Consultation Paper:
Aligning Network Charges to
the Cost of Peak Demand
(Long Run Marginal Cost)
March 2015
……………………………………………………………………………………
Ergon Energy is seeking further customer and stakeholder input as we progress our
future network tariff strategy.
There has been a major shift in the way Ergon Energy’s customers use the electricity
network over recent years. In response, to help ensure we can continue to meet our
customers’ needs into the future for the best possible price, we are changing the way
we charge for the use of the network. The changes will also make network charges
more equitable.
Our proposed changes aim to help our customers make informed decisions,
especially when making investments relating to their use of electricity. To do this we
are restructuring charges so that they better reflect the impact of a customer’s
electricity use on the electricity network.
Our reform journey has already started. Following consultation with stakeholders, we
introduced a number of new tariffs and made structural changes to some tariffs in
July 2014. We are now focused on further changes for 2015-16 and beyond.
This paper builds on the Consultation Paper Future Network Tariffs, released in
December 2014, with a particular focus on the issue of Long Run Marginal Cost – an
important element of future network tariff design.
……………………………………………………………………………………
Purpose of this consultation paper
……………………………………………………………………………………
The purpose of this supplementary consultation paper is to:
 articulate Ergon Energy’s considerations in determining our Long Run Marginal Cost
(LRMC) and where and how it is applied in the tariffs for each user group

provide an opportunity for our customers and other stakeholders to provide further input
and feedback into the future network tariff development process

facilitate feedback that will allow us to deliver network tariff outcomes that are in the best
long-term interests of customers and Ergon Energy overall.
This paper builds on the consultation process undertaken to date. We are, at the same time,
consulting on our proposal to bring forward the introduction of a voluntary seasonal Time of
Use demand tariff for residential and small business customers in July 2015. This and earlier
consultation papers and associated documents are available at
www.ergon.com.au/futurenetworktariffs
Consultation Paper Network Tariff Strategy
1
1. Overview
Ergon Energy’s network tariff reform journey commenced in 2013 and is expected to continue over
a number of years. We are transitioning gradually – toward more efficient pricing – to minimise the
potential scale of the annual price impact on individual customers as well as any implementation
issues. The content of this paper focuses on changes we would like to implement from 1 July 2015,
as well as our longer-term tariff development and reform pathway.
The network tariff reform journey
* Our ongoing consultation process will support the development of our Tariff Structure Statement.
Consultation Paper: Aligning Network Charges to the Cost of Peak Demand
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2. What are we consulting on now and why?
In December 2014 we released a consultation paper that focused on the changes we would like to
implement from 1 July 2015, as well as our longer-term tariff development and reform pathway.
In this supplementary consultation paper we emphasise the importance of aligning charges to the
incremental network costs associated with the increase of co-incident peak demand. We estimate
the Long Run Marginal Cost (LRMC) as the present value of the cost that we need to incur over
the long run to manage an additional kW of customer demand on the network at peak times.
This LRMC is a key pricing signal because it is cumulative additional peak demand that will drive
future network augmentation (capital investment) and increase Ergon Energy’s future cost base.
We are, at the same time, also consulting on our proposal to bring forward the introduction of a
voluntary seasonal Time of Use demand tariff for residential and small business customers in July
2015. The Consultation Paper The Case for Demand Based Tariffs is available online.
2.1
Supporting documents for this consultation
In addition to this consultation paper the following documents are available for further information.

Long Run Marginal Cost Considerations in Developing Network Tariffs

Estimating the Average Incremental Cost of Ergon Energy’s Distribution Network Average
Incremental Cost Approach; prepared by Harry Colebourn Pty Ltd.
3. Long Run Marginal Cost – an important element in pricing
Incorporation of LRMC into network tariff rates is one of the key changes incorporated into the rule
change made by the Australian Energy Market Commission (AEMC) with regards to the future
development of network tariffs. Moving forward Ergon Energy, and all distributors, will need to
demonstrate that tariffs submitted to the Australian Energy Regulator (AER) for approval are based
on LRMC.
For 2015-16, our intention is to anchor peak demand charges to the LRMC in a new optional
seasonal Time of Use (ToU) demand tariffs that will be offered to the Standard Asset Customers
Large (SAC-Large) segment. In the case of Standard Asset Customers Small (SAC-Small) ToU
tariffs where energy is used, the 2015-16 peak energy rate will again refer back to the LRMC.
Figure 1: Voluntary SAC-Large Seasonal Time of Use Demand Tariff
The Long Run Marginal
Rate will form the basis of
the peak demand rate.
Residual costs will be
recovered through the
other elements of the tariff
in a way that does not
distort the pricing signal in
the peak demand rate.
Consultation Paper: Aligning Network Charges to the Cost of Peak Demand
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4. Our current approach to Long Run Marginal Cost
Many of our current tariffs do not align charges to network costs associated with peak demand.
This will change in the future. Nevertheless, some existing tariffs have some element of cost
reflectivity.
For example, in determining rates for the new SAC-Small seasonal ToU energy tariffs introduced in
2014-15, Ergon Energy used a benchmark cost of supply (BCS) as a proxy for a broad-based
network-wide LRMC. The BCS was originally developed to assess the appropriateness of
undertaking non-network alternative initiatives, but it can also be used as a rough estimate of
LRMC across the network as a whole.
The BCS is a measure of the network-average cost (in $/kVA/year) of providing additional network
capacity to meet additional peak demand at the high voltage level of the network. The BCS is
derived using data from across the network and is not based on augmentation costs at any
individual location or customer tariff class.
The most recent estimate of Ergon Energy’s BCS is $162/kVA/year, which represents a network
average value based on the capital works program at the time of compilation.
5. Why we are reviewing Long Run Marginal Cost
Recent changes to the National Electricity Rules (NER) require Ergon Energy to employ a robust
method of calculating and applying LRMC; having regard to a number of considerations, including
the:

costs and benefits of each approach to calculating and applying a particular tariff formulation

additional costs likely to be associated with meeting demand from the customers assigned to
the tariff at times of greatest utilisation of the relevant part of the distribution network

geographic location of customers assigned to the tariff and the extent to which costs might vary
between different locations in the distribution network.
The AER has also been given more powers to scrutinise our approach to calculating LRMC. On
this basis we have prepared a more detailed supporting document, Long Run Marginal Cost
Considerations in Developing Network Tariffs, for stakeholder consultation.
Consultation Paper: Aligning Network Charges to the Cost of Peak Demand
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6. Summary of our proposed changes
This next section outlines our intentions for changes to LRMC in 2015-16, as summarised here.
Summary of Changes to LRMC in 2015-16
Issue
Proposed changes
Choice of method for
calculating LRMC

Movement away from Benchmark Cost of Supply (BCS) to Average
Incremental Cost (AIC) approach.
Costs to be included
in LRMC


Network demand related capital costs.
Incremental operating and maintenance expenditure associated with
the demand related capital costs.
Allocation of LRMC to
peak charges

Given the relatively large difference between current peak charges
and LRMC based peak charges, we proposing a 50% allocation of
LRMC to the peak charge in 2015-16.
Application of LRMC
to tariffs

For SAC-Large future maximum demand tariff – application to the
customer’s maximum demand during peak times each month.
For SAC-Small future maximum demand tariff – application to the
customer’s demand recorded during peak times for the highest four
days in the month.

6.1
Choice of method for calculating LRMC
Conceptually speaking, there are a number of ways to define and calculate LRMC. The two key
broad approaches highlighted by the AEMC are the Turvey ‘perturbation’ approach and the
Average Incremental Cost (AIC) approach. These are detailed in our supporting document.
We note in our consultation paper that BCS, while a useful proxy for LRMC, is not completely
consistent with either methods recommended by policy makers. Section 3.3 of Ergon Energy’s
“Long Run Marginal Cost Considerations in Developing Network Tariffs” report provides further
analysis of the BCS and why it differs to other calculations of LRMC.
Using Average Incremental Cost as a basis for calculating LRMC in 2015-16
The AIC approach to estimating LRMC takes the present value of incremental costs expected to be
incurred over a future period of time and divides this by the Net Present Value (NPV) of the
additional demand expected to be served over the same period.
Consultation Paper: Aligning Network Charges to the Cost of Peak Demand
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The formulation of the AIC in $/kW/year is as follows:
AIC =
NPV (Demand related capital cost, $/yr + Incremental O&M, $/yr)
NPV (Incremental network demand, kW)
Where:
Demand related capital cost
is the annual increment in capital cost, calculated using a
capital recovery factor for the incremental capital
expenditure. An asset life of 40 years is assumed for this
calculation.
Incremental O&M
is the annual increment in operational and maintenance
expenditure, calculated as a percentage of the
incremental capital expenditure.
Incremental network demand
is the year-on-year increase in demand in kW.
This calculation is repeated for three functional levels of the network: subtransmission, high voltage
and low voltage. It is then converted to a marginal cost in $/kVA/year using the average power
factor for the voltage level concerned for application to network tariff setting. We have assessed
AIC over a 25 year period.
Proposal to use Long Run Incremental Cost to substantiate AIC LRMC value
The Long Run Incremental Cost (LRIC) approach calculates the annualised cost of the next
proposed investment measured relative to an increment in demand. An example of this approach
is the Common Distribution Charging Methodology (CDCM), which has formed the basis for
distribution tariffs in the United Kingdom for many years.1
This model is based upon the creation of a hypothetical network for the supply of a demand
increment of 500MW, using the spatial characteristics and standardised equipment typical for the
distributor.
Ergon Energy is developing this model to validate the findings of the AIC method.
Turvey perturbation and the dynamic layer
The Perturbation approach is based on deriving the present value cost of the additional capacity
required to serve a hypothetical permanent increase in forecast demand at a particular location.
While this methodology is conceptually the closest to reflecting ‘true’ LRMC, it has the
disadvantage that it effectively requires the re-estimation of the entire capital and operating
expenditure programs for an assumed increased demand growth. Deriving individual LRMCs for
multiple locations, for every potential size and type of customer and at different points in time
would be extremely time-consuming and impracticable, particularly for a network area of Ergon
Energy’s size.
1
Energy Networks Association (UK), CDCM model user manual Model Version: 102, 28 February 2013.
Consultation Paper: Aligning Network Charges to the Cost of Peak Demand
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An alternative to determining a multitude of LRMCs is to overlay a ‘dynamic layer’ of bespoke
demand management or other non-network incentives/mechanisms on top of generic LRMCs to
encourage efficient non-network options in specific locations at specific times where generic
LRMCs are likely to be particularly inaccurate. Such bespoke options can be developed by taking
advantage of Ergon Energy’s knowledge of specific local network and loading conditions and
particular customers’ characteristics.
6.2
What costs should be included in LRMC
Having defined LRMC and proposed a method for calculation, the next step is to work out which
network costs ought to be included in the calculation of LRMC. The principal inputs to Ergon
Energy's AIC calculation are included in our supporting document, Estimating the Average
Incremental Cost of Ergon Energy’s Distribution Network Average Incremental Cost Approach, and
are summarised as follows:

network demand related capital costs

operating and maintenance expenditure associated with the demand related capital costs

the incremental network demand.
Network demand related capital costs
The sources for demand related capital costs were based on the information accompanying Ergon
Energy’s Regulatory Proposal and include the following:

augmentation expenditure

connections expenditure offset by the capital contributions made by customers

a small proportion of replacement expenditure (2.5%) recognising a proportion of repex results
in increasing the capability of assets as modern equivalent assets frequently have higher
capacity than those they replace.
Capitalised overheads were allocated to the three capital expenditure categories.
Operating and maintenance expenditure
Operating and maintenance costs relevant to the network demand related capital costs are
assumed at 2.5% of new capital expenditure. However some differentiation is made between high
voltage assets and low voltage assets (given that lower voltage assets are more maintenance
intensive). Some allowance is made for the fact that newly commissioned assets do not require full
maintenance for a period.
The incremental network demand
A demand forecast is required for each functional level of the network, from which the incremental
demand is derived in each year. At this point suitable demand forecasts at the system levels are
not developed within Ergon Energy. Our supporting document, Estimating the Average Incremental
Cost of Ergon Energy’s Distribution Network Average Incremental Cost Approach summarises
details of the approach used to develop the incremental network demand based on a variable
growth rate averaging 1.4% over the 2015-20 regulatory control period.
Consultation Paper: Aligning Network Charges to the Cost of Peak Demand
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6.3
Outcome of proposed changes
Using the analysis, detailed in the supporting document, provides AIC values for Ergon Energy
tariff setting in range set out below. The right hand column sets out the LRMC values of 50% of
AIC that are now proposed for adoption in Ergon Energy’s network tariffs in 2015-16.
System Level
Current BCS
AIC
$/kVA p.a.
AIC/
Average Cost
50% of AIC
$/kVA p.a.
-
$40-$50
20%-25%
$23
High voltage
$162
$350-$430
42%-52%
$195
Low voltage
-
$470-$580
51%-60%
$263
Subtransmission
$/kVA p.a.
It should be noted that the proposed cost level for customers at the high voltage level represents a
20% increase on the nominal 2011-12 BCS value of $162/kVA per annum. More importantly, the
changes in Ergon Energy’s tariffs will eventually reflect the direct application of the LRMC to setting
peak period charges, as is now required by the NER.
6.4
Application to tariffs impacted by the change
Apart from the subtransmission level of the network, the LRMC values represented by the revised
AIC calculation are significantly higher that the charges currently applied ($162/kVA p.a.).
The higher value attributable to determining AIC compared to our BCS proxy is a result of the use
of a different approach and methodology. We expect that, given the changes to the NER, Ergon
Energy will need to move towards the AIC values.
However, rather than moving immediately to the AIC LRMC values, we intend to adopt LRMC
values for different voltage-level customer classes equal to 50% of the calculated AIC figures. Our
rationale for this approach is that:

the AIC calculation of LRMC is substantially higher than the LRMC that currently applies and,
in accordance with the NER, we consider that the impact on customers of an immediate
adoption of the full AIC values would be too extreme

there is a degree of uncertainty regarding the level of expenditure and demand, which will
ultimately be determined for Ergon Energy by the AER’s distribution determination for the
2015-20 period.
In structuring tariffs to reflect LRMC (howsoever derived), it is important for tariffs to be based on
the variable(s) with the greatest ability to influence future costs. Tariffs should signal the costs of
serving additional demand at peak network utilisation times2 – meaning that charges should ideally
only be based on a customer’s individual peak demand or usage to the extent that either a
customer’s individual peak demand:

is an important driver of shared network costs, and/or

coincides with peak utilisation of the relevant part of the network.
2
In Ergon Energy LRMC is recovered in the peak summer months – December, January and February.
Consultation Paper: Aligning Network Charges to the Cost of Peak Demand
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6.5
Indicative Impact on Customers
SAC-Small Residential Seasonal ToU energy
Estimates of SAC-Small Residential seasonal ToU energy (SToUE) tariff rates based on 50%
LRMC and 100% LRMC are outlined below. These are compared to both the existing optional
2014-15 seasonal ToU energy tariff and the default inclining block tariff for the same tariff class.
Block 1
(0 - 1,000
MWh p.a.)
Block 1
(1,000 - 6,000
MWh p.a.)
Block 1
(6,000-20,000
MWh p.a.)
($/kWh)
($/kWh)
($/kWh)
$0
$0.15
$0.16
$1.52
Peak
Shoulder
Off-Peak
Fixed
($/kWh)
($/kWh)
($/kWh)
($/day)
$0.55*
$0.27**
$0.10
$1.52
SToUE (50% LRMC)
$0.56***
-
$0.07
$1.52
SToUE (100% LRMC)
$1.13***
-
$0.05
$0.95
Inclining Block Default
Tariff
Inclining Block Tariff (2014-15)
SToU Energy Optional
Tariff
SToUE (2014-15 BCS)
Fixed
($/day)
* Applies from 4:30pm to 9:00pm on Summer weekdays
** Applies from 3pm to 4:30pm and 9:00pm to 9:30 pm on summer weekdays and 3pm to 9:30pm on summer weekends
*** Applies from 3pm to 9:30pm on all summer days
The network bill for a typical small residential customer, consuming 4,621kWh per year is shown
below.
$1,400
$1,200
Network Bill ($)
$1,000
$800
$600
$400
$200
$0
SToUE 14/15
SToUE
Current
SToUE
50% LRMC
Peak
Shoulder
Off‐Peak
100% LRMC
Fixed
Under the 50% LRMC seasonal ToU energy tariff, the typical small residential customers saves 2%
on their annual network bill. The customer pays 106% more in peak charges but reduces their offpeak charges by 33%.
Under the 100% LRMC seasonal ToU energy tariff, the typical small residential customers saves
6% on their annual network bill. The customer pays 312% more in peak charges but reduces their
off-peak charges by 53% and their fixed charges by 38%.
Consultation Paper: Aligning Network Charges to the Cost of Peak Demand
9
The network bill for a typical medium residential customer, consuming 9,677kWh p.a. is shown
below.
$2,500
Network Bill ($)
$2,000
$1,500
$1,000
$500
$0
SToUE 14/15
SToUE
SToUE
Current
50% LRMC
100% LRMC
Peak
Shoulder
Off‐Peak
Fixed
Under the 50% LRMC seasonal ToU energy tariff, the typical medium residential customer has an
annual network bill increase of 2%. The customer pays 137% more in peak charges but reduces
their off-peak charges by 38%.
Under the 100% LRMC seasonal ToU energy tariff, the typical medium residential customer has an
annual network bill increase of 20%. This is made up of a 374% increase in peak charges, a 56%
reduction in off-peak charges and a 38% reduction in fixed charges.
SAC-Small Business Seasonal ToU energy
Estimates of SAC-Small Residential seasonal ToU tariff rates based on 50% LRMC and 100%
LRMC are outlined below. These are compared to both the existing optional 2014-15 seasonal
ToU energy tariff and the default inclining block tariff for the same tariff class.
($/kWh)
Block 1
(1,000 - 20,000
MWh p.a.)
($/kWh)
Block 1
(20,000100,000 MWh
p.a.)
($/kWh)
$0
$0.15
$0.16
$1.52
Peak
Shoulder
Off-Peak
Fixed
($/kWh)
($/kWh)
($/kWh)
($/day)
$0.41*
$0.31**
$0.12
$1.52
SToU Energy (50% LRMC)
$0.56***
-
$0.10
$1.52
SToU Energy (100% LRMC)
$1.13***
-
$0.03
$1.52
Inclining Block Default
Tariff
Inclining Block Tariff (2014-15)
SToU Energy Optional
Tariff
SToU Energy (2014-15 BCS)
Block 1
(0 - 1,000 MWh
p.a.)
Fixed
($/day)
* Applies from 11.30am to 5:30pm on Summer weekdays
** Applies from 10.00am to 11:30am and 5:30pm to 8:00 pm on summer weekdays
*** Applies from 10.00am to 8:00 pm on summer weekdays
Consultation Paper: Aligning Network Charges to the Cost of Peak Demand
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The network bill for a typical small business customer, consuming 4,003kWh per year is shown in
below.
$1,400
$1,200
Network Bill ($)
$1,000
$800
$600
$400
$200
$0
SToUE 14/15
SToUE
SToUE
Current
50% LRMC
100% LRMC
Peak
Shoulder
Off‐Peak
Fixed
Under the 50% LRMC seasonal ToU energy tariff, the typical small business customer saves 0.7%
on their annual network bill. The customer pays 121% more in peak charges but reduces their offpeak charges by 25%.
Under the 100% LRMC seasonal ToU energy tariff, the typical small business customer saves 1%
on their annual network bill. The customer pays 203% more in peak charges but reduces their offpeak charges by 77%.
The network bill for a typical medium business customer, consuming 33,518kWh p.a. is shown
below.
$6,000
Network Bill ($)
$5,000
$4,000
$3,000
$2,000
$1,000
$0
SToUE 14/15
SToUE
SToUE
Current
50% LRMC
100% LRMC
Peak
Shoulder
Off‐Peak
Fixed
Under the 50% LRMC seasonal ToU energy tariff, the typical medium business customer has an
annual network bill decrease of 3.1%. The customer pays 130% more in peak charges but reduces
their off-peak charges by 24%.
Consultation Paper: Aligning Network Charges to the Cost of Peak Demand
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Under the 100% LRMC seasonal ToU energy tariff, the typical medium business customer has an
annual network bill decrease of 19%. This is made up of a 205% increase in peak charges;
however, the customer also experiences a 77% reduction in off-peak charges.
Seasonal ToU demand SAC-Small Business and Residential
We are currently also consulting on a proposal to bring forward the introduction of a voluntary
seasonal Time of Use demand tariff for residential and small business customers to 1 July 2015.
For our initial modelling of the indicative price impact of this tariff refer to the Consultation Paper
The Case for Demand Based Tariffs.
7. Opportunity to make a submission
Ergon Energy is committed to working with our customers and other stakeholders to ensure we
evolve our network tariffs in a way that delivers the best long-term outcome for regional
Queensland. To ensure we do this we would appreciate your input.
Our preference is for submissions to be lodged by email. Comments and enquiries regarding this
consultation paper are also welcome. Ergon Energy will consider all submissions received in the
submission period.
In the interests of transparency and to promote informed discussion, Ergon Energy would prefer
submissions to be able to be made publicly available wherever this is reasonable. However, if you
do not want your submission to be public, you should clearly claim confidentiality in respect of that
document (or part there-of). In the absence of any claims of confidentiality Ergon Energy will treat
any responses as being able to be made public either in their entirety or partially.
Email submissions (preferred): [email protected]
Written submissions:
Ergon Energy Corporation Limited
Group Manager Regulatory Affairs
PO Box 264
Fortitude Valley QLD 4006
The closing date for submissions is Friday, 27 March 2015.
8. Other reference documents available
The supporting documents, and any additional papers developed will be made public through
Ergon Energy’s website at www.ergon.com.au/futurenetworktariffs
Related documentation is available at www.ergon.com.au/networktariffs. This includes
Ergon Energy’s AER Approved Pricing Proposal 2014-15.
Consultation Paper: Aligning Network Charges to the Cost of Peak Demand
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AEMC
Australian Energy Market Commission
AER
Australian Energy Regulator
AIC
Average Incremental Cost
BCS
Benchmark Cost of Supply
CDCM
Common Distribution Charging Methodology
kW
kilowatt
kWh
kilowatt hour
LRIC
Long Run Incremental Cost
LRMC
Long Run Marginal Cost
MW
megawatt
NPV
Net Present Value
NER
National Electricity Rules
PV
Photovoltaic
QCA
Queensland Competition Authority
SAC-Large
Standard Asset Customers – Large
SAC-Small
Standard Asset Customers – Small
SToUE
seasonal Time-of-Use energy
SToUD
seasonal Time-of-Use demand
ToU
Time-of-Use
Consultation Paper: Aligning Network Charges to the Cost of Peak Demand
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