offers.76 These retailers will be predominately affected by the
DMO in its capacity as a reference price for currently advertised market offers but, giventhat smaller retailers compete on aggressively priced market offers that are often lower
than the Tier 1 retailers, their market offers would still be the lowest relative to the
DMO 4 reference price.

Lagged cost recovery adjustment
A lagged cost recovery adjustment could be warranted under a cost build-up approach
establishing an efficient price. This would work by adjusting future DMO prices to account forcapital holding costs arising from any difference between actual retail costs and the amountretailers were allowed to recover in previous DMOs. However, we do not consider a lagged
cost recovery adjustment is required to meet the DMO objectives given our 10% and 15%
retail allowances. It would also create additional unnecessary complexities in determining
DMO prices because it would require a back-calculation of costs. We also note that this
could result in an adjustment in costs in either direction. If the actual costs in DMO 4 werelower than what we allowed retailers to recover based on ACCC 2020–21 retail operating
costs, then a lagged cost recovery adjustment should be negative in a future DMO to reflect
the up-front over-recovery of retail costs during the DMO 4 period.
Precision of ACCC cost allocation
The ACCC November 2021 report noted that some retailers did not record certain categories
of costs in a way that aligned with the data definitions requested by the ACCC. For example,
some retailers did not record costs separately for residential and small business customers
or on a region-by-region basis.
In such cases, the ACCC asked retailers to apply an allocation methodology when reporting
data to the ACCC. Where this was not done by the retailer, the ACCC applied its own
allocation methodology.77
To further inform our views on these issues, we sought further information from the ACCC on
its approach to allocating costs where it needed to.

75
76
77

AER Retail Performance Reporting data, Q3 2021-22.
AER Retail Performance Reporting data, Q3 2021-22.
ACCC, Inquiry into the National Electricity Market November 2021 report, Appendix B p. 47.

Default market offer prices 2022–23: Final determination39

It confirmed that retailers that provide cost information to the ACCC typically claimed
confidentiality over their responses, including the allocation approaches they used, andconsequently the ACCC is not in a position to discuss specific approaches.
However, it has confirmed that its overarching approach recognises that retailers have very
different allocation methodologies due to different data systems and business structures,
which means that in practice its analysis relies on a range of allocation methodologies.
Where necessary, it engages with retailers to understand and improve allocation
methodologies, and its general practice is to discuss any material allocation issues with therelevant retailers.78
Our view is that the ACCC’s allocation approach is reasonable, robust and provides retailers
with the opportunity to ensure that the costs they report reflect the intention and operation ofindividual retailers. We have no reason to think that costs reported on this basis would beless accurate than costs reported under a one-size-fits-all approach.
More generally, we consider the ACCC’s measures to ensure the accuracy and quality ofretailer information are robust. These include:•

including standardised definitions for each cost stack quantity and data field that retailers
are required to provide in their response to the ACCC information request79•

undertaking a quality assurance process that includes examining the returned data forinconsistencies, omissions and potential errors and crosschecking it against other data
sources, such as public data from the AER. It queries retailers on any large or
unexpected movements in their data relative to previous years.80

Further, the additional information provided by the ACCC confirms our view that thedevelopment of DMO-specific information templates, as suggested by some retailers, isunlikely to solve cost allocation issues, would be complex and challenging, and would
impose significant administrative burden on the retailers, adding cost pressure to retail bills.
Bad and doubtful debt
Our DMO methodology includes an allowance for bad and doubtful debts by taking theweighted average bad and doubtful debts from the 3 publicly listed retailers (AGL, Origin and
Red-Lumo) that report these costs. We expect that in the event bad and doubtful debts
increase during the DMO 4 period, they will be reported by the publicly listed retailers in their2022–23 annual reports and would be reflected in the DMO 6 price under our DMO
methodology.
Customer acquisition and retention costs
The Regulations require us to have regard to all costs including CARC.81 Therefore, we will
use the ACCC’s retail and other operating costs (which includes CARC) in our DMO prices.

78
79
80
81

Correspondence with ACCC staff, April 2022.
ACCC, Inquiry into the National Electricity Market November 2021 report, Appendix C p. 50-53.
ACCC, Inquiry into the National Electricity Market November 2021 report, Appendix B p.48.
Regulations, s. 16(iv).

Default market offer prices 2022–23: Final determination

40

Advanced meter costs
We agree with EnergyAustralia’s submission that residual capital meter costs are relevantcosts to take into account when calculating advanced metering allowance.
To calculate these costs, we have used the summed proportion of all advanced meters
installed before the technical end of life of the replaced accumulation meter. These include
advanced meters installed when a customer installs solar or moves to a cost-reflective retailoffer, advanced meters installed due to faulty accumulation meters, and advanced meters
installed under a new meter deployment reported by retailers in the AER retail performance
reports. This is approximately 80% nationally.82
This adjustment has a $0.30 to $4.42 impact on the metering cost component, comparedwith the draft determination, depending on customer type and region.
Calculations for each region are included in Appendix D.
We note PIAC’s concerns that there are some uncertainties as to how retailers recovered
these costs. Retailers responding to our information request provided average annual
ongoing costs of smart meters. For some retailers their average annual ongoing costs
included recovery of installation costs because these were part of the contract with a thirdparty metering coordinator, but for other retailers these costs were excluded from thecalculations. Some retailers noted that they do not pass on metering installation costs
through one-off fees to customers. We have reviewed the website of each retailer withmarket offers on the Energy Made Easy website and found that AGL and EnergyAustralia do
not charge up-front fees for smart meter installation,83 but Origin may charge up to $150 if
additional work is required.84 Practices vary by retailer – a number of retailers explicitly
stating they do not charge up-front fees for installing meters,85 others charge an up-front
administration or metering fee ranging from $49.50 to $149,86 and other retailers do not
explicitly state one way or the other on their website.87
Due to the uncertainty in how all retailers would recover costs incurred when installing
advanced meters, we acknowledge there is a risk that our estimate of our advanced metercosts may include a portion of ongoing advanced meter costs that some retailers may
recover through one-off fees.

82

AER Retail Performance Reporting data, Q3 2021-22, schedule 2.
https://www.energyaustralia.com.au/home/help-and-support/faqs/powerofchoice, accessed 14 April
2022; https://www.agl.com.au/help-support/energy/meters-and-reads/meters/digital-meters, accessed 14 April
2022.
84
Origin Energy, Meter Installation, alteration and abolishment fees, October 2021, p. 3-5, Appendix A.
https://www.originenergy.com.au/wp-content/uploads/fees_tables_all_states_Oct2021.pdf, accessed 14 April
2022.
85
Amber, CovaU, Diamond Energy, Mojo, Ovo Energy, Pooled Energy, Powershop, Qenergy, Simply
Energy and Social Energy.
86
Energy Locals, https://supportcentre.energylocals.com.au/hc/en-au/articles/4410322486297-New-meterrequest, accessed 14 April 2022; Kogan, https://www.koganenergy.com.au/smart-meter-request/, accessed 14
April 2022; Powerclub, https://powerclub.com.au/fees-and-charges/smart-meter, accessed 14 April 2022; Radian
Energy, https://radian.com.au/policies, accessed 14 April 2022.
87
Alinta, Discover Energy, Bright Spark, Dodo, Electricity in a box, Elysian, Enova, Future X, GEE Energy,
Globird, Glow Power, Momentum, Nectr, People Energy, ReAmped, Red, Smart, Tango.
83

Default market offer prices 2022–23: Final determination

41

However, we are satisfied that advanced meters do incur significant costs for retailers, which
are not captured in the ACCC retailer operating costs, and that there is a greater risk of the
DMO 4 price failing to meet the DMO objectives if our estimate of these costs are notincluded in the DMO 4 price. Because these costs exist and will continue to be incurred in
DMO 4 and future DMOs, we do not consider it warranted to delay reflecting these costs inthe DMO price until after the AEMC finishes its smart meter review.

7.4 DMO retail allowance
7.4.1

Draft determination

Our draft determination position was that DMO prices should include the same retailallowance within each customer type, regardless of region. We noted:•

this approach provides a consistent balance of the DMO objectives and more equitableoutcomes•setting the retail allowance as a proportion of the overall bill in each region, rather than afixed dollar figure, should ensure it moves in step with, and reflects, any different cost
structures for a particular region.

Importantly, with retail allowances as low as 1.3% in South Australia, we could not be
confident that the DMO would continue to maintain incentives for competition, innovation andinvestment. Similarly, with effective allowances at nearly 30% for small business customers
in NSW, we could not be confident the DMO was protecting consumers from unjustifiably
high prices.
Our draft determination was to set the retail allowance, encompassing retail margin andadditional DMO retail allowance, at 10% of the total bill for residential customers and at 15%
for small business customers. These allowances are higher than what has previously been
available under the DMO in some regions and lower in others.
To minimise any potential negative impacts of a sudden large change in retail allowance, we
proposed to transition to these targets over the next 3 DMO determinations so that they are
fully in place in all regions for DMO 6 (in 2024–25).
7.4.2

Stakeholder submissions

A number of stakeholders raised concerns with our proposed approach to setting retailallowances.
Some stakeholders considered our proposed retail allowances for residential and small
business customers were subjective judgement calls that needed further justification.88
Some stakeholders considered our approach to determining the residential and small
business allowances to be inconsistent, noting that the small business retail allowance was88

Australian Energy Council, Submission to DMO 4 draft determination, 17 March 2022, p. 4; Origin,
Submission to DMO 4 draft determination, 17 March 2022, p. 7, Powershop, Submission to DMO 4 draft
determination, 17 March 2022, p. 3; ReAmped Energy, Submission to DMO 4 draft determination, 17 March 2022,
p. 3.

Default market offer prices 2022–23: Final determination42

at the lower range of previous DMO margins, whereas the residential retail allowance wastowards the upper end of the range of previous DMO margins.89
Some retailers expressed concerns about the uncertainty of the retail allowances in future
DMO determinations, and that the retail allowance could be arbitrarily set by the AER and
influenced by political factors, such as a desire to keep the DMO lower by setting a low retailallowance to offset increases in other costs.90
The SA Department for Energy and Mining considered the increase from an effective 1%
retail allowance in DMO 3 to a 10% retailer allowance (even transitioned over multiple
DMOs) to be a significant increase.91 PIAC considered a smooth transition upwards in South
Australia was consistent with protecting consumers but a smooth transition downwards forsmall business retail allowance in other regions was not consistent with this objective andinstead should be implemented immediately to also protect small business consumers.92
Alinta considered that a uniform allowance does not reflect varying competitive dynamics,
risk profiles and market conditions across jurisdictions in different regions.93 The SA
Department for Energy and Mining considered that retail allowance, like other cost
components in the DMO, should be based on the particular region’s data and, given thatcompetition in South Australia was strong, there was no need for higher margins than in
DMO 3.94
Some retailers submitted that retail margin and an allowance to meet the DMO objectives
should be calculated separately to be more transparent and objective.95 Origin noted that theretail allowance is not solely profit margin and that the AER needs to be clear whether themargin is based on estimated returns or EBITDA margin.96
Some retailers expressed concerns that the proposed margins were not high enough torecover efficient costs97 or to allow for errors in forecasting retail and wholesale costs.98
ReAmped considered the impacts of war in Ukraine have not been fully reflected in thecurrent forecast CPI and that there should be sufficient headroom to absorb reasonable

89

AGL, Submission to DMO 4 draft determination, 17 March 2022, p. 3; Public Interest Advocacy Centre,
Submission to DMO 4 draft determination, 17 March 2022, p. 2.
90Australian Energy Council, Submission to DMO 4 draft determination, 17 March 2022, p. 4; Powershop,
Submission to DMO 4 draft determination, 17 March 2022, p. 3.
91
Department of Energy and Mining, Submission to DMO 4 draft determination, Energy and TechnicalRegulation Division, South Australian Government, 17 March 2022, p. 2.
92
Public Interest Advocacy Centre, Submission to DMO 4 draft determination, 17 March 2022, p. 2.
93
Alinta, Submission to DMO 4 draft determination, 17 March 2022, p. 3.
94
Department of Energy and Mining, Submission to DMO 4 draft determination, Energy and TechnicalRegulation Division, South Australian Government, 17 March 2022, p. 2.
95
AGL, Submission to DMO 4 draft determination, 17 March 2022, p. 3; Origin, Submission to DMO 4 draft
determination, 17 March 2022, p. 7; Simply Energy, Submission to DMO 4 draft determination, 17 March 2022, p.
3.
96
Origin, Submission to DMO 4 draft determination, 17 March 2022, p. 7.
97
EnergyAustralia, Submission to DMO 4 draft determination, 17 March 2022, p. 2.
98
Alinta, Submission to DMO 4 draft determination, 17 March 2022, p. 4; AGL, Submission to DMO 4 draft
determination, 17 March 2022, p. 3; Simply Energy, Submission to DMO 4 draft determination, 17 March 2022, p.
3.

Default market offer prices 2022–23: Final determination

43

increases.99 Powershop considered there may not be enough funds for industry to invest ininnovation required to adapt to the current energy transition.100
Retailers warned that if the DMO price is too low as a result of how the allowance and retailcosts were calculated, this would negatively impact competition by:•leading customers to think they did not need to shop around for a better offer101•

reducing the spread of market offers and reducing incentives to shop around102•

diluting investment signals for smaller retailers because it is harder to compete,
eventually restricting competition and entrenching incumbent retailers, which would not
be in the long-term interests of consumers103•

leading to unintended consequences, with some retailers potentially exiting certain
regions and segments.104

In contrast, ECA submitted that the proposed retail margins were too high and did not meetthe DMO objective of protecting customers from unreasonably high prices. ECA argued theretail margins should be similar to standing offer margins in jurisdictions where efficient-costprice regulation is in effect, noting:•there is significant competition and innovation present in some regions•

the implied margins in previous DMO decisions are not relevant to today’s market
conditions•

CARC is already included in our estimate of retail costs, so there was no need for an
additional allowance for competition within the retail allowance.105

Origin recommended that the AER allow an ex-post assessment so that we can make an
informed judgement on what needs to be adjusted and why in future DMO determinations.106
The SA Department for Energy and Mining also noted that our proposed approach of settinga retail margin as a fixed percentage of the total DMO price would result in larger retailallowances in dollar terms if other cost components increased.107
7.4.3

Final determination

We consider the overall level of retail allowance across the DMO was appropriate in previous
DMO determinations. We also acknowledge ECA and PIAC’s concerns that the proposed
retail allowances are too high. However, we consider them to be commensurate with thefunction of DMO as a fallback that protects customers from unreasonably high prices rather
than an efficient price. We observed that since the introduction of the DMO new retailers

99

ReAmped Energy, Submission to DMO 4 draft determination, 17 March 2022, p. 2.
Powershop, Submission to DMO 4 draft determination, 17 March 2022, p. 3.
101
Powershop, Submission to DMO 4 draft determination, 17 March 2022, p. 3.
102
Energy Consumers Australia, Submission to DMO 4 draft determination, 17 March 2022, p. 2.
103
Tango Energy, Submission to DMO 4 draft determination, 17 March 2022, p. 2.
104
Red Energy and Lumo Energy, Submission to DMO 4 draft determination, 17 March 2022, p. 1.
105
Energy Consumers Australia, Submission to DMO 4 draft determination, 17 March 2022, p. 1.
106
Origin, Submission to DMO 4 draft determination, 17 March 2022, p. 7.
107
Department of Energy and Mining, Submission to DMO 4 draft determination, Energy and TechnicalRegulation Division, South Australian Government, 17 March 2022, p. 3.
100

Default market offer prices 2022–23: Final determination

44

were continuing to enter the market, price dispersion among market offers did not contract
and the proportion of customers on standing offers remained low. We have examined thetotal retail allowance in previous DMO determinations available across all DMO regions andare not intending to substantially reduce nor increase this overall retail allowance for DMO 4.
However, we were concerned with the previous variation in retail allowance from region toregion. We consider that consumers in NSW, south-east Queensland and South Australia
should pay the same retail allowance for the same product. We retain our concerns that low
retail allowances in South Australia would present risks to competition, and higher retailallowances in NSW risk the DMO objective of protecting consumers on standing offers fromunreasonably high prices. Setting a consistent retail allowance across regions means
retailers will be able to achieve a reasonable margin overall without support from higher
margin customers in other regions.
We have set the 10% residential retail allowance, which is consistent with the weighted
average for residential customers across DMO regions. We have set the 15% small businessretail allowance because it is at the lower end of previous small business allowances andenables the DMO prices to maintain approximately the same aggregate level of allowanceacross the DMO regions and customers.
We are satisfied that higher retail allowance for small business customers meets the DMO
objectives because it also reflects the different market characteristics of this customer type.
In its November 2021 report, the ACCC observed NEM-wide retail margins for small
businesses to be 0.5c/kWh or 60% higher than for residential customers.108 A higher margin
is also appropriate because small business customers pose distinct risks. We note that the
average debt per small business customer is around 2.5 times greater than for residential
customers.109
In redistributing the retail allowance, we took care to broadly maintain the same volume ofallowance available in the market in each year of our transition path. Our proposed retailallowance transition path across DMO 4, 5 and 6 provides a reasonably smooth (although
not identical) shift to the 10% and 15% targets across all 5 regions without significantly
reducing or increasing the aggregate amount of allowance available across the DMO regions
in any given year.
Overall, we consider that the transition path appropriately balances the impacts of thechange to the cost build-up approach on retailers and consumers.
We acknowledge retailers’ concerns about our approach to retail allowances that not all
retailers, such as retailers with high amounts of depreciation expenses or smaller retailers
that could have higher retail operating costs, may be able to make a reasonable profit. We
have conducted analysis testing the impact of varying costs faced by different retailers on thenominal retail allowance in section 7.5.

108

ACCC, Inquiry into the National Electricity Market November 2021 report, Appendix E, Supplementary
Table E4.1 A, E4.8 A.
109
AER Retail Performance Reporting Q3 2021-22, schedule 3.

Default market offer prices 2022–23: Final determination

45

7.5 Retail allowance analysis
To evaluate retailers’ concerns about our use of ACCC data, and ECA and PIAC’s concerns
about the amount of retail allowance included int the DMO 4 prices, we have analysed theimpact of depreciation costs and Tier 2 operating costs on the DMO retail allowance.
Table 7.3 in section 7.6 sets the retail allowances for each of the 15 DMO prices. We haveincluded the charts setting out this analysis in Appendix G, but summarise the findings of thisstress test below.
Analysis of depreciation costs
While several retailers’ submissions mentioned depreciation, only 2 provided some form of
cost information. One of these provided separate confidential estimates of depreciation costs
for residential and small business electricity customers. The other, AGL, provided public
information from its 2020–21 annual report showing total depreciation expenses of$134 million for its retail business (encompassing gas and telecommunication customers aswell as electricity).110
Based on this limited information it is difficult to assess the extent to which the informationreflects other retailers’ costs. However, for the purposes of analysis we have tested whatpercentage allowance remains after deducting a hypothetical:•$30 per customer depreciation cost from the residential retail allowance in each region•$110 from the small business retail allowance.

We note that by treating nominal depreciation costs as a retail cost for this analysis, theresulting nominal DMO allowance is equivalent to an earnings before interest and taxes(EBIT) retail margin, in accounting terms. As we have noted elsewhere, Australian regulators
have set allowed margins on the basis that retailers will recover any depreciation costs fromthat component of the regulated price (that is, EBITDA margins).
Residential customers
Adding a hypothetical $30 on to the ACCC’s average residential retail costs (that is, ourbase DMO 4 retail cost figure), we found effective DMO 4 retail allowances would range from
4.4% (SAPN) to 8.8% (Endeavour and Essential controlled load customers).
•

Due to the transition path, by DMO 6 the effective margins would range from 8.0%
(Ausgrid) to 8.8% (SAPN, Endeavour and Essential controlled load customers).

Adding a nominal $30 to the ACCC’s average Tier 1 retail costs, we found the effective
DMO 4 retail allowances would range from 5.7% (SAPN) to 9.8% (Endeavour and Essential
controlled load customers).
•

By DMO 6, the effective margins would range from 9.6% (Ausgrid, Energex) to 9.8%
(SAPN, Endeavour and Essential controlled load customers).

110

AGL reported in its 2020-21 Annual Report $134m of depreciation expenses among 4.208m customers
mass market customers. This is approximately $32/customer or $35 including GST. AGL 2020-21 Annual Report,
p.17,36.

Default market offer prices 2022–23: Final determination

46

The analysis indicates that, except for the SAPN region in DMO 4, retailers with this level ofdepreciation costs would achieve EBIT margins that are higher than the EBITDA margins by
ESCV, ICRC and OTTER allowed EBITDA margins. As we have noted, these range from 5%
to 6%.
While the 4.4% effective margin in the SAPN region is slightly below this range, it is higher
than:•

the –1% EBITDA margin identified by the ACCC as what retailers achieved in thecompetitive South Australian retail energy market in 2020–21•

the 1.3% to 4% nominal retail allowances available under previous DMO prices for the
SAPN region.

Small business customers
Adding a hypothetical $110 to the ACCC’s average small business retail costs (that is, ourbase DMO 4 retail cost figure), we found effective DMO 4 retail allowances would range from
12.6% (SAPN) to 22.5% (Ausgrid).
•

By DMO 6 the effective retail allowances would range from 11.7% (Energex) to 12.6%(SAPN and Essential).

Analysis of Tier 2 retail costs
To test retailers’ concerns that our use of average retail costs would affect the DMO
objectives for Tier 2 retailers, we have analysed the impact on the DMO allowance of adding$57 to the DMO retail cost component.
Residential customers
Adding $57 to the ACCC’s average retail costs, we found a retailer with these costs would
achieve effective DMO 4 EBITDA retail allowances ranging from 2.9% (SAPN) to 7.7%
(Essential controlled load customers).
While these figures suggest retailers with this level of costs would have less scope to offer
discounts off the reference price and make a return in comparison to a retailer with lower
costs in DMO 4, we consider such a retailer would still make a reasonable profit and have
incentives to innovate and invest. We note:•the effective 2.9% residential retail allowance in SAPN in the DMO 4 is greater than what
was available under DMO 3•

by DMO 6 the effective retail allowances available to retailers with these costs would
range from 6.2% (Ausgrid) to 7.7% (Essential controlled load customers).

Adding a hypothetical $30 depreciation costs in addition to the ACCC’s Tier 2 operating
costs, we found effective EBITDA DMO 4 retail allowances ranging from 1.3% (SAPN) to
6.5% (Essential controlled load customers).
We consider that this a highly conservative assumption, given that Tier 1 retailers, who havethe highest depreciation costs, tend to have lower retail operating costs.
•

By DMO 6 the effective retail allowances available to retailers with these costs would
range from 4.2% (Ausgrid) to 6.5% (Essential controlled load customers).

Default market offer prices 2022–23: Final determination47

We acknowledge that, even with the completed transition to a 10% retail allowance in
DMO 6, retailers with average Tier 2 operating costs and high depreciation costs may haveeffective retail allowances in some regions that are below the efficient margins set by ESCV,ICRC and OTTER. However, Tier 2 retailers generally do not have many customers on
standing offers, so are mainly impacted by their ability to discount off the DMO reference
price.
In practice, higher retail costs do not appear to have prevented Tier 2 retailers fromcompeting aggressively on price. For instance, the lowest residential Tier 2 market offer is$35 to $292 below the lowest Tier 1 offer (in May 2022) and would have a further 1% to 16%
discount off the DMO 4 reference price compared with the median Tier 1 offer, which is 12%
to 26% below the DMO 4 reference price.
Conclusion
Our analysis above shows that, for residential and small business customers, retailallowances are sufficiently high that even retailers with higher than average costs will be able
to make a reasonable profit and have incentives to innovate and invest. However, thisanalysis also demonstrates that the retail allowance is not unreasonably high, as smaller
retailers with these higher costs would have difficulties competing and making a reasonableprofit if allowances were lower.
While this capacity is more constrained in SAPN and Energex for retailers with significantly
higher costs in DMO 4, the transition to consistent retail allowances means this impact will be
short term.
Based on the analysis we are satisfied that the DMO 4 price, based on the ACCC’s averageretail costs (plus our adjustments for bad debt and advanced meters), meets the objectives
without the need for adjustments for depreciation or to reflect Tier 2 retail costs. We are alsosatisfied that the retail allowances in the DMO 4 price protect consumers from unreasonably
high prices.

7.6 Final determination on overall approach, retail costs
and retail allowance
We will adopt a cost build-up approach for DMO 4. As discussed in section 7.1, thisapproach is the best suited to achieving the DMO policy objectives going forward.
The DMO 4 retail cost component will comprise:•

retail operating costs in the ACCC’s November 2021 report as our base estimate oftypical retailer operating costs•

an adjustment for bad and doubtful debt, based on publicly reported information•

an adjustment to reflect the costs retailers incur in relation to advanced meters, including
the residual capital costs retailers face for accumulation meters that are removed before
their end of their operational lives

Default market offer prices 2022–23: Final determination

48

•a CPI adjustment to bring forward the ACCC’s 2020–21 costs to 2022–23 dollars. We
have updated the CPI adjustment from the draft determination to reflect the latest RBA
forecasts.111

Tables 7.1 and 7.2 set out the residential small business and retail costs for DMO 4.
Table 7.1 DMO 2022–23 residential retail costs (ex. GST)
ACCC retail
costs

Advancedmeter costs

BDD

CPI

Total –
retail cost
component

Ausgrid (NSW)$132$15.12$25.71$17.26$190.09

Endeavour (NSW)$132$21.40$25.71$17.88$196.99

Essential (NSW)$132$18.03$25.71$17.55$193.29

Energex (SE QLD)

$132

$17.01$25.71$17.44$192.16

SAPN (SA)$133$24.28$25.71$18.27$201.26

RegionTable 7.2 DMO 2022–23 small business retail costs (ex GST)
ACCC retail
costs

Advancedmeter costs

BDD

CPI

Total – retailcost component

Ausgrid (NSW)

$204

$9.22

$25.71$23.85$262.78

Endeavour (NSW)$204$14.90$25.71$24.42$269.03

Essential (NSW)

$204

$3.87

$25.71$23.32$256.90

Energex (SE QLD)

$153

$16.29$25.71$19.47$214.47

SAPN (SA)

$153

$5.98

$25.71$18.44$203.13

RegionWe will set a retail allowance, encompassing retail margin and an additional allowance toachieve the DMO objectives. The retail allowance will be 10% of the total DMO annual bill forresidential customers and 15% for small business customers.
We intend to transition to these target allowances over the DMO 4, 5 and 6 determinations,so that they are fully implemented in all regions for DMO 6. The transition path for this has
not changed from the draft determination.
Table 7.3 sets out our final determination on the retail allowances (in percentage terms) thatwill apply in DMO 4.

The Draft Determination used the RBA’s November 2021 Statement on Monetary Policy forecast CPI for
2021-22 and 2022-23 (2.75 and 2.25% respectively). The Final Determination uses the RBA’s May 2022
Statement on Monetary Policy forecast CPI for 2021-22 and 2022-23 (5.5 and 4.25%)
111

Default market offer prices 2022–23: Final determination

49

Table 7.3 Retail allowances, DMO 2022–23
RegionCustomer type

Ausgrid (NSW)Residential without CL$151 (10%)

Residential with CL$212 (10%)

Small businessEndeavour (NSW)

Energex (SE QLD)SAPN (SA)$1,090 (25%)

Residential without CL$184 (10%)

Residential with CL$238 (10%)

Small business
Essential (NSW)DMO 4 retail allowance ($, % of
DMO bill)$628 (16.6%)

Residential without CL$209 (10%)

Residential with CL$249 (10%)

Small business$995 (20.3%)

Residential without CL$136 (8.4%)

Residential with CL$196 (10%)

Small business$586 (17%)

Residential without CL$110 (6%)

Residential with CL$137 (6%)

Small business$681 (15%)

Default market offer prices 2022–23: Final determination

50

8 Model annual usage
Under Part 3 of the Regulations, we are required to determine ‘broadly representative’annual supply amounts for residential and small business customers in each distribution
region, from which a DMO price and reference price can be calculated. In this document werefer to annual supply as annual usage.
We must also determine the timing and pattern of supply to residential customers. The
Regulations refer to these elements in combination as the ‘model annual usage’.

8.1 Draft determination
Our draft determination position was to retain the same annual usage benchmarks forresidential customers as in previous determinations. Our analysis of usage data obtained
from network providers, and other information, suggested average usage had not changed
significantly and was still ‘broadly representative’ as required by the Regulations.
We proposed not taking into account the usage of TOU customers because these reduce theusefulness of the reference price for the roughly 80% of customers on flat rate tariffs.
For small business customers, our draft determination was to change the annual usage
benchmark from 20,000 to 10,000 kWh per year. Reasons for this change included:•

it was more representative of small business customer usage, in particular given the
ACCC and network data indicated median or average figures below 10,000 kWh per
year•

it provided a more useful reference price for consumers using less than 20,000 kWh peryear because it was more effective in identifying the cheapest offers for most users.

Our draft determination for timing and pattern of supply was to retain the main settings fromprevious determinations but update the usage profiles using new interval meter dataobtained from AEMO.
We did not make any changes to our previous methodology considered as part of our options
paper consultation. For example, we proposed not to base the TOU profiles solely on theusage of TOU retail tariff customers because this would have only marginal influence.

8.2 Stakeholder submissions
Tango Energy raised model annual usage in their submission, questioning whether it wasnecessary and efficient to update the TOU profiles each year.112
We note patterns of usage for TOU customers are likely to be more dynamic due to the pricesignals, and there are benefits in the profiles reflecting current usage patterns. Our intention
is to keep the same profile structure going forward, so only data values will need to be
updated, which should not impose a significant administrative burden.

112 Tango Energy, Submission to DMO 4 draft determination, 17 March 2022, p. 2-3.

Default market offer prices 2022–23: Final determination

51

8.3 Final determination
Our final determination position on annual usage is unchanged from the draft determination.
We will:•

for residential customers, retain the same usage amounts for general usage andcontrolled usage as in previous determinations – these are set out in Appendix E•for small business customers, adopt a 10,000 kWh per year annual usage benchmark.

To provide consistency and continuity for stakeholders, our intention is to use these settings
for the 2023–24 (DMO 5) and 2024–25 (DMO 6) determinations. Our intention is to review
these as part of the next DMO methodology review as part of the 2025–26 (DMO 7) process.
Our final determination for timing and pattern of supply is that we will update the usage
profiles using new AEMO interval meter data but retain our key assumptions from previous
determinations. That is, we will:•assume the same usage occurs every day (with no variation for weekday, weekend or
season), as in previous determinations•

use the same proportional allocations of annual controlled load usage across multiple
controlled loads•

retain a single 24-hour usage profile•

update these using the AEMO interval meter data for each region, averaged over
3 years•

specify usage at 30-minute intervals.

We have updated the single day usage profile and specified usage for each 30-minuteinterval over a 24-hour period (see Appendix E). We propose to continue to update theprofiles with new data each year.
We will continue to review ACCC Electricity Monitoring Inquiry’s annual reports examining
the usage and prices paid by market and standing offer customers, to inform ourunderstanding of these issues.

Default market offer prices 2022–23: Final determination

52

Appendices
Appendix A – List of submissions to the DMO 4 options paper
Appendix B – Market offer analysis
Appendix C – Nominal price movements from draft determination to final determination
Appendix D – Advanced meter costs
Appendix E – Legislative instrument
Appendix F – DMO 3 to DMO 4 price movements
Appendix G – Analysis of DMO 4 final retail costs and margins

Default market offer prices 2022–23: Final determination

53

A List of submissions to the DMO 4 Draft
Determination
1.

Australian Energy Council (AEC)

2.

AGL

3.

Alinta Energy

4.

Ausgrid

5.

Energy Consumers Australia (ECA)

6.

EnergyAustralia

7.

Enova Energy

8.

Momentum Energy

9.

Origin Energy

10. Public Interest Advocacy Centre (PIAC)
11. Powershop Australia / Meridian Energy
12. Red Energy / Lumo Energy
13. South Australian Department for Energy and Mining
14. South Australian Council of Social Services (SACOSS)
15. Simply Energy
16. Tango Energy
17. Queensland Energy Users Network (QEUN)

Default market offer prices 2022–23: Final determination

54

B Market offer analysis for each distribution region
As the agency responsible for determining DMO prices each year, we consider it necessary
to understand any DMO-related impacts so they can inform our future DMO pricedeterminations. The purpose of this analysis is to provide a snapshot of how the market has
moved immediately following the DMO’s introduction.
This section looks at changes to highest, lowest and median market offer prices before andafter the introduction of the DMO on 1 July 2019. We have recalculated small business offers
at 10,000 kWh annual usage to reflect the updated consumption amount.
Figures B.1 to B.15 show these movements in graph form. These 15 graphs show the offersfrom Energy Made Easy (EME) for the 3 customer types and 5 distribution regions. To
calculate the annual bill amounts from EME data, we used assumptions to allow directcomparison of generally available offers. The list of annual bill calculation assumptions ispublished in our DMO 2 final determination.

Changes in market offer prices in Ausgrid’s region
Figure B.1 Residential flat rate tariff

Default market offer prices 2022–23: Final determination

55

Figure B.2 Residential flat rate tariff with controlled load

Figure B.3 Small business flat rate tariff

Default market offer prices 2022–23: Final determination

56

Changes in market offer prices in Endeavour’s region
Figure B.4 Residential flat rate tariff

Figure B.5 Residential flat rate tariff with controlled load

Default market offer prices 2022–23: Final determination

57

Figure B.6 Small business flat rate tariff

Default market offer prices 2022–23: Final determination

58

Changes in market offer prices in Essential region
Figure B.7 Residential flat rate tariff

Figure B.8 Residential flat rate tariff with controlled load

Default market offer prices 2022–23: Final determination

59

Figure B.9 Small business flat rate tariff

Default market offer prices 2022–23: Final determination

60

Changes in market offer prices in Energex region
Figure B.10 Residential flat rate tariff

Figure B.11 Residential flat rate tariff with controlled load

Default market offer prices 2022–23: Final determination

61

Figure B.12 Small business flat rate tariff

Default market offer prices 2022–23: Final determination

62

Changes in market offer prices in SAPN region
Figure B.13 Residential flat rate tariff

Figure B.14 Residential flat rate tariff with controlled load

Default market offer prices 2022–23: Final determination

63

Figure B.15 Small business flat rate tariff

From August 2021 to May 2022, the change in the median market offer prices across the
distribution regions for residential customers ranged from a decrease of 3.2% (SAPN,
residential with controlled load) to an increase of 3.7% (Energex, residential without
controlled load). For residential customers without controlled load, the median market offer
increased from 0.1% (SAPN) to 3.7% (Energex). For residential customers with controlled
load the change in the median market offer price ranged from a reduction of 3.2% (SAPN) to
an increase of 0.1% (Endeavour). The change in the median market offer price for small
business customers ranged between a decrease of 2.5% (SAPN) to an increase of 2.9%
(Energex).
We observed a number of May 2022 market offers priced above both DMO 3 and DMO 4
from 3 retailers (46 out of 1063 offers included in the analysis). Two retailers with high prices
also offered market contracts that were priced below both DMO 3 and DMO 4. However weobserved for the first time one other retailer in most regions has priced all their current
generally available single rate market offers above the DMO 3 and DMO 4 prices. Thisretailer’s lowest residential market offers in Ausgrid, Endeavour, Essential and Energex arearound 3% to 18% above the DMO 4 price. The lowest residential market offers in SAPN
from the same retailer are below the DMO 4 price by around 8% (no controlled load) and 4%(controlled load).
Smaller retailers may have greater exposure to spot prices and have less hedged load thanlarger retailers. In previous DMO determinations we have observed that this may havebenefited retailers because they could take advantage of lower wholesale prices andcompete aggressively, offering market offers priced at deep discounts relative to Tier 1
retailers. However, we have observed a steep increase in wholesale prices in 2022 andthese same retailers may be more affected by this reversal of the wholesale price trend.
While Tier 2 retailers have the highest market offers in each region, we observed that otherTier 2 retailers have the lowest market offer in each region, offering a further 1% to 16%
discount off the DMO 4 price compared with lowest offer from Tier 1 retailers.

Default market offer prices 2022–23: Final determination

64

C Nominal price movements from draft
determination to final determination
Tables C1 to C3 show the nominal movement for each cost component between the DMO 4
draft determination published on 18 February 2022 and our final determination.
Table C1 Residential without CL
RegionDMO 4
Draft
2022–23

Network
cost

Wholesale
cost

Environmental
cost

Retailoperatingcost

Retailallowance

OverallnominalchangeDMO 4
Final
2022–23

Ausgrid$1,372

-$3

$104

$13

$12

$14

$140

$1,512Endeavour$1,599

$51

$136

$16

$10

$24

$237

$1,836

Essential$1,869

$52

$124

$14

$11

$22

$223

$2,092

Energex$1,540

-$48

$91

$15

$14

$7

$80

$1,620SAPN$1,769

$15

$28

$12

$12

$4

$71

$1,840

Table C2 Residential with CL
RegionDMO 4
Draft
2022–23

Network
cost

Wholesale
cost

Environmental
cost

Retailoperatingcost

Retailallowance

OverallnominalchangeDMO 4
Final
2022–23

Ausgrid$1,887

-$4

$182

$22

$12

$24

$235

$2,122Endeavour$2,055

$59

$201

$24

$10

$33

$327

$2,383

Essential$2,204

$58

$167

$21

$11

$29

$285

$2,490

Energex$1,839

-$56

$131

$21

$14

$12

$122

$1,961SAPN$2,178

$20

$40

$18

$13

$6

$97

$2,275

Table C3 Small business without CL
RegionDMO 4
Draft
2022–23

Network
cost

Wholesale
cost

Environmental
cost

Retailoperatingcost

Retailallowance

OverallnominalchangeDMO 4
Final
2022–23

Ausgrid$3,901

$30

$267

$32

$15

$115

$459

$4,360Endeavour$3,306

$73

$278

$33

$13

$79

$476

$3,782Essential$4,365

$114

$269

$31

$13

$109

$536

$4,901

Energex$3,250

-$84

$199

$33

$15

$33

$196

$3,446

SAPN$4,369

$34

$69

$31

$10

$25

$170

$4,539The key drivers for these movements are:•

Networks costs used in the draft determination were the 2022–23 indicative prices fromthe 2021–22 annual pricing proposals. This was the only available information at thetime we made the draft determination. Network tariffs have been updated with the 2022–
23 final prices approved by the AER for the final determination. Network Use of Systemcharges are the majority of network costs. There was a slight change (up to $1.03) in

Default market offer prices 2022–23: Final determination

65

charges in the Alternate Control Services (ACS) for customers depending on the region.
See section 4 for more detail.
•

Wholesale costs, which includes wholesale energy and other market participation
costs, increased across all regions. Since the draft determination, wholesale energy
costs have increased by between $6.27 per MWh (4.89% in SAPN) and $24.44 per
MWh (26.7% in Essential) due to higher observed forward contract prices, which could
be attributed to increasing fuel costs, a reduction in thermal generation and a slowing ofinvestment of new capacity.

•

Environmental costs increased, with minor upward revisions to the Small-scale
Renewable Energy Scheme compliance costs resulting from the Clean Energy
Regulator’s issuance of binding 2020 Small-scale Technology Percentages in March.
Large-scale generation certificate forward prices increased due to an increase indemand for LGCs driven by net zero and environmental corporate policies. This has
increased the cost of the LRET.

•

Retail operating costs increased slightly as a result of the RBA’s revised CPI forecast
for the 2021–22 and 2022–23 periods, increasing from 2.75% and 2.25% to 5.5% and4.25%, respectively. Retail operating costs also increased slightly due to an adjustment
to advanced meter costs to account for ongoing metering capital charges for replaced
accumulation meters.

•

Retail allowances, which are calculated as a percentage of the total DMO price,increased due to the increases in other cost components.

Default market offer prices 2022–23: Final determination

66

D Advanced meter costs
We requested retailers selling to approximately 94% of customers in DMO regions to provide the number of customers on advanced meters
and accumulation meters for each DMO region and customer type as at 30 September 2021. We also asked retailers to provide average peradvanced meter costs. In our final determination we have made a small adjustment to the advanced meter allowance to reflect the legacy
accumulation capital charges that retailers continue to incur when an accumulation meter has been installed due to the request of thecustomer, a faulty accumulation meter, or when a smart meter has been installed by the retailer as part of the new meter deployment.
Tables D.1 and D.2 set out our calculations for estimating advanced meter costs per residential and small business customer.
Table D.1 Residential advanced meter counts and per customer costs
RegionTotal
advancedmetersTotal
advancedmeter costs

Averageperadvanced
meter
cost (exGST)

ACS
metering
allowance
included in
networkcomponent(ex GST)

Capitalmetering
chargewithin ACS
metering
allowance% ofadvancedmeter
installations
where
retailer
incurs capitalmetering
charge forreplaced
accumulation
meter

Averagelegacycapitalmetering
chargesincurred peradvanced
meter

Average peradvancedmeter costs
net of ACS
metering
allowance,
includinglegacy meter
capitalchargesTotalcustomers
30
September
2021

% of
customerswithadvancedmetersAdvancedmeter costpercustomernet of ACS
metering
allowancein network
component,
includinglegacymeter
capitalcharges (exGST)

Ausgrid279,093$29,606,278$106$27.03$15.1080%$12.08$91.13

1,681,650

16.6%$15.12Endeavour

246,015$25,836,718$105$22.16

$2.17

80%

$1.74

$84.60972,61725.3%$21.40Essential

176,851$18,830,123$106$37.31$10.3280%$8.26$77.42759,46323.3%$18.03

Energex276,837$27,868,108$101$39.42$26.8480%$21.47$82.72

1,346,20420.6%$17.01

SAPN

196,995$22,324,163$113$23.98

$9.60

80%

$7.68

$97.02787,069

25.0%$24.28DMO

1,175,791$124,465,391$106$29.96$13.5280%$10.81$86.71

5,547,003

21.2%$18.38

Default market offer prices 2022–23: Final determination

67

Table D.2 Small business advanced meter counts and per customer costs
RegionTotal
advancedmetersTotal
advanced
meter
costs

Averageperadvanced
meter
cost (exGST)

ACS
metering
allowance
included in
networkcomponent(ex GST)

Capitalmetering
chargewithin ACS
metering
allowance% ofadvancedmeter
installations
where
retailer
incurs capitalmetering
charge forreplaced
accumulation
meter

Averagelegacycapitalmetering
chargesincurred peradvanced
meter

Average peradvancedmeter costs
net of ACS
metering
allowance,
includinglegacy meter
capitalchargesTotalcustomers
30
September
2021

% of
customerswithadvancedmetersAdvancedmeter costpercustomernet of ACS
metering
allowancein network
component,
includinglegacymeter
capitalcharges (exGST)

Ausgrid

5,905$663,868$112$35.39$23.0880%$18.46$95.5061,149

9.7%

$9.22

Endeavour

11,179$1,310,252$117$32.47

$2.17

80%

$1.74

$86.4764,87017.2%$14.90Essential

2,250$295,641$131$37.31$10.3280%$8.26$102.34

59,533

3.8%

$3.87

Energex

13,227$1,455,526$110$39.42$26.8480%$21.47$92.0974,77617.7%$16.29

SAPN

2,347

$308,705$132$23.98

$9.60

80%

$7.68

$115.23

45,255

5.2%

$5.98

DMO

34,908$4,033,992$116$35.34$16.0880%$12.86$93.08305,583

11.4%$10.63

Default market offer prices 2022–23: Final determination

68

E Legislative instrument

Competition and Consumer (Industry Code –Electricity Retail) (Model Annual Usage and Total
Annual Prices) Determination 2022
The Australian Energy Regulator makes the following determination.

Dated 26 May 2022

Australian Energy Regulator

Default market offer prices 2022–23: Final determination

69

1.

Name
This instrument is the Competition and Consumer (Industry Code – Electricity Retail)(Model Annual Usage and Total Annual Prices) Determination 2022.

2.

Commencement
This instrument commences on 1 July 2022.

3.

Authority
This instrument is made under section 16(1) of the Competition and Consumer (Industry
Code – Electricity Retail) Regulations 2019 (the Regulations).

4.

Definitions
In this Determination:a)Regulations means the Competition and Consumer (Industry Code – Electricity
Retail) Regulations 2019; andb)

Residential Annual Usage without Controlled Load applies to the type of small
customer considered in s 6(2)(b) of the Regulations; andc)Residential Annual Price without Controlled Load applies to the type of small
customer considered in s 6(2)(b) of the Regulations; andd)Residential Annual Usage with Controlled Load applies to the type of small
customer considered in s 6(2)(a) of the Regulations; ande)Residential Annual Price with Controlled Load applies to the type of small
customer considered in s 6(2)(a) of the Regulations; andf)Small Business Annual Usage applies to the type of small customer considered ins 6(2)(c) of the Regulations; andg)Small Business Annual Price applies to the type of small customer considered ins 6(2)(c) of the Regulations; andh)General Usage means the non-controlled load usage of a small customer under s6(2)(a) of the Regulations; andi)Controlled Load Usage means the controlled load usage of a small customer unders 6(2)(a) of the Regulations.

j)Terms defined in the Regulations have the same meaning in this instrument.

Default market offer prices 2022–23: Final determination

70

5.

Per-customer usage determination
In accordance with s 16(1)(a)(i) of the Regulations, the AER determines the per-customer
amount of electricity supplied in specified distribution regions to small customers of thefollowing types:
Per-customer annual usage determination
Distribution region

6.

Residential Annual
Usage without
Controlled Load

Residential Annual Usage with
Controlled Load

General Usage

Controlled Load
Usage

Small BusinessAnnual Usage

Ausgrid

3,900 kWh

4,800 kWh

2,000 kWh

10,000 kWh

Endeavour Energy

4,900 kWh

5,200 kWh

2,200 kWh

10,000 kWh

Energex

4,600 kWh

4,400 kWh

1,900 kWh

10,000 kWh

Essential Energy

4,600 kWh

4,600 kWh

2,000 kWh

10,000 kWh

SA Power Networks

4,000 kWh

4,200 kWh

1,800 kWh

10,000 kWh

Timing or pattern of supply determination
In accordance with s 16(1)(a)(ii) of the Regulations, the AER determines the timing or
pattern of the supply of electricity in specified distribution regions to small customers:a) Seasonality assumptions, all tariff and customer types
For all tariff and customer types, consumption has no seasonal weighting. That is,kilowatt hours consumed are assumed to be the same on each day of the year.
b) Daily usage profile for Flexible Tariffs (Time of Use tariffs, including the South
Australian TOU controlled load tariff) – Residential Usage without Controlled
Load and General Usage / Residential Usage with Controlled Load

Default market offer prices 2022–23: Final determination

71

i.

Ausgrid distribution region

Flexible Tariff (Time of Use tariff) daily usage profile – Daily Residential Usage without Controlled Load (3,900 kWh/yr)
Time

Usage
(kWh)

Time

Usage
(kWh)

00:00 00:30

00:30 01:00

01:00 01:30

01:30 02:00

02:00 02:30

02:30 03:00

03:00 03:30

03:30 04:00

04:00 04:30

04:30 05:00

05:00 05:30

05:30 06:00

06:00 06:30

06:30 07:00

07:00 07:30

07:30 08:00

08:00 08:30

08:30 09:00

09:00 09:30

09:30 10:00

10:00 10:30

10:30 11:00

11:00 11:30

11:30 12:00

0.23180.22280.21240.18870.17170.15550.14440.13750.13470.13510.1406

0.15

0.168

0.19080.20550.21940.22050.21840.21630.21370.211

0.20890.20730.207712:00 12:30

12:30 13:00

13:00 02:00

13:30 03:00

14:00 14:30

14:30 15:00

15:00 15:30

15:30 16:00

16:00 16:30

16:30 17:00

17:00 17:30

17:30 18:00

18:00 18:30

18:30 13:00

19:00 19:30

19:30 20:00

20:00 20:30

20:30 21:00

21:00 21:30

21:30 22:00

22:00 22:30

22:30 23:00

23:00 23:30

23:30 24:00

0.20910.20950.20870.20780.20730.20820.21180.22070.23360.25090.27380.30180.31850.32290.31780.31050.30410.29620.28370.27220.26360.25530.24650.2376

Flexible Tariff (Time of Use tariff) daily usage profile – Daily General usage – Daily Residential Usage with Controlled Load (4,800 kWh/yr)
Time

Usage
(kWh)

Time

Usage
(kWh)

00:00 00:30

00:30 01:00

01:00 01:30

01:30 02:00

02:00 02:30

02:30 03:00

03:00 03:30

03:30 04:00

04:00 04:30

04:30 05:00

05:00 05:30

05:30 06:00

06:00 06:30

06:30 07:00

07:00 07:30

07:30 08:00

08:00 08:30

08:30 09:00

09:00 09:30

09:30 10:00

10:00 10:30

10:30 11:00

11:00 11:30

11:30 12:00

0.28530.27420.26140.23230.21140.19140.17770.16930.16580.16630.17310.18460.20670.23480.253

0.27010.27140.26880.26620.263

0.25970.25710.25520.2556

12:00 12:30

12:30 13:00

13:00 02:00

13:30 03:00

14:00 14:30

14:30 15:00

15:00 15:30

15:30 16:00

16:00 16:30

16:30 17:00

17:00 17:30

17:30 18:00

18:00 18:30

18:30 13:00

19:00 19:30

19:30 20:00

20:00 20:30

20:30 21:00

21:00 21:30

21:30 22:00

22:00 22:30

22:30 23:00

23:00 23:30

23:30 24:00

0.25740.25790.25690.25570.25520.25620.2607

0.27160.28750.30880.337

0.37150.392

0.3974

0.3911

0.38210.37430.3646

0.3491

0.335

0.32450.31430.30340.2925

Default market offer prices 2022–23: Draft determination

72

ii.

Endeavour Energy distribution region

Flexible Tariff (Time of Use tariff) daily usage profile - Daily Residential Usage without Controlled Load (4,900 kWh/yr)
Time

Usage
(kWh)

Time

Usage
(kWh)

00:00 00:30

00:30 01:00

01:00 01:30

01:30 02:00

02:00 02:30

02:30 03:00

03:00 03:30

03:30 04:00

04:00 04:30

04:30 05:00

05:00 05:30

05:30 06:00

06:00 06:30

06:30 07:00

07:00 07:30

07:30 08:00

08:00 08:30

08:30 09:00

09:00 09:30

09:30 10:00

10:00 10:30

10:30 11:00

11:00 11:30

11:30 12:00

0.29380.28140.25570.227

0.20180.18390.17320.16750.16710.17070.1812

0.19520.219

0.2456

0.25840.26950.26610.25540.25020.24430.23860.23370.22960.2303

12:00 12:30

12:30 13:00

13:00 02:00

13:30 03:00

14:00 14:30

14:30 15:00

15:00 15:30

15:30 16:00

16:00 16:30

16:30 17:00

17:00 17:30

17:30 18:00

18:00 18:30

18:30 13:00

19:00 19:30

19:30 20:00

20:00 20:30

20:30 21:00

21:00 21:30

21:30 22:00

22:00 22:30

22:30 23:00

23:00 23:30

23:30 24:00

0.23190.2332

0.23480.23950.24690.25620.27110.29460.32080.35040.38020.41590.43440.43570.4256

0.41450.40230.38820.3706

0.34580.33550.32780.3206

0.309

Flexible Tariff (Time of Use tariff) daily usage profile - Daily General Usage – Daily Residential Usage with Controlled Load (5,200 kWh/yr)
Time

Usage
(kWh)

Time

Usage
(kWh)

00:00 00:30

00:30 01:00

01:00 01:30

01:30 02:00

02:00 02:30

02:30 03:00

03:00 03:30

03:30 04:00

04:00 04:30

04:30 05:00

05:00 05:30

05:30 06:00

06:00 06:30

06:30 07:00

07:00 07:30

07:30 08:00

08:00 08:30

08:30 09:00

09:00 09:30

09:30 10:00

10:00 10:30

10:30 11:00

11:00 11:30

11:30 12:00

0.31180.2986

0.27130.24090.21410.19510.18380.17780.17730.18120.19230.20710.23240.2606

0.27430.286

0.28240.271

0.26550.25920.25320.248

0.2436

0.244412:00 12:30

12:30 13:00

13:00 02:00

13:30 03:00

14:00 14:30

14:30 15:00

15:00 15:30

15:30 16:00

16:00 16:30

16:30 17:00

17:00 17:30

17:30 18:00

18:00 18:30

18:30 13:00

19:00 19:30

19:30 20:00

20:00 20:30

20:30 21:00

21:00 21:30

21:30 22:00

22:00 22:30

22:30 23:00

23:00 23:30

23:30 24:00

0.24610.24750.24920.2541

0.262

0.27180.28770.31270.34040.37190.40350.44140.461

0.46240.45170.43990.42690.412

0.3933

0.367

0.356

0.34790.34020.3279Default market offer prices 2022–23: Draft determination

73

iii.

Energex distribution region

Flexible Tariff (Time of Use tariff) daily usage profile - Daily Residential Usage without Controlled Load (4,600 kWh/yr)
Time

Usage
(kWh)

Time

Usage
(kWh)

00:00 00:30

00:30 01:00

01:00 01:30

01:30 02:00

02:00 02:30

02:30 03:00

03:00 03:30

03:30 04:00

04:00 04:30

04:30 05:00

05:00 05:30

05:30 06:00

06:00 06:30

06:30 07:00

07:00 07:30

07:30 08:00

08:00 08:30

08:30 09:00

09:00 09:30

09:30 10:00

10:00 10:30

10:30 11:00

11:00 11:30

11:30 12:00

0.19780.18010.16830.15870.15190.14740.14490.14390.14630.152

0.16430.18050.2052

0.23420.25910.26680.26670.2631

0.2626

0.26130.25930.25830.25740.259812:00 12:30

12:30 13:00

13:00 02:00

13:30 03:00

14:00 14:30

14:30 15:00

15:00 15:30

15:30 16:00

16:00 16:30

16:30 17:00

17:00 17:30

17:30 18:00

18:00 18:30

18:30 13:00

19:00 19:30

19:30 20:00

20:00 20:30

20:30 21:00

21:00 21:30

21:30 22:00

22:00 22:30

22:30 23:00

23:00 23:30

23:30 24:00

0.26240.26470.26790.27010.27450.27710.28470.29720.312

0.33290.35520.38030.39830.40750.39670.3866

0.37880.3551

0.33220.31320.30110.28540.25550.2236

Flexible Tariff (Time of Use tariff) daily usage profile - Daily General Usage – Daily Residential Usage with Controlled Load (4,400kWh/yr)
Time

Usage
(kWh)

Time

Usage
(kWh)

00:00 00:30

00:30 01:00

01:00 01:30

01:30 02:00

02:00 02:30

02:30 03:00

03:00 03:30

03:30 04:00

04:00 04:30

04:30 05:00

05:00 05:30

05:30 06:00

06:00 06:30

06:30 07:00

07:00 07:30

07:30 08:00

08:00 08:30

08:30 09:00

09:00 09:30

09:30 10:00

10:00 10:30

10:30 11:00

11:00 11:30

11:30 12:00

0.18920.17230.161

0.15180.14530.141

0.13860.13760.13990.14540.15720.17270.19630.224

0.24790.25520.25510.25170.2512

0.25

0.248

0.247

0.24620.248512:00 12:30

12:30 13:00

13:00 02:00

13:30 03:00

14:00 14:30

14:30 15:00

15:00 15:30

15:30 16:00

16:00 16:30

16:30 17:00

17:00 17:30

17:30 18:00

18:00 18:30

18:30 13:00

19:00 19:30

19:30 20:00

20:00 20:30

20:30 21:00

21:00 21:30

21:30 22:00

22:00 22:30

22:30 23:00

23:00 23:30

23:30 24:00

0.251

0.25320.25620.25830.26260.2651

0.27230.28430.29840.31840.33970.36380.381

0.38980.37950.36980.36230.33960.31770.2996

0.288

0.273

0.24440.2139Default market offer prices 2022–23: Draft determination

74

iv.

Essential Energy distribution region

Flexible Tariff (Time of Use tariff) daily usage profile - Daily Residential Usage without Controlled Load (4,600 kWh/yr)
Time

Usage
(kWh)

Time

Usage
(kWh)

00:00 00:30

00:30 01:00

01:00 01:30

01:30 02:00

02:00 02:30

02:30 03:00

03:00 03:30

03:30 04:00

04:00 04:30

04:30 05:00

05:00 05:30

05:30 06:00

06:00 06:30

06:30 07:00

07:00 07:30

07:30 08:00

08:00 08:30

08:30 09:00

09:00 09:30

09:30 10:00

10:00 10:30

10:30 11:00

11:00 11:30

11:30 12:00

0.27010.26950.26140.24780.22540.20220.18450.17330.16890.16920.17780.19090.21350.23640.24650.25880.25970.25250.25210.24980.2466

0.24430.24120.238

12:00 12:30

12:30 13:00

13:00 02:00

13:30 03:00

14:00 14:30

14:30 15:00

15:00 15:30

15:30 16:00

16:00 16:30

16:30 17:00

17:00 17:30

17:30 18:00

18:00 18:30

18:30 13:00

19:00 19:30

19:30 20:00

20:00 20:30

20:30 21:00

21:00 21:30

21:30 22:00

22:00 22:30

22:30 23:00

23:00 23:30

23:30 24:00

0.24

0.2404

0.24

0.238

0.23850.24040.24590.257

0.2706

0.28830.31870.35610.37830.37940.36690.35330.3416

0.32830.31880.31110.31130.29740.28430.2777

Flexible Tariff (Time of Use tariff) daily usage profile - Daily General Usage – Daily Residential Usage with Controlled Load (4,600 kWh/yr)
Time

Usage
(kWh)

Time

Usage
(kWh)

00:00 00:30

00:30 01:00

01:00 01:30

01:30 02:00

02:00 02:30

02:30 03:00

03:00 03:30

03:30 04:00

04:00 04:30

04:30 05:00

05:00 05:30

05:30 06:00

06:00 06:30

06:30 07:00

07:00 07:30

07:30 08:00

08:00 08:30

08:30 09:00

09:00 09:30

09:30 10:00

10:00 10:30

10:30 11:00

11:00 11:30

11:30 12:00

0.27010.26950.26140.24780.22540.20220.18450.17330.16890.16920.17780.19090.21350.23640.24650.25880.25970.25250.25210.24980.2466

0.24430.24120.238

12:00 12:30

12:30 13:00

13:00 02:00

13:30 03:00

14:00 14:30

14:30 15:00

15:00 15:30

15:30 16:00

16:00 16:30

16:30 17:00

17:00 17:30

17:30 18:00

18:00 18:30

18:30 13:00

19:00 19:30

19:30 20:00

20:00 20:30

20:30 21:00

21:00 21:30

21:30 22:00

22:00 22:30

22:30 23:00

23:00 23:30

23:30 24:00

0.24

0.2404

0.24

0.238

0.23850.24040.24590.257

0.2706

0.28830.31870.35610.37830.37940.36690.35330.3416

0.32830.31880.31110.31130.29740.28430.2777

Default market offer prices 2022–23: Draft determination

75

v.

South Australian Power Networks distribution region

Flexible Tariff (Time of Use tariff) daily usage profile - Daily Residential Usage without Controlled Load (4,000 kWh/yr)
Time

Usage
(kWh)

Time

Usage
(kWh)

00:00 00:30

00:30 01:00

01:00 01:30

01:30 02:00

02:00 02:30

02:30 03:00

03:00 03:30

03:30 04:00

04:00 04:30

04:30 05:00

05:00 05:30

05:30 06:00

06:00 06:30

06:30 07:00

07:00 07:30

07:30 08:00

08:00 08:30

08:30 09:00

09:00 09:30

09:30 10:00

10:00 10:30

10:30 11:00

11:00 11:30

11:30 12:00

0.27180.31370.29820.24160.206

0.18260.17110.15510.14430.14

0.14320.15210.16990.18510.204

0.21090.2022

0.19540.19350.19230.19250.19240.19270.193912:00 12:30

12:30 13:00

13:00 02:00

13:30 03:00

14:00 14:30

14:30 15:00

15:00 15:30

15:30 16:00

16:00 16:30

16:30 17:00

17:00 17:30

17:30 18:00

18:00 18:30

18:30 13:00

19:00 19:30

19:30 20:00

20:00 20:30

20:30 21:00

21:00 21:30

21:30 22:00

22:00 22:30

22:30 23:00

23:00 23:30

23:30 24:00

0.1956

0.1956

0.19640.19640.2

0.20260.20950.22090.23920.263

0.29590.329

0.3472

0.3486

0.33950.32970.31930.3077

0.2916

0.26990.244

0.21920.20760.2463

Flexible Tariff (Time of Use tariff) daily usage profile - Daily General Usage – Daily Residential Usage with Controlled Load (4,200 kWh/yr)
Time

Usage
(kWh)

Time

Usage
(kWh)

00:00 00:30

00:30 01:00

01:00 01:30

01:30 02:00

02:00 02:30

02:30 03:00

03:00 03:30

03:30 04:00

04:00 04:30

04:30 05:00

05:00 05:30

05:30 06:00

06:00 06:30

06:30 07:00

07:00 07:30

07:30 08:00

08:00 08:30

08:30 09:00

09:00 09:30

09:30 10:00

10:00 10:30

10:30 11:00

11:00 11:30

11:30 12:00

0.28540.32940.31310.2536

0.21630.19170.1796

0.16280.15150.147

0.15040.15970.17840.19430.21420.22150.21230.20520.20310.20190.20220.202

0.20230.2036

12:00 12:30

12:30 13:00

13:00 02:00

13:30 03:00

14:00 14:30

14:30 15:00

15:00 15:30

15:30 16:00

16:00 16:30

16:30 17:00

17:00 17:30

17:30 18:00

18:00 18:30

18:30 13:00

19:00 19:30

19:30 20:00

20:00 20:30

20:30 21:00

21:00 21:30

21:30 22:00

22:00 22:30

22:30 23:00

23:00 23:30

23:30 24:00

0.20530.20540.20620.20620.21

0.21270.22

0.23190.25110.27620.31070.34540.36450.36610.35650.34620.33530.32310.30610.28340.25620.23010.218

0.2586

Default market offer prices 2022–23: Draft determination76

Flexible Tariff (Time of Use tariff) daily usage profile - Daily Controlled Load usage – (1,800 kWh/yr)
Time

Usage
(kWh)

Time

Usage
(kWh)

00:00 00:30

00:30 01:00

01:00 01:30

01:30 02:00

02:00 02:30

02:30 03:00

03:00 03:30

03:30 04:00

04:00 04:30

04:30 05:00

05:00 05:30

05:30 06:00

06:00 06:30

06:30 07:00

07:00 07:30

07:30 08:00

08:00 08:30

08:30 09:00

09:00 09:30

09:30 10:00

10:00 10:30

10:30 11:00

11:00 11:30

11:30 12:00

0.17610.17610.17610.17610.17610.17610.17610.17610.17610.17610.17610.17610.1761

0

0

0

0

0

0

0

0.24660.24660.24660.2466

12:00 12:30

12:30 13:00

13:00 02:00

13:30 03:00

14:00 14:30

14:30 15:00

15:00 15:30

15:30 16:00

16:00 16:30

16:30 17:00

17:00 17:30

17:30 18:00

18:00 18:30

18:30 13:00

19:00 19:30

19:30 20:00

20:00 20:30

20:30 21:00

21:00 21:30

21:30 22:00

22:00 22:30

22:30 23:00

23:00 23:30

23:30 24:00

0.24660.24660.24660.24660.24660.2466

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0.1761

Default market offer prices 2022–23: Draft determination77c) Controlled Load (CL) annual usage allocationsi.

Ausgrid distribution region (kWh/year)

CL1 only

2,000

ii.

2,200

CL1 (67%)

CL2 (33%)

1,340

660

2,000

CL 2 only

CL 1 and 2 (% of total)
CL 1 (67%)

CL 2 (33%)

1,474

726

2,200

Energex distribution region (kWh/year)

CL 1 only

1,900

iv.

CL 1 and 2 (% of total)

Endeavour Energy distribution region (kWh/year)

CL 1 onlyiii.

CL2 only

CL 2 only

CL 1 and 2 (% of total)
CL 1 (29%)

CL 2 (71%)

551

1,349

1,900

Essential Energy distribution region (kWh/year)

CL 1 only

2,000

CL 2 only

CL 1 and 2 (% of total)
CL 1 (77%)

CL 2 (23%)

1,540

460

2,000

Default market offer prices 2022–23: Final determination78

South Australian Power Networks distribution region (kWh/year)113

v.

7.

CL 1 only

CL 2 only

CL 1 and 2

1,800

NA

NA

Per-customer annual price determination
In accordance with s 16(1)(b) of the Regulations, the AER determines what it considers
the reasonable per-customer annual price for supplying electricity in specified distribution
regions to small customers of the types set out below.

Per-customer annual price determination (all prices GST-inclusive)
Annual Residential
Price without
Controlled Load

Annual Residential Price with
Controlled Load

Ausgrid$1,512$2,122$4,360Endeavour Energy$1,836$2,383$3,782

Energex$1,620$1,961$3,446

Essential Energy$2,092$2,490$4,901SA Power Networks$1,840$2,275$4,539Distribution
regionSmallBusiness
Annual PriceDATED THIS 26 DAY OF
MAY 2022

Australian Energy Regulator

113

Refer to section 6.b)v. for the daily usage profile for the TOU controlled load tariff.

Default market offer prices 2022–23: Final determination

79

F DMO 3 to DMO 4 price movements
The charts in this appendix show the movement in the DMO cost components between
DMO 3 and DMO 4, with the overall height indicating the total DMO price.
We note that:•

Network and environment cost components in DMO 4 are calculated using the same
methodology as DMO 3, so the changes directly reflect year-on-year movement.

•

Changes to the wholesale cost component incorporate the impact of methodologicaladjustments, including the use of the 75th percentile estimate and the inclusion of AEMO
direction costs in South Australia.

•

The move to a cost build-up approach means DMO 4 has no residual component. Thishas been replaced by a retail cost component and a separate retail allowance.

•

Due to our use of the new 10,000 kWh per year small business usage benchmark, directcomparisons between DMO 3 and DMO 4 small business prices are not possible. For
illustrative purposes, Figure F.3 compares the DMO 3 price with an indicative DMO 4
price based on the previous 20,000 kWh/year benchmark.

Figure F.1 Residential without CL, % change from DMO 3 (nominal)

Default market offer prices 2022–23: Final determination

80Figure F.2 Residential with CL, % change from DMO 3 (nominal)

Figure F.3 Small business, % change from DMO 3 (nominal)

Note: Small business DMO 4 prices in this figure are based on 20,000 kWh of usage for comparison purposes.

Default market offer prices 2022–23: Final determination

81

G Analysis of DMO 4 final retail costs and margins
Figure G.1 Ausgrid, residential without controlled load, DMO 3 residual, DMO 4 retailallowance and retail operating costs, % of DMO 4 price

Figure G.2 Endeavour, residential without controlled load, DMO 3 residual, DMO 4
retail allowance and retail operating costs, % of DMO 4 priceDefault market offer prices 2022–23: Final determination

82

Figure G.3 Essential, residential without controlled load, DMO 3 residual, DMO 4 retailallowance and retail operating costs, % of DMO 4 price

Figure G.4 Energex, residential without controlled load, DMO 3 residual, DMO 4 retailallowance and retail operating costs, % of DMO 4 priceDefault market offer prices 2022–23: Final determination

83

Figure G.5 SAPN, residential without controlled load, DMO 3 residual, DMO 4 retailallowance and retail operating costs, % of DMO 4 price

Figure G.6 DMO regions, residential customers, DMO 3 residual, DMO 4 retailallowance and retail operating costs, % of DMO 4 priceDefault market offer prices 2022–23: Final determination

84

Figure G.7 Ausgrid, residential with controlled load, DMO 3 residual, DMO 4 retailallowance and retail operating costs, % of DMO 4 price

Figure G.8 Endeavour, residential with controlled load, DMO 3 residual, DMO 4 retailallowance and retail operating costs, % of DMO 4 priceDefault market offer prices 2022–23: Final determination

85

Figure G.9 Essential, residential with controlled load, DMO 3 residual, DMO 4 retailallowance and retail operating costs, % of DMO 4 price

Figure G.10 Energex, residential with controlled load, DMO 3 residual, DMO 4 retailallowance and retail operating costs, % of DMO 4 priceDefault market offer prices 2022–23: Final determination

86

Figure G.11 SAPN, residential with controlled load, DMO 3 residual, DMO 4 retailallowance and retail operating costs, % of DMO 4 price

Figure G.12 Ausgrid, small business, DMO 3 residual, DMO 4 retail allowance andretail operating costs, % of DMO 4 priceDefault market offer prices 2022–23: Final determination

87

Figure G.13 Endeavour, small business, DMO 3 residual, DMO 4 retail allowance andretail operating costs, % of DMO 4 price

Figure G.14 Essential, small business, DMO 3 residual, DMO 4 retail allowance andretail operating costs, % of DMO 4 priceDefault market offer prices 2022–23: Final determination

88

Figure G.15 Energex, small business, DMO 3 residual, DMO 4 retail allowance andretail operating costs, % of DMO 4 price

Figure G.16 SAPN, small business, DMO 3 residual, DMO 4 retail allowance and retail
operating costs, % of DMO 4 priceDefault market offer prices 2022–23: Final determination

89

Figure G.17 DMO regions, small business, DMO 3 residual, DMO 4 retail allowance andretail operating costs, % of DMO 4 priceDefault market offer prices 2022–23: Final determination

90