Chapter 5 - Network value - Victorian Competition and Efficiency

Network value
Enabling the network value of distributed generation to be captured by distributed
generators is an important driver of efficient investment and installation of distributed
generation technologies of all sizes. If network vale can be identified, captured and
paid to those parties providing distributed generation, positive net network values can
provide incentives to connect distributed generation in areas where it has the biggest
benefits in reducing the cost of the network. Network costs are a major driver of retail
electricity prices (ACIL Tasman 2012c).
Positive network values signal areas where the existing network is close to, or at
capacity, and investment in distributed generation would allow additional investment
in the network to be deferred or avoided. Those able to connect distributed generation
in these congested areas of the network would receive a greater financial incentive to
do so than those proposing to connect in areas where the network value may be zero
or negative because of the investment required to reinforce the network to
accommodate distributed generation.
Identifying and realising the network value of distributed generation is more difficult
than identifying the output value of exported electricity because network value is
location and time specific. In addition, it relies on distributed generation being able to
guarantee production when it is needed by the network. Furthermore, network value is
a capital value rather than a value based on per unit of output.
If there were an effective market for identifying and realising network value the
Commission expects that distribution businesses would plan measures, including for
distributed generation, to alleviate identified localised system constraints where such
investment would have a net benefit. The distribution businesses and the proponents of
distributed generation would also be able to access sufficient information to assess the
costs and benefits of the proposed distributed generation to the network and the
The rules on how any necessary network reinforcement costs should be shared, and
who pays, would be clear, efficient and equitable. Areas where network investment
could be avoided by distributed generation (or demand side responses more
generally) would be identified and payments made available to proponents of such
investments. If distributed generation projects arise outside this planning and require
investment to be brought forward the rules on how such projects would be charged
would also be clear and predetermined.
In these circumstances each party would be in a position to make an informed decision
about the value of proposed investment in distributed generation.
Such a system would allow distributed generation to be planned into the network and
charges and payments to be defined up front as part of the Australian Energy
Regulator’s (AER’s) five yearly price reset when regulated distribution charges are
determined. This system would avoid the problem of one distributed generation project
bearing the full cost of any necessary network reinforcement.
However, the current market is unlikely to deliver this sort of outcome because
distribution businesses are regional monopolies and therefore do not face competition,
and the way they are regulated reinforces the traditional approach of meeting future
demand by investing in the capability of the existing network. The Commission
considers these issues and possible recommendations to address them in the remainder
of the chapter.
How material is network value?
The value of deferring additional investment in the network is both time and location
specific, and where the network is constrained the value may be significant. Based on
a range of estimates on the network value of distributed generation ACIL Tasman
reported that:
In a recent report to the AEMC, Ernst and Young noted that the network
value of reducing growth in peak demand is complex and recommended
“exercising extreme caution in using any (general) measure of value”. Ernst
and Young considered that there was sufficient precedent for using “rules
of thumb” of between $90 and $300 per kVA per year for deferred network
expenditure. (ACIL Tasman 2012c, p.87)
Another estimate found similar values:
Similarly, in the context of the Victorian Advanced Metering Infrastructure
program, Oakley Greenwood calculated the value of reduced growth in
peak demand at $200 per kW, although this included the value of deferred
investment in generation, so is greater than the network value. (ACIL
Tasman 2012c, p.87)
In very constrained networks the value of deferring can be very high. For example, in
the very constrained parts of the Sydney network:
… there are potential avoidable network costs of up to and beyond $1000
per kVA of peak demand reduction per year. If such a peak lasted, say 10
hours per year, this represents a potential avoidable cost of $1000/10 hours
or about $100 per kWh. (Dunstan et al. 2011, p.11)
In terms of what this means for a distributed generation in Victoria, ACIL Tasman noted
If it is assumed that the network value is in the order of $150 per kW, and a
2.5 kW solar PV system defers a planned network augmentation by three
years, the network value is $375 per year for the three years for which the
augmentation is deferred. (ACIL Tasman 2012c, p.83)
Currently there is little information about the nature, location and value of network
constraints. This situation clearly limits the capacity of market participants to identify
and value opportunities to relax these constraints and/or defer investments in the
network. That said, the ACIL Tasman findings suggest that network value, if it could be
realised and made available to the proponents of distributed generation, is likely to
provide a material financial incentive for those in constrained parts of the network to
invest in distributed generation.
Market power concerns
Local distribution businesses have monopoly power, and access to information on
where the network is constrained or is reaching capacity (hence where network value
is greatest) and on the need for, and cost of, any network reinforcement necessary to
support the connection of distributed generation. This is a significant information
Market power concerns can be reduced by putting distributed generation proponents
in a better negotiating position. Increasing their negotiating position through the use of
aggregators (being considered in the AEMO Small Generator Aggregator Framework
rule change) would help by providing distributed generation proponents a degree of
countervailing power (AEMO 2011). However, issues remain, the two key ones for this
inquiry are:
provision of better information
increased clarity on the size and sharing of reinforcement costs.
Better information
Many inquiry participants argued that information on network capacity by location
could help reveal areas where network values are likely to be higher and inform better
siting of investment in distributed generation. Such information would assist with
negotiation thereby improving the functioning of the market and reduce connection
costs. Distributed generators can benefit from information on where their projects are
needed or can be tolerated in the network and where there are network constraints to
their further addition. The lack of such information could be a significant barrier to
efficient distributed generation investment and active demand management, and
makes it more difficult for distributed generators to negotiate with monopoly distribution
Many participants, for example Ironbark Sustainability, sub. 50 and the Clean Energy
Council, sub. DR200 suggested that regulators should require the publication of better
information about network constraints and other issues that may render certain
locations unsuitable for new connections. The Energy Efficiency Council recommended
the publication of:
Annual maps of the costs and benefits of connecting cogeneration at
different points on the grid, including potential payments for offsetting
infrastructure investment. The pre-emptive analysis of the costs and benefits
of connecting to the grid at different points would provide greater
information transparency, opening up competition in the market. (sub.
DR200, p. 11)
In the UK, distribution network service providers (DNSPs) submit information strategies for
regulatory approval (ACIL Tasman 2011b, p.30). Ironbark Sustainability suggested maps
of network constraints could reduce barriers to distributed generation (sub. 50, p. 14).
The Institute for Sustainable Futures prepared maps that identify network constraints that
can help inform where distributed generation could result in savings from deferred
network investment (SV 2012). However, these maps are not available on the
Sustainability Victoria website. In addition, the ISF report does not contain information
on fault levels, the main driver of distributed generation connection costs in Melbourne.
Exigency’s submission argued that:
Publication of network performance data (capacity constraints, quality
of supply) would simultaneously support regulatory oversight of prudent
network expenditure and enable the market to proactively devise
non-network solutions.
The process of consideration of non-network solutions by DNSPs could
be made more transparent, for the benefit of energy market efficiency
overall. (sub. 4, p. 3)
The Clean Energy Council proposed that transparency could be improved by
compelling the DNSPs to provide information in sufficient detail to inform negotiation
(sub. DR197). The CEC suggested that any new arrangements should take account of
the fact that DNSPs are monopoly businesses (CEC, sub. 76, p. 6).
CitiPower and Powercor (sub. DR 184) and United Energy (sub. DR 199) claimed that
such information is already available (discussed in the following section).
The AEMC is currently considering a rule change request from the Ministerial Council on
Energy on the Distribution Network Planning and Expansion Framework (AEMC 2011a).
The proposed rule change includes a requirement for DNSPs to publish a Distribution
Annual Planning Report (DAPR) that would detail peak demand, forecast
augmentation of the network and, of particular relevance to distributed generation:
… forecasts of any factors that may have a material impact on the
network, including factors affecting:
(A) fault levels;
(B) voltage levels;
(C) other power system security requirements; and
(D) ageing and potentially unreliable assets. (AEMC 2011a S5.8(2)(v))
In June 2012, the AEMC published a draft rule determination and is seeking submissions
on it by 9 August 2012. The AEMC states that:
The Commission considers that the draft rule will contribute to the
achievement of the National Electricity Objective by establishing a clearly
defined and efficient planning process for distribution network investment.
This will support the efficient development of distribution networks. The draft
rule will also provide transparency to, and information on, distribution
business planning activities and decision making processes. This will assist
market participants in making efficient investment decisions and enable
non-network providers to put forward credible non-network options as
alternatives to network investment. (AEMC 2012d, p.1)
The submission process for the draft rule determination will provide an opportunity for
affected interested parties to comment on the value of the draft change from the
perspective of removing barriers to the connection of distributed generation.
The Commission’s view
The Commission considers improved spatial information on network constraints and
fault levels would improve contestability through fairer negotiation which would help
reveal the network value of distributed generation, and better siting of investment
leading to reduced connection costs. The information would allow distributed
generator proponents to make judgements about likely connection costs and manage
the risks of pursuing projects that are less likely to proceed. Information can support
proponents to make informed decisions and to negotiate more effectively with DNSPs.
The MCE’s proposed Distribution Network Planning and Expansion Framework rule
change request is expected to improve transparency and lead to better long-term
planning to accommodate distributed generators (box 5.1). It would also require DNSPs
to more actively engage with distributed generators.
The AEMC noted ‘that the proposed content of the DAPR would maintain the core of
existing jurisdictional requirements’ (AEMC 2012d, p.30) and the aim is to reduce
inconsistency across jurisdictions.
In response to the AEMC’s consultation paper, Seed Advisory asserted:
Guidance should be provided to ensure that DAPRs appropriately reflect
existing and well-based anticipations about future projects in the five years
covered by each DAPR. This guidance could include:
Requiring the DNSP to provide information on the basis for projections of
estimated embedded generating units and outputs…
Requiring the DNSP to discuss the methodology on which estimates of
capacity in sections of the network have been based…
Requiring the DNSP to discuss the methodology on which estimates of
system security issues, design fault levels and the requirement for
voltage regulation have been based … (Seed Advisory 2011, p.2)
Other participants considered that sufficient information already exists and that
additional information requirements would impose unnecessary burdens on electricity
companies. For example, CitiPower and Powercor claimed:
In relation to information and planning, Victorian DNSPs have for more than
ten years produced annual planning reports for their distribution assets and
transmission connection assets. The Essential Service Commission of Victoria
(ESCV) ensured through various amendments to the Electricity Distribution
Code over time that the detail provided in these reports is the most detailed
in Australia and publicly available from DNSP websites.
The current annual planning reports already place a significant work load
on the Businesses taking many months of preparation, review and
co-ordination with other parties. The Australian Energy Market Commission’s
(AEMC) proposed Distribution Network Planning and Expansion Framework
further increases the detail required in each report. The Businesses question
how much further information can practically and cost effectively be
included in these reports. Further, the Businesses would note the Distribution
Network Planning and Expansion Framework Rule changes have been
subject to detailed consultation over many years and the Businesses would
expect the AEMC has reviewed and considered the same issues identified
by stakeholders in the current review. (sub. DR 184, p. 6)
Similarly, United Energy stated that information provision is required by Victorian
… distributors have, for the past 10 years, published distribution system
planning reports which must set out, among other information: (a) the
historical and forecast demand from, and capacity of, each zone
substation; (b) a description of feasible options for meeting forecast
demand including opportunities for embedded generation and demand
management; (c) where a preferred option for meeting forecast demand
has been identified, a reasonably detailed description of that option,
including estimated costs; and (d) the availability of financial contributions
from the distributor to embedded generators or customers to reduce
forecast demand and defer or avoid augmentation of the distributor’s
distribution system. (sub. DR 199, p. 3)
Distributed generation of all scales is likely to grow (chapter 2) and pressure to reduce
the growth of network costs will increase. This will make it increasingly important that
distribution businesses and regulators have good information on the constraints in the
network and where network investment is needed and where it could be avoided.
Distributed generation projects that address network needs are more likely to be
identified and brought forward if regular information is produced in sufficient detail and
made available to the market. The red tape risk is that DNSPs are required to produce
information they would not otherwise need for their own planning for areas that are not
of interest to the proponents of distributed generation.
Patricia Boyce from Seed Advisory questioned the value of information currently
provided through the distribution code:
The information required by the Distribution Code is answering the wrong
question from the perspective of embedded generators not primarily
interested in demand side management. The requirements of the Victorian
and other state Annual Planning Reviews have been strongly influenced
over time by Demand Side Management proponents and, as a result, the
information focuses on the requirement for network augmentation, the
planned timing and costs of that augmentation and the potential for a DSM
proponent to receive payments from the network from identifying an
alternative solution. The material is focussed on the network’s own
requirements, but the underlying customer facing information is not
provided and, I would judge, would be difficult to derive without an
intimate knowledge of the network.
As a customer, you’d want to know:
How to map your project’s location to a zone sub-station, so as to
identify whether or not, at first glance, there appear to be capacity
issues at the zone sub-station that would serve your project;
Whether the underlying projections for energy demand at the zone substation already allow for your project proceeding;
Whether there’s any fault level headroom in the location you’re
planning to build and, if so, how much;
For what areas of the network there is effectively a choice of zone
substation, giving the project proponent the opportunity to consider
alternative connection routes. (Boyce 2012)
Additional information will be available to the proponents of distributed generation as a
result of the rule change (box 5.1).
Box 5.1
AEMC’s draft determination: reporting
The AEMC’s Draft Determination on the Distribution Network Planning and Expansion
Framework proposes the publication of the following information:
forecasts for the forward planning period, including at least:
a description of the forecasting methodology used, sources of input
information and the assumptions applied;
load forecasts for:
transmission-distribution connection points;
sub-transmission lines;
zone substations,
total capacity;
firm delivery capacity for summer periods and winter periods;
peak load (summer or winter and the number of hours per year that
95 per cent of peak is expected to be reached);
power factor at time of peak load;
load transfer capacities; and
generation capacity of embedded generating units;
forecasts of future sub-transmission lines, transmission-distribution connection
points and zone substations, including for the latter two asset categories:
future loading level; and
proposed commissioning time (estimate of month and year);
forecasts of any factors that may have a material impact on its network,
including factors affecting:
fault levels;
voltage levels;
other power system security requirements; and
ageing and potentially unreliable assets.
Source: AEMC 2012.
There was a strong consensus among the participants that were investing in distributed
generation projects that information is important and current levels of information are
inadequate. But there was disagreement and differing emphasis on where in the
process that information should be provided. Information can be provided up front
through distribution system planning reports. Location specific information tailored to
specific projects seems best provided during connection negotiations. The need for
information can be reduced by setting predetermined standards that allow for
automatic connection.1 The AEMC is considering a rule change request which, among
other things, would set connection standards. These avenues for information provision
are not mutually exclusive. They form a continuum and if more information is available
at one stage the need for information at other stages can be reduced.
Information provided during connection negotiations and through predetermined
standards is discussed in chapter 6.
If the framework and other process do not deliver the level of specificity needed the
Victorian Government could:
Undertake and release specific work on network constraints and augmentation
Seek a further rule change
Require distribution businesses to provide information through state requirements.
The Commission therefore considers it prudent to wait until the rule changes are
finalised and then assess the extent to which gaps remain in the information provided.
While the Commission considers that access to information is a significant barrier to
distributed generation it is not in a position, at this stage of the process, to recommend
the approach Victoria should take if the results of the rule changes are inadequate.
Network reinforcement costs
A network may need to be reinforced to accommodate the connection of distributed
generation. However, given the monopoly position of the network providers, four
questions arise:
are the quoted costs of reinforcement and augmentation appropriate?
how does the proponent know this?
who benefits from the reinforcement?
how are the costs shared among distributed generation proponents?
Information and transparency
A lack of transparency makes it difficult for distributed generators to evaluate the
appropriateness or competitiveness of the cost estimates and distributed generators’
share of the costs of network augmentation. Bauknecht and Brunekreeft (2008, p.489)
argued that in theory the form of regulation used for distributed generation, 100 per
cent cost pass through, gives DNSPs incentives to shift costs of system augmentation,
which would happen regardless, onto distributed generation customers. The MCE in
2006 and the AEMC in 2012 identified that this is a problem in practice.
Augmentation of existing network assets may provide benefits to other
network users, creating difficulties in assigning these costs. Furthermore, DG
may provide other benefits to network users, for example, through improved
system security. Quantifying and assigning these benefits is difficult.
(Ministerial Council on Energy Standing Committee of Officials 2006, p.26)
… in relation to augmentations, it is difficult to distinguish the causes of the
increased need of augmentation in a meshed network. (AEMC 2012f, p.173)
Distributed generators claimed that the information provided by the DNSPs is often
insufficient to do due diligence on estimated network costs (Synergy 2010, p. 22). The
Energy Efficiency Council argued there are ‘uncertain and often unjustifiable costs for
connecting to the grid’ (sub. DR200, p. 11). Additional concerns raised by participants
are discussed in chapter 6.
Sharing costs
Determining how to share reinforcement costs among distributed generation
proponents is also problematic. Where a network is constrained, a distributed generator
may have to pay the full cost of network reinforcement that would accommodate
several distributed generation projects and other demand growth:
Requiring non-registered DG [distributed generator] proponents to possibly
pay for costs of augmenting the shared network will affect the incentives for
DG projects, especially in Victoria. Currently DG projects in that state are
only liable for shallow connection costs (i.e., direct connection assets and
extensions)… The incremental DG project application that leads to the
available fault level headroom/capacity being breached will be asked to
meet the full costs of the required shared network augmentation. (AEMC
2012f, p.270)
The DNSPs consider this problem is complex:
There are no easy ways to remove the fault level barrier problem although
long term planning should aim to reduce fault levels to make allowance for
future distribution generation. (UE sub 77, p. 5)
Where network reinforcement does occur, there is no mechanism to charge
subsequent distributed generation projects for their share of the reinforcement. For
example, the Energy Efficiency Council argued there are:
Inequitable rules about who pays for network upgrades to facilitate
cogeneration. Currently, the last cogeneration unit that wants to connect to
the grid before an upgrade is required to pay the full cost of the upgrade,
despite the fact that other units may connect before or after the upgrade. In
contrast, the cost of upgrades to the grid to address rising energy demand
are generally smeared across all energy users. (sub. DR200, p. 11)
Who benefits from reinforcement
Another aspect of the incremental network reinforcement cost is identifying who
benefits and which activities have produced the need for that investment. Growth in
demand, for example, also naturally leads to the need for increased fault level
capacity. As electricity demand increases due to population growth, more energyintensive appliances and changing land use (such as higher density housing), new
substations are required to accommodate increased energy from the transmission
network and this requirement increases the fault levels on the distribution network. The
AER considers that, in general, the beneficiary of network augmentation to
accommodate a distributed generation project is the distributed generator and that
these increased costs should not be recovered from customers through network
charges (AER 2011c, p.64). The AEMC considers treatment of this issue will have a
significant impact on distributed generation:
… the effectiveness of [the AER’s proposed connection] arrangements will
depend upon how they are applied in practice, including the net benefit
test and whether DNSPs offer constraint reduction services, and the
transparency of connection cost estimates. (AEMC 2012f, p.174)
There is also an issue that if a distributed generator does pay for investment required to
connect to the network this may open the way for other distributed generators to
connect without incurring any of the costs.
However, while distributed generation can impose costs on the network there are
potential network benefits including increased reliability, smaller incremental cost and
deferred network investment. These benefits depend on highly localised characteristics
and timing of distribution network investment. While the AER does recognise where
there are ‘demonstrable benefits’ to other users and the negotiation process offers an
opportunity to share these benefits, the onus of proof is on the distributed generator
proponent (AER 2011c, p.64).
In terms of regulatory incentives for distributed generation specifically, even if the
overall benefits of a project are positive, additional network costs can represent a
disincentive for network operators to connect the distributed generator. Consistent with
this view, the AEMC concluded that the incentives for DNSPs to engage in demand side
participation, which includes distributed generation, may not be optimal: ‘the current
arrangements may fail to provide the right incentives even if it is efficient to do so’
(AEMC 2012f, p.135). The AEMC also concluded DNSPs have strong incentives to
concentrate on security concerns, and weak incentives to connect distributed
generation (AEMC 2009b, p.28).
The Commission’s view
The Commission considers that the lack of guidance and clarity around regulatory
mechanisms to recover network reinforcement costs presents a significant barrier to
connecting distributed generation to the electricity network in Victoria.
There have been attempts to clarify how reinforcement costs will be shared but they
have been unsuccessful. For example, CitiPower proposed a levy on distributed
generators for the 2011-15 price determination. The cost was to be recovered partly
through a charge on embedded generators and partly from all customers (standard
control service). In rejecting the proposal the AER argued the service should fully
recover fees from distributed generators (alternative control service) and requested
CitiPower to provide further information to support the fee (ACIL Tasman 2011b, p.20).
AER was of the view that this service should be an alternative control
service rather than a standard control service on the basis that the works to
maintain fault levels were attributed to specific connections rather than
recognising that an efficient solution requires works to be undertaken in the
shared network. (ACIL Tasman 2011b, p.20)
This process illustrates that there is no agreed framework on how these costs should be
allocated and shared.
A lack of clarity also means DNSPs are less likely to plan distribution networks to
accommodate distributed generation. The sharing of costs could be improved by
developing guidance on the conditions and circumstances for allocating the network
reinforcement costs across new distributed generation projects and across customers
when they result in system wide benefits. These guidelines could inform future price
determinations and connection charges. Addressing these barriers through improved
guidance and cost recovery mechanisms is a longer term issue and could potentially
benefit network efficiency more broadly, not just for distributed generation.
Options to address sharing network reinforcement costs include guidance, a distributed
generation cost recovery scheme for DNSPs or more efficient incentives for DNSPs to
invest overall. There is currently a proposal to amend the National Electricity Rules for
connecting embedded generators before the AEMC. The proposed rule change could
set broad principles for sharing reinforcement costs and the AER could then develop
the necessary guidance material. While this is a national issue the Victorian
Government could engage with the AER, AEMC, DNSPs and distributed generator
proponents to develop a solution for incorporation into Victoria’s next round of DNSP
pricing determinations. The pricing determinations are expected in October 2015
providing sufficient time to work on a possible solution or solutions. The AEMC’s
consideration of the Proposal to amend the NERs for connecting embedded
generators provides an avenue for the Victorian Government to engage the relevant
Recommendation 5.1
That to clarify the circumstances and conditions in which network reinforcement
costs can be spread across new distributed generators and other users, the
Victorian Government:
make a submission seeking the development of principles for cost sharing to the
Australian Energy Market Commission’s consideration of the Proposal to amend
the National Electricity Rules for connecting embedded generators. This
submission be prepared by the Department of Primary Industries in consultation
with the Australian Energy Regulator (AER), distribution network service providers
and distributed generator proponents
advocate to the AER for appropriate guidance on cost sharing arrangements
for the connection of distributed generators before the next round of network
distribution pricing determinations expected in 2015.
Regulatory incentives
Addressing market power concerns and improving information is a necessary but not
sufficient step to removing barriers to connection of distributed generation. Distributed
generators need to negotiate connection with a monopolist whose incentives for
efficient augmentation through distributed generation are further dampened by the
regulatory environment.
In particular, it is argued that the current regulatory structure favours investment in
traditional ‘poles and wires’ delivery systems. Participants raised concerns about the
extent to which there are sufficient incentives for distribution businesses to reveal
network value and encourage investment in distributed generation even where there
are network benefits. For example, the Grattan Institute suggested that:
… the current regulatory environment does not always recognise the
economic value of such distributed generation… Many of the current
regulations do not create the incentives for network operators to recognise
the value of distributed generation. Indeed, because many of them earn a
guaranteed rate of return on “necessary” augmentation, they have an
incentive to discourage distributed generation that would reduce peak
demand. (sub. 86, p. 2)
ACIL Tasman suggested distribution businesses have limited incentive to innovate
except when the payback is short because there is no incentive across revenue
… where capital expenditure deferral benefits accrue across regulatory
periods … the building blocks approach reduces the benefits to the
distributors as the benefits may be returned to customers at the subsequent
price review. This could reduce the viability of demand management
initiatives to the distributors. (ACIL Tasman 2011b, p.6)
ACIL Tasman also noted that ‘a DNSP’s revenue is based on a return on its regulatory
asset base so there is an incentive for the DNSPs to invest in network solutions to
increase the regulatory asset base’ (ACIL Tasman 2012c, p.48)
These views are shared by participants in this inquiry who, based on their experiences,
argued that regulatory incentives are making it harder for the proponents of distributed
generation. Mike Reeves argued that:
The business model for the monopoly distributers is that they are paid for
investing in their network rather than ‘deferring network augmentation by
encouraging distributed generation’. They also have no incentive to pass
on any network value to the DG. (sub. DR130, p. 3)
Similarly, Anne-Marie Gibson stated that:
… power distributors receive significant incentives to upgrade network
infrastructure. The introduction of distributed energy generation, particularly
in regional and remote areas of substantial size, will in fact delay or
significantly decrease the requirement for some of the infrastructure
projects being undertaken. (sub. DR155, p. 1)
Currently there is an incentive scheme, the Demand Management Embedded
Generation Connection Incentive Scheme (DMEGCIS) (previously DMIS), designed to
encourage DNSPs to investigate demand management options, including distributed
generation. The scheme, as it applies to distributed generation, has a number of
the amount provided to distribution businesses is too small to be effective
uncertainty associated with the ex-post assessment of the DMIS payment because
DNSPs have no certainty of recouping their costs
narrow focus of expenditure (ACIL Tasman 2011b, pp.17, 39).
The AER identified that the ‘DMIS is not intended to be the sole or even primary source
of cost recovery’ and included $221 million for Demand Side Participation (DSP) in the
Queensland DNSPs’ price determinations (AER 2010c). While DSP includes distributed
generation, most of the $221m in Queensland was allocated to funding DSP
technologies such as air-conditioning and pool filtration direct load control and some
pilots of pricing options. This suggests that exploring options for distributed generation is
not the primary focus of DNSPs even when financial incentives are offered.
The AEMC’s Power of Choice Review’s directions paper noted that current regulatory
arrangements could create:
… a bias towards capital expenditure in favour of operating expenditure,
both in terms of the potential to make profit and certainty about cost
recovery. Therefore, other factors being equal, operating expenditure on
DSP [demand side participation] may be at a disadvantage compared to
capital expenditure. (AEMC 2012f, p.138)
The Power of Choice Review is considering a number of these issues in a broader
context. Two specific issues highlighted in this review were:
How to recover the costs of the existing network — there are different views on how
these costs interact with distributed generation. Some proponents of distributed
generation argue that they do not use the network and therefore should not pay.
Distribution businesses argue that costs are not avoided by distributed generators
as the network is still required as a form of insurance. Distributed generators can
access electricity if their systems are unavailable and the system still has sufficient
capacity if distributed generation is not available at a time of peak demand. In
addition, the way network charges are currently levied means that as the amount
of distributed generation increases, the network costs are shared across a
deceasing volume of electricity sales.
Finding mechanisms that will allow distributed generators to be paid for network
In relation to the first point, the increasing burden of network costs being shared across
less electricity will need to be addressed in the longer run but the problem is not unique
to distributed generation as it can also result from falling demand for other reasons such
as energy saving (chapter 4). These issues should be considered in more general
regulatory and price reforms.
The Commission’s views on recovering network value is discussed in the following
Recovering network value
The Commission considers that recovering the network value and paying it to the
proponents of distributed generation is important to ensure there are incentives for the
efficient incorporation of distributed generation into Victoria’s electricity system.
However, recovering this value is not easy. Ceramic Fuel Cells noted that they accept
that it is hard to produce a single specific figure for the network value’ (sub. DR135,
p. 5).
Advice provided to the Commission by ACIL Tasman suggested that the network value
of distributed generation is in the nature of a local specific capital value that is
unrelated to the quantity of energy generated, and is not easily incorporated into the
FiT payment (ACIL Tasman 2012). The Commission’s view is that the network value is
appropriately dealt with outside of the FiT payment.
Possible options for addressing this network value, include:
Recognising that there is a value but do nothing because of the difficulty and
possible transactions costs involved in trying to calculate it. These costs arise
because the network value will vary by location, time of day, type of generator
and the extent to which the DNSP can rely on the generator producing electricity
when it is needed.
Improving regulatory structures to provide incentives to reveal the network value —
proposed changes to the regulations governing incentive structures for distribution
businesses, simpler (and less costly) connection processes, and better information
about local bottlenecks may make the value more accessible to distributed
The value could be estimated and spread across all distributed generators and
reflected in FiT payments, but as noted earlier this is not the Commission’s preferred
approach because the network value is not based on output.
However, none of these options is particularly effective in identifying the network value
and ensuring it is paid to the distributed generation proponent.
The Commission considers that another option is to use the AER’s price reset process to
consider the value of any network benefits from distributed generation and to then
require distribution companies to make payments based on this value.
The payments could be made available to large distributed generators, retailers (to
pass on to relevant distributed generators), or aggregators who may be responsible for
aggregating a number of distributed generators to have an appreciable effect on the
Distribution businesses are already required to provide the AER with estimates of the
need for and cost of network investment as part of the price reset process. Those
requirements could be modified to include providing estimates of the network costs
and benefits of distributed generation (or demand side responses more broadly). This
information would be the basis for identifying the areas of the network where the
network benefits of distributed generation would be positive and setting up how
payments would be made to proponents bringing forward proposals that would realise
those benefits.
Recommendation 5.2
That the Victorian Government, through the Department of Primary Industries
investigate whether, and how, the Australian Energy Regulator’s price reset process
can be used to:
Identify the network value of distributed generation
Require distribution businesses to make available payments based on that
Subject to the investigation producing a practical solution, and in the absence of
any other relevant developments, the Victorian Government prepare and submit a
rule change proposal so it could be considered by the AEMC prior to the next price
reset process in 2015.