Business Models and Regulatory Considerations for Storage on the Distribution Network - For the Energy Security Board
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Business Models and Regulatory
Considerations for Storage on
the Distribution Network
For the Energy Security Board
August 2020
Project No. A0350 – Business Models and Regulatory Considerations for Storage on the Distribution Network
i
ABOUT ITP RENEWABLES
ITP Renewables (ITP) is a global leader in renewable energy engineering, strategy, construction,
and energy sector analytics. Our technical and policy expertise spans the breadth of renewable energy,
energy storage, energy efficiency and smart integration technologies. Our range of services cover the
entire spectrum of the energy sector value chain, from technology assessment and market forecasting
right through to project operations, maintenance and quality assurance.
We were established in 2003 and operate out of offices in Canberra (Head Office), Sydney, North
Coast NSW, Adelaide and Auckland, New Zealand. We are part of the international ITPEnergised
Group, one of the world’s largest, most experienced and respected specialist engineering consultancies
focussing on renewable energy, energy efficiency, and carbon markets. The Group has undertaken
over 2,000 contracts in energy projects encompassing over 150 countries since it was formed in 1981.
Our regular clients include governments, energy utilities, financial institutions, international
development donor agencies, project developers and investors, the R&D community, and private firms.
ABOUT THIS REPORT
This report was commissioned by the Energy Security Board to support their work on DER
integration and the development of post-2025 market design. The ESB is seeking to understand both
the economics and regulation of business models for distribution-level storage and the interaction
between the two. Its focus of this report is primarily on battery storage, but the analysis includes other
forms of storage (e.g. hot water, and/or other controllable loads) considered useful to understand the
issues.
Project No. A0350 – Business Models and Regulatory Considerations for Storage on the Distribution Network
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REPORT CONTROL RECORD
Business Models and Regulatory Considerations for Storage on the
Report Title Distribution Network
Client Contract No. ITP Project Number AO350
Energy
Client Client Contact Gabrielle Kuiper
Security Board
Rev Date Status Author/s Reviewed By Approved
Rob Passey, Annie Ngo,
1 3/4/2020 Draft Muriel Watt, Joshua Jordan, Rob Passey Approved
Jose Zapata
Rob Passey, Annie Ngo,
2 4/5/2020 Final draft Muriel Watt, Joshua Jordan, Rob Passey Approved
Jose Zapata
Rob Passey, Annie Ngo,
3 8/6/20 Final draft Muriel Watt, Joshua Jordan, Rob Passey Approved
Jose Zapata
Rob Passey, Annie Ngo,
4 240820 Final Muriel Watt, Joshua Jordan, Rob Passey Approved
Jose Zapata
A person or organisation choosing to use documents prepared by IT Power (Australia) Pty Ltd accepts the following:
a. Conclusions and figures presented in draft documents are subject to change. IT Power (Australia) Pty Ltd accepts no
responsibility for use outside of the original report.
b. The document is only to be used for purposes explicitly agreed to by IT Power (Australia) Pty Ltd.
c. All responsibility and risks associated with the use of this report lie with the person or organisation who chooses to
use it.
Document prepared by:
ITP RENEWABLES
Address: Level 1, 19 Moore St Phone: +61 (0) 2 6257 3511
Turner, ACT, 2612, Australia Email: info@itpau.com.au
Postal: PO Box, 6127 itp.com.au
O’Connor, ACT, 2602, Australia
IT Power (Australia) Pty Limited (ABN 42 107351 673)
Project No. A0350 – Business Models and Regulatory Considerations for Storage on the Distribution Network
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LIST OF ABBREVIATIONS
AC Alternating Current
ACT Australian Capital Territory
ACT Australian Capital Territory
AEMC Australian Energy Market Commission
AEMO Australian Energy Market Operator
AER Australian Energy Regulator
API application programming interface
ARENA Australian Renewable Energy Agency
AUD Australian Dollar
COAG Council of Australian Governments
DC Direct Current
DER Distributed Energy Resources
DERMS Distributed Energy Resources Management System
DMIA demand management innovation allowance
DNSP Distribution Network Service Provider
DPT Discounted Payback Time
DRED Demand Response Enabled Device
DRSP Demand Response Service Provider
EDCWNC Energy Democracy Central West NSW Co-operative
EN embedded network
ENAC Electricity Network Access Code
ENO embedded network operator
ENSMS Electricity Network Safety Management System
ERA Economic Regulation Authority
ERF Emissions Reduction Fund
ESB Energy Security Board
EV electric vehicle
FCAS Frequency Control Ancillary Services
FiT feed-in tariff
FRMP Financially Responsible Market Participant
GIS Geographic Information Systems
GW gigawatt
Hz hertz
IQR Interquartile Range
ITP ITP Renewables
kW kilowatt
kWh kilowatt-hour
LET local energy trading
LGC Large Generation Certificate
Project No. A0350 – Business Models and Regulatory Considerations for Storage on the Distribution Network
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LRET Large-scale Renewable Energy Target
LUOS Local Use of System
LV low voltage
MASP Market Ancillary Service Provider
MASS Market Ancillary Service Specification
MLFs marginal loss factors
MSGA Market Small Generation Aggregator
MTR multiple trading relationship
MW megawatt
NEM National Electricity Market
NMI National Metering Identifier
NSCAS Network support and control ancillary services
NSW New South Wales
NWIS North West Interconnected System
openCEM open Capacity Expansion Model
PV Photovoltaic
PVRP Photovoltaic Rebate Program
QRET Queensland Renewable Energy Target
RCEF Regional Community Energy Fund
RERT Reliability and Emergency Reserve Trader
RET Renewable Energy Target
SA South Australia
SAPS Stand Alone Power Systems
SGA Small Generation Aggregator
SPT simple payback time
SWIS South West Interconnected System
TOU Time of Use
TWh Terawatt hours
VCR Value of Customer Reliability
VPP virtual power plant
VRET Victorian Renewable Energy Target
WA Western Australia
WALDO Widespread and Long Duration Outages
WDRM Wholesale Demand Response Mechanism
WEM Wholesale Electricity Market
WP Western Power
ZS zone substation
Project No. A0350 – Business Models and Regulatory Considerations for Storage on the Distribution Network
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TABLE OF TABLES
Table 1: International Examples of Non-orchestrated Behind the Meter Battery Programs ........... 27
Table 2: Type 1 Barrier and Solution Summary ............................................................................. 28
Table 3: International examples of orchestrated behind the meter storage programs ................... 42
Table 4: Type 2 Summary of issues and suggested solutions for orchestrated behind the meter
storage ................................................................................................................................................ 44
Table 5: International examples of Utility-scale battery systems.................................................... 60
Table 6: Type 3 Summary of Regulatory and Other Barriers ......................................................... 62
Table 7: Simple and Discounted Payback Times Under Different Operational Modes, over 2017,
2018 & 2019: Enova’s Shared Community Battery Scheme ............................................................... 69
Table 8: Sources of Annual Revenue Under Different Operational Modes, Averaged over 2017,
2018 & 2019: Enova’s Shared Community Battery Scheme ............................................................... 69
Table 9: Simple and Discounted Payback Times Under Different Operational Modes, over 2017,
2018 & 2019: Byron Bay Solar Farm & Battery Storage Facility ......................................................... 70
Table 10: Sources of Annual Revenue Under Different Operational Modes, Averaged over 2017,
2018 & 2019: Byron Bay Solar Farm & Battery Storage Facility ......................................................... 70
Table 11: Simple and Discounted Payback Times Under Different Operational Modes, over 2017,
2018 & 2019: Goulburn Community Dispatchable Solar Farm............................................................ 71
Table 12: Sources of Annual Revenue Under Different Operational Modes, Averaged over 2017,
2018 & 2019: Goulburn Community Dispatchable Solar Farm............................................................ 71
Table 13: Simple and Discounted Payback Times Under Different Operational Modes, over 2017,
2018 & 2019: Orange Community Renewable Energy Park ............................................................... 72
Table 14: Sources of Annual Revenue Under Different Operational Modes, Averaged over 2017,
2018 & 2019: Orange Community Renewable Energy Park ............................................................... 72
Table 15: International examples of third party owned or operated batteries................................. 73
Table 16: Type 4 Summary of Regulatory and Other Barriers ....................................................... 74
TABLE OF FIGURES
Figure 1. Number and capacity of residential battery systems installed: 2015 to 2019 (Sunwiz,
2020)..................................................................................................................................................... 2
Figure 2. Residential battery systems installed in 2019: By state/territory (Sunwiz, 2020) .............. 2
Figure 3. sonnenFlat Packages ....................................................................................................... 6
Figure 4. Annual bills with different PV and battery combinations: residential customers, Flat tariff
............................................................................................................................................................ 11
Figure 5. Change in median annual bills with different PV and battery combinations: residential
customers, Flat tariff ........................................................................................................................... 11
Figure 6. Simple Payback Time for different PV and battery combinations, new PV: residential
customers, Flat tariff ........................................................................................................................... 11
Figure 7. Simple Payback Time for different PV and battery combinations, customer already had
PV: residential customers, Flat tariff ................................................................................................... 12
Figure 8. Annual bills with different PV and battery combinations: residential customers, TOU tariff
............................................................................................................................................................ 13
Project No. A0350 – Business Models and Regulatory Considerations for Storage on the Distribution Network
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Figure 9. Change in median annual bills with different PV and battery combinations: residential
customers, TOU tariff .......................................................................................................................... 14
Figure 10. Simple Payback Time for different PV and battery combinations, new PV: residential
customers, TOU tariff .......................................................................................................................... 14
Figure 11. Simple Payback Time for different PV and battery combinations, customer already had
PV: residential customers, TOU tariff .................................................................................................. 14
Figure 12. Annual bills with different PV and battery combinations: residential customers, Demand
charge tariff ......................................................................................................................................... 15
Figure 13. Change in median annual bills with different PV and battery combinations: residential
customers, Demand charge tariff ........................................................................................................ 16
Figure 14. Simple Payback Time for different PV and battery combinations, new PV: residential
customers, Demand charge tariff ........................................................................................................ 16
Figure 15. Simple Payback Time for different PV and battery combinations, customer already had
PV: residential customers, Demand charge tariff ................................................................................ 17
Figure 16. Annual bills with different PV and battery combinations: residential customers, Tariff
with spot price ..................................................................................................................................... 18
Figure 17. Change in median annual bills with different PV and battery combinations: residential
customers, Tariff with spot price ......................................................................................................... 18
Figure 18. Simple Payback Time for different PV and battery combinations, new PV: residential
customers, Tariff with spot price ......................................................................................................... 19
Figure 19. Simple Payback Time for different PV and battery combinations, customer already had
PV: residential customers, Tariff with spot price ................................................................................. 19
Figure 20. Simple Payback Time for different PV and battery combinations, new PV: residential
customers, Flat, TOU, Demand and Spot tariffs ................................................................................. 20
Figure 21. Change in Simple Payback Time for the large commercial tariff as the battery MWh
capacity changes ................................................................................................................................ 21
Figure 22. Simple Payback Time for different PV and battery combinations, new PV: residential
customers, Flat, TOU, Demand and Spot tariffs ................................................................................. 22
Figure 23. Residential battery systems installed in 2019: By state/territory (Sunwiz, 2020) .......... 23
Figure 24. Decline in PV prices and resultant increase in uptake .................................................. 25
Figure 25. Comparison of AEMO ESOO forecasts of battery uptake, ESOO 2018 compared to
March 2018 EFI Update ...................................................................................................................... 25
Figure 26. Decline in PV prices and resultant increase in uptake .................................................. 26
Figure 27. Test of coordinated and un-coordinated battery dispatch in a 24 hour period
(Information courtesy of SA Power Networks) .................................................................................... 32
Figure 28. Ausgrid VPP typical battery operation and typical network VPP dispatch profile
(Ausgrid’s Battery Virtual Power Plant, Phase 1 Summary Report August 2019) ............................... 34
Figure 29. Spot price response for SA VPP 9-15 January 2020 (AEMO Virtual Power Plant
Demonstration, Knowledge Sharing Report #1, March 2020) ............................................................. 36
Figure 30. Negative price event response for SA VPP 30 April 2019 (AEMO Virtual Power Plant
Demonstration, Knowledge Sharing Report #1, March 2020) ............................................................. 37
Figure 31. Average load shape of AGL South Australian VPP (Virtual Power Plant in South
Australia, Stage 2 Public Report, AGL, June 2018) ............................................................................ 38
Figure 32. SA VPP daily revenue September 2019 to February 2020 (AEMO Virtual Power Plant
Demonstration, March 2020, Knowledge Sharing Report #1) ............................................................. 40
Project No. A0350 – Business Models and Regulatory Considerations for Storage on the Distribution Network
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EXECUTIVE SUMMARY
The ESB commissioned ITP Renewables to undertake a review of the different ways that
distribution-level batteries are used, the related business models, and any barriers, regulatory or
otherwise. Such batteries are becoming more widely deployed and are demonstrating significant
potential to provide a wide variety of services, including reduction in consumer bills, network support
(through soaking up excess solar generation, reducing demand peaks and improved power quality), as
well as participating in wholesale spot and Frequency Control and Ancillary Services (FCAS) markets,
and so reducing costs for all consumers.
Distribution-level batteries can be defined into four different types:
Type 1: Autonomous behind-the-meter, which includes standard residential and commercial-scale
batteries, as well as those in Local Energy Trading schemes and embedded networks (not including EV
batteries).
Type 2: Orchestrated behind-the-meter, which includes controlled loads and Demand Response
Enabled Devices (DREDs), and the use of batteries in embedded networks and VPPs.
Type 3: Owned by Distribution Network System Providers (DNSPs) in front of the meter
Type 4: Owned by a third party (such as a retailer or a solar farm) in front of the meter
Each of these has different potential business cases, and each of these business cases can have
different barriers, regulatory and otherwise. These are all discussed in detail in this report. The following
tables summarise the key barriers faced by each of the four types and suggests solutions.
Type 1: Autonomous behind-the-meter storage
Of the four types, Type 1 batteries have by far the greatest take-up in both number and capacity in
the National Energy Market (NEM) and Western Australia Energy Market (WEM). As outlined in Table
A, implementation of cost-reflective tariffs is the best option to help overcome the current high installed
cost, and if combined with a reduction in installed cost could result in a step change in uptake. This
would have significant benefits in terms of reducing demand peaks, reducing solar export and
smoothing demand profiles, as well as reduction in spot prices, improved power quality control and
voltage ride through, depending on the batteries operational control and technical specifications.
Table A: Autonomous behind-the-meter Barrier & Solution (Type 1)
Australia-wide
The installed capital cost of batteries is currently generally too high for them to be financially viable
for most residential applications, even when combined with a PV system. Commercial-scale
batteries can be financially viable but only if correctly sized and with an appropriate tariff.
Although capital subsidies can help drive uptake and can be used for targeted programs,
such as for low-income households (and are being used successfully in Australia and
internationally), they impose a cost on governments and so are best applied to stimulate
initial uptake until they become financially viable in their own right.
Project No. A0350 – Business Models and Regulatory Considerations for Storage on the Distribution Network
viii
The optimal driver of ongoing increased uptake of Type 1 batteries will be cost-reflective
tariffs but only if the battery is operated to take advantage of them. Such tariffs are being
implemented by DNSPs but need to also be passed through by electricity retailers, in which
case they can also allow for spot price exposure. PV/battery systems should also be
eligible for feed-in tariffs (FiTs) as long as the FiTs reflect the benefit they are providing to
retailers, which can be time-specific (higher in the early evening).
More research is needed into the ability of non-orchestrated batteries to provide the
benefits described above. This would focus on the potential benefits that batteries operated
simply to directly minimise customer bills could provide in terms of reducing network
peaks, reducing solar exports, reducing spot prices and regulating voltage and frequency.
Type 2: Orchestrated behind-the-meter storage
The aggregation and orchestration of demand and DER shows significant promise to participate in
wholesale spot and Frequency Control Ancillary Services (FCAS) markets and in providing network
support. Although the focus of this report was on batteries, it is clear that demand response, in the form
of controlled load and DREDs for example, have significant potential, especially with the forthcoming
introduction of mandatory DRED standards and the ability for controlled load to be managed more
actively.
The current focus of Virtual Power Plant (VPP) trials is on consumer acquisition and on successfully
demonstrating the technical capabilities required. The final uptake of VPPs will of course depend on the
demand for the services they can provide and the technology’s ability to provide them, but also on their
financial viability and their ability to offer consumers something they can’t obtain independently (through
Type 1 batteries).
The key barriers to Type 2 options are identified in Table B, as are our recommendations for
overcoming them.
Table B: Orchestrated behind-the-meter Barriers & Solutions (Type 2)
Western Australia NEM
There are no regulatory barriers to the use of ripple-controlled loads to reduce peak loads on
Controlled networks or exposure to peak energy pricing. Changing the timing of controlled loads is currently
under active investigation by several DNSPs to soak up excess solar generation.
Loads
For novel options to be effective, they would need to be financially attractive to the
consumer.
The main barrier to DRED use has been the cost of installing the control hardware and software.
introduction of mandatory DRED capability for a range of appliances at the end of 2020 will
reduce costs for new installations, though they will remain an issue for legacy appliances. Third-
party aggregation of demand response (DR) is emerging, in residential (trials), commercial
DREDs (viable) and large consumers (wholesale demand response mechanism Rule change). Cost is
an issue for increased use of batteries for these applications.
Consumer education and recompense through appropriate price signals will be needed
to incentivise uptake of demand response via appliances or batteries. Although the recent
Rule change for the Wholesale Demand Response Mechanism (WDRM) includes a
Project No. A0350 – Business Models and Regulatory Considerations for Storage on the Distribution Network
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Demand Response Service Provider (DRSP), this will only target large consumers and
there is no guarantee it could or would be extended to small consumers – with the AEMC’s
position being that a two-sided market is the best way to engage small consumers in
demand response.
A range of new PV-based embedded networks (ENs) and microgrids have been developed or
announced over recent years. Some ENs and all microgrids include batteries. This market
appears to be growing as commercial and industrial (C&I) as well as residential consumers take
their own initiatives to reduce their carbon footprints.
Embedded
The main regulatory issues for ENs have been around the requirements to provide access
Networks to retailer competition for consumers on the EN. However, this competition may
incentivise batteries as a means of maximising onsite PV use, or managing grid
connection restrictions. The success of an EN ultimately depends on whether it
financially viable i.e. can it off competitive tariffs and cover its costs of electricity
purchase from the grid as well as any on-site generation and battery storage.
There have been no regulatory barriers to The various issues for VPPs are being
VPPs in WA, although operation of behind the addressed through several trials, which
meter batteries required a derogation from the currently focus on technical outcomes and
Economic Regulation Authority (ERA) to consumer acquisition, with the financial
absolve Horizon of safety management outcomes being fine-tuned.
obligations. They also had to develop
bespoke privacy and data agreements for Generally, consumer participation in trials
consumers. requires significant subsidies to the battery
cost, which may limit future roll-out, and most
Synergy is a monopoly retailer in the South financial value for consumers likely comes from
West Interconnected System (SWIS) and is increased use of solar electricity at the single
responsible for any issues created by DER, consumer level, which does not need a VPP.
whether or not they were supplied by a third
party, which restricts third parties ability to Hence VPPs would need to be seen by
provide VPPs in WA. consumers to offer additional advantages
which they cannot access on their own.
Third parties should be made responsible
for DER operational health and safety risks For VPPs to be financially viable they may need
for the consumer in their own VPPs. to stack value streams from network, spot and
FCAS markets. While this could be achieved via
bilateral contracts, this increases both cost and
VPPs complexity.
There is a need to carefully examine how
market participants are defined in the Post-
2025 market design. For example, the
possibility of either/both SGAs and MASPs
participating in spot and both FCAS markets
could be examined.
SGAs can only aggregate solar PV systems on
gross meters, limiting their ability to establish
VPPs that are attractive to consumers.
This restriction could be removed, at least
for VPPs.
The required six second fast FCAS response
does not take full advantage of batteries’
capabilities.
The FCAS fast response requirement could
be reduced to less than 6 seconds. This is
currently the subject of a rule change
request. 1
1 https://www.aemc.gov.au/rule-changes/fast-frequency-response-market-ancillary-service
Project No. A0350 – Business Models and Regulatory Considerations for Storage on the Distribution Network
xType 3: Owned by Distribution Network System Providers
The use of batteries by distribution networks is gathering momentum, and there are no regulatory
barriers to using them for network support. The barriers relate more to the need for the networks to
develop the technical understanding of batteries (which they are now doing), as well as financial
impediments which are generally overcome through Demand Management Initiative Allowance (DMIA).
The only significant regulatory issues from the DNSP’s point of view occur when network operators
in the NEM wish to use batteries in contestable services (such as electricity retail and participation in
wholesale spot and FCAS markets). This may be necessary where DNSPs wish to develop community-
scale batteries (batteries that are on the low voltage network but in front of the meter and have some
level of community participation), where value stacking of benefits from these services is likely to be
required for financial viability. The simplest way for a DNSP to access these value streams is likely to
be through third parties. This approach would compete with third party-ownership of such batteries, with
bilateral contracts with DNSPs for providing network support. It is important that the regulatory
environment enables effective competition between these options.
Some of the key issues and solutions for batteries owned by DNSPs are summarised in Table C.
The modular Market Participant based on functionality discussed above could be useful here.
Table C: DNSP-owned Barriers & Solutions (Type 3)
Western Australia NEM
There are no barriers to the use batteries There are no barriers to the use batteries for
for network support. network support.
Western Power overcame issues related to DNSPs face issues related to justifying
justifying expenditure on low expenditure on low probability/ high impact
probability/high impact events using the events. Such expenditure is required to
Value of Customer Reliability model in the increase the resilience of the electricity
context of WEM regulation. network to extreme events.
Fringe-of-grid
The current AER review on the standard
outages Value of Customer Reliability
(VCR) 2 only covers periods up to 12
hours should use time frames and
approaches more suited to blackouts due
to extreme events – for example over a 3-
5 day period.
Western Power (WP) is currently The AEMC’s final decision for the operation
converting many fringe-of-grid areas to of SAPS, and the DNSPs’ role in this is much
SAPS, aided by the Electricity Industry more complex than in the SWIS because of
Amendment Bill 2019, although there are the objective of ensuring retail competition
some relatively minor consumer pricing and the ring-fencing of DNSP activities.
SAPS issues to be resolved. The advanced
metering requirements and investment In summary, the AEMC has ruled that
tests appear to be resolved. Horizon Power distribution businesses can provide both the
can of course build SAPS. SAPS distribution and generation services as
long as the AER will provide a waiver.
2 https://www.aer.gov.au/networks-pipelines/guidelines-schemes-models-reviews/values-of-customer-reliability
Project No. A0350 – Business Models and Regulatory Considerations for Storage on the Distribution Network
xiWP’s Community PowerBanks face no Ausgrid’s Community Battery trial is facing a
regulatory barriers. The full cost of the number of regulatory and other barriers. The
batteries is covered by a combination of main barriers are:
capital expenditure and inclusion of
regulated revenue from the battery in the That the Community Battery consumers will
RAB. have multiple retailers which will make it very
complex for a DNSP or third party to
Following on from the Electricity Industry interface will all the different consumers.
Amendment Bill 2019, Western Power is
expecting to deploy more batteries for This might be solved using a single
network support, but these are to be retailer to both buy the exported PV
assessed on a case by case basis. electricity and sell it back to the
consumers through a multiple trading
relationship (MTR) approach. The
proposal to allow MTR without the need
for separate connection points, that was
rejected by the AEMC in 2016, could be
revisited. This is also relevant to
obtaining consumer value through VPPs
that could involve many different
retailers.
Electricity going from consumers to the
battery and back again would be double
counted in terms of network and retail
charges.
This might be solved under a subtractive
netting arrangement through AEMO
settlements and through some type of
Local Use of System (LUOS) charge
Network As for VPPs, for community batteries to be
Support financially viable they may need to stack
value streams from network, spot and FCAS
markets.
May be able to access spot through the
MTR retailer, and can access contingency
FCAS through a MASP.
As for VPPs, there is a need to carefully
examine how market participants are
defined in the Post-2025 market design.
For example, the possibility of either/both
SGAs and MASPs participating in both
spot and FCAS markets could be
examined.
An appropriate method to allocate costs and
benefits to the various parties is yet to be
determined
Given the nature and scope of these
issues, they will only be solved in close
collaboration with the relevant regulatory
bodies.
Powercor, Jemena, Ausnet, Endeavour and
United Energy are using batteries in a range
of trials. None of these faced regulatory
barriers because the battery is treated as a
network asset as it is only providing network
support, and any losses are just treated as
normal network losses.
Project No. A0350 – Business Models and Regulatory Considerations for Storage on the Distribution Network
xiiType 4: Owned by a third party
The deployment of medium scale batteries by community groups and retailers is a nascent market.
Interested parties include electricity retailers, solar farm operators and community groups. The most
significant barriers do not appear to be regulatory but are related to the internal capacity of the
organisations involved, and to the financial viability of the proposed projects. The outcomes of the
current round of the NSW Regional Community Energy Fund (RCEF) community battery trials will
provide useful guidance as to the likely success of this model and resultant uptake of batteries.
Table D: Third party-owned Barriers & Solutions (Type 4)
Western Australia NEM
Synergy’s community battery pays full Enova’s community battery also pays full
network charges when the battery is network charges when the battery is
charging and then when consumers use charging and then when consumers use the
the electricity. electricity. This could be particularly relevant
for participation in regulation FCAS.
The use of LUOS charges would help
Network although Synergy say the battery is LUOS charges may be needed for
charges financially viable without these. financial viability because payment of full
network charges both to and from the
battery would significantly decrease the
financial attractiveness to consumers
Not a problem for Synergy as it is a retailer. Not a problem for Enova as is a retailer.
All other PV/battery systems can access
these markets through a bilateral contract
with a single retailer, so is not a significant
barrier.
Access to spot Participation in FCAS which requires
and FCAS sophisticated equipment and telemetry.
This would be facilitated if AEMO allowed
different standards and telemetry/
measurement requirements for the
community battery in line with those
allowed for VPP demonstration trials.
Future Potential
In terms of total battery uptake on the low-voltage network, the implementation of cost-reflective
tariffs would appear to have the most potential in terms of total numbers as well as capacity. Although
the use of VPPs has clear technical benefits, their success depends on their net financial outcomes and
consumer interest. Ideally, they should be able to combine the best outcomes of Type 1 batteries when
not in VPP mode with the targeted benefits when they are. Batteries are currently providing clear
benefits to network operators in terms of providing network support, and so will continue to be deployed
for this function. This could extend to significantly reducing the costs to service fringe-of-grid areas
depending on regulatory outcomes related to SAPS. The development of community batteries is a new
area and it is too soon to ascertain the degree to which this will help drive battery uptake.
Project No. A0350 – Business Models and Regulatory Considerations for Storage on the Distribution Network
xiiiTABLE OF CONTENTS
EXECUTIVE SUMMARY ................................................................................... VIII
1 INTRODUCTION............................................................................................ 1
2 APPROACH................................................................................................... 4
3 TYPE 1: NON-ORCHESTRATED BEHIND-THE-METER .............................. 5
3.1 Financial outcomes ....................................................................................................... 8
Residential-scale batteries ........................................................................................ 10
Commercial-scale batteries ....................................................................................... 20
3.2 Future uptake ............................................................................................................... 22
3.3 International Examples of Support for Non-orchestrated Behind the Meter
Batteries 26
3.4 Type 1 Summary of main issue and potential solutions .......................................... 28
4 TYPE 2: ORCHESTRATED BEHIND-THE-METER ..................................... 29
4.1 Controlled loads .......................................................................................................... 29
4.2 Demand Response Enabled Devices ......................................................................... 29
4.3 Embedded Networks ................................................................................................... 31
4.4 Virtual Power Plants .................................................................................................... 31
Network Peak Demand Management Trials .............................................................. 31
Network Support and Control Ancillary Services ....................................................... 35
Spot Market Trials ..................................................................................................... 35
FCAS Market Trials ................................................................................................... 39
4.5 International Examples of Orchestrated Behind the Meter Batteries ..................... 41
4.6 Summary of issues and potential solutions.............................................................. 43
5 TYPE 3: DNSP-OWNED .............................................................................. 46
5.1 Fringe-of-grid ............................................................................................................... 46
5.2 Stand Alone Power Systems ...................................................................................... 49
5.3 Network Peak Demand Support & Increased DER Hosting Capacity ..................... 52
5.4 International examples of Utility-scale batteries ...................................................... 60
5.5 Summary of issues and potential solutions.............................................................. 62
Project No. A0350 – Business Models and Regulatory Considerations for Storage on the Distribution Network
xiv6 TYPE 4: THIRD PARTY-OWNED/OPERATED ........................................... 65
6.1 Financial outcomes ..................................................................................................... 66
Enova Community Energy’s Shared Community Battery Scheme ............................ 68
Byron Bay Solar Farm Holdings’ Byron Bay Solar Farm & Battery Storage Facility .. 69
Community Energy for Goulburn’s Goulburn Community Dispatchable Solar Farm . 70
ITP Renewables’ Orange Community Renewable Energy Park................................ 71
6.2 International Examples of Third-Party Owned/Operated Batteries ......................... 72
6.3 Summary of issues and potential solutions.............................................................. 74
7 DISCUSSION OF BARRIERS AND FUTURE UPTAKE .............................. 75
7.1 Type 1 Autonomous behind-the-meter storage ........................................................ 75
7.2 Type 2 Orchestrated behind-the-meter storage ........................................................ 75
7.3 Type 3 DNSP-owned storage ...................................................................................... 78
7.4 Type 4 Third party-owned storage ............................................................................. 81
STAKEHOLDERS CONTACTED ............................................... 83
DNSPs ....................................................................................................................................... 83
Businesses ............................................................................................................................... 83
Project No. A0350 – Business Models and Regulatory Considerations for Storage on the Distribution Network
xv1 INTRODUCTION
The Energy Security Board (ESB) is leading a wholesale review of the National Electricity Market
(NEM), focussed on developing a post-2025 market design. The ESB is seeking to understand both the
economics and regulation of business models for distribution-level storage and the interaction between
the two. This report is intended to support the ESB’s work on DER integration and the development of
post-2025 market design.
The ESB commissioned ITP Renewables to undertake a review of the different ways that
distribution-level batteries are used, their related business models, and any barriers, regulatory or
otherwise. It has a particular interest in the changes required to overcome any barriers and so unlock
otherwise successful business models in order to drive the uptake of distribution-level batteries.
Such batteries can be autonomous behind-the-meter, orchestrated behind-the-meter, owned by
Distribution Network System Providers (DNSPs) in front of the meter, or owned by a third party (such
as a retailer or a solar farm) in front of the meter. Each of these has different potential business cases,
and each of these business cases can have different barriers – with the regulatory barriers different in
the NEM and the Western Australian Wholesale Electricity Market (WEM) which covers the South West
Interconnected System (SWIS) and the North West Interconnected System (NWIS).
Use cases
Distribution-level batteries can be used in a number of different ways. At the simplest level they can
be used behind the meter to capture excess solar PV generation for later use and can also be optimised
according to the electricity tariff to charge during low cost periods and discharge during high cost
periods. Such batteries could also allow individual consumers to participate in local energy trading
(LET), where they can discharge their batteries to sell electricity to others in the trading scheme, and
vice versa. The inclusion of a centralised battery in an embedded network with solar PV allows
optimisation of electricity use and therefore costs across a number of aggregated consumers.
Consumer-owned distribution-level batteries can also be orchestrated into a virtual power plant
(VPP) that can potentially bid into spot markets, provide ancillary services (e.g. Frequency Control
Ancillary Services (FCAS)) and support distribution networks. Such orchestration extends to the
coordinated control of storage water heaters as well as Demand Response Enabled Devices (DREDs)
that can control loads such as air conditioners.
There is growing interest in the use of larger batteries (hundreds of kW) by DNSPs, primarily as a
form of network support, but also as centralised batteries that can be used by consumers to store excess
solar. Batteries can provide network support in fringe-of-grid areas, for stand-alone power systems
(SAPS), to help meet demand peaks and to increase the network’s Distributed Energy Resources
(DER) hosting capacity by soaking up excess solar. The use of centralised batteries to store excess
consumer solar is of growing interest in the WA market, which has a much more amenable regulatory
environment to DER than the NEM.
These larger-scale batteries can also be used by electricity retailers as a physical hedge against
spot price movements and again as a form of community storage, which can help with consumer
acquisition. They can also be used by medium-scale solar farms (sub 5MW) to enable targeted bidding
into the spot market.
Project No. A0350 – Business Models and Regulatory Considerations for Storage on the Distribution Network
1Current battery uptake
Estimates for the number of residential batteries installed on the distribution network in the NEM
vary between around 25,000 (AEMO) to 70,000 (Sunwiz) 3, A much smaller number of commercial-scale
batteries had been installed. It has been estimated that another 28,000 batteries will be installed in
2020, which would equate to an additional 280MWh. 4 The estimated residential battery installations by
year is shown in Figure 1, and the number installed in each state is shown in Figure 2. It can be seen
that the average system size decreased slightly in 2019 and that, despite its smaller population, South
Australia has the greatest number of installations, followed by NSW, Qld, then Vic.
Figure 1. Number and capacity of residential battery systems installed: 2015 to 2019 (Sunwiz, 2020)
Figure 2. Residential battery systems installed in 2019: By state/territory (Sunwiz, 2020)
3 The large difference is put down to the AEMO data not including any post-PV battery installation, and being
voluntary with no data check, so the actual value is likely somewhere in between.
4 Data derived from ‘Australian Battery Market Report – 2020’, SunWiz 2020
Project No. A0350 – Business Models and Regulatory Considerations for Storage on the Distribution Network
2Contributors to current uptake
As discussed in the sections below, batteries are still struggling to be financially viable, yet there is
still significant uptake. This is in part simply driven by early adopters who also have solar PV systems,
but is also helped by state government subsidy programs such as the ACT NextGen program, the South
Australian Home Battery Scheme and the Victorian battery rebate scheme, and more recently by the
interest-free loans through the NSW Empowering Homes Program and grants through the Northern
Territory’s Home and Business Battery Scheme, and of course by the variety of trial VPPs that include
subsidised batteries.
Nevertheless, the State schemes have contributed a relatively small proportion of the total
installations to date. The SA Home Battery Scheme aims to install 40,000 systems and as at Jan 2020
had about 5,500 batteries either installed or on order, with the recent flagged decrease in the rebate
triggering a rush of applications that brought the total (installed or on order) to 12,334. Although the
ACT NextGen program aims to install up to 5,000 batteries, as at mid-April 2020, only 1,550 had been
installed. The Victorian battery rebate scheme aims to install 1,000 systems over 2019/20, and to date
has installed 311. This brings the total installed under state schemes to less than 7,000 systems.
AEMO estimates that between 8,000 and 9,000 batteries have been installed to date under VPPs,
which when combined with the state schemes, brings the total to around 15,500 batteries, meaning that
the bulk of the approx. 70,000 batteries connected to the distribution network to date have been installed
by individuals acting on their own initiative.
Report structure
This report is divided into the following sections.
Section 2 describes the approach we have taken to produce this report, which includes division into
the following use cases: Type 1 (non-orchestrated behind the meter), Type 2 (orchestrated behind the
meter), Type 3 (DNSP-owned) and Type 4 (third party-owned).
Section 3 discusses the different tariffs and operating models for Type 1 batteries, provides some
high-level financial assessments and discusses future uptake.
Section 4 covers four different types of Type 2 storage: controlled loads and DREDs, and the use
of batteries in embedded networks and VPPs. It also discusses the range of regulatory barriers to VPPs.
Section 5 describes the range of Type 3 storage and discusses the different ways that DNSPs are
using batteries, with a particular focus on regulatory barriers and options to overcome them, and how
they differ between Western Australia and the NEM.
Section 6 covers the Type 4 examples of third party owned batteries in Australia to date, which are
generally in the early stages, but provide some promising and novel business models. Again, regulatory
barriers are discussed, and recommendations are provided.
Section 7 concludes with a discussion of the report’s key findings and recommendations.
Project No. A0350 – Business Models and Regulatory Considerations for Storage on the Distribution Network
32 APPROACH
This project was undertaken in four stages. Firstly, the different Types of storage were established
and described. Secondly, for each Type, the possible business models were characterised. Thirdly, the
barriers, regulatory and otherwise, were identified. Fourthly, financial analysis of different battery
business models was undertaken where appropriate.
Consultation was undertaken with distribution networks, providers of distributed storage options,
retailers and solar farm developers, as well as the organisations involved in the recent VPP battery
trials. Consultation was performed through a semi-structured interview process, with conversations
recorded and transcribed (where permitted). The stakeholders contacted are listed in Appendix A.
We also undertook a detailed review of relevant reports and other sources, some not publicly
available, related to specific projects, their outcomes and the regulatory environment. This included a
systematic review of the various battery storage trials undertaken to date in Australia, as well as a
review of relevant international experience.
Financial modelling was undertaken using the UNSW Tariff Tool 5 for residential consumers and
ITP’s proprietary battery optimisation model6 for commercial consumers and for the MW-scale batteries,
both in Python. The UNSW Tariff Tool simply calculates the outcomes for each half hourly increment
based on the load, PV generation and battery capacity, with the battery operated in load-following mode,
meaning that it simply minimises solar export to the grid and minimises import from the grid. ITP’s
proprietary battery optimisation model can be used to simulate battery operation and financial returns
based on price signals from a range of markets/sources (including a range of retail energy import and
export tariffs, network energy and peak demand charges, market and environmental charges, demand
response, and FCAS contingency and regulation). It does this over a year assuming perfect foresight
optimising the overall financial outcomes for the consumer, and as such, provide the best-case
outcome.
5http://www.ceem.unsw.edu.au/cost-reflective-tariff-design
6This model was originally developed for a NSW Government agency, and is a derivative of the openCEM model
(www.openCEM.org.au).
Project No. A0350 – Business Models and Regulatory Considerations for Storage on the Distribution Network
43 TYPE 1: NON-ORCHESTRATED BEHIND-THE-METER
Type 1 distribution level storage includes residential and commercial batteries that may be exposed
to different tariffs or operated in particular ways, as below:
1. On conventional tariffs
2. On an annual cost package
3. Exposed to spot prices
4. Batteries operating as part of a Local Energy Trading scheme
5. Batteries operating as part of an Embedded Network
Conventional tariffs
The most common form of Type 1 storage is operated in response to price signals derived from retail
tariffs (and the underlying network tariffs). Such batteries can be operated in simple load-following mode
(also known as ‘PV self-consumption’ and ‘solar storage’) or in response to tariffs such as TOU and
demand charge. In line with the recommendations of the Power of Choice review, all DNSPs are
including more cost-reflective tariffs such as TOU and demand charge tariffs in their Tariff Structure
Statements and Pricing Proposals, and so we expect a significant number of consumers will be on such
tariffs by around 2025. The main function provided in load-following mode is ‘load levelling’, where
excess PV electricity that would otherwise be exported to the grid is captured for use at a later time. If
the PV and battery capacities are large enough, this approach can also reduce demand later in the day
during the high price periods of TOU and demand charge tariffs. ‘Peak shaving’ focuses on reducing
demand peaks during these high price periods and can take place without a PV system.
Annual Cost Packages
A variation on conventional tariffs is the use of what are really annual cost packages, such as
sonnenFlat, which allows households to select one of three packages and be provided with electricity
up to an annual limit for a fixed amount per month. Usage over the limit is charged at a flat tariff rate.
The household has to buy a Sonnen battery and have a minimum-size solar PV system. The currently
available sonnenFlat packages are shown in Figure 3. To the best of our knowledge these make up a
very small portion of the market and is only available to residential consumers.
Project No. A0350 – Business Models and Regulatory Considerations for Storage on the Distribution Network
5Figure 3. sonnenFlat Packages
Spot price exposed
A further variation involves exposing consumers to spot prices through their tariffs. Having a battery
provides a significant advantage as it can be discharged during times of high spot prices. This is
currently offered by both Amber Electric and Powerclub. They include a fixed monthly fee ($10 for
Amber Electric) or an annual fee ($36 for Powerclub).7 The wholesale price applies only to the energy
component of the retailer portion of the tariff, so the underlying network tariff structure is retained. Again,
ITP’s understanding is that this has been taken up by a relatively small number of consumers, in part
because it is not offered by many retailers.
ARENA has recently funded Epho (Dec 2019) to develop commercial-scale batteries with switching
technology that can dynamically distribute the output of a solar system between the consumer on-site
and the network to take advantage of wholesale spot prices. The first stage, a 1.7MW rooftop system
has just been commissioned at Goodman’s Oakdale Industrial Estate in Horsley Park.
Local energy trading
Distributed energy resources can be linked through a local energy trading (LET) platform where
electricity produced by generators on the LV network (such as solar PV systems with batteries) can be
sold directly to consumers participating in the same platform. This minimises involvement by third
parties, which should reduce costs, and so maximises the returns to owners of distributed generation
systems. It is fair to say that LET is still in the trial and development stage, with most organisations
emerging in the LET field use blockchain technology that uses software that tracks multiple transactions
7 Although Energy Locals say that they expose consumers to spot prices, they also say “We buy wholesale
power in advance to ensure you’re not exposed to any surprises – our prices will change once each year”
https://compare.energylocals.com.au/residential.
Project No. A0350 – Business Models and Regulatory Considerations for Storage on the Distribution Network
6between peers in a very secure manner without a third-party facilitator (and so in this case is called
peer-to-peer trading; P2P). Examples include Powerledger, LO3, Enosi and Sonnen.
LET is included here as ‘non-orchestrated’ because such batteries are not directly controlled by the
operator of the trading platform. Instead, they respond only to price signals provided through the trading
platform, which are themselves provided by other participants in that particular platform.
The only significant regulatory barrier to the uptake of LET, and therefore LET helping to drive the
uptake of batteries, is that full network charges are paid on all electricity traded through the platform,
whether it be between participants in different states or between neighbours. One option to address this
problem is to use Local Use of System (LUOS) charges, where the charge would be proportional to the
amount of network used. Note that there may be regulatory barriers to this, as discussed for the
community batteries discussed in Sections 5 and 6. Another option to overcome network charges that
has been discussed in the past is the use of Local Generation Network Credits that would be paid to
DER if they export at times of peak demand. However these were rejected by the AEMC in 2016
because it considered they would result in higher costs for consumers because payments would be
made regardless of whether the embedded generator is located where it provides value, and this would
distort the incentives for investment in embedded generation at the expense of other services, such as
demand response. 8,9 Because of this network charges barrier, ITP does not believe that LET will be a
significant driver for uptake of batteries, apart from possibly in embedded networks such as apartment
buildings as discussed below. Even if LUOS charges are introduced, it is likely they will be for particular
projects (such as community batteries) rather than for LET projects that can span a large geographical
area. 10
Embedded Networks
Embedded networks (EN) are privately owned networks with a single point of connection to the main
grid. According to the AEMC, at 28 May 2019 there was 4,592 ENs that had received network
exemptions, and 5,251 that had received electricity retail exemptions, but there are also an unknown
number of ENs that have received deemed exemptions.11 Examples include greenfield urban
developments, industrial estates, shopping centres, apartment blocks, retirement villages and caravan
parks. An embedded network operator (ENO) sells electricity to the EN consumers (who also have the
option to buy electricity from an external retailer). Sale of electricity within the EN can be achieved
simply using sub-meters, even where consumers within the EN have solar and/or batteries and export
to the EN – as long as all exported solar/battery electricity is on-sold at the same tariff as is the electricity
drawn from the wider grid. Similarly, a single large battery could be used to capture excess solar
electricity generated within the EN (before it is exported to the wider network) for use by the EN
consumers. However, it is more complicated if the internally generated solar/battery electricity is on-
8 https://www.aemc.gov.au/news-centre/media-releases/local-generation-networks-credits-final-rule
9 A simpler alternative could be to allow batteries to earn the value of the demand charge for any exports. From
the network’s point of view, a house exporting 1kWh during peak times is the same as their neighbour not using a
kWh at the same time. However, this may have unrealistically complex metering, tariff and billing requirements
when taking the retail component of the tariff into consideration.
10 As explained in Section 5.3 it is possible to get a waiver that allows LUOS charges to be introduced, and Rule
6.18.1C allows a tariff structure to be changed as long as the DNSP’s revenue from the relevant tariff each year
is no greater than 0.5% of its annual revenue, and as long as the DNSP’s revenue from the relevant tariff, as well
as from all other relevant tariffs, each year is no greater than 1% of its annual revenue.
11 https://www.aemc.gov.au/market-reviews-advice/updating-regulatory-frameworks-embedded-networks
Project No. A0350 – Business Models and Regulatory Considerations for Storage on the Distribution Network
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