PLEASE NOTE
The Australian Government is undertaking further design work on a possible national Energy
Savings Initiative (ESI). Reports, such as the one which is provided below, have been prepared
by consultants to assist with this work. However:
•
no decision has been made about whether a national ESI will be introduced;
•
the report should not be interpreted as reflecting Government thinking on the design of
a possible national ESI (for example, comments by consultants about the eligibility of
activities for creating certificates should not be interpreted as a proposed list of eligible
activities under a possible national scheme); and
•
the report should not be interpreted as a commitment by Government to a policy or
course of action.
Peak Energy Savings Scheme Design
Options
A Report for the Energy Savings Initiative Secretariat
22 March 2012
Australian Government Disclaimer
This report was prepared by NERA Economic Consulting and Oakley Greenwood for
the Commonwealth of Australia as represented by the Department of Resources, Energy and
Tourism, as part of the Australian Government’s efforts to investigate the cost and benefits of a
possible national Energy Savings Initiative.
The report includes the views and opinions of third parties and does not necessarily reflect the views
of the Commonwealth of Australia or any Australian State or Territory Government, or indicate a
commitment to a particular policy or course of action.
This report includes the opinions of, and analysis by, NERA Economic Consulting and Oakley
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Project Team
NERA Economic Consulting
Adrian Kemp
Martin Chow
Oakley Greenwood
Lance Hoch
NERA Economic Consulting
Darling Park Tower 3
201 Sussex Street
Sydney NSW 2000
Tel: +61 2 8864 6500
Fax: +61 2 8864 6549
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Oakley Greenwood
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Tel: +61 3 9486 8097
Fax: +61 3 8080 0760
www.oakleygreenwood.com.au
Peak Energy Savings Scheme Design
Options
Contents
Contents
Executive Summary
i
Potential benefits of a peak demand scheme
Evaluation of peak scheme design options
Modelling the benefits of peak savings
i
iii
iv
1.
Introduction
1
2.
The Rationale for a Peak Energy Savings
Scheme
3
2.1.
2.2.
2.3.
2.4.
2.5.
Concepts relevant to a peak energy savings scheme
What is load factor?
Context and rationale
Potential benefits from a peak savings scheme
Objective for a peak savings scheme
3.
Peak Energy Savings Scheme Options
3.1.
3.2.
3.3.
3.4.
Status Quo Arrangements
Option 1: Peak Energy Saving Incentives
Option 2: A Stand-Alone Peak Energy Saving Scheme
Option 3: A Single Buyer of Peak Energy Savings
4.
Modelling the Benefits of Peak Energy
Savings
4.1.
4.2.
4.3.
Modelling generation benefits
Modelling network benefits
Summary
5.
Evaluating Scheme Design Options
5.1.
5.2.
5.3.
5.4.
5.5.
Criteria for assessment
Scheme design and implementation
Scheme benefits
Other considerations
Summary
6.
Further Considerations for the Design of a
National ESI
Appendix A. Peak Technical Group and Network
Modelling Group Members
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List of Tables
Table 4.1 Data Requirements of the Static and Dynamic Approaches to Estimate Wholesale Market
Benefits
Table 4.2 Principal Advantages and Disadvantages of the Deferral and Area-Wide Approaches to
Assessing the Network Benefits of Peak Savings
Table A.1: Organisations that Participated in the Peak Technical Group and Network Modelling
Group
34
38
52
List of Figures
Figure 2.1 Stylised Example of an Activity that Improves Load Factor: Direct Load Control for Air
Conditioners
Figure 2.2 Stylised Example of an Activity that Worsens Load Factor: High Efficiency Street Lighting
Figure 2.3 Maximum Demand by National Regions, 1996-07 to 2010-11
Figure 3.1 Incentives for Peak Demand Reductions under Current Arrangements
Figure 3.2 Option 1: Peak Energy Savings Incentive Scheme
Figure 3.3 Option 2: Stand-Alone Peak Energy Savings Target Scheme
Figure 3.4 Option 3: Single Peak Savings Buyer Scheme
Figure 4.1 Illustrative Alignment of Peak Savings Measure with Network Peaks (Impact of High
Efficient Street Lighting)
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Executive Summary
Concerns about rising electricity prices have led to a renewed focus on the drivers of costs in
the electricity supply chain. One often cited contributing factor for electricity price rises is
the cost of expanding both network and generation capacity to satisfy continuing growth in
peak electricity demand.
Indeed, electricity use during peak periods has been growing at around 1.7 times the rate of
total electricity use over the past ten years. If this continues, then the unit cost of supplying
electricity will also continue to grow as there is a need for:

increased use of peaking generators, which have a higher cost per unit of electricity
produced; and

greater network capacity that is used for a small fraction of the year, and remains idle for
the remainder.
The Australian Government is currently considering options for implementing a possible
national Energy Savings Initiative (ESI) to replace the existing state based schemes.1 As part
of its consideration of design options for a national ESI, NERA Economic Consulting and
Oakley Greenwood have been asked to investigate design options for an incentive or scheme
to explicitly promote peak electricity savings. This report presents the outcomes of this
investigation.
Potential benefits of a peak demand scheme
Central to a consideration of the potential benefits of a peak demand scheme is an
appreciation that the demand for – and the cost to supply – electricity varies depending on
customers’ aggregate needs throughout the day. A ‘peak’ in demand is therefore a normal
phenomenon of this variation in demand and is not in and of itself a sign of a problem. It is
therefore important to consider the rationale for introducing a peak demand scheme within
the existing electricity system and market framework.
It is commonly understood in economics that in a market with many buyers and sellers where
prices represent the cost of supplying the next unit of production, consumers purchase a good
or service up to the point where the value to them is equal to the price. This means that if
electricity prices paid by consumers represented the cost of supplying each unit of electricity,
and if a consumer’s use of electricity did not affect the price paid by any other consumer,
then the use of electricity would be efficient (ie, it would equate the value to the consumer
with the cost). However, because the cost of supply varies considerably depending on the
time and location of use, the actual price faced by consumers rarely equates with the cost of
supply and so either:

more electricity is demanded, particularly during peak times, than is warranted given the
underlying true cost of supply and benefits received from its use; or
1
Subject to economic modelling and a regulatory impact analysis, the Government will make a final decision on whether
to adopt a national energy savings initiative. A national energy savings initiative would be conditional on the agreement
of the Council of Australian Governments and the abolition of existing and planned state schemes.
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
less electricity is demanded, particularly during off-peak times than is warranted given
the underlying true cost of supply and benefits received from its use.
The challenge for the framework applying to the electricity system is to ensure that
consumers face appropriate incentives for peak demand reductions in the absence of price
signals of the true cost of supply at each point in time and location. Addressing this
challenge is not straightforward because:

the benefits of reducing peak demand are split along the supply chain, and so no single
entity along the supply chain will have an incentive to invest appropriately in demand
reductions;

the generation benefits arise from avoiding the cost of new generation investments, and
over time changes to the generation plant mix, which is an avoided cost where the benefit
of which is captured by consumers;

there remains uncertainty as to the reliability of non-network alternatives to network
investments, which creates an additional hurdle to realising the benefits those alternatives
could provide; and

there is a lack of depth in the market for provision of demand management and energy
efficiency services, which means that these services have been unable to achieve
sufficient economies of scale to be cost effective.
The current National Electricity Rules address the split benefit problem by requiring
transmission businesses to explicitly consider non-network alternatives to proposed network
augmentations, and in doing so to consider the entire supply chain benefits and costs. This
means that a non-network alternative that delivers greater net benefits across the entire supply
chain when compared to a network augmentation must be undertaken even if its direct costs
exceed the cost of a proposed network augmentation. This has the effect of transferring part
of the benefit received by consumers from such an option to the network to assist with
funding the proposed non-network investment. While these rule requirements currently apply
only to transmission network investments, similar requirements are being proposed to be
applied to distribution network investments.
We believe that the rules provide an incentive to network operators to consider non-network
solutions to network investments, and should in principle promote efficient investment in
peak demand reducing activities.
That said there remain potential benefits from a peak savings scheme that provides a direct
incentive on reductions to wholesale market peaks, where the cost of reducing peak demand
is less than the forward looking cost of satisfying the peak demand from generation
investments. The wholesale market benefits of peak savings include:

direct generation fuel cost savings from lower electricity use;

new peak generation investment cost savings from investment deferral; and

a reduction in unserved energy.
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These wholesale market benefits arise despite the wholesale market reflecting the cost of
wholesale supply in each five minute interval because:

a customer typically does not face the wholesale market price as retailers manage
wholesale price fluctuations on behalf of end-use customers;

a customer has an incentive to reduce demand during peak periods where the cost (either
direct costs and/or the cost from not using electricity) does not exceed the price paid for
electricity during the peak period; and

the value of a reduction in peak demand, which alters the system load profile and is
sufficient to significantly defer future need for new peak generation capacity, is greater
than the current wholesale price (which only reflects the cost of supplying the current and
expected system load profile).
This combination of factors means that a customer will underinvest in peak demand savings
as compared to the value this investment would reflect for the market as a whole from the
associated peak demand saving.
Evaluation of peak scheme design options
We have considered and evaluated three broad peak energy savings scheme designs, namely:

schemes that provide incentives to promote peak demand reductions as part of a national
Energy Savings Initiative (ESI) – ie, a peak savings incentive within an ESI;

schemes that create a separate obligation on a party to achieve specified reductions in
peak demand – ie, a stand-alone peak savings scheme; and

schemes that directly purchase peak demand reductions within a specified budget – ie, a
peak savings buyer scheme.
Placing a peak savings incentive within an ESI scheme could be achieved through either:

deeming activities that result in peak demand savings as having higher value (ie,
receiving a greater number of certificates); or

requiring obligated parties (ie, retailers) to obtain a portion of the scheme target from
peak savings.
A stand-alone peak savings scheme would stand apart from a national ESI and therefore
creates flexibility to place the target obligation on network businesses as compared with
retailers. By having a peak savings certificate, a direct value would be created for peak
savings as compared to energy savings achieved under a national ESI.
A peak savings buyer scheme is a non-market approach to achieving peak savings outcomes.
It involves the creation of a new role within the electricity system, responsible for achieving
peak savings targets. The buyer could fulfil its role by: standing in the market to purchase all
peak savings at a predetermined price; conducting auctions to purchase peak savings
outcomes in the future; working closely with network businesses and/or demand management
operators to fund identified peak demand activities and achieve voluntary targets; or
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contracting for callable or dispatchable peak demand activities and operating directly in the
wholesale market to reduce wholesale market peaks.
All the peak savings design options are expected to achieve generation sector benefits and
incremental network benefits over the medium to long term. The main differences between
the design options are the incentives and penalties that would be placed on network and
retailer businesses and the likely timeframes for the achievement of benefits.
The advantage of including an incentive for peak savings within an ESI scheme is its ease of
administration and implementation. It also allows sufficient flexibility to adapt to an
improved understanding of the benefits from peak savings and modify the value attributed to
peak savings within the scheme accordingly.
A stand-alone peak savings target suffers from placing additional compliance burdens on
network businesses compared to the inclusion of an incentive within an ESI scheme. The
incremental benefits of this approach compared against the first design option are minimal.
A single peak savings buyer scheme benefits from creating a market for peak savings with
greater revenue certainty for market participants compared with a national ESI and standalone peak savings scheme options. This is because it relies on direct contracts to purchase
peak savings rather than predictions of the likely value of certificates that might be created by
peak savings activities. That said the establishment and ongoing costs of such an approach
would be substantial compared against the earlier design options.
Finally, we believe that an important consideration for the design of an ESI scheme or for any
approach to provide an explicit peak savings incentive is the likely impact on load factor for
the system. Load factor measures the ratio of peak to average electricity demand and so any
deterioration in load factor (ie, if average demand decreases at a higher rate than peak
demand decreases) will result in unit network electricity prices increasing. As a consequence
any energy savings scheme should consider the merits of explicitly recognising and
accounting for this possible outcome in order to avoid the introduction of an energy savings
scheme potentially causing negative outcomes.
Modelling the benefits of peak savings
In addition to considering design options, we were also asked to provide advice on the
methodologies that can be used to model the wholesale and network benefits of peak savings.
In general, there are two approaches that can be used to estimate the wholesale market
benefits of peak savings, namely;

a static approach that multiplies the typical values for peak demand and energy
consumption reductions (that is, the avoided cost associated with generation investments
that do not have to be made, and the cost of fuel that does not need to be used in
generation) by the anticipated savings in peak demand and energy consumption; and

a dynamic approach that estimates the change in cost by simulating the change in plant
mix and fuel usage using an electricity market model.
Overall the dynamic approach is likely to provide a more realistic estimate of the generation
benefits compared with a static approach. While the static approach is significantly easier to
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apply, the data and computing resources needed for the dynamic approach are generally
readily available.
There are two principal approaches to calculating network benefits, these are:

the deferral approach, which uses a bottom-up approach to estimate network benefits by
examining actual projects and considering which projects could be deferred if peak
demand savings were to be achieved; and

the area-wide demand reduction approach, which is a top-down approach that assumes
that peak demand reductions made anywhere in the network will result in reduced need
for capital expenditure in the long run.
Applying the deferral approach is particularly complex given the detailed network data
required, as savings only occur in locations where additional capacity is required in the
foreseeable future. A detailed understanding of these opportunities is required and so this
approach can only be practically done for time periods where distribution companies have
forecasts of additional network capacity needs, which is typically for five years.
To estimate network benefits over a longer time horizon, an area-wide approach is more
likely to be appropriate. An area-wide approach can be used to account for some network
areas experiencing very slow (or even negative) growth, and other areas experiencing peak
demands at different times of the day or seasons.
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1.
Introduction
Introduction
Electricity use during peak periods has been growing at around 1.7 times the rate of total
electricity use over the past ten years. Growing peak demand has a disproportionate impact
on household bills because it results in:

increased use of peaking generators, which have a higher cost per unit of electricity
produced; and

the need for network capacity that is used for a small fraction of the year, and remains
idle for the remainder.
If electricity use was not so variable over a year, the total cost of supplying electricity would
be lower because less physical infrastructure would be needed, lower cost generation could
be used to supply electricity and the average cost of providing network capacity would also
be lower.
Given concerns about the network and generation cost implications of growing peak demand,
NERA Economic Consulting (NERA) and Oakley Greenwood (OGW) have been asked to
investigate design options for a scheme to reduce peak electricity demand. This investigation
has been undertaken within the context of a wider review of the merits of implementing a
national Energy Savings Initiative scheme to provide direct incentives to promote overall
energy efficiency.
To assist with the investigation of peak energy savings scheme design options, a Peak
Technical Group (PTG) and Network Modelling Group (NMG) were formed to provide an
advisory and review role for the project. The groups were made up of representatives of
electricity retailers, networks and generation, energy savings companies, and regulators. The
groups met on a number of occasions between November 2011 and February 2012 and
provided input on the design options presented in this paper. We have benefited considerably
from these discussions, but the remainder of this paper reflects our opinions on the relative
merits of the design options considered.
In this report we outline three broad design options for a peak energy savings scheme, and
examine the relative merits of each scheme. We also examine the methodologies for
estimating the benefits of such a scheme, and the associated data requirements.
The remainder of this report explains these scheme options in greater detail, and is structured
as follows:

chapter 2 sets out the rationale for a peak energy efficiency scheme;

chapter 3 describes each of the design options that have been investigated in detail,
namely: a specific peak energy saving incentive within a broader energy savings scheme,
a stand-alone peak energy savings scheme, and a peak energy savings buyer scheme;

chapter 4 discusses methodologies for estimating the benefits of a peak energy savings
scheme, with a particular focus on estimating network deferral benefits, and the
associated data requirements;
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Introduction

chapter 5 provides an evaluation of the scheme options against a number of identified
criteria for assessment; and

chapter 6 sets out some further considerations for the design of an ESI Scheme.
Appendix A provides a list of the organisations that were represented in the PTG and NMG
meetings.
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2.
The Rationale for a Peak Energy Savings Scheme
The Rationale for a Peak Energy Savings Scheme
This chapter explains some of the key electricity supply chain concepts relevant for a
consideration of peak energy savings, and also provides the rationale for a peak energy
saving scheme.
2.1. Concepts relevant to a peak energy savings scheme
Before considering peak energy savings design options, it is important to have a common
understanding about what is the ‘peak’. In this section we explain how ‘peak’ can be defined,
while also explaining the concept of ‘load factor’ and the distinction between demand
management and energy efficiency. These concepts are relevant for any scheme design.
2.1.1.
What is the ‘peak’?
The starting point for a consideration of a peak energy savings scheme is to consider what is
meant by a ‘peak’. The peak can relate to either:

the half hourly period within an electricity supply system within a year where demand is
at its maximum;

the half hourly period within an electricity supply system within a year where the half
hourly wholesale market settlement price2 is at its maximum;3

the period of half hours that represent the top say 10 per cent4 of total load or wholesale
prices within an electricity supply system within a year;

the period of highest demand or wholesale price within an electricity supply region within
a day; or

a localised network maximum demand, either over a year or day.
These different definitions of what a ‘peak’ is highlights that the peak can be defined for
either electricity demand or wholesale price, with reference to:

the period of time over which the demand or price is considered to be at its peak (eg, a
year, a quarter, or a day);

the length of the period that is considered to be ‘peak’ (eg, 10 per cent of total periods);
and

the geographic area over which the demand or price is considered to be at its peak (eg, a
NEM region, subregion or a defined distribution network or sub-network).
2
The half hourly wholesale market settlement price (ie, the half hourly spot price) is calculated as the average of the six
dispatch prices within the half hour period. The dispatch prices are determined every 5 minutes by actual demand and
dispatch price submitted by the generators.
3
Peak price and peak demand may not occur within the same half hour period within a year.
4
10 per cent has been chosen here as an illustrative example only.
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The Rationale for a Peak Energy Savings Scheme
For the purpose of this paper there is no need to decide on a single definition of ‘peak’ as this
choice is immaterial to a consideration of design options. Any of the designs considered can
be tailored to any definition of ‘peak’ that is preferred.
That said, the choice of definition for the peak requires consideration to be given to:

the benefits of targeting different peaks during particular times of the year or geographic
locations; compared against

the administrative costs and ease of implementation of the scheme.
As part of our consideration of scheme design options, we examine how each scheme varies
in terms of the scope to target benefits versus the administrative costs and ease of
implementation.
2.1.2.
The cost of supplying electricity differs throughout the day and
year
A key characteristic of the electricity sector is the variation between the costs of the different
generation technologies available, ie:

base load plants (such as coal) and renewable electricity generation technologies (such as
solar and wind), have relatively low operating costs, but this intrinsic, short run cost
advantage is offset by relatively high capital fixed costs (ie, the cost per unit of potential
output) and reduced ability to vary output in the short term (ie, ‘stopping’ and ‘starting’
such plants is not straightforward);

mid-merit plants, typically in the form of combined cycle gas turbines (CCGT), have
higher running costs, but mid-range capital (fixed) costs; and

peaking plants, typically in the form of open cycle gas turbines (OCGT) have relatively
low capital costs, a high degree of short-term controllability (ie, ‘stopping’ and ‘starting’
such plants is easy) but relatively high running costs.
The variability of demand for electricity during the day and over a year means that the least
cost combination of generation involves a mixture of these plants. Given the different fuel
and operating costs of each plant type the wholesale price of electricity generation also varies
throughout the day and year.
In addition, the variability of demand when combined with system reliability and security
obligations means that networks are built so as to ensure that maximum demand can be
satisfied most of the time at all geographic locations across the network. By implication this
means that the network cost of supplying an additional unit of electricity (ie, the marginal
cost) can vary considerably according to the specific location, and the localised demand and
network characteristics.
These characteristics of electricity generation and networks mean that the cost of supplying a
unit of electricity varies according to both the time it is used in a day and year, and the
location within the network. In other words, the marginal cost of supplying electricity varies
considerably across the network.
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The Rationale for a Peak Energy Savings Scheme
It follows that the potential benefits of saving a unit of electricity also vary depending on the
time profile of the saving and its location within the network. In general terms this means
that:

energy savings have a higher value in locations where the network is nearing its capacity
and only during peak periods when demand is highest and thereby driving the need for
additional capacity in that location5;

energy savings have higher value when wholesale energy prices are higher, and
particularly when they are at or near the market price cap;

where the local network peak period coincides with the peak period of the wholesale
market and the local network peak demand is approaching local network capacity limits,
peak period energy savings will be of high value from both perspectives; and

energy savings have a significantly lower value when neither of the conditions described
in the first two dot points above are met; in such cases, the value of energy savings are
most accurately represented by the avoided fuel cost.
2.2. What is load factor?
Load factor is simply a measure of the ratio of average demand to peak demand, and so
measures the ‘peakiness’ of electricity consumption. Given the variation in costs of the
different technologies, the average cost of supplying electricity decreases as load factor
improves (ie, as electricity load becomes ‘flatter’) and vice versa.
Activities that reduce energy consumption during peak periods or shift energy use from peak
periods to off-peak periods will therefore result in a flatter load curve. This means that the
average cost of supplying electricity will decrease, all other things being equal.
Figure 2.1 provides a stylised example of an activity that improves load factor. The figure is
based on data for New South Wales on 2 February 2011 and shows the potential effect of
direct load control systems for air conditioners, which are activated during the peak to reduce
total demand. In this example, this has the effect of reducing the amount of electricity
generated from open cycle gas turbines.
5
To be of most value in a network application demand reductions must achieve the level of megavolt ampere needed to
defer the need for a planned expenditure of capital to augment the capacity of the local distribution network, and that
level must be achieved prior to the time commitment to the augmentation would need to be made (or at very least, the
achievement of that amount of demand response would need to be seen as certain to be achieved prior to the time the
additional capacity itself would be needed). The deferral of that network investment has a financial value at the time
the deferral is achieved, and this value flows into network charges no later than the subsequent regulatory period.
However, even if demand reductions in these areas do not achieve the level needed to defer the planned augmentation,
they will reduce the potential for peak demand in such areas to exceed network supply capacity, thereby increasing
supply security, until the augmentation has been implemented. However the benefit of increased security of supply
does not have a financial impact on network charges. More broadly, any demand reduction anywhere on the
distribution network can be seen to have an economic value in that, as long as that demand reduction remains available,
it will potentially delay the time at which augmentation of capacity in that part of the distribution network will be
needed. Clearly, the financial impact of this is much less certain and will have a lower present value the farther into the
future that deferral might be. While the value of any such demand reduction will vary based on where it occurs and
when it is likely to affect capacity augmentation, its value can be thought of as being equal to the average cost of
capacity augmentation over time, which is referred to as the long run average incremental cost (LRAIC).
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The Rationale for a Peak Energy Savings Scheme
Figure 2.1
Stylised Example of an Activity that Improves Load Factor:
Direct Load Control for Air Conditioners
16000
14000
14000
12000
12000
10000
8000
8000
6000
$/MWh
MW
10000
6000
4000
4000
2000
2000
0
0:30
2:00
3:30
5:00
6:30
8:00
0
9:30 11:00 12:30 14:00 15:30 17:00 18:30 20:00 21:30 23:00
Time of Day
Gas - CC
Hydro - intermediate
Black coal
Other
Gas - OC
Hydro - peaking
DLC AC
$/MWh
However, if activities that reduce peak energy use also decrease non-peak energy use, then
this could have the effect of increasing unit costs as the load curve becomes peakier. This is
because the fixed network and generation costs need to be recovered from a lower through
put of electricity. Similarly, any activities that only reduce electricity use during non-peak
periods without affecting energy use during peak periods will also increase the average cost
of supplying electricity.
Figure 2.2 provides a stylised example of the impact of installing high efficiency street lights
on the system load profile. The reduction in electricity demanded during off-peak periods
has the effect of reducing the need to use both hydro and combined cycle gas turbines, and
also marginally decreases black coal generation. However, because over time network costs
are sunk, the reduced overall demand without any offsetting decrease in the network capacity
leads to a higher network cost per unit of electricity supplied.
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The Rationale for a Peak Energy Savings Scheme
Figure 2.2
Stylised Example of an Activity that Worsens Load Factor:
High Efficiency Street Lighting
16000
14000
14000
12000
12000
10000
8000
8000
6000
6000
4000
4000
2000
2000
0
0
0:30
2:00
3:30
5:00
Black coal
Hydro - intermediate
High efficiency streetlighting
2.2.1.
6:30
8:00
9:30 11:00 12:30 14:00 15:30 17:00 18:30 20:00 21:30 23:00
Time of Day
Other
Gas - CC
Gas - OC
Hydro - peaking
$/MWh
What is energy efficiency and demand management?
Energy efficiency can have a number of different meanings. Importantly, a distinction can be
drawn between the terms ‘energy saving’ and ‘energy efficiency’.
Energy saving is any absolute reduction in energy use, and it follows that peak energy saving
is an absolute reduction in energy use during a defined peak period. However, energy
efficiency is a change in the ratio of productive output per unit of energy used. This means
that an improvement in energy efficiency can occur when:

for a given level of energy input, productive output (or benefits) increases; or

for a given level of productive output (or benefits), energy input decreases.
This means that an improvement in energy efficiency does not necessarily imply that total
energy use falls. Examples of activities that improve energy efficiency include (amongst
other things):

replacing older appliances with newer, and more efficient appliances;

programmes that replace light globes with more efficient light globes; and

improvements in home insulation, which lowers the need for energy for heating or
cooling.
Demand management in contrast is any activity that seeks to actively manage customer
demand in response to either electricity price signals (whether at the wholesale, network or
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MW
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retail level) or electricity marginal costs.6 As a consequence, the net effect of demand
management activities is to shift the proportion of energy consumed from peak to non-peak
periods. Examples of demand management activities include (amongst other things):

direct load control programmes, where load is ‘switched off’ or ‘cycled’ during peak
periods;

investments in customer-side local power storage to shift demand from the network
during peak periods; and

power factor correction improvements at the site or facility level.
2.3. Context and rationale
Growing peak energy demand over recent years has been identified as a significant
contributor to the planned growth in network and generation expenditure to ensure that
system reliability requirements are satisfied. Peak demand has been growing across Australia
at a compound growth rate of 1.2 to 4.2 per cent, with the highest growth occurring in
Queensland – see Figure 2.3.
MW
Figure 2.3
Maximum System Demand by National Regions, 1996-07 to 2010-117
16000
14000
12000
10000
8000
6000
4000
2000
0
NSW
VIC
QLD
1996-97
SA
WA
TAS
NT
SNOWY
2010-11
The core of the network peak problem is that:
6
Where electricity pricing reflects electricity supply costs in both the magnitude of the price and how the price is
structured, it is more likely to engender demand management activities on the part of end-use customers without further
intervention. The less cost-reflective electricity prices are, the more likely it is that programmatic interventions will be
required to motivate end-use customers to undertake those actions.
7
Some of the growth in peak demand for New South Wales and Victoria between 1996-97 and 2010-11 is as a
consequence of the abolishment of the Snowy region in 2008. 2009-10 maximum demand figures were used for NT.
Source: AEMO (2011), Statement of Opportunities, ESAA, (1998), Electricity Australia, IMO (2011), Statement of
Opportunities, and Utilities Commission (2011), Power System Review 2009-10.
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
the network costs of supplying electricity to customers for the top 10 per cent of the load
duration curve can be significant;

current network charges mean that customers using electricity during these periods pay a
fraction of the costs incurred by the network to supply the infrastructure necessary to
satisfy demand (that is, a lack of cost-reflective pricing);

demand is therefore higher than would be the case if customers faced the true cost of
meeting system peak demands; and

the benefits (from avoided network costs) of lowering demand during peak periods are
likely to be greater than the costs involved.
The problem from a generation perspective is more complex. Specifically:

the wholesale costs of supplying electricity vary for each period according to the lowest
marginal cost of generation to satisfy demand in the period;

most consumers do not pay the marginal wholesale market prices, as retailers manage
these wholesale price volatility risks on behalf of their customers principally through
wholesale market hedging;

while this might suggest that wholesale investment is efficient because customers are
managing wholesale costs either directly or via a retailer, it does not take into account the
observation that:
– sufficient and persistent reductions in wholesale peak energy use could result in the
avoidance or deferral of new peak generation capacity, thereby reducing the long run
wholesale costs of electricity generation by an amount greater than the current
observed wholesale price; and
– no individual would be likely to invest at the level required to reduce peak demand
because the benefits received by other electricity users through lower wholesale
charges for all would not be factored into the decision to reduce demand.
In other words, the benefit to a customer of reducing demand during peak periods is equal to:

the avoided wholesale cost (as typically represented by the electricity price faced by the
customer); plus

the deferral of investment in additional peak generation capacity in the future to satisfy
growing peak demand if sufficient demand can be reduced.8
However, the customer would only receive at most the avoided wholesale cost benefit and so
will underinvest in demand reducing activities.
The current market pricing arrangements mean that the true supply chain cost (ie, the
combined cost of electricity generation, network provision and retailing services) of
8
This benefit arises because of the lumpy nature of generation capacity investments, which is not adequately represented
in wholesale prices. The benefit is therefore contingent on the achievement of sufficient demand reduction to defer the
generation investment and so lower the wholesale price.
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supplying electricity during system peak periods is considerably higher than faced by
electricity consumers. As a consequence electricity demand is higher than would be the case
if the true benefits of reducing demand were reflected in prices. It follows that there is less
investment in demand management and energy saving activities than is ideal, given the costs
of these activities as compared to the benefits they would produce in avoided network and
generation costs.
The impracticality of pricing to most customers the true cost of generation and network
supply during peak periods means that alternative mechanisms are needed to ensure that cost
effective demand management and energy saving activities are undertaken.
Under current arrangements retailers operating in New South Wales, Victoria, and South
Australia are required to satisfy energy reduction obligations. While these schemes do not
explicitly target peak reductions, many of the activities that are undertaken have an impact on
peak energy use.
In addition, the National Electricity Rules require transmission network providers to consider
the system costs and benefits of both network augmentation and non-network alternatives (eg,
peak demand reducing activities) when considering an expansion to network capacity. In
principal this should ensure that where non-network alternatives are more cost effective they
are undertaken instead of network augmentations.
The challenges with ensuring appropriate incentives for peak demand reductions by
consumers in the absence of providing direct price signals are:

the benefits of reducing network peak demand arise from various sources, such as
deferring network augmentation, improving reliability and where network and wholesale
peaks coincide, from deferring generation investments;

the generation benefits arise from avoiding the cost of new generation investments, and
over time changes to the generation plant mix, which is a non-monetised benefit captured
by consumers;

uncertainty as to the reliability of non-network alternatives to network investments; and

the lack of depth in the market for provision of demand management and energy
efficiency services.
The first two challenges arise because of the split in benefits between generation and
networks. This means that for efficient network investments to be made the entire supply
chain benefits of both network and non-network investments to satisfy reliability obligations
should be considered. Fortunately, the requirements in the NER directly address the split
benefits disincentive by allowing transmission network businesses to recover the cost of nonnetwork alternatives where they deliver greater net benefits to a planned network
augmentation. A similar approach is anticipated to be included in revisions to the regulatory
investment test applied to distribution networks. This can be expected to result in efficient
investment in non-network alternatives.
The uncertainties of demand management compared to network alternatives are likely to act
as a barrier, and are related to the lack of depth in the market and experience with these
activities so as to allow them to be relied upon. As network businesses are charged with
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managing these risks, so their appetite for risk given the incentives faced for cost efficiency is
a relevant consideration.
Finally, the uncertainty surrounding demand management arises in part because of a lack of
depth in third party demand management provision. This has likely arisen because of the
lack of a transparent market for the provision of these services, in part because there is no
clear purchaser with the requisite incentives to purchase these services.
2.4. Potential benefits from a peak savings scheme
The benefits from peak demand reductions arise from:

changes in the mix of plant needed to satisfy load requirements;

avoiding network augmentation investments and fuel over time; and

reductions in unserved energy.
The relative size of these benefits is difficult to determine in total, but will likely arise in the
medium to long term given the planning time horizons for both generation and network
augmentation investments.
A significant amount of investment in network and generation capacity is needed over the
next few years. The total regulatory allowance for electricity network capital expenditure is
around $38 billion ($7.7 and $30 billion for transmission and distribution businesses
respectively in the NEM) in the current five year cycle9, of which $3.7 billion for
transmission10 and between $10 to $16 billion for distribution,11 are related to augmentation
expenditure. Augmentation related expenditure is therefore expected to account for
somewhere between 35 and 50 per cent of all electricity network capital expenditure forecast
to take place within the next five years. That said, not all of this will be related simply to
growth in peak demand. In many cases, the growth will come from the construction of new
residential developments and other sources of growth in the customer numbers. Peak energy
savings can be valuable in both cases. However, where augmentation is needed to meet
growing peak demand in established areas, peak energy savings can, in some cases, defer the
need for that augmentation. In this regard it is useful to note that 25 per cent of network
capacity in the Victorian region in 2008-09 was used for only 10 days.12 Where network
augmentation is needed to meet the demand of new customer facilities – as is the case in
areas experiencing significant population growth – peak energy savings can reduce the
amount of infrastructure needed to meet that demand. However, the specific amount of the
9
Page 15, Investment Reference Group, (2011), ‘Investment Reference Group Report - A Report to the Commonwealth
Minister for Resources and Energy’, April.
10
48 per cent of the $7.7 billion transmission capital expenditure is related to system augmentations.
11
Estimated using augmentation expenditure information (excluding reliability and quality improvements) from various
state AER distribution determinations. The proportion of DNSP expenditure related to augmentation and demand
expenditure is around 33 to 54 per cent ( 33 and 54 per cent for Ergon and Energex from 2010-11 to 2014-15, 34, 36
and 40 per cent for Country Energy, EnergyAustralia and Integral Energy from 2009-10 to 2013-14, and 48 per cent for
Victorian DNSPs as a whole).
12
Page 172, (2011), ‘Draft Energy White Paper 2011: Strengthening the Foundations for Australia’s Energy Future’, A
Report to the Commonwealth Minister for Resources and Energy, December.
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forecast network augmentation that can be reduced or deferred by demand management is
very difficult to estimate without a great deal of research and analysis.
In addition expenditure on new generation capacity required by 2020 in the NEM and the
Western Australia South West Interconnected System (SWIS) is estimated to be between
$33.4 billion and $36.5 billion, assuming a moderate emission reduction target. This figure
includes plant that will be required to meet the Renewable Energy Target and to replace old
generation units that are likely to be retired. Reductions in peak demand could help
significantly offset the need for some of this expenditure. Energy savings in peak periods can
reduce the amount of plant required to meet peak demand, and change the proportion of peak,
intermediate and baseload generation (and associated fuels) that are needed to meet
customers’ aggregate electricity needs.
A number of studies have been conducted to estimate the effect on system costs of growing
peak demand:

ENERGEX estimates that the cost of supplying an additional MW of electricity during
peak periods is approximately $3.5 million (comprising $2 million of distribution network
costs, $0.7 million of transmission network costs, and $0.8 million of generation costs);13

Ausgrid’s estimates of benefits of between $2.6 and $4.5 million for avoiding each MW
of peak demand;14

Institute for Sustainable Futures and Energetics estimate that the possible savings in
infrastructure costs of $16.7 billion (undiscounted) by 2020 as a result of improving
building energy efficiency, which results in reductions in summer peak demand of
between 5,000 and 7,000 MW and 26,000 GWh less electricity consumption annually
over the period. The network benefits, which are likely to be caused by a reduction in
peak demand, are around $11 billion;15

Ernst & Young estimated ‘the possible value of reducing peak in the NEM at between
$3.3 billion and $15 billion from 2011 to 2030 in present value terms’ and that “the
majority of precedent supports a value of between $90 and $300/kVA per annum to defer
network load”;16

EnergyAustralia reduced its forecast capital expenditure by $234 million from 2009-10 to
2013-14 when it updated its average peak demand growth from 2.8 per cent to 2.7 per
cent from 2009 to 2014, which represents a reduction in peak demand of around 33 MW.
This is a savings of around $7 million per MW of peak demand avoided, and represents a
6 per cent reduction in its revised area plan expenditure during this period17; and
13
Page 4, Department of Employment, Economic Development and Innovation, (2011), ‘Queensland Energy
Management Plan’, May.
14
Page 5, Ausgrid, (2011), ‘submission responding to the Australian Energy Market Commission’s Discussion Paper on
Strategic priorities for Energy Market Development’, May
15
Page 98, Institute for Sustainable Futures, (2010), ‘Building Our Savings: Reduced Infrastructure Costs from Improving
Building Energy Efficiency’, Final Report, May.
16
Page 72 and 73, Ernst and Young, (2011), ‘Rationale and Drivers for DSP in the Electricity Market – Demand and
Supply of Electricity’, December.
17
Page 26, EnergyAustralia, (2009), ‘Revised Regulatory Proposal and Interim Submission’, January.
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on the generation side, CRA estimated that demand management programmes that reduce
summer peak demand by 2770MW and winter peak demand by 1770MW, would create
generation benefits of $949 million in present value terms over a 20 year time period.18
While the exact figures vary, these reports highlight that the potential benefits of a peak
demand scheme over the next 20 years are likely to be material.
2.5. Objective for a peak savings scheme
Within this context, the two potential objectives for introducing a specific peak energy
savings scheme include:

improving the efficiency of wholesale generation and network investment by reducing
inefficient use of and investment in infrastructure to satisfy periods of high demand; or

lowering the total cost of electricity supply, by changing the electricity load shape over
time.
In addition, the objective can have a temporal dimension, ie, for the achievement of the stated
objective in the short, medium or long term. This depends on the relative preference for near
term efficiency achievements, as compared to the achievement of benefits over a longer time
horizon.
The scheme design options have been developed with these potential objectives in mind. We
consider how each option compares against these objectives and different timeframes in
chapter 5.
18
Page 4, CRA International, (2006), ‘Assessing the Value of Demand Response in the NEM’, Final Report prepared for
IEA Task XIII Team, December.
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3.
Peak Energy Savings Scheme Options
Peak Energy Savings Scheme Options
The peak savings scheme options that we have considered can be grouped into three broad
approaches, namely:
 schemes that provide incentives to promote peak demand reductions as part of a general
energy savings scheme – ie, a general peak savings incentive within a general energy
savings scheme;

schemes that create a separate obligation on a party to achieve specified reductions in
peak demand – ie, a stand-alone peak savings scheme; and

schemes that directly purchase peak demand reductions within a specified budget – ie, a
peak savings buyer scheme.
The remainder of this chapter describes how these schemes might operate, and their
associated benefits, costs, risks and uncertainties. We start with a brief description of current
arrangements to provide a basis against which the scheme design options can be evaluated.
3.1. Status Quo Arrangements
The National Electricity Rules (NER) provide the framework within which network
businesses (both transmission and distribution businesses) undertake planning and investment
decision making. The incentives created by the NER for undertaking non-network
alternatives to planned network augmentations are therefore relevant for peak savings scheme
design.
Box 3.1 provides an overview of the rules relating to the requirements on network businesses
to consider non-network alternative investments. In summary, the rules:

require transmission and distribution businesses to explicitly consider non-network
alternatives to planned network augmentations, as part of annual planning processes;

provide information to the market about planned network augmentations and the network
and non-network alternative options that had been considered in its project evaluation;

require transmission businesses to explicitly calculate a value for benefits of both network
and non-network investments along the entire supply chain, including any benefits
received by generators or consumers; and

provide dispute resolution procedures if any party believes that the analysis has been
undertaken inappropriately.
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Box 3.1: Summary of the Principal National Electricity Rules related to
Network Planning and Investment
Rule 5.6.2(b) requires each Transmission Network Service Provider (TNSP) to conduct an
annual planning review with each Distribution Network Service Provider (DNSP) taking into
account a number of factors. Relevant to a consideration of peak demand is the obligation to
consider the potential for network and non-network alternatives to augmentations that are
likely to provide a net economic benefit to all those who produce, consume and transport
electricity in the market. 19
Rule 5.6.2(g) requires DNSPs to carry out an economic cost effectiveness analysis of possible
options to identify options that satisfy the regulatory test.
Rule 5.6.2A obliges TNSPs to publish an annual planning report that provides information
arising from the planning review. As part of this report, information must be provided (Rule
5.6.2A(4)(vi)) on what other reasonable network and non-network options were considered as
an alternative to a planned network augmentation.
Rule 5.6.5A requires the Australian Energy Regulator to publish the regulatory test, the
purpose of which is to identify new network investments or non-network alternative options
that:

maximise the net economic benefit to all those who produce, consume and transport
electricity in the market; or

in the event the option is necessitated to meet the service standards… minimise the
present value of the costs of meeting those requirements.
Rule 5.6.5B outlines the requirements for the regulatory investment test for transmission
(RIT-T). Rule 5.6.5B(4) lists all of the benefits that must be taken into account by the TNSP,
which explicitly includes wholesale market benefits in additional to network benefits.
Rule 5.6.5D requires a TNSP to explicitly consider non-network options as being credible for
a network solution.
The Australian Energy Regulator is obliged to develop guidelines for the application of the
regulatory investment test as it is applied to transmission (RIT-T) and distribution network
investments (RIT-D). The most recent guidelines for the RIT-T were finalised in July 2011.
The effect of these arrangements is that:

TNSPs must consider non-network alternatives to network investments and also consider
benefits along the entire electricity supply chain in its evaluation;

if a non-network solution costs more than a network solution, but it has high net benefits,
then the non-network solution must be undertaken; and

any additional costs incurred will be recovered through network charges to customers.
19
See in particular Rule 5.6.2(b)(4), NER.
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In short, these arrangements address the split benefits problem and are also intended to go
some way to addressing possible network business aversions to non-network investments by
at least requiring a proper analysis of alternative non-network investments to be undertaken.
While most likely not perfect, these arrangements go a long way towards promoting peak
savings when and where it is cost effective for peak saving activities to defer planned
transmission network investments.
That said, the changes to the regulatory investment test as applied by distribution businesses
have not been implemented as yet. As a consequence, there is a need to ensure that these
changes are made so that distribution businesses also take adequate account of up and
downstream benefits when evaluating network and non-network alternative investments to
maintain network reliability.
In addition, AER’s demand management incentive scheme (DMIS) is aimed at providing
distributors with incentives to implement non-network alternatives to reduce or shift peak
demand. At a high level, there are two key components to the DMIS, namely:

an allowance to fund innovation in demand management (the demand management
innovation allowance (DMIA)); and

a methodology for recovering any revenue that might be foregone as a consequence of
engaging in demand management activities.
The DMIA provides distributors with an additional allowance each year to implement
demand management projects or programs that meet the DMIA criteria. To remove any
financial disincentive that distributors have to implement demand management programs, the
AER allows distributors to recover forgone revenue from implementing DMIS programs and
projects for non-tariff demand management programs20.
Figure 3.1 provides a representation of the incentives and likely effects of the RIT-T and
anticipated revisions to the RIT applicable to distribution network investments. Importantly,
under these arrangements there are incentives on network businesses to engage with third
party energy savings businesses (ESCOs) to deliver targeted peak demand savings to achieve
network deferrals.
20
Tariff based demand programs allow distributors to charge cost reflective prices by charging a higher price during peak
periods. The AER argues that distributors that implement tariff based demand management will receive more revenue
due to higher prices and therefore do not need to recover forgone revenue.
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Figure 3.1
Incentives for Peak Demand Reductions under Current Arrangements21
The effect of these incentives is to lower network charges and so overall charges to customers
in the near term compared to the alternative where these rule changes had not been made. To
the extent that network peaks correspond with wholesale peaks there is also potential to
influence the shape of the overall generation system load profile over time, and so deliver
generation deferral and fuel savings benefits as well. That said, because the incentives do not
explicitly target the load profile these benefits are likely to be less than might be the case if
wholesale peak demand was explicitly targeted.
Finally, the incentives under the rules to achieve network deferral savings where cost
effective are limited by the requirement that they are implemented on a project-by-project
basis. The rules require market benefits to be considered for each project evaluated, so long
as the analysis is commensurate with the size of the project. This means that while market
benefits might be small for a project when considered in isolation, there is the potential that
demand side opportunities that might be viable on a larger scale are ignored.
3.2. Option 1: Peak Energy Saving Incentives
This section provides a detailed explanation of Option 1, which involves providing a direct
incentive to promote peak energy savings as part of a wider energy savings scheme.
3.2.1.
Description of the option
The first option presumes that a peak demand savings scheme has been implemented as part
of a national ESI. From this starting assumption, Option 1 examines how incentives to
promote peak savings might be incorporated as part of a general energy savings scheme.
21
We have characterised anticipated changes to the RIT as applied to distribution as part of the current arrangements but
acknowledge that these changes have not been implemented at this time.
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Given that the details of how a general energy savings scheme might operate are currently
being explored, we have had to assume how such a scheme might operate to allow for a
consideration of how a peak savings incentive might be included. We have therefore
assumed that a national energy savings scheme would:

place an energy savings obligation on electricity retailers,22 requiring energy savings
certificates to be surrendered annually to fulfil the obligation;

require a retailer to pay a penalty price if it does not have sufficient certificates to satisfy
its obligations;

allow approved activities to generate energy efficiency certificates based on the total
kilowatt hours (kWh) saved (or deemed to be saved);

be based on energy efficiency certificates that represent 1 kWh of energy saved;

allow energy efficiency certificates to be traded and capable of being carried over into
future years; and

allow the energy efficiency attributable to identified actions to be deemed for
administrative simplicity, with a certificate creator having the option to use actual energy
savings measurement as an alternative to deeming.
Such a scheme would value energy savings equally irrespective of the time of day or day of
the year those savings are achieved. This means that the value of a certificate represents the
average value of reducing energy demand by 1 kWh and so will:

be an underestimate of the value of reducing demand
– in locations that might need network augmentation as a consequence of peak demand
expectations within the near term; and
– at times when the wholesale market price is above the annual average price

be an overestimate of the net value of reducing demand
– in locations where there is sufficient spare capacity to supply all of the energy
demanded including during peak periods; and
– at times when the wholesale market price is below the annual average price; and

ignore the impacts of that energy saving on the load factor of both the generation and
network systems, and the consequent impact on infrastructure use and the average cost
per unit of electricity produced, and so impact on average electricity price.
Incorporating an additional incentive for peak energy savings would allow for reduced energy
consumption at times of peak demand to be valued more accurately (ie, higher than they
would be based on the average value of reducing energy demand), and would increase the
benefits received by those energy saving activities that have a greater impact on peak demand.
22
We understand that no decision has been made on the obligated party for a wider energy efficiency scheme. We have
chosen retailers given that this has been the approach used in the state-based energy savings schemes.
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An explicit incentive to achieve peak energy savings could be incorporated in a wider energy
savings scheme by:

Option 1A – assuming that a 1 kWh reduction in peak energy generates more than one
energy savings certificate (eg, say 3 certificates23); or

Option 1B – requiring electricity retailers to achieve a specified minimum percentage of
energy savings within a defined peak period, or a specific peak energy savings target.
Option 1A provides an additional incentive for energy saving activities that target peak
savings by multiplying the value of these reductions by a fixed amount, compared against the
value of a kWh saved during non-peak periods. This approach presumes that any energy
saving during a peak period is valued equally irrespective of the location of the saving, as
represented by the multiple applied to energy savings during the peak period. So long as the
multiple represents the relative difference in the average benefits of peak versus non-peak
energy savings then this approach will provide a better signal to energy saving creators of the
value of peak energy savings along the supply chain, and so can be expected to lead to greater
uptake of peak saving activities than if no direct peak incentive was created.
Option 1B differs from Option 1A by providing energy retailers with a specific peak energy
savings target. The target could take the form of a minimum of energy savings being
achieved during peak periods, or by establishing a separate peak savings target. Either
approach provides a specific target that must be satisfied, and so ensures that a predetermined
level of peak energy savings is achieved.
Figure 3.2 provides a representation of the incentives and likely impacts of the inclusion of a
peak savings incentive as part of a national energy savings scheme. The key features are:

an incentive is created to achieve peak energy savings through an obligation on retailers;

the creation of a market for energy savings certificates, which provides certificate creators
with a market for the sale of activities that lower energy use and provides additional
incentive for activities that reduce energy use in periods that are characterised by peak
demand;

retailers will recover the costs of the energy savings obligation through retail charges,
with the competitive retail market and retail price regulation creating the incentives to
lower the cost of compliance with the obligation;

network businesses retain an incentive to undertake cost effective targeted demand
savings where this results in network deferral from existing arrangements;

while network businesses can also create certificates, the incentive to do so is limited
because the cost of network deferral activities can be recovered through network charges
and so any revenue from the sale of certificates would most likely simply reduce the
amount of revenue needing to be recovered in network charges; and
23
Ideally the number would be determined with reference to the temporal and locational value of the energy saving,
including avoided capacity. However, the interaction between these two factors means that understanding these values
in practice is difficult. This issue is discussed further in Section 6.
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
Peak Energy Savings Scheme Options
a direct incentive can be created for wholesale peak savings, separate from network peak
savings.
Figure 3.2
Option 1: Peak Energy Savings Incentive Scheme
3.2.2.
Benefits
By providing a direct incentive for peak savings, Option 1 is expected to result in peak
savings over time compared against the status quo arrangements. That said, because the
incentives for network deferral arises from the status quo arrangements, the incremental
benefit of this option results from the scope to provide incentives for targeted wholesale peak
savings to change the load shape over time. This would be expected to incrementally
increase the generation deferral and fuel savings benefits compared to the status quo case
because:

under the status quo the wholesale benefits arise only where network peak savings are
coincident with wholesale peaks and so influence the wholesale market over time;

the current wholesale market arrangements do not compare the cost of changes to the load
shape compared with the associated cost of new generation investments; and

even if customers faced the cost of wholesale and networks at each point in time and
location, energy savings would not be optimal because of the need to aggregate sufficient
demand savings to defer lumpy network and wholesale investments (in other words, no
single customer acting alone will likely face a price signal that reflects the full potential
value for each unit of demand saved).
The last two points are particularly important as they go to the heart of the benefit case for
providing an incentive for peak savings over time. In the absence of pricing that reflects the
true cost of supplying electricity at each location and point in time, and given the lumpiness
of wholesale and network investments, demand savings need to be coordinated to achieve
optimal investment in electricity supply chain infrastructure. The market alone, without
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appropriate pricing, cannot provide this coordination and so there is a case for a market
intervention to facilitate optimal peak energy savings.
The benefits of Option 1 therefore arise from the placement of a value on the wholesale
benefits resulting from the achievement of wholesale peak energy savings over time, where
these are independent of network peaks. This option provides a means for transferring a
portion of the benefit that is ultimately received by customers to the party that can engage in
activities to promote large-scale wholesale peak savings.
Importantly, this scheme is unlikely to result in more targeting of network benefits compared
against the incentives created through the rule requirements. This is because the RIT-T and
the likely amendments to the RIT for distribution investments provides a means of ensuring
that any wholesale benefits created are taken into account when choosing between network
and non-network investment alternatives. As a consequence the introduction of a specific
peak savings incentive is unlikely to further enhance these network deferral incentives.
That said, creating a peak savings incentive as part of an energy savings certificate scheme
does create the means of transferring possible wholesale benefits from customers separate
from the network regulatory arrangements and so third party aggregators might be prepared
to offer networks a lower price for demand savings activities in localised areas. This is
because the value of peak savings to the third party aggregator is equal to:

the revenue received by the creation of certificates, plus

the revenue that can be earned from networks for network investment deferral.
If third party aggregators do not target peak savings in areas that create value for network
businesses then those aggregators are potentially losing additional revenue that could be
earned from network businesses.
So far in our analysis we have assumed that the incentives created through the scheme to
achieve peak energy savings translates into both wholesale and network benefits, which are
captured in part through the value of the certificates created. This assumption relies on there
being strong incentives within the wholesale market to minimise the cost of generation given
changes to the load profile over time. In our opinion the current wholesale market
arrangements do provide strong incentives to minimise the cost of generation to satisfy a
given electricity demand load profile.24 However, the current arrangements do not provide an
incentive to optimise investment in peak load generation investments compared with
investments in peak savings activities.
In addition it requires strong incentives within the network regulatory arrangements to ensure
that incidental changes in peak energy demand are translated into network deferral savings
and passed back onto customers.
A further benefit from this option is that by creating a market for demand savings separate
from network businesses it provides a platform for innovation in the development of
programmes and activities to achieve demand savings. Businesses that are capable of
24
As we have explained earlier, this does not imply that the current wholesale market arrangements optimise the mix of
demand management and generation activities to balance electricity demand and supply.
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delivering demand savings for a cost less than market certificate prices will have an incentive
to invest in those activities. Over time these incentives might be expected to lower the
overall cost of reducing peak demand and improve the acceptability of these activities as a
means of deferring network investments.
In terms of the likely timing of benefits, Option 1A will likely result in changes to the load
profile over the medium to long term and so will likely only deliver network or wholesale
cost savings in the future. In contrast because Option 1B specifies a peak savings target, the
peak demand reductions can be expected to arise in the near term and so there is a greater
chance that this will result in near term benefits. However, for this to occur there is a need to
ensure that the regulatory framework provides sufficient incentive to ensure that peak savings
do in practice translate into network augmentation deferrals given the reliability risks created
for network businesses.
3.2.3.
Costs
While this option is expected to result in lower wholesale costs over time, this will be partly
offset by higher retail charges as retailers recover the cost of meeting energy savings
obligations. For Option 1 to be net beneficial the incremental costs of the scheme should be
less than these incremental benefits, taking into account all of the uncertainties involved.
The incremental costs of including peak energy savings incentives within a wider scheme are
likely to be minimal once a wider scheme is established. This is because much of the cost of
the scheme is likely to involve developing appropriate assumptions about the energy savings
values associated with particular activities, and the development of a scheme register.
That said there are likely to be additional costs associated with determining the time profile
of demand savings for defined energy saving activities, to allow the peak savings to be
separately identified. This information is not needed for a general energy efficiency scheme.
3.2.4.
Risks and uncertainties
The core risk associated with creating a peak incentive relates to the size of the incentives
created. If the value of certificates for peak savings, or a peak savings target is larger than the
anticipated benefits then there is a risk that there will be over investment in peak savings
programmes and activities. This creates a risk that costs will be imposed on electricity
customers without the resultant benefits outweighing those costs. Alternatively, if the value
of certificates or a peak savings target is smaller than the anticipated benefits from the
scheme then there is a risk that there will be under investment in peak savings programmes
and activities.
There is also an issue related to additionality. In both Option 1A and 1B25 there is the risk
that some activities that would have been undertaken even without additional certificates for
peak energy savings or a peak savings target would now receive additional compensation
through the creation and sale of peak certificates. This ‘free-rider’ cost means that the true
25
This risk would be reduced under a peak energy savings target to the extent that such a scheme expanded the list of
eligible measures and tended to incentivise measures whose energy savings primarily take place at times of peak (eg,
interruptible load).
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benefit of such a peak savings incentive would need to be calculated as the value of
additional take-up engendered by the peak savings initiative (in terms of avoided capacity
and energy costs) less the additional compensation provided to those activities that would
have occurred regardless of the peak savings scheme.
Given these uncertainties, there is merit in ensuring that the scheme is sufficiently flexible to
adapt to an improved understanding of the benefits over time. This suggests that
incorporating an initial peak savings incentive based on the best available information and
with a penalty price that is appropriate to manage the cost of the scheme to electricity
consumers would be appropriate. However, the scheme administrators should be capable of
updating this value or altering the penalty price as improved information becomes available.
To ensure that scheme participants have certainty for their programme investments, this
flexibility might involve periodic reviews of the target and penalty price after say two to three
years. This would help ensure that a balance between scheme certainty and flexibility is
achieved.
In addition, Option 1B also risks pre-empting the outcomes of certain review processes
currently underway in the NEM. Both the AER’s RIT-D and the AEMC’s Power of Choice
review are exploring potential barriers to demand-side participation (DSP) and identifying
mechanisms for overcoming those barriers. There is at least some potential for a mechanism
that sets an explicit target for peak energy savings to (a) pre-empt the approaches to be
developed by those processes (or require the peak energy saving mechanism to be
discontinued, thereby potentially stranding investments made by ESCOs in responding to it),
or (b) set a target level that turns out to have been inefficient as revealed subsequently by
those processes.
3.2.5.
Summary
In summary, incorporating a specific incentive for peak energy savings within a wider energy
savings scheme benefits from being administratively simple to implement, and will likely
improve incentives to achieve incremental wholesale cost savings, particularly in the medium
to long term. It would also complement incentives to consider non-network investments to
planned network augmentations as provided through the NER.
3.3. Option 2: A Stand-Alone Peak Energy Saving Scheme
This section examines the development of a stand-alone peak energy saving scheme that is
separate from any general energy savings scheme that might be implemented.
3.3.1.
Description of the option
Option 2 creates a separate dedicated peak energy savings scheme that is not directly linked
to a national energy savings scheme. This provides the flexibility to tailor the scheme’s
design to ensure that the best peak energy savings outcomes are achieved.
The key features of a stand-alone peak energy savings scheme include:
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
placing an energy savings target obligation on either electricity retailers or electricity
network businesses, requiring energy savings certificates to be surrendered annually to
fulfil the obligation;

requiring the obligated entity to pay a penalty price if it does not have sufficient
certificates to satisfy its obligations;

allowing approved activities to generate energy savings certificates based on the total
kilowatt hours (KWh) saved within a defined peak period (or deemed to be saved);

being based on peak energy savings certificates that represent 1 kWh of energy saved
during peak periods;

allowing energy savings certificates to be traded and capable of being carried over into
future years; and

allowing the energy savings attributable to identified actions to be deemed for
administrative simplicity, with a certificate creator having the option to use actual energy
savings measurement as an alternative to deeming.
The key differences of a stand-alone scheme compared to having an incentive for peak
savings within a national energy savings scheme are:

the flexibility to place the obligation on a different entity to the entity that might be
responsible for the obligation under a national energy savings scheme (eg, allowing the
obligation to be placed on network businesses rather than retailers); and

the transparency of the cost of peak savings, as represented by the market price of peak
savings certificates.
In addition, there is the potential with a stand-alone scheme to place different target
obligations for each state, network business or subregions within a network business’ area of
operations, and/or apply a network deferral obligation rather than a peak energy savings
obligation on network businesses. This would allow for potentially more refined targeting of
the incentive for peak savings reductions.26
Figure 3.3 provides an illustrative representation of the incentives and outcomes anticipated
from the implementation of a stand-alone peak energy savings target scheme on network
businesses. For the purposes of this figure and the subsequent discussion we have assumed
that the peak savings target is placed on distribution network businesses.
26
That said, we are sceptical about whether such an approach would enhance the incentives already faced by network
businesses through the requirements of the NER to achieve peak savings where this is a cost effective alternative to a
network investment.
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Figure 3.3
Option 2: Stand-Alone Peak Energy Savings Target Scheme
Under this option certificates would be generated for activities that lead to peak energy
savings regardless of the location of those savings within the network. Network businesses
would be required to surrender certificates up to the value of its obligation, or pay a penalty
price. The penalty price ensures that the cost of achieving peak savings does not exceed the
anticipated benefits from these savings.
As a matter of principle, whether a peak energy savings obligation is placed on network
businesses or retailers should not have any implications for the outcomes achieved from the
scheme. So long as there are no limitations on the creation of certificates, the least cost
options for achieving peak savings should be preferred as certificate creators seek to
maximise profits from the creation of certificates. This means that network businesses will
have an incentive to seek out network peak reductions, particularly where the network
benefits, through avoided network costs, and additional revenue via the creation and sale of
peak energy efficiency certificates is less than the cost of achieving the peak energy
reductions.
That said, a stand-alone peak energy savings scheme is unlikely to create additional
incentives for a network business to seek out peak savings to defer planned network
investments, because the cost of purchasing peak savings certificates in the market would be
recoverable through network charges, which is equivalent to the purchase of peak savings
directly from ESCOs, where this is a cost effective alternative to a planned network
investment. It follows that the obligation and creation of a peak savings certificate market
should not result in any ‘additional’ network deferment to the extent that the current
incentives are sufficient to drive efficient investment in network deferral.
That said, placing a direct obligation on network businesses means that these businesses
would most likely actively participate in any peak energy savings scheme as it seeks to
manage its obligation. In other words it enhances the incentives that network businesses
would already have through the NER. In contrast, if the obligation is placed on retailers the
incentives for network businesses arise only from the NER requirements and so if the
reliability risks are considered substantial relative to the network deferral benefits then this
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might result in less non-network investment activity than is desirable given the underlying
cost and benefit comparisons.
As with Option 1, while placing an obligation on peak energy savings will ensure that peak
savings are achieved this does not mean that there will be greater deferral of near term
planned network augmentation investments. This is because:

there might be insufficient peak demand savings in locations where network
augmentations are required; or

the network business is not confident that planned non-network approaches will in
practice avoid anticipated growth in peak demand and so undertakes the network
augmentation so as to not breach system security requirements; and

the network will already have a strong incentive to defer network investments where this
is cost effective, through the NER requirements.
This highlights the importance of the incentives placed on network businesses through the
application of the NER to ensure that cost effective peak demand savings and associated
network augmentation deferrals are achieved.
3.3.2.
Benefits
As with Option 1B, a stand-alone peak energy savings target scheme where the target is a
peak savings obligation ensures that the peak savings are achieved where the cost of doing so
does not exceed the penalty price. The scheme ensures that a market is created particularly
for wholesale peak savings and so addresses the problem that there is no mechanism in the
current arrangements to transfer the value of wholesale peak savings, where these savings are
not coincident with network peaks, from customers to those parties that engage in activities to
achieve peak savings.
The benefits therefore most likely arise from placing a direct incentive on peak demand
savings and influencing the load shape over time. This in turn allows for generation
investment deferrals that over time lead to cost savings for consumers.
Such a scheme is expected to create wholesale market benefits over the medium to long term
because it provides a value for activities and programmes that target wholesale peak savings
where these cost effectively result in generation investment deferrals over time. Importantly
it provides the means for transferring the external benefits from an individual reducing peak
demand to the third party undertaking the peak savings activity thereby ensuring that peak
savings reductions are efficient.
3.3.3.
Costs
The cost of Option 2 is likely to be incrementally higher than for Option 1 because of:

the additional administration costs associated with a separate scheme; and

the need for a separate peak energy certificate register, certificate creation accreditation,
and system for trading.
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That said a stand-alone scheme would most likely make use of the systems and processes that
would be developed for a national energy savings scheme and so these additional costs would
most likely be marginal, so long as a national energy savings scheme was also introduced.
As with Option 1B, the additional costs of the scheme therefore relate mostly to the
establishment costs of determining the time profile for energy savings for activities that target
peak demand reductions. We understand that there is some information available on this,
which would likely form the base for developing further evidence on these savings. In
addition, we would expect that the agency responsible for the scheme would develop its
understanding of these savings over time, and so could improve upon any initial estimates
made thereby improving the incentives for peak savings.
3.3.4.
Risks and uncertainties
The risk with any target based scheme is ensuring that incentives are not created to overinvest in peak savings relative to the anticipated benefits from the peak savings. This creates
a risk that costs will be imposed on electricity customers without the resultant benefits
outweighing those costs.
This highlights the importance of ensuring that any penalty price associated with a scheme is
set in line with an estimate of the anticipated benefits from each kilowatt hour of peak
savings achieved. If the penalty price is set too high, then more activity will be undertaken
than is justified relative to the underlying benefits and costs. Similarly if the penalty price is
set too low then less activity will be undertaken compared to the underlying benefits and
costs.
In addition, Option 2, like Option1B, increases the risk that some activities which would have
been undertaken absent a peak savings target will now receive additional compensation
through the creation and sale of peak certificates. This ‘free-rider’ cost means that the true
benefit of such a peak savings incentive would need to be calculated as the value of
additional take-up engendered by the peak savings initiative (in terms of avoided capacity
and energy costs) less the additional compensation provided to those activities that would
have occurred regardless of the peak savings scheme.
Given the uncertainty of benefits, there would be merit in having a modest penalty price
commensurate with the costs of existing programmes that achieve peak energy savings. This
will ensure that the scheme results in some activities being undertaken while limiting the
possible costs of the scheme.
It should also be noted that several current and past reviews have been undertaken with the
explicit purpose of exploring the potential barriers to demand-side participation (DSP) and
identifying mechanisms for overcoming those barriers and so promoting an efficient level of
DSP. Two reviews of significance that are currently underway are the AER’s RIT-D and the
AEMC’s Power of Choice review. There is at least some potential for a mechanism that sets
an explicit target for peak energy savings to (a) pre-empt the approaches to be developed by
those processes (or require the peak energy saving mechanism to be discontinued, thereby
potentially stranding investments made by ESCOs to respond to it), or (b) set a target level
that turns out to have been inefficient as revealed subsequently by those processes.
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3.3.5.
Peak Energy Savings Scheme Options
Summary
In summary, Option 2 provides flexibility to design a peak energy savings scheme that places
an obligation on network businesses directly (as compared to retailers) and also potentially
allows those obligations to be more directly targeted. This will ensure that the value of peak
savings is separately identifiable to general energy savings.
3.4. Option 3: A Single Buyer of Peak Energy Savings
This chapter examines the creation of a single buyer for peak energy savings, as an
alternative to the market based approaches for providing incentives for peak savings
embodied in Options 1 and 2.
3.4.1.
Description of the option
The final option involves the creation of a new energy market role to manage peak energy
demand. As a consequence, this option does not place any direct obligations on energy
market participants to reduce peak demand. It also does not create a tradable certificate
scheme. The aim of the single peak buyer would be to cost effectively flatten the load profile
by purchasing activities from third parties that seek to reduce peak demand. Such an entity
could:

stand in the market offering to purchase all peak energy reductions at a predetermined
price (linked to the estimated benefits of peak demand reduction); and/or

conduct periodic requests for bids to achieve peak demand outcomes for each year over a
forward time horizon, say every six or twelve months; and/or

work closely with network businesses and/or demand management operators to fund
identified peak demand activities and achieve voluntary targets; and/or

activate/control purchased demand management actions during wholesale or network
peak periods to directly achieve peak demand reductions.
This function and the associated activities could be funded either through a levy on all
electricity customers or from consolidated revenue.
The middle two approaches would allow for specific targeting of peak demand reductions to
achieve network deferral benefits. It would create an opportunity for each network business
to determine its price for undertaking a demand management option as compared to a
network augmentation given both the direct costs and risks involved.
Figure 3.4 provides an illustrative representation of the incentives and outcomes anticipated
from the implementation of a single peak savings buyer scheme.
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Figure 3.4
Option 3: Single Peak Savings Buyer Scheme
The key feature of the single peak savings buyer scheme is that it creates a market distinct
from networks or retailers, for the provision of peak savings whereby third parties can have
certainty about the revenue associated with providing actual or deemed peak savings. In
contrast to the previous two options, energy savings businesses would be paid an agreed
amount (either through an agreed purchase contract or fixed price arrangement) and so could
undertake activities with certainty about the revenue that will be received. The certificate
based schemes require ESCOs to forecast likely revenue from the sale of peak savings
certificates which would be more uncertain.
3.4.2.
Benefits
The benefits of this option include:

it creates a transparent market for demand management initiatives with financial certainty
provided to demand management providers about the value of peak demand reductions
into the future;

the cost of the scheme can be directly managed through the size of the levy;

where the entity purchases demand reductions directly and guarantees the achievement of
these reductions, it removes the risk of non-achievement of peak demand reductions from
network businesses,27 as a third party becomes responsible for managing the load profile;
and

to the extent that the single buyer controls load it can actively manage load during
wholesale peak demand events.
27
This arrangement would require distributors to gauge the likely effectiveness of peak savings programmes given
obligations to satisfy reliability and security standards.
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This approach allows generators, network businesses and retailers to focus on their own
activities and respond to changes in forecast load shape as a consequence of the scheme over
time. It also does not alter the incentives for network businesses to seek out peak savings to
defer network investments, as created through the NER regulatory investment test
requirements.
3.4.3.
Costs
Establishing a dedicated peak energy savings buyer is the highest cost option across each of
the options that have been developed. These costs relate to:

the cost of establishing a new entity or creating a new responsibility within an existing
entity, to undertake the single buyer functions; and

the ongoing cost of operating the entity, which will vary according to the extent of
involvement of the entity in developing and identifying peak savings options.
This option is likely to have considerably higher costs for administration compared to the
other scheme design options. This is because of the need for the buyer to be actively
involved with managing peak energy use, and potentially working directly with network
businesses and/or ESCOs to identify the opportunities for peak savings.
The cost of operating the entity would also need to be borne by either governments (ie,
taxpayers) or electricity customers more directly perhaps through the implementation of a
levy. The latter arrangement would mean that the cost of the scheme would be transparent,
while the benefits arising from the scheme will be less clear as they will be shared across
electricity users in the form of lower prices. This is in comparison to a scheme that places an
obligation on retailers to achieve peak energy savings, where the costs of this obligation will
likely be incorporated into the retail prices (though likely not in a transparent way).
3.4.4.
Risks and uncertainties
While the single buyer has higher establishment and ongoing operational costs, it also
provides greater flexibility to manage peak savings over time as improved information and
understanding of the opportunities arise. This means that the single buyer:

will likely learn from its experience in purchasing peak savings and so improve its
understanding of the reliability of particular activities and programmes;

can choose to increase or decrease the amount of peak savings purchased as its
understanding of the benefits increases; and

can directly manage the cost of peak savings through its budgetary processes.
In addition, it means that any changes in the anticipated load profile that are achieved by the
actions of the single buyer can be taken by network businesses in their network planning
processes. This means that network businesses need not separately evaluate the potential for
peak savings activities to be achieved.
As in the case of Options 1B and 2, Option 3 runs the risk of pre-empting the various reviews
that have been put in train to explore the potential barriers to demand-side participation
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(DSP) and to identify mechanisms for overcoming those barriers and thereby assist in
achieving an efficient level of DSP. The two most significant of these are the AER’s RIT-D
and the AEMC’s Power of Choice review. As was also the case in Options 1B and 2, there
is at least some potential for Option 3 to (a) pre-empt the approaches to be developed by
those processes (or require the peak energy saving mechanism to be discontinued, thereby
potentially stranding investments made by ESCOs to respond to it), or (b) set a target level
that turns out not to have been an efficient level as revealed subsequently by those processes.
3.4.5.
Summary
The single peak energy buyer option has the advantage of creating a clear and transparent
market for third party providers of peak energy savings activities to develop, which over time
would be expected to enhance the market’s capacity to deliver these activities. Similarly the
single buyer would have the flexibility to adapt to changes over time and learn from its
experience in delivering peak energy savings.
In practice this means that the load duration curve for the market would be actively managed
by an independent third party entity with clear rules governing its activities, and within an
overarching operational objective. This means that network businesses can focus on
satisfying network reliability obligations given expectations about future load requirements,
taking into account the activities of the single buyer.
While a single buyer creates flexibility in the achievement of peak demand savings, and
allows for greater targeting of activities, it also involves the largest administrative costs
compared to scheme design Options 1 and 2. This is because of the costs involved with
actively planning and participating in the market for peak demand savings. Relevantly, this
option is least consistent with a market-based approach to reducing peak demand.
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4.
Modelling the Benefits of Peak Energy Savings
Modelling the Benefits of Peak Energy Savings
There are two principle benefit categories resulting from peak energy savings, namely:

generation benefits; and

network benefits.
This chapter examines the methodologies that can be employed to model these benefits. In
addition, we outline some of the data considerations.
4.1. Modelling generation benefits
Lowering wholesale peak demand over the medium to long term is expected to result in three
key wholesale market outcomes, specifically:

a reduced need for new peaking generation capacity and fuel costs (as greater use is made
of lower fuel cost generation capacity) as a consequence of a flatter system load profile
and load duration curve;

reduced fuel requirements as a direct result of reduced total electricity consumption; and

a reduction in unserved energy.
The effect of these outcomes is lower average wholesale market prices over time and reduced
unserved energy.
The remainder of this section describes the methodological approaches that can be used to
estimate these benefits.
4.1.1.
Methodological approaches
There are two basic approaches that can be used to assess the impact of peak demand (and
energy consumption) reductions on the generation sector, namely: a static approach, and a
dynamic approach.
The static approach uses a representative economic value for each unit of demand saved and
simply multiplies this unit value by the peak demand and energy consumption impacts
expected to be achieved by an ESI scheme (or other scheme of interest). The unit value of
peak demand reduction is usually estimated with reference to the installed cost of peaking
generation (though in some analyses fixed operating and maintenance costs are added). The
unit value of reduced electricity consumption is generally estimated with reference to the fuel
and other variable operating and maintenance costs of a peaking plant.
In both cases, the costs used are generally those of an open-cycle gas turbine (OCGT), which
is the type of plant most commonly used to meet peak energy and demand requirements.28
28
That said, this is not always the case. In practice OCGT plants are not always the marginal generation type. Often
other plants are called upon specifically to meet peak demand. These can include hydro or wind generation depending
on the particular characteristics of the NEM region or generation system.
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Modelling the Benefits of Peak Energy Savings
Energy reductions are generally estimated on an annual basis over a future time horizon and
the resulting avoided costs discounted to a present value. The installed cost of the plant is
therefore converted into an annualised cost that includes the initial capital and labour cost to
construct the plant, the financing charges that would be incurred, and the annual fixed
operating and maintenance costs. Future fuel costs are estimated based on expected real price
increases.
By contrast, the dynamic approach uses a market model to simulate the change in the overall
plant mix and fuel usage that could be expected to result from the peak demand and
electricity consumption reductions achieved by a peak energy savings scheme.
Such models are set up to represent the generation system being examined29 and the businessas-usual forecast30 of peak demand and electricity consumption (ie, the peak demand and
electricity consumption that is expected to occur in the absence of the scheme being
analysed). These models also generally have databases of the cost and operating
characteristics of a wide range of types of electricity generation plant. An optimisation
model is used to identify the amount of generation capacity of each different plant type that
will meet forecast peak and total electricity demand at least cost.31
The impact of the scheme is assessed by altering the load forecast to reflect the changes that
the scheme is forecast to produce in peak demand and electricity consumption on an annual
basis over the life of the scheme and the expected useful life of the changes in end-use
technology it engenders.32
4.1.2.
Data considerations
The data requirements for the two approaches differ considerably, as shown in Table 4.1
below.
29
Wholesale electricity market models will also generally ensure that “committed plant” (generating plants that have
already at least commenced the siting and licencing process) are included as planned in the future generation plant mix.
Plants beyond the existing and committed plants are brought into the generation system based on their ability to meet
forecast peak and total electricity demand at least cost. To do so, these models rely on ‘perfect foresight’; that is, they
take the future demand forecast as certain and bring specific new plant into the generation system in the order and sizes
that will produce the lowest cost for meeting all demand over the entire timeframe being analysed. While generation
plant investment in real-world competitive electricity markets are not made by such a central decision-making process,
the NEM has been shown to provide very close to least-cost generation investment outcomes.
30
Although these analyses generally use an ‘expected’ forecast of peak and total electricity demand, in practice, a number
of alternative forecasts are generally investigated.
31
Many of these models will also have a mechanism for simulating generation bidding behaviour as a means of better
forecasting prices. The realism of the prices is also often checked against the commercial adequacy of the total revenue
they provide for individual generators and generation companies, the logic being that prices that fail to provide
commercial returns for individual plants are likely to result in retirements and prices that fail to provide commercial
returns for a number of plants are likely to be unsustainable in the longer term.
32
A less frequently used approach is to view demand-side actions as alternative generation options in the generation plant
database. In this approach, the load forecast is simply re-run with the demand-side options included in the generation
plant database. The optimisation routine will then simply see the various demand-side options as additional means for
meeting forecast peak and total electricity demand at least cost.
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Modelling the Benefits of Peak Energy Savings
Table 4.1
Data Requirements of the Static and Dynamic Approaches to Estimate
Wholesale Market Benefits
Static approach
Supply-side data requirements
Annualised cost of marginal generation
plant
Current and expected price of fuel for
marginal generation plant (real dollars)
Dynamic approach
Operating costs and technical
performance of existing and committed
generation plants
Bidding behaviour of current generation
plants
Capital costs for construction and
operating costs and technical
performance of the range of generation
plant that could be constructed in the
future (including any limits on how much
or how quickly such plants can be
constructed)
Forecast annual
electricity demand
Demand-side data requirements
peak
and
total
Annual reduction in peak demand
Either:
Annual reduction in energy consumption

reduction in demand on an hourly
basis for each year of the period of
interest, or

reduction in peak demand and
energy consumption in peak,
shoulder and off-peak period for
weekdays and weekends in each
season
While the data required in the dynamic approach on the supply side is considerable and
complex, it is generally available in market simulation and generation system expansion
models that are used by electricity market participants and regulatory and planning bodies
concerned with the electricity market.
Importantly, the information required in both the static and dynamic approaches to estimating
wholesale benefits of peak and total electricity demand reductions requires consideration of a
number of important and complex inputs, including:

the number of existing facilities for which any particular demand-side technology is
applicable (technical potential);

the number of facilities in which any particular demand-side technology is likely to
achieve a level of cost-effectiveness that could be assumed to be of interest to the owner
of that facility (economic potential);

the number of those facilities that will actually purchase and use the demand-side
technology, and the timeframe over which they do so (achievable potential and take-up
rate);

the number of existing facilities (and end-use equipment) that will be taken out of service
and the number of new facilities that will be built over the period of interest and the rate
at which this will happen, as this will determine the number of facilities for which each
demand-side technology is eligible;
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
the degree to which new facilities differ from existing facilities and the consequent
change in the amount of savings that each demand-side technology will provide and
therefore its likely economic and achievable potential;

the degree to which the actual technical performance of each demand-side technology
differs from the expected performance;

the degree to which end users may increase their use of electricity (in the affected end use
or other end uses) due to the savings provided by the demand-side technology (rebound
effect);

the degree to which participants in the scheme would have adopted the demand-side
technology even in the absence of the programme (free-rider impact); and

the degree to which the scheme encourages end users to undertake additional peak
demand or energy consumption reduction technologies or behaviours (free-driver impact).
Relatively little ‘real-world’ information on these variables is available in Australia, and as a
result these variables are generally estimated in the analyses. While actual in-field data for
these variables would be useful (and an increasing amount of data is becoming available from
the various trials and pilot programs that have been undertaken by electricity companies and
governments) the impact of changes in these variables on the overall performance of a
demand-side scheme can be investigated via sensitivity and break-even analysis.33
Data availability is particularly poor for the hourly demand impacts of demand-side
technologies that are required in the dynamic approach, and this variable is much more
difficult to address through sensitivity analysis as it is actually a series of values (8,760
hourly values, though in practice many fewer can be used to adequately characterise the
relevant load shape impact for the purpose of the dynamic analysis). While a number of
programs have been undertaken in which interval metering has been installed along with
demand-side technologies, very little data on the load shape of the affected end use both
before and after installation of the demand-side technologies has become widely available.
Establishment of a database of such information would provide an important resource for and
significantly add to the credibility of demand-side analysis to support policy decision-making.
Finally, the above discussion concerns the information that is required to assess the benefits
of the demand-side activities that could be expected to result if a national peak energy
savings initiative scheme were to be implemented. To evaluate the merits of such a scheme
would also require consideration of the cost – and therefore the cost-effectiveness – of those
activities and the scheme as a whole. Relevant costs include:

the cost to the end-use consumer for purchase, installation and maintenance of the
demand-side measures (note that these costs are those that will serve as the key inputs to
the economic attractiveness and take-up of the demand-side activity);
33
Sensitivity analysis assesses the change in the dependent variable (in this case, the scheme’s impact on peak and total
electricity demand) as changes are made to the value assumed for the independent variable (in this case, the variable
discussed in the series of dot points above). The analyst can then ascertain whether the outcome of the dependent
variable is particularly sensitive to assumptions about the independent variable, as well as the likelihood of the outcome
of the dependent variable based on the likelihood of the specific values required for the independent variable to produce
that outcome. Break-even analysis identifies the value of the independent variable that produces a given outcome in the
dependent variable.
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
the cost to obligated parties in complying with the scheme obligation, which will include
the amount these parties have to pay to purchase their required number of certificates
(including penalty payments), and any administrative or marketing costs they incur in
meeting their obligation;

the cost incurred by certificate-creating organisations for accreditation or other
compliance requirements; and

the costs incurred by relevant government agencies in designing or administering the
scheme, including any costs incurred by governments in decommissioning existing
programs in favour of a national scheme.
4.2. Modelling network benefits
There is the potential for network peak demand savings to result in lower network costs by:

reducing the need for additional network infrastructure to satisfy reliability requirements
under conditions of growing peak demand and so lower the costs of network
infrastructure; and

improving system security and reliability due to the scope for:
– (a) ‘passive’ demand-side measures34 to reduce demand on system elements that
could be overburdened at times of peak demand; and
– (b) ‘callable’ and ‘dispatchable’ demand response35 to change the level of demand on
system elements in response to peak demands or forced outage of a system element.
Importantly, a reduction in the total amount of electricity consumed does not provide a
benefit to networks (and therefore a benefit that could flow on in whole or in part to end-use
consumers). This is primarily because the most significant driver of network costs is capital
expenditure for network infrastructure. The costs of that infrastructure is recovered through
tariffs which are largely based on throughput (ie, charges for electricity consumed).
It follows that any scheme that reduces total electricity consumption will also reduce network
revenue without any commensurate reduction in network costs, except where that
consumption reduction is coincidental with peak demand. As a result, where the combination
of peak and total electricity demand reduction reduces system load factor, it will exert
upward pressure on network prices. Where demand-side activities increase system load
factor, they will put downward pressure on network tariffs.
34
‘Passive’ demand-side measures are those whose impact on peak and total electricity demand are a function of the
technology itself, rather than how the end user operates the technology. High efficiency lighting, high efficiency
refrigerators and high efficiency air conditioning are examples of passive demand side measures.
35
Both ‘callable’ and ‘dispatchable’ demand response differ from passive demand side measures in that they only come
into play when the network (or generation) systems need them. In ‘dispatchable’ demand response, the network (or
network agent) has control over the end-use load that is to be reduced or interrupted, though the exercise of that control
is generally governed by explicit conditions mutually agreed by the network and the end-use customer. In ‘callable’
demand response, the network (or its agent) has the right to request that the end user reduce his/her consumption, but
does not have control of that consumption. The number of such calls, the amount of load to be reduced, the timing and
duration of the reduction, and the extent to which the end-use consumer can deviate from those conditions are generally
agreed to between the network and the end-use customer.
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Finally, as explained earlier many of the network benefits associated with network peak
demand savings are likely to be attributable to the new and proposed arrangements for
network investment decision making required by the NER. That said, the methodological
approaches to estimating these benefits are common irrespective of the mechanisms by which
the incentives for efficient investment in peak savings are achieved.
4.2.1.
Methodological approaches
Estimating network benefits of an energy savings scheme are complicated by the need to
understand the peak demand and load factor implications of any energy saving activates
undertaken. It is further complicated by the need to understand the locations in the network
where demand is saved, as the benefits can vary considerably by location. Those areas within
a distribution network can be as small as a feeder or a zone substation.
In practice, this makes modelling the benefits of network peak demand savings for electricity
networks significantly more difficult than in the case of the generation system. Specifically:

the network costs that can be reduced by demand-side activities – namely reduction in
peak demand – arise at the local level within the network asset base, and most networks
(particularly distribution networks) have a very large number of such areas – not
infrequently in the hundreds of specific areas;

the need for additional capacity to meet peak demand within each local area can be
foreseen by network planners, but the exact timing of each project can vary substantially;
and

the key parameters for each capacity augmentation project are unique in terms of:
– the amount of demand reduction needed to defer augmentation;
– the timeframe by which that amount of demand reduction must be achieved;
– the exact timing, duration and frequency that demand response will need to be
available in order to achieve the deferral; and
– the nature of the customer base within the constrained area (and so the demand-side
potential for providing the demand response needed within the timeframe available).
Two basic modelling approaches can be used to estimate potential network benefits from
network peak savings, namely:

the deferral approach, which is a bottom-up approach that seeks to determine the actual
capacity augmentation projects that can be deferred by demand-side activities (or other
non-network solutions) and the aggregate value of those deferrals over time; and

the area-wide demand reduction approach, which is a top-down approach that makes the
assumption that any permanent reduction in peak demand that occurs anywhere in the
network will reduce capital costs at some point in time, and applies judgemental (or at
least semi-judgemental) adjustment factors to account for the fact that (a) some portions
of the service territory may be experiencing very slow (or even negative growth) and (b)
different parts of the service territory will experience peak demands at different times of
the day or even different seasons from each other, and from the generation sector.
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Table 4.2 below summarises the key advantages and disadvantages of each of these
approaches.
Table 4.2
Principal Advantages and Disadvantages of the Deferral and Area-Wide
Approaches to Assessing the Network Benefits of Peak Savings
Advantages
Disadvantages
Deferral approach
Closely reflects the real financial cost of peak demand on the
network and the benefits to be realised from deferral of
specific augmentation projects
Requires a significant amount of data on specific demand
growth-related augmentation projects, including:

the current capacity limitation and level of peak demand
in the local area

how quickly peak demand is growing in the local area

the estimated cost and latest construction start date of
the supply-side solution

a list of major customers within the area and their peakday load profiles

the number of other customers within the local area
broken down into at least major customer sectors,
including their contribution to peak demand or at least
their aggregate electricity consumption on a peak day
Networks generally project likely augmentation requirements
on a rolling 5-year horizon, and the need for augmentation is
not constant over time in volume or cost terms.
This makes it difficult to accurately project potential deferral
benefits over a longer time frame which also makes it more
appropriate for guiding programme targeting rather than for
assessing long-term scheme benefits.
Area-wide approach
Very simple to use
Establishing the ‘average value’ for reducing network peak
demand is difficult --the cost of network augmentation differs
significantly across and within distribution service territories
Requires only minimal network-specific information
An average value – even a distribution business-specific
average – will tend to be ‘wrong’ more often than right.

some areas experience extremely slow growth

not all local areas peak in the same season or time of
day
Adjustment factors are generally needed to account for this
but rely significantly on the judgement of the analyst
Can be made more granular by applying the approach to
regions within the distribution service territory that have
different cost characteristics or peak demands in different
seasons
4.2.2.
Each increase in granularity requires that all of the required
information be gathered regarding the new level of granularity,
and adds complexity to the task of forecasting outcomes
Data considerations
The main difficulties with obtaining the data required to assess the area-specific network
benefits of network peak demand savings are that:
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
there are a large number of areas within each network (especially the distribution
networks) that may require augmentation at any particular point in time;

virtually all of the inputs to the valuation of area-specific augmentation deferral are
specific to the particular situation, adding significantly to the amount of analysis required;

the timing of the need for each specific augmentation can change not only due to external
circumstances (such as deviations from forecast load growth and non-normal weather) but
also due to changes in other parts of the network asset base (eg, new circuits that allow
different areas to share capacity); and

the network only publicly predicts the need for area-specific augmentation about five
years into the future.
Assembling and maintaining this data requires a significant amount of effort.
The amount of data required for the area-wide assessment of the network benefits of network
peak savings, by contrast, is much smaller – generally only consisting of:

the season and time of day that best characterises peak demand across the network;36

the amount of peak demand reduction that can be provided by the scheme;37 and

the average cost of augmenting network capacity.38
While these data requirements make area-wide analyses much less taxing from the
perspective of data assembly and maintenance, the fact that several key bits of information
are likely to be represented by highly uncertain values is of concern. The two items of most
concern in this regard are:

the appropriate value to use for the average cost of additional capacity that is required due
to increases in peak demand – the value most frequently used is the long-run average
incremental cost (LRAIC) of network capacity, which is easy to define but values can
vary significantly; and

the judgemental factors to be used to discount the expected value of the peak demand
reductions available within the area due to peak demand that occur at different times or in
areas within the network that are experiencing very slow (or negative) load growth.
The area-wide approach can be applied at areas within a given distribution service territory
that have different demand profiles and/or cost structures. This can allow a greater level of
36
In the case of larger network service areas that span different areas, different climate characteristics can produce peak
demands that occur at different times of the day or even seasons of the year. Similar differences can occur in different
local areas with different mixes of customers across the major customer sectors. In such cases, the network can be
broken up into smaller, more homogeneous sub-areas and a different area-wide analysis conducted in each.
37
The amount of peak demand reduction that can be provided by the scheme is a function of the customer mix and enduse characteristics of those customers. Where different parts of the network can be classified as having different
customer and end-use mixes, these groupings can be used to identify the amount and type of peak demand reduction
that is likely to be available in various areas, based on customer counts.
38
In the case of networks that have different portions of their infrastructure with very different cost characteristics,
separate area-wide analyses can be undertaken for each part of the system, with each area being expected to have its
own average cost of incremental capacity.
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granularity to the analysis, but requires a corresponding increase in data and would add to the
complexity of scheme implementation.
4.2.3.
Recommendations on modelling the network benefits of a national
ESI
Modelling the network benefits of the introduction of a national ESI requires consideration to
be given to:

the likely impact of the scheme on network peak savings; and

the likely size of the network deferral benefits that can be achieved by the associated
network peak savings.
As we discuss in this report, we believe that the incremental impact on network peak savings
of a peak energy savings incentive as part of an ESI is likely to be relatively small compared
to the efficient peak savings which will potentially be achieved through incentives created
through the NER.
Regardless, there remains merit in considering the likely size of the network benefits of peak
energy savings irrespective of how the incentives to achieve these savings are created.
We have been asked as part of this project to provide any insights on the methodology for
estimating the network benefits of an ESI, based in part on our discussions with both network
businesses and the consultants that have been engaged to undertake this modelling. In
summary, we believe that:

To the extent possible, the analysis should try to assess the impact of a national ESI on
network tariffs. This will require consideration of the changes wrought by the scheme in
terms of both peak and total demand (ie, the change in load factor) as this will determine
whether the scheme will tend to have an upward or downward impact on average network
tariffs, and the relative magnitude of that pressure. This analysis will need to be
undertaken on a jurisdictional or individual company basis, and will be unlikely to be
undertaken with any real degree of accuracy for more than a single regulatory
determination period (or two such periods at most), due to the large number of factors that
are relevant to the setting of the tariffs, and the degree to which they could change over
that timeframe.

Both the system and end-use load profiles to be used in the analysis should be based on
10% Probability of Exceedance conditions as these will provide a more realistic
assessment of the impact of the demand-side measures being considered.

The load profiles (and more specifically the change in load profile) attributed to each
energy efficiency or peak savings measure should be re-assessed for their impact at the
time of network (or area-specific) peak demand, as illustrated in Figure 4.1 below. This
is an important step to ensure that the demand-side impacts anticipated to be available are
as realistic as possible.
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Figure 4.1
Illustrative Alignment of Peak Savings Measure with Network Peaks (Impact of
High Efficient Street Lighting)
14000
160
12000
140
MW (System wide)
100
8000
80
6000
60
4000
MW (Local network)
120
10000
40
2000
20
0
0
0:30
2:00
3:30
System peak demand
5:00
6:30
8:00
9:30
Reduced system peak
11:00
12:30
14:00
15:30
Local network peak
17:00
18:30
20:00
21:30
reduced network peak
23:00
Figure 4.1 illustrates the point by overlaying the summer peak day profile of the generation
system (characterised by a broad, midday peak that persists through to early evening), on the
peak day profile of a network area whose loads are predominantly residential (and
characterised by a load profile of heavy demand in the morning and a slightly higher peak
that builds in the afternoon and persists through the mid-evening hours). Overlaid on both of
these is a representation of how an increase in the efficiency of street lighting would affect
these load profiles.
Note that the profiles are illustrative and so are not drawn to scale. Rather, it is the shape of
these demands that is of interest. Specifically, in the middle of the day the street lights are
turned off so the increase of efficiency in street lighting will not produce any reduction in the
generation peak demand, which occurs at about 16:00. By contrast, by the time the network
experiences its peak demand – at about 19:30 or 20:00 – the street lights will have come on
and the increase in efficiency will reduce network peak demand.
In addition, the following recommendations are offered with regard to modelling network
benefits related to each of the peak scheme design options presented in chapter 3 above,
regardless of which of the three design options discussed above is taken forward into the
analysis:

The peak demand impacts of the energy efficiency and peak demand reduction measures
to be assessed should be calculated at the specific season and time of day of the relevant
network or network area peaks to provide as accurate an estimate as possible of the value
of the measure in each network application. This should be done whether the analysis is
undertaken on an area-specific or area-wide basis. Any peak demand benefit of the
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measure to the network will then need to be considered in addition to any generation
system benefit that is taken into account in valuing the measure.39

Forecast impacts of the measures on network tariffs, (and electricity prices more
generally) where material, should be taken into account in assessing the economic
attractiveness of the demand-side measures in subsequent year programme take-up
estimates.

The consumers’ share of forecast certificate values should be taken into account in
estimating the take-up of the various measures eligible for certificates under the
programme.

Wholesale market modelling should be used to assess the impacts of the benefits in the
generation sector based on retailer obligations.

To the extent that there is seen to be merit in adding a value for the potential network
benefits of a national ESI to the wholesale market benefit, this would seem to be most
reasonably done by using the area-wide approach and using a value such as the long-run
average incremental cost (LRAIC) of network capacity additions as the value to be
ascribed to reductions in network peak demand. The LRAIC value will allow the
network to provide additional targeting for area-specific augmentation deferral where the
deferral value is higher than the LRAIC, and consideration should be given to developing
LRAIC values specific to each distribution business (or to different regions within larger
distribution service territories, which might be at the option of the distribution business).
In any case, the LRAIC should probably also be subject to an adjustment factor (a
decimal value less than 1.0) to reflect the fact that not all energy efficiency impacts will
result in peak demand savings for the network, and that even where they do reduce peak
demand they may not change network capital requirements for the foreseeable future.

No additional credit should be attributed for short-term deferral network benefits as these
will accrue primarily due to the regulatory framework as it is expected to be enhanced by
the addition of the RIT-D.40
4.3. Summary
There are two principal approaches for assessing the impact of demand-side measures
(including energy efficiency activities) that might be implemented as a consequence of peak
savings on the generation sector. While the static approach is significantly easier to apply,
the data and computing resources needed for the dynamic approach are generally available,
and it also provides a more realistic estimate of peak savings implications on the generation
sector.
39
It is our understanding that market modelling is being used to assess the benefits to the generation sector of each of the
options for adding a peak demand savings initiative to a retailer obligation based ESI. We strongly support the use of
that approach.
40
Although, it should be noted that under Option 1, networks may have a significant incentive to use the existence of an
ESI to focus area-specific demand-side augmentation deferral efforts in those areas where there is significant overlap in
the timing and duration of generation and network peak demand.
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Data is significantly more problematic to estimate the impact of peak savings on electricity
networks. This is because the network peak demand impacts that drive network costs are
those that occur in the various specific asset areas comprising the network, and even more
importantly, in those areas in which additional capacity is forecast to be needed within the
foreseeable future. The benefit of a scheme to reduce peak demand in such areas rests in the
potential to encourage the take-up of a sufficient number of demand-side options to keep
peak demand within the capacity of the current infrastructure and to do so before construction
of assets required to meet additional demand would have to be commenced. Calculating the
aggregate potential of such instances across any single network requires a significant amount
of data, and can only be done over the time period for which the distribution company can
project the need for additional capacity, which is typically five years or so.
It follows that while such an approach may be helpful for identifying specific targets in the
event that a national ESI with either Option 1 or Option 2 is implemented, it is less likely to
be useful for projecting the potential benefits of peak savings over a longer time period. For
that purpose, an area-wide approach (of a yet to be determined level of granularity) is likely
to be more appropriate. In that approach, the assumption is made that any reduction in peak
demand anywhere on the network will be of value at some point, as ultimately, the entire
network is very likely to have to be expanded. The long run average expenditure for capital
expansion of the network is then deemed to equate, on an annualised basis, as the value of
reduced peak demand to the network. Judgemental factors are applied to the figure to
account for the fact that some parts of the network may experience peak demand at a different
time of day or season than the system as a whole, and that some parts of the network are
experiencing very slow growth.
This approach can be used in association with the market modelling recommended for use in
assessing the generation sector benefits of peak energy savings in each of the three options
described in this study.
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5.
Evaluating Scheme Design Options
Evaluating Scheme Design Options
This chapter evaluates the scheme design options and highlights the relative merits and
disadvantages of each approach.
5.1. Criteria for assessment
Each of the scheme designs has merits and deficiencies. To assist with an evaluation of the
options a number of design criteria have been developed, specifically:

scheme design and implementation;
– ease of implementation;
– scheme establishment and administrative costs;

scheme benefits;
– likelihood of achieving peak savings;
– likelihood of achieving near term wholesale/network benefits;
– likelihood of achieving medium to long term wholesale/network benefits;

promotion of innovation in peak demand reductions;

consistency with other regulatory processes; and

certainty of peak reduction.
The following sections examine each of the schemes against these criteria.
5.2. Scheme design and implementation
The first criteria relates to the ease of scheme design and implementation.
Both Option 1 (ie, a peak savings incentive) and Option 2 (a stand-alone peak savings
scheme) are likely to be relatively easy to implement and administer compared against
Option 3 (ie, a single peak energy savings buyer scheme). This is principally because of the
scope to make use of the systems and processes that will also need to be developed as part of
a national energy savings scheme. The incremental cost of either creating an incentive for
peak savings, or establishing a separate peak savings target obligation, is therefore relatively
small.
That said, if a separate peak savings target is created with either Option 1 or 2, additional
compliance costs will be imposed on the obligated party (ie, retailers or networks). These
arise from the need to separately surrender peak certificates (in the case of Option 2) or
account for peak savings (in the case of Option 1).
Establishing a single peak energy savings buyer scheme (Option 3) would require
consideration of the administrative arrangements for the scheme. The options could include
the scheme being administered by a government department, the entity responsible for the
national energy savings scheme, or a new separate entity. The choice between approaches
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would likely reflect the entity’s approach to managing peak demand. If it was to actively
manage peak demand then ensuring the entity was independent would be important to
minimise any uncertainties for participants in the wholesale electricity market. However, if it
was managing medium to long term load profile via a bidding scheme, then this might be
readily administered by a government department or the peak energy savings scheme
administrator.
5.3. Scheme benefits
An important consideration for the choice of scheme design is the certainty with which the
scheme will achieve the anticipated benefits.
As we have noted, most of the schemes will achieve either the level of peak savings specified
by a target obligation or requirement or result in a penalty being paid. The differences
between the schemes relate to the incentives created to target the achievement of benefits and
the timeframe within which those benefits might be achieved.
As we have explained in the report, these schemes are unlikely to enhance the achievement of
short-term network benefits arising from the deferral of specific augmentation projects
because the incentives to undertake peak savings to defer network investments are based
mostly on the requirements in the NER. That said there might be some incremental network
benefits over the medium to long term from:

innovation in peak savings activities and programmes resulting from an expansion of
activities by ESCOs seeking to create certificates or to respond to requests from a single
peak savings buyer; and

improved certainty of savings as more peak savings programmes and activities are
developed and implemented over time.
In regards to wholesale benefits, both a peak savings incentive and a target scheme have the
potential to achieve benefits in the medium to long term. This is because the benefits arise
mostly from the deferral of new peak generation investments in the medium to long term.
That said, a peak energy savings buyer might be capable of achieving near term wholesale
benefits if it engaged in activities that involved controlling load into the market to influence
peak prices. This would have a near term effect of lowering wholesale costs that would
influence future contract prices and so lower retail costs.
In summary, a peak savings incentive or peak savings target scheme would be expected to
deliver benefits in the medium to long term as load profiles changed and generation
investments were deferred. A peak savings buyer has the potential to create nearer term
wholesale benefits.
5.4. Other considerations
The remaining criteria relate to the promotion of innovation in peak demand reductions;
consistency with other regulatory processes; and certainty of peak reductions.
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All of the schemes will have the effect of promoting innovation in peak demand reductions
because they all create a market for these activities. This contrasts with the current
environment where any innovation in programmes and activities for peak demand savings
may not have a buyer, which inhibits the development of innovation in the first place.
Of the three scheme designs, the single peak savings buyer is anticipated to have the best
incentives for innovation because it creates certainty of revenue for peak savings programmes
through either a contracting or defined payment system. In contrast the market based
schemes still require third parties to forecast likely certificate prices to determine the
expected revenue from peak saving activities.
All of the schemes are likely to be consistent with the existing incentives for network peak
savings embodied in the NER. The creation of a peak savings incentive or peak savings
target as part of a national energy savings scheme is most consistent with the wider policy
approach to managing energy savings. That said, a single peak savings buyer would
minimise the regulatory burden for electricity businesses while a stand-alone peak savings
scheme with an obligation on networks would likely increase the compliance burden across
the electricity sector.
Finally, most of the scheme designs provide certainty of achieving a peak reduction because
they place a direct obligation on the achievement of a defined level of peak savings, or the
payment of a penalty. The exception is where the incentive for peak savings is achieved by
increasing the number of energy savings certificates associated with activities that result in
peak savings.
5.5. Summary
In summary, providing a peak savings incentive as part of a national savings scheme is a low
cost option for achieving wholesale peak savings benefits in the medium to long term. It
ensures that the value of peak savings as compared to savings that worsen load factor can be
explicitly valued.
In contrast a single peak savings buyer provides the most flexibility to adapt to changing
circumstances and the opportunity to target and learn from activities and programmes over
time. It will also, most likely, provide the best incentives for the development of innovation
in peak savings activities and programmes because of the certainty of funding that would be
created for third parties contracted to deliver defined peak savings. That said, it is the highest
cost option and also involves the greatest deviation from a market-based approach that has
been an important part of electricity industry reforms over the past two decades. A risk with
this scheme is the uncertainties it creates on the likely wholesale market outcomes, which
could therefore create distortions to the signals created in the market with negative
consequences for wholesale market efficiency.
A stand-alone peak savings scheme seems to have relatively few incremental benefits
compared to an incentive being placed within a national energy savings scheme. Its possible
incremental merits arising from the potential to target savings within particular networks are
diminished by the incentives created through the NER for network businesses. Given this, it
is likely to have a similar impact on wholesale benefits but with incrementally higher
administrative costs. In addition it would place a compliance burden on network businesses
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Options
Evaluating Scheme Design Options
that would otherwise not be directly obligated to be involved in a national energy savings
scheme.
Finally, Table 5.1 provides a summary of our ranking of the scheme design options against
each of the design criteria. It is important to note that the criteria shown in the table have not
been weighted in importance, and therefore the ratings shown should not be seen as
establishing a definitive preference ranking of the various options.
Table 5.1:
Assessment of Peak Energy Savings Scheme Design Options
Option 1:
Option 2:
Option 3:
Peak savings
included in
national energy
savings scheme
Standalone peak
savings scheme
Peak savings buyer
scheme









Likelihood of achieving
wholesale/network cost reductions
in short term (< 3 years)



Likelihood of achieving
wholesale/network cost reductions
in medium/long term (> 3years)



Promotion of innovation in peak
demand savings



Consistency with other regulatory
processes



Certainty of peak reduction



Design Criteria
Scheme design and
implementation
Ease of implementation
Scheme development and
administrative costs
Scheme benefits
Likelihood of achieving peak
efficiency outcomes
Other considerations
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6.
Further Considerations for the Design of a National ESI
Further Considerations for the Design of a National
ESI
Peak demand growth is a significant driver of costs for both the generation and network
components of the electricity supply chain. As a consequence ongoing growth in peak
demand is one of the main contributors to the electricity price rises that have been
experienced over the past several years and that are projected to continue into the medium
future.
Concerns about peak demand growth and its impact on electricity system costs and electricity
prices is one of the main reasons that the Commonwealth Government decided that one part
of its Clean Energy Future package would be to
expedite the development of a national energy savings initiative (ESI) and will
examine further how such a scheme may assist households and businesses to
adjust to rising energy costs,41
and that an ESI itself would
have broad coverage (that is residential, commercial and industrial sectors); and
create an incentive or a requirement to create certificates in both low income
homes and in ways that reduce peak electricity demand.42
This specific project was undertaken by NERA and Oakley Greenwood to consider how
incentives might be created to reduce peak demand.
However, while reductions in peak demand will put downward pressure on the costs incurred
by the electricity supply chain – and therefore the price of electricity – other factors are also
important determinants of electricity prices. As discussed in Section 2.2, considering
changes in load factor – ie, the time distribution of energy demand – is the simplest approach
to understanding the impact of both energy consumption and peak demand reductions on
electricity system costs and prices.
While each of the options developed in this report have been designed to provide an incentive
for peak demand savings, ensuring that they have a positive (or at least neutral impact on load
factor) will require additional consideration. Specifically:

While Option 1A can be expected to promote peak demand savings it cannot ensure
(without the inclusion of additional measures) that enough peak demand savings will
occur to keep load factor from deteriorating.43

Options 1B, 2 and 3 could be implemented in a way so as to avoid deterioration of load
factor. This would require that the separate peak demand target be set to counterbalance
41
Australian Government, Report of the Prime Minister’s Task Group on Energy Efficiency, Canberra, July 2010, p. 81.
42
Australian Government, Securing a Clean Energy Future – The Australian Government’s climate change plan, Canberra, July 2011, p.
126.
43
An example of a measure that could be added to accomplish this is discussed below.
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Further Considerations for the Design of a National ESI
any negative consequences on load factor that could be expected to result from the
specific level of overall energy efficiency that had been targeted. Setting such a peak
demand reduction target with regard to the load factor of the generation system would be
relatively straightforward. However, it will be difficult to do so in such a way that would
also protect the load factor of individual distribution networks or specific areas within any
distribution network. This is because it is extremely unlikely that the geographic
distribution of peak demand and general energy consumption reductions produced by an
ESI at a national level would match the load profile of – and thereby produce beneficial
load factor impacts in – each distribution network. This means that the setting of a peak
demand savings target would have to be adapted to each distribution network, or at least
to a set of categories of electricity distribution network types based on the timing of their
peak demand. In Options 2 and 3 these arrangements could become more difficult in the
event that the peak demand target is not set by the same agency responsible for setting the
overall energy saving target.
Of equal or perhaps greater concern is the fact that the scope for load factor deterioration is
currently present in the state-based ESIs.44
The general conception of white certificates is that they represent a certain quantity of kWh
(or tonnes of CO2-e) saved. These certificates are then awarded to eligible energy efficient
activities under a white certificate scheme. But each energy saving activity also has an
impact on the peak demand of the generation system and the local network system in which
the activity occurs. These impacts can generate positive or negative effects on the load factor
of the generation sector and each distribution network, and therefore on the unit price of
electricity. Where load factors deteriorate, there will be upward pressure on unit prices. This
will result in bill increases for consumers that have not reduced their consumption, essentially
constituting a dis-benefit for non-participants in the scheme.
One approach for addressing this that could be applied to either (a) an ESI that did not take
peak demand into explicit account, or (b) Option 1A would be to award certificates to the
various energy efficiency measures on the basis of the measure’s impact on system load
profile.
Under this option, the predicted public benefit or dis-benefit arising from each energy
efficiency measure would be incorporated into the certificate-based reward it receives under
the scheme, thereby encouraging the uptake of activities that minimise the scheme’s potential
negative outcomes (and maximise the positive public benefit outcomes). Put another way,
the relative number of certificates per annual kWh saved to be awarded to any energy
efficiency measure would be proportional to the measure’s marginal impact on system load
factor.
In sum, the relative number of certificates per annual kWh saved to be awarded to any energy
efficiency measure would be proportional to the measure’s marginal impact on system load
factor.
44
This is not to say that the state-based energy savings schemes have resulted in load factor deterioration, but only to say
that such an outcome could happen.
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Further Considerations for the Design of a National ESI
This adjustment could be undertaken at either or both the generation system and/or network
levels. The generation system loadshape impact for any particular measure would be likely
to be relatively constant across jurisdictions within any particular generation system (ie, the
NEM, the SWIS, etc). This is because the generation load shape is unlikely to vary
significantly within each generation system. The exception to this would be where the
magnitude of the measure’s impact changes across the area served by the generation system.
For example, high efficiency air conditioners deployed in Tasmania are unlikely to have as
great an impact on the loadshape of the NEM as the same machine installed in South
Australia.
The load shape impact of any particular energy efficiency activity is more likely to vary
between distribution networks within each of the larger generation systems, as well among
different areas within each of the distribution areas. If these network impacts are sufficiently
different, consideration will need to be given to whether the added incentive value of their
inclusion within the scheme justifies the additional complexity their inclusion will entail.
For example, the installation of high efficiency lighting in office buildings is likely to reduce
system load factor and revenue in network areas dominated by residential loads because it
reduces energy use at non-peak times. Under this approach, the energy efficiency activity
would receive fewer certificates than under a conventional ESI scheme design. In contrast,
high efficiency air conditioning would be likely to receive more certificates under this
approach as compared to a conventional ESI design. This would likely be the case because in
this example the high efficiency air conditioning system would reduce peak demand for both
the generation system and the network.
In summary, the approach proposed here – or some variant of it – would seem to be of
significant value in ensuring that the pursuit of energy efficiency and greenhouse gas
reductions (which have a mix of private and public benefits) do not come at the expense of
deteriorating load factors, which place upward pressure on prices the impact of which may be
unequal across various different groups of end-use consumers.
If the impacts at the network level are sufficiently large, it may be important (in terms of
protecting the net public benefit of the scheme) to incorporate the network load factor impact
into the overall scheme certificate award mechanism. However, if the impacts at the network
level are very different from one another consideration will need to be given to whether the
added incentive value and net public benefit of their inclusion within the scheme justifies the
additional complexity that inclusion would entail for the implementation and administration
of the scheme.
Finally, there is merit in giving further consideration to:

the materiality of the network benefits, by collecting information on actual network peak
profiles of distributors and consulting with distributors on the possible opportunities to
adjust LRAIC values to represent area-wide benefits of an ESI scheme;

using information on distribution system load profiles to assess the likelihood of possible
negative network consequences from different ESI scheme design options;
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Further Considerations for the Design of a National ESI

how an ESI might be designed so as to avoid any possible negative consequences from
deteriorating system load profiles;

enhancing the operation of an ESI scheme through the development of a mechanism to
provide incentives for demand management activities that directly manage load factor;

scoping the information requirements and the feasibility of possible institutional and
governance arrangements for implementing a preferred approach to creating a peak
savings incentive; and

the establishment of an expert advisory group to guide the further development and
analysis of an national ESI scheme design options and associated benefits and costs,
given the complexities involved.
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Appendix A.
Appendix A
Peak Technical Group and Network
Modelling Group Members
The following organisations participated in Peak Technical Group and Network Modelling
Group meetings.
Table A.1: Organisations that Participated in the Peak Technical Group and
Network Modelling Group
Peak Technical Group Members
Network Modelling Group Members
Department of Resources, Energy and Tourism
(DRET)
Department of Resources, Energy and Tourism
(DRET)
Department of Climate
Efficiency (DCCEE)
Department of Climate
Efficiency (DCCEE)
Change and
Energy
Change and
Energy
Australian Energy Market Commission (AEMC)
Australian Energy Market Commission (AEMC)
Australian Energy Market Operator (AEMO)
Australian Energy Market Operator (AEMO)
Australian Energy Regulator (AER)
Australian Energy Regulator (AER)
Commonwealth Scientific and Industrial Research
Organisation (CSIRO)
Commonwealth Scientific and Industrial Research
Organisation (CSIRO)
Energy Networks Associations (ENA)
Energex
Energex
AusGrid
AusGrid
Office of Environment and Heritage (NSW)
Ergon Energy
Energy Retailers Association of Australia (ERAA)
ERM Power
Origin Energy
EnerNOC
UTS Institute for Sustainable Futures
Office of Environment and Heritage (NSW)
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