power from the people - draft report
TRANSCRIPT
Power from the People
Inquiry into distributed generation
A draft report for further consultation and input
May 2012
© State of Victoria 2012
This draft report is copyright. No part may be reproduced by any process except in
accordance with the provisions of the Copyright Act 1968 (Cth), without prior written
permission from the Victorian Competition and Efficiency Commission.
ISBN 978-1-922045-76-8 (paperback)
ISBN 978-1-922045-77-5 (PDF)
Disclaimer
The views expressed herein are those of the Victorian Competition and Efficiency
Commission and do not purport to represent the position of the Victorian
Government. The content of this draft report is provided for information purposes only.
Neither the Victorian Competition and Efficiency Commission nor the Victorian
Government accepts any liability to any person for the information (or the use of such
information) which is provided in this draft report or incorporated into it by reference.
The information in this draft report is provided on the basis that all persons having
access to this draft report undertake responsibility for assessing the relevance and
accuracy of its content.
Victorian Competition and Efficiency Commission
GPO Box 4379
MELBOURNE VICTORIA 3001
AUSTRALIA
Telephone: (03) 9092 5800
Facsimile: (03) 9092 5845
Website: www.vcec.vic.gov.au
An appropriate citation for this publication is:
Victorian Competition and Efficiency Commission 2012, Power from the People: Inquiry
into Distributed Generation, draft report, May.
About the Victorian Competition and Efficiency Commission
The Victorian Competition and Efficiency Commission (VCEC), which is supported by a
secretariat, provides the Victorian Government with independent advice on business
regulation reform and opportunities for improving Victoria’s competitive position.
VCEC has three core functions:
reviewing regulatory impact statements, measuring the administrative burden of
regulation and business impact assessments of significant new legislation
undertaking inquiries referred to it by the Treasurer, and
operating Victoria’s Competitive Neutrality Unit.
For more information on the Victorian Competition and Efficiency Commission, visit our
website at: www.vcec.vic.gov.au
Disclosure of interest
The Commissioners have declared to the Victorian Government all personal interests
that could have a bearing on current and future work. The Commissioners confirm their
belief that they have no personal conflicts of interest in regard to this inquiry.
Opportunity for further comment
You are invited to examine this draft report and provide comment on it within the
Commission’s public inquiry process. The Commission will be accepting submissions
commenting on this report and will be undertaking further consultation before
delivering a final report to the Government.
The Commission should receive all submissions by Friday 15 June 2012.
Submissions may be sent by mail, fax, or email; in electronic, paper or audio format.
By mail: Inquiry into Feed-in Tariffs & Barriers to Distributed Generation
Victorian Competition and Efficiency Commission
GPO Box 4379
MELBOURNE VICTORIA 3001
AUSTRALIA
By facsimile: (03) 9092 5845
By email: [email protected]
TERMS OF REFERENCE V
Terms of reference
Inquiry into Feed-in Tariff Arrangements and Barriers to
Distributed Generation
I, Kim Wells MP, Treasurer, pursuant to section 4 of the State Owned Enterprises (State
Body – Victorian Competition and Efficiency Commission) Order (‘the Order’), in
conjunction with Michael O’Brien MP, the Minister for Energy and Resources, hereby
direct the Victorian Competition and Efficiency Commission (‘the Commission’) to
conduct an inquiry into feed-in tariff arrangements and barriers to distributed
generation.
Background
Victoria currently has in place a number of programs that are designed to reduce
greenhouse gas emissions and facilitate an adjustment towards a low emissions
economy.
These programs include feed-in tariff schemes such as the standard feed-in tariff
scheme for customers with installations up to 100kW capacity and the premium and
transitional feed-in tariff schemes applying to eligible customers with solar inverter
systems up to 5kW capacity. In the context of the implementation of a national carbon
price, it is appropriate that the Commission undertakes a review of Victoria’s feed-in
tariff schemes.
Addressing any state and local regulatory or other barriers to the uptake of low
emissions generation, including co-generation and tri-generation, is also important to
ensure that any transition to low emissions generation occurs as smoothly and as cost-
effectively as possible.
Scope of the inquiry
In this inquiry, the Commission is required to:
(1) Assess the design, efficiency and effectiveness of feed-in tariff schemes, including
market-based gross feed-in tariff schemes, in the context of a national carbon
price.
(2) Prove a recommendation as to whether existing feed-in tariff arrangements should
be continued, phased-out or amended. Where phase-out of existing arrangements
is proposed, the appraisal should give consideration to whether any transitional
arrangements may be necessary. Any changes to existing arrangements would not
be applied retrospectively.
(3) Identify and State and/or local regulatory and other barriers to the development of
a network of distributed renewable and low emission generation in Victoria,
including co-generation and tri-generation.
In conducting this inquiry, the Commission should have regard to:
recent reports by the Australian Energy Market Commission on planning and
connection arrangements for distributed energy generation;
reviews currently being undertaken by the Victorian Government; and
relevant reports by Commonwealth forums and bodies such as the Productivity
Commission.
VI POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
Inquiry Process
In undertaking this inquiry, the Commission is to have regard to the objectives and
operating principles of the Commission, as set out in section 3 of the Order. The
Commission must also conduct the inquiry in accordance with section 4 of the Order.
The Commission is to consult with key interest groups and affected parties, including
representatives of end-use electricity consumers, and may hold public hearings. The
Commission should also draw on the knowledge and expertise of relevant Victorian
Government departments and agencies.
The Commission is required to produce a draft report for public consultation, ahead of
a final report to the Government within 6 months of receipt of this reference.
KIM WELLS MP
Treasurer
Received: 13 January 2012
PREFACE VII
Preface
The release of this draft report gives interested parties the opportunity to comment on
the Commission’s analysis in relation to its inquiry into feed-in tariff arrangements and
barriers to distributed generation. The Commission will consider comments received
prior to developing and presenting the final report to government.
In preparing this draft report, the Commission invited public submissions and consulted
widely with a range of individuals, businesses, organisations, government departments
and local councils.
The Commission invites written submissions on the draft report. These submissions may
address any of the issues covered by the terms of reference. In light of the submissions
received, the Commission will hold further consultations as necessary.
At the conclusion of consultation on the draft report, the Commission will prepare a
final report to be presented to the Victorian Government by 13 July 2012. The Order in
Council establishing the Commission says that the Treasurer should publicly release the
final report and that the Victorian Government should publicly release a response to
the final report within six months of the Treasurer receiving the report.
The Commission looks forward to receiving feedback on the draft report.
Deborah Cope Dr Matthew Butlin
Presiding Commissioner Chair
CONTENTS IX
Contents
Terms of reference V
Preface VII
Contents IX
Abbreviations XI
Glossary XIII
Key Messages XVII
Summary report XIX
Draft recommendations and information requests XXXV
1. Introduction 1
1.1 Background to the inquiry 1
1.1.1 What is distributed generation? 1
1.1.2 What are feed-in tariffs? 2
1.2 Context and why this inquiry is important 3
1.3 The Commission’s approach 4
1.4 Inquiry process 4
1.5 Structure of the report 5
2. Distributed generation in Victoria 7
2.1 The Victorian electricity industry 7
2.1.1 Market for distributed energy 8
2.2 Regulation of distributed generation in Victoria 13
2.2.1 Regulation of the NEM 13
2.2.2 Connecting to the distribution network 15
2.2.3 Selling excess electricity generated 18
2.2.4 What does this all mean for the inquiry? 21
2.3 Policies for distributed generation and renewable energy 27
2.3.1 Commonwealth policies 27
2.3.2 State policies 29
2.4 Future trends 30
2.4.1 Cost trends 30
2.4.2 Improved metering technology 33
2.5 Conclusions 34
3. The Commission’s approach 35
3.1 Introduction 35
3.2 Issues raised by participants 35
3.2.1 Connecting to the network 36
3.2.2 Selling electricity 41
3.3 A framework for analysis 43
3.3.1 What are the policy objectives? 44
3.3.2 Barriers to distributed generation 46
3.3.3 How might markets fail to achieve efficient outcomes? 48
3.3.4 Equity considerations 52
3.4 Conclusion 53
4. Connecting generators to the distribution network 55
4.1 Context 55
4.2 Overview of barriers to efficient distributed generation connection 57
4.3 Barriers to medium-scale distributed generation 58
4.3.1 Information and planning 60
4.3.2 Right to connect 63
X POWER FROM THE PEOPLE: AN INQUIRY INTO DISTRIBUTED GENERATION
4.3.3 Costs: process, timelines and uncertainty 65
4.3.4 Costs: sharing network costs, benefits and risks 72
4.4 Barriers to efficient connection of household-scale
distributed generation 77
4.5 Impact of removing barriers to connection of distributed generators 82
5. Victorian feed-in tariffs: selling electricity 85
5.1 Introduction 85
5.2 Victorian feed-in tariffs 85
5.2.1 Overview 85
5.2.2 Objectives of the three feed-in tariff schemes 86
5.2.3 Objective of reducing greenhouse gas emissions 88
5.3 Industry support 91
5.4 Providing a ‘fair and reasonable’ price 92
5.4.1 Is there competition within the Victorian electricity
retail market? 94
5.5 Are there barriers preventing the establishment of
‘fair and reasonable’ feed-in tariff prices? 98
5.5.1 Structural issues 98
5.5.2 Information and transaction costs 102
5.5.3 Market power issues: vertical integration of retail
energy businesses 104
5.5.4 Limitations on time of use and locational pricing 105
5.5.5 Conclusion on fair and reasonable prices 106
5.6 Conclusion 106
6 Future Victorian feed-in tariff arrangements 109
6.1 Design, efficiency and effectiveness of feed-in tariff schemes 111
6.1.1 The value of distributed generation 111
6.1.2 Market-based feed-in tariffs 116
6.1.3 Eligibility 117
6.1.4 Metering arrangements 120
6.1.5 Information provision 123
6.1.6 Billing arrangements 123
6.1.7 The Commission’s view 124
6.1.8 Terms of Reference 1: The Commission’s summary view 125
6.2 Network value of distributed generation 126
6.2.1 Incentives for investment in distributed generation 127
6.2.2 The Commission’s view 128
6.3 Implications for existing Victorian feed-in tariff schemes 130
6.4 Transitional arrangements 134
Appendix A: Consultation 137
A.1 Introduction 137
A.2 Submissions 137
A.3 Roundtables 139
A.4 Stakeholder consultations 140
Appendix B: Regulation of the electricity sector 143
B.1 Victorian regulation 143
B.2 Regulatory framework after 1 July 2012 144
B.3 Connecting to the distribution network 144
B.4 Selling electricity generated 156
References 169
ABBREVIATIONS XI
Abbreviations
AEMC Australian Energy Market Commission
AEMO Australian Energy Market Operator
AER Australian Energy Regulator
AMI Advanced Metering Infrastructure
ASP Accredited service provider
CA Connectional applicant
CEC Clean Energy Council
CES Certificate of electrical safety
COAG Council of Australian Governments
DG Distributed generation
DMIS Demand Management Incentive Scheme
DNSP Distribution network service providers
DSP Demand-side participation
ESAA Energy Supply Association of Australia
ESC Essential Services Commission
ESV Energy Safe Victoria
EWOV Energy and Water Ombudsman Victoria
EWR Electrical works request
FiT Feed-in tariff
IPART Independent Pricing and Regulatory Tribunal
JEN Jemena
kW Kilowatt
kWh Kilowatt hour
LGC Large-scale generation certificate
LRET Large-scale Renewable Energy Target
MCE
MEFL
Ministerial Council on Energy
Moreland Energy Foundation Ltd.
MEI Melbourne Energy Institute
MW Megawatt
MWh Megawatt hour
NECF National Energy Customer Framework
NEL National Electricity Law
NEM National Electricity Market
NEO National Electricity Objective
NER National Electricity Rules
NERL National Energy Retail Law
XII POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
NERR National Energy Retail Rules
PC Productivity Commission
PCA Property Council of Australia
PFiT Premium feed-in tariff
PV Photovoltaic
REBS Renewable Energy Bonus Scheme
REC Renewable energy certificate
RET Renewable Energy Target
SCER Standing Council on Energy and Resources
SCF Solar connection form
SFiT Standard feed-in tariff
SRES Small-scale Renewable Energy Scheme
STC Small-scale technology certificate
TFiT Transitional feed-in tariff
TNSP Transmission network service providers
UE United Energy
VEEC Victorian energy efficiency certificate
VEET Victorian Energy Efficiency Target
VRET Victorian Renewable Energy Target
GLOSSARY XIII
Glossary
Australian Energy Market
Operator
Manager and operator of the National Electricity Market,
and coordinator of market planning
Australian Energy Markets
Commission
Rule maker and adviser to Ministers on development of
energy markets
Australian Energy
Regulator
Enforcer and monitor of compliance with the National
Electricity Rules; responsible for economic regulation of
electricity transmission and distribution networks in the
National Electricity Market
Capacity
Generator capacity The full-load sustained output of a generator under ideal
conditions. Capacity often exceeds output as output is
limited by weather conditions, equipment failure and
maintenance
Network capacity The power limit (in megawatts) a network can support
Carbon price Commonwealth tax on carbon production (initially fixed at
$23 per tonne before shifting to a market-determined
price)
Co-generation The simultaneous production of electricity and heat from
the same fuel source
Competitive market Two or more independent parties attempting to attract
business by offering the most favourable terms
Connection From 1 July 2012, distributed generators can connect to
the distribution network through a process under chapter 5
or 5A of the National Electricity Rules. Each process sets the
rights and obligations of those connecting and certain
sizes/types of generators may be excluded from, or find it
more difficult to access, specific connection processes.
Distributors apply fees and charges associated with
connection, which vary with the size/type of generator
and type of connection
Consumer Electricity purchaser and user
Distributed generation Small- to medium-scale electricity production by
households, business and community groups,
predominantly for on-site use or to supply people and
organisation close by. Generators may be stand-alone or
connected to the distribution network and may export
excess electricity into the grid
Distribution network Links the transmission system to electricity consumers
through distribution lines that carry low voltage electricity
Distributor (distribution
network service provider)
Operator and manager of the distribution network
Embedded generator A generator connected to a distribution network with no
direct access to the transmission network
Equity Fair distribution of assets and resources throughout society
XIV POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
Fault level limit The maximum current that can flow through a network in
the event of a short circuit. Exceeding the fault level limit
increases the risk to the reliability and safety of the
distribution system
Feed-in tariff Price paid (by retailers) per unit of energy exported to the
grid by small to medium distributed generators (from
renewable or low-emissions sources)
Gross feed-in tariff Price paid for total electricity produced, regardless of
whether it is used on-site or exported into the grid
Net feed-in tariff Price paid for electricity exported into the grid
Premium feed-in tariff Net feed-in tariff (of at least 60 cents per kWh) available to
customers with solar photovoltaic systems of five kilowatts or
less. The scheme began in late 2009 and closed in late 2011,
although payments to subscribers will continue to 2024
Standard feed-in tariff Net feed-in tariff available to customers with specified
renewable energy generators up to 100 kilowatts
capacity. Tariff level must be ‘fair and reasonable’ and the
scheme has no prescribed end date
Transitional feed-in
tariff
Net feed-in tariff (of at least 25 cents per kWh) available to
customers with solar photovoltaic systems of five kilowatts
or less. The scheme began in 2012 and will run until 2016,
but can be ended early at the Minister’s discretion
Generator A unit that generates electricity. Definitions of generators
by size vary, and the Commission uses the following
capacity limits as a guide only:
Small-scale or
household-scale
generator
100 kilowatts or less. ‘Household-scale’ includes distributed
generators owned by small business and community
groups.
Medium-scale
generator
Greater than 100 kilowatts and less than five megawatts
Large-scale generator Greater than five megawatts
Greenhouse gas Atmospheric gas that traps radiation emitted by the Earth.
Increasing levels of greenhouse gases (such as carbon
dioxide) have caused the atmosphere and Earth’s surface
to heat up
Industry assistance Government support to encourage the innovation and
development of an industry, achieved by stimulating the
demand for products of that industry or reducing its costs
Kilowatt or megawatt Measure of real electrical power, or energy rate of
production or demand (one megawatt equals 1000
kilowatts)
Kilowatt hour or megawatt
hour
Measure of energy consumption or use (one megawatt
hour equals 1000 kilowatt hours)
Low-emissions generation Energy produced from hydrocarbon based fuels (such as
coal, gas and oil) that uses lower carbon fuel sources or
advanced technologies to significantly reduce
greenhouse gas emission levels
GLOSSARY XV
Market-based pricing Unregulated pricing determined by supply and demand.
In an efficient and competitive market, market price will
equal market value
Market failure The inefficient allocation of goods and services by a free
market
Market power The ability of a business to raise prices without losing
customers to its competitors
National Electricity Market The market for the supply of electricity to retailers and end-
users in all states and territories except Western Australia
and the Northern Territory
National Energy Customer
Framework
National consumer protection framework for the retail sale
of electricity and gas
Peak demand A historically high point in electricity price resulting from
strong consumer demand. It is estimated that 10 per cent
of distribution network capacity is built to meet peak
demand which occurs 1 per cent of the time
Photovoltaic Power generated by converting solar radiation into
electricity using semiconductors. Photovoltaic generation
uses solar panels composed of solar cells containing a
photovoltaic material (commonly crystalline silicon)
Renewable energy Energy produced from naturally replenished sources
including solar, wind, marine, geothermal, hydro-electricity
and bioenergy
Retailer Interface between the electricity wholesale market and
customers that sells electricity to the customer and
manages customer transfers, connections, billing,
complaint handling, and service information. Victorian
retailers with 5000 or more customers are required to offer
feed-in tariffs
Smart meter Device that measures two-way electricity flow and
communicates this information to electricity distributors. By
the end of 2013 each Victorian house and business will
have one installed
System load The demand in megawatts or megawatt hours placed on
the total network generation system — equal to the
demand created by network-connected consumers plus
distribution and transmission losses
Thermal capacity The more power sent through a line or transformer, the
higher the temperature of the equipment. The equipment
is designed for temperature tolerances based on power
levels
Transmission network Transports electricity from generators to the distribution
network service providers and large end users through high
voltage transmission lines
Tri-generation The simultaneous production of heat, cooling and
electricity
XVI POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
Voltage level The amount of electrical pressure necessary to transfer
electricity. Transmission lines carry high voltage electricity
long distances, before the voltage level is decreased for
compatibility with the distribution network, and decreased
again for customer use
Wholesale electricity
market
Exchange between electricity producers and retailers
whereby the output of all generators is aggregated and
instantaneously scheduled to meet demand in the most
cost-effective way
KEY MESSAGES XVII
Key messages
In the right locations, small-scale consumer and commercial electricity generation
can deliver low cost energy that avoids transmission losses and benefits the network.
This improves the efficiency of the electricity industry, consistent with the National
Electricity Market objectives. To play this role, distributed generators need to connect
to the network without compromising its reliability. Such generators should also
receive a fair return for the value of the energy they produce and for their value to
the network.
The introduction of a price on carbon will change low-emissions energy market
signals. In this context, it is timely to reconsider the amount, structure and regulation
of feed-in tariffs (FiTs) and distributed generation in Victoria. Similar reviews have
already taken place in New South Wales and South Australia.
FiTs are paid to small-scale domestic and commercial distributed generators for the
electricity they produce. Three FiT schemes operate in Victoria — Standard feed-in
tariff (SFit), the Premium feed-in tariff (PFit) and the Transitional feed-in tariff (TFiT). Only
SFiT and TFiT, are open to new entrants. A FiT can effectively pay distributed
generators for the value of the energy they produce. This value can be delivered
through a competitive market and, therefore, the Victorian Government should
phase out its involvement in regulating FiTs. From 1 July 2012 when the carbon tax is
introduced this price will also automatically incorporate a value for greenhouse gas
reduction. The Commission proposes:
moving to a fully competitively determined FiT by December 2015, provided
adequate consumer protection, transparency and information are in place
this transition be gradual to smooth the move to deregulation
TFiT be closed to new entrants once 75 MW of generating capacity is reached
(as previously announced) or by 31 December 2013, whichever is sooner
SFiT be broadened to include all low-emissions and renewable technologies, with
a requirement that until 31 December 2015 large retailers must offer a wholesale
price based FiT for distributed generation of 100 kW or less.
The Victorian Government should focus its efforts on barriers to distributed generation
where there is market failure and current regulation is flawed. One such barrier is
proponents’ limited ability to realise the network value of their generators. This value is
highly location specific and depends on the type of generator and when and how
reliably it produces electricity. Because it is not directly related to actual output, this
value cannot be efficiently captured through a feed-in price. Other mechanisms are
needed to capture this ‘network value’.
Medium-scale generators, due to their size, have most potential to reduce network
costs and greenhouse gas emissions. But the process for connecting such generators
is often difficult and costly. The rules for sharing costs, such as the cost of augmenting
the network to accommodate multiple distributed generators, are also unclear.
These rules and processes are regulated nationally and there are processes in train to
address these barriers. By advocating for change the Victorian Government could
reduce a major burden on medium-scale generators.
The Victorian regulations for connecting household-scale generation result in more
complex connection processes than in other states. It imposes considerable
regulatory burden on the installers of solar PV units and creates confusion for
consumers. The Victorian regulation should be changed to simplify this process.
SUMMARY REPORT XIX
Summary report
In this inquiry, the Commission has been directed to look at the policies that relate to
distributed electricity generation using low-emissions and renewable technologies.
More specifically, the terms of reference require the Commission to:
assess the design, efficiency, and effectiveness of feed-in tariff (FiT) schemes
recommend any changes to current FiT arrangements
identify state and/or local regulatory and other barriers to the development of a
network of distributed renewable and low emissions generation.
What is distributed generation?
There is no definitive definition of distributed renewable or low-emissions generation. For
the purposes of this inquiry, the Commission is focussing on generation with the following
characteristics:
the energy is generated by households, businesses or community groups who
predominantly intend to use the energy on-site or to supply people or organisations
close by, and includes co-generation and tri-generation systems1
the generator is connected into the electricity grid through the distribution network,
not the transmission network. In some cases the system may be stand alone
energy in excess of the needs of the generator owner may be sold (exported) into
the grid
the energy could be from renewable sources such as solar, wind, biogas or waste,
but may also be low-emission fossil fuels, using technologies that produce with up to
half the average emissions intensity of electricity generation in Australia
the total amount of energy generated is often small- to medium-scale, up to
around 5MW.
While a few larger-scale generators, such as some wind farms, can be connected to
the distribution network and classified as distributed generation, any barriers to such
activities appear to be common across centralised and distributed generation. The
Commission has therefore not focussed on larger-scale generation in this inquiry.
What are feed-in tariffs?
Feed-in tariffs (FiTs) are:
payments to distributed generators for electricity generated at their premises
usually the subject of contracts between generators and electricity retailers
traditionally intended to encourage the installation of photovoltaic (PV) cells and
other renewable energy generation technology.
Victoria currently has three regulated FiTs and all retailers with more than 5000
customers are required to provide them.
1 Co-generation is the simultaneous production of electricity and heat. Tri-generation is the simultaneous
production of electricity, heat and cooling.
XX POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
Premium FiT (PFiT) — introduced in 2009 and closed in December 2011, the PFiT is paid
to customers generating electricity using solar PV systems of 5kW or less. Customers are
paid 60 cents a kWh for surplus electricity fed into the electricity network. The level of
the PFiT was set according to the amount needed to pay back the cost of the solar PV
system over 10 years. At that time solar panels were considerably more expensive.
Transitional FiT (TFiT) — the TFiT commenced in January 2012 following the closure of PFiT.
It has similar eligibility criteria to PFiT but sets the tariff at 25 cents per kWh. Again the
tariff was set at the level needed to pay back the cost of an average solar PV system. It
is open to new applicants until 2016 but may be closed earlier if a cap of 75MW of
installed capacity is reached, the cost the scheme on other energy users exceeds
$5 per year per customer or the Minister thinks earlier closure is appropriate.
Standard FiT (SFiT) — introduced in 2004 for energy from wind generators, the SFiT was
extended in 2007 to cover all renewable energy generators up to 100kW in capacity.
The scheme has no specified end date and requires eligible retailers to pay a fair and
reasonable price for the surplus electricity fed into the grid. Although not mandated in
legislation, the Essential Services Commission’s (ESC) guidelines indicate fair and
reasonable is interpreted to mean that the price paid to customers supplying electricity
from distributed generation under SFiT should not be less than the price they pay the
retailer for electricity bought from the network.
Why this inquiry is important
Importance of efficient distributed generation
Renewable and low-emission generation has a role to play in reducing greenhouse gas
emissions, offsetting rising power costs and contributing, on a competitive basis, to a
diverse and efficient electricity sector. Often the business case for individual households
or businesses to install distributed generation is compelling. And the attractiveness of
distributed generation is increasing as technology costs fall and the cost of electricity
bought from the network increases. Distributed generation enables businesses and
households to offset their electricity costs by using their own power (in place of
purchasing it from a supplier). They may also earn additional income by selling unused
power into the network.
Interest in installing distributed generation in Victoria has been growing, but there are
concerns about unnecessary barriers to its use and how electricity fed into the network
will be priced.
Historically, Victoria’s electricity system was developed to transport electricity from
large coal powered generators in the La Trobe Valley to consumers throughout the
state. However, increasing electricity prices, the introduction of a carbon price and
growing community concerns about greenhouse gas emissions mean that the
electricity sector is changing. The electricity sector needs to be flexible and respond
quickly and efficiently to this changing environment to prevent unnecessary increases
in electricity prices.
Developments in Commonwealth policy
The Commonwealth Government has policies either in place or about to be
implemented that will reduce carbon emissions and make installing distributed
generation more attractive, including:
SUMMARY REPORT XXI
a fixed carbon price of $23 a tonne from 1 July 2012, moving to a market
determined price after three years
the Clean Energy Finance Corporation, with a mandate to encourage and leverage
private investment in renewable energy and clean technology projects
a target that 20 per cent of Australia’s electricity supply will come from renewable
energy by 2020 (supported by assistance that includes subsidises for small-scale
renewable energy).
Since January 2011 households, small businesses and community groups installing small-
scale renewable energy technologies have been eligible for financial credits in the
form of small-scale technology certificates. Additional credits are available for installing
small-scale renewable generators, such as solar PV, wind generators or small-scale
hydroelectricity.
A climate of reform
These Commonwealth measures have led to suggestions that other policies for
reducing carbon emissions are no longer relevant. For example, the Council of
Australian Governments (COAG), argued that subsidies mandated through FiTs should
be discontinued. Both New South Wales and South Australia have already responded
by reducing FiTs:
In 2012 New South Wales’ Independent Pricing and Regulation Tribunal (IPART)
reviewed New South Wales FiTs for small-scale solar PV systems, recommended
removing the obligation for retailers to offer a FiT and suggested that a fair and
reasonable tariff would be in the range of 5.2 to 10.3 cents per kWh.
South Australia’s price regulator, ESCOSA, also made a price determination in 2011
for FiTs applying to small-scale solar PV and concluded that retailers must pay a
minimum FiT of 7.1 cents per kWh in 2011-12, increasing slightly in subsequent years.
Distributors will pay an additional 16 cents per kWh until 30 September 2013.
In May 2011 Western Australia halved its FiT from 40 cents to 20 cents per kWh and
has subsequently closed the scheme.
The recommendations in other states contrast with Victoria’s TFit and SFiT which
respectively set FiTs of at least 25 cents per kWh and the retail price. The terms of
reference for this inquiry note it is appropriate to review Victoria’s FiTs in light of a
national carbon price.
Queensland has decided to continue its FiT at 44 cents per kWh.
Distributed generation in Victoria
The Victorian electricity network reflects centralised system design decisions made in
the 1920s and a legacy structure that has been adapted somewhat over the ensuing
years. Since privatisation, smaller gas-fired generators have increasingly played a part
in the energy market and, more recently, large-scale wind and small-scale solar
capacity have grown. This growth reflects the falling cost of renewable technologies,
increasing climate change awareness and responses to government policies designed
to increase generation from renewable energy sources.
Distributed generation is a diverse sector with a wide range of energy sources and
producers, ranging from small-size household-scale solar PV systems to medium-size
commercial-scale systems. The distributed generation market is made more complex
XXII POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
by a slew of standards, regulations, policy and legislation imposed by various levels of
government.
The extent of distributed generation
Widespread distributed generation is relatively new to the electricity industry and, as
such, does not always fit neatly into Victoria’s traditional electricity market. While the
data on generation capacity depend on the definitions used, ESAA figures suggest
‘embedded and non-grid generation’2 account for 7.2 per cent of Victoria’s installed
capacity. Most of this installed capacity is medium-scale (chapter 2).3
Table 1 Capacity of embedded and non-grid generation
in Victoria – June 2010
All embedded/non-grid MW Non-hydro renewable
embedded/non-grid MW
Natural gas 133 Black liquor 55
Waste gas 45 Landfill gas 40
LPG 0.6 Sewage gas 22
Hydro 103 Solar 75
Non- hydro renewable 619 Wave 0.2
Wind 428
Solar hot water 131 000 units
Total 900 Total 619
Note: Solar hot water not included in total, renewable embedded/non-grid does not include hydro.
Sources: (ESAA 2011, pp. 20-21; CEC 2011a).
Distributed generation is growing, but it is still a small portion of Victoria’s energy
generation capacity and is falling as a percentage of total generation. However,
changes to government policy, consumer choices and cheaper technology are
expected to encourage the installation of decentralised generators. Figure 1 shows the
capacity of solar PV installed annually, and highlights the impact of the PFiT. The TFiT
commenced on 1 January 2012 but there is not yet a full year of data to make a
meaningful comparison. Clean Energy Australia predicted that Victoria would have
over 80 000 solar PV systems installed by the end of 2011 (CEA 2011, p. 35).
2 Embedded generation is generation embedded in the distribution network and non-grid generation is not
connected to the electricity network. Both are included in the Commission’s definition of distributed
generation.
3 Wind power is classed as ‘embedded’ generation even though the majority of wind power connects to the
transmission network.
SUMMARY REPORT XXIII
Figure 1 Additional annual capacity of solar PV installed in
Victoria (MW)
Source: (CEC 2011a, p.p 34).
Objectives of distributed generation policies
The terms of reference direct the Commission to assess the effectiveness and efficiency
of FiTs and identify barriers to distributed generation. To do so, the Commission needs a
clear view on what distributed generation and FiT policies should try to achieve. But the
policy objectives around distributed generation are not clear and have changed over
time. This lack of clarity is illustrated in the diversity of views presented to this inquiry on
the role of distributed generation and FiTs.
As noted above, Commonwealth policies affecting low emissions and renewable
distributed generation are changing, which affects the role of state policies such as FiTs.
The objectives of these state policies also need to recognise the future role of
distributed generation. Therefore as distributed generation takes a more active role in
supplying electricity nationally, state policy objectives will need to be consistent with
the objective of the National Electricity Market (NEM). Regulation of the NEM seeks to
‘promote efficient investment in, and efficient operation and use of electricity services
for the long term interests of consumers of electricity’.
In the past, three broad objectives have been assigned to distributed generation and
FiT policies in Victoria:
reducing greenhouse gas emissions, including assisting households to make a
personal contribution to environmental outcomes and reducing greenhouse gas
emissions
supporting innovation and development of a new industry and stimulating
investment in distributed generation by overtly allocating risks, including reducing
the energy market risks for small investors installing solar panels
XXIV POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
ensuring fair and reasonable payments for electricity from household-scale
investment in renewable generation.
In the Commission’s view the first two of these objectives are based on previously
identified policy gaps that are no longer relevant.
reducing greenhouse gas emissions — this objective has been overtaken by the
Commonwealth’s carbon pricing policy and other Commonwealth greenhouse
gas reduction initiatives. The carbon tax will raise the cost of carbon-intensive
generators, lifting the wholesale price of electricity and increasing the price paid
for distributed generation. In addition, Commonwealth subsidies for renewable
energy further support investment in some types of distributed generation.
Therefore, while the objective of reducing greenhouse gas emissions is now most
appropriately addressed through the price on carbon (not state FiTs), distributed
generation is still likely to contribute to the transition to a low carbon economy.
industry support — this is likely to be a highly distorting policy objective. While
additional assistance to solar PV (through the PFiT or TFiT) may benefit the solar
industry, this is likely to be at the expense of other distributed generation
technologies or other industries supplying innovative energy efficiency solutions.
Such policies have also proven uncertain and disruptive to industry, as they often
change significantly at short notice, with adverse implications for business planning.
The third objective, ensuring fair and reasonable payments for electricity from
household-scale investment in renewable generation is, in the Commission’s view, the
most relevant objective for Victorian FiTs and consistent with national FiT principles and
the objectives of the NEM. The Commission considers that a fair and reasonable return
involves taking account of the full value of distributed generation and reflecting this
value in the prices and other incentives facing market participants. It also involves
providing efficient processes to connect distributed generators to the network, so this
value can be realised. Such an approach would be fair and reasonable because:
the owners of distributed generation are rewarded for the value they contribute to
the energy market and are not disadvantaged by unnecessarily complex
processes that prevent them from realising that value
network owners and retailers are not required to incorporate or pay for distributed
generation that does not contribute to the efficiency of the electricity market
other users of the electricity network are not required to pay more for electricity to
subsidise those who have installed distributed generation. Such cross-subsidies are a
feature of all of Victoria’s current FiTs and are regressive because they
disadvantage the poorest energy users, such as renters and those who cannot
afford solar panels
investment in distributed generation would be encouraged when it is an efficient
way of developing and using electricity services, and it would not favour the
development of one industry over another
distributed generation policies would be more sustainable and predictable.
The Commission notes that fair and reasonable payments for electricity could be
achieved without government intervention if the electricity market was competitive
and well informed. Competing service providers would voluntarily offer efficient prices
and services that meet the above objectives without the costs and distortions created
by government regulation. A summary of the Commission’s view on the relevant
objectives for distributed generation policy is outlined in box 1.
SUMMARY REPORT XXV
Box 1 Objectives of distributed generation policy in
Victoria
The Commission has concluded that the appropriate objective for Victoria’s policy
on distributed generation is to ensure distributed generators have access to a fair
and reasonable return for the value of their generation. In achieving this objective
government policies should:
rely on the market when it is capable of achieving this objective
if markets fail, ensure the right policy tool is used to solve the identified problem
be as administratively simple as possible
be equitable so that one group does not subsidise benefits that go to others
fit well with existing institutional arrangements and national policy directions.
Much of the regulation affecting the electricity industry is, however, nationally
agreed and hence while Victoria can advocate for change it cannot directly
determine the regulatory regime in most instances.
Providing a fair and reasonable return to distributed
generation
If Victorian policies for distributed generation are to ensure distributed generators have
access to a fair and reasonable return for the value of their generation, it is important to
understand the components that make up this value (chapters 4, 6). This value includes:
Energy value — which is the value of the energy output delivered by the distributed
generator. This value is captured through the competitively determined price per
unit of energy and based on the wholesale price of electricity at the time the
energy is delivered.
Network value — which is the capital value of the difference between upgrading
the network sooner, and upgrading it later because of distributed generation. This
value takes into account the capacity for distributed generation to meet rising
local demand without the need to augment the network as well as any additional
network investment needed to accommodate the distributed generator. The
network value is time and location specific and would be zero (or negative) in parts
of the network where the system is below capacity.
Externality value — this mainly reflects the costs of unpriced pollution and
greenhouse gas emissions. However, with the advent of the carbon tax from 1 July
2012 the value of greenhouse gas reductions will be reflected in the wholesale
price of electricity and therefore incorporated in the energy value as defined
above.
Ensuring the different elements of the value of distributed generation are recognised
and captured is critical to ensuring market participants face appropriate and efficient
incentives to invest in distributed generation. However, none of the methods used
previously to set Victorian FiTs (the amount needed to pay back investment in a solar
PV system or the retail price of electricity) are an accurate measure of any of the
above values. Also, policies that focus solely on the price paid for exported electricity
fail to address issues around the ability to connect distributed generators to the network
efficiently and effectively. Without efficient connection distributed generators cannot
realise the full value of their investments.
XXVI POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
Recovering the energy value
As noted above, the energy value is the value of the energy delivered by the
distributed generator. With the introduction of the carbon price it will also embody the
greenhouse gas reduction value. In addition, distributed generation will have more
value in locations further from the centralised power stations, where the system losses
from transporting electricity are high, and at times when demand is at its peak so the
cost of purchasing electricity on the wholesale market is high. Because the energy
value is related directly to the amount of electricity delivered it is well suited to recovery
through a FiT (chapters 5 and 6).
The Commission retained ACIL Tasman (2012) to provide indicative estimates of the
potential size of the energy value of distributed generation for various generation
profiles. ACIL Tasman estimated the average energy value for a flat generation profile
(generating constantly throughout the year), a solar generator, battery storage system
(that stores energy off-peak and exports it back into the grid when the wholesale price
is highest) and a peaking plant that generates and sells energy when the wholesale
price exceeds $100 a MW (table 2). These estimates illustrate that the energy value of
distributed generation varies with time and location, according to the type of
generation technology and over time as factors such as the wholesale price of
electricity change (chapter 6).
Table 2 Estimated average energy value of distributed
generation at Keilor, for various generation
profiles (nominal)
Generation Profile 2013 cents per kWh 2014 cents per kWh 2015 cents per kWh
Flat 6.1 6.9 7.3
Solar 7.0 10.2 12.4
Battery 12.0 15.0 16.9
Peak $100 62.1 80.1 63.3
A ‘fair and reasonable’ FiT
In a competitive and well informed energy market it is reasonable to assume that
competing energy retailers would offer efficient prices and services consistent with the
characteristics of a fair and reasonable return described above. In an ideal scenario
price would reflect the energy value of the electricity supplied taking account of when
and where the electricity is produced.
In contrast, an approach where the government sets the FiT involves a lot of regulatory
costs and risks setting prices too low or too high (regulatory error), leading to inefficient
investment in distributed generation. If prices are too high regulation may also impose
costs on other electricity consumers or reduce competition by encouraging retailers to
try to avoid certain customers or classes of customers (section 6.1.7).
Regulation should not be used unless there is a clear case that the market will not
deliver a fair and reasonable price and outcomes could be improved significantly by
government intervention. The Commission has therefore assessed whether there is
effective competition within the Victorian retail electricity market.
The fundamentals for competition in Victoria’s retail market are strong. Victoria has had
retail competition since 2002 and electricity consumers can choose among an
SUMMARY REPORT XXVII
increasing pool of energy retail businesses. The numbers of consumers switching
between retailers is higher in Victoria than any other state and an Australian Energy
Market Commission (AEMC) review in 2007 concluded that the retail market was
competitive. The regulation of retail electricity prices in Victoria was discontinued in
2009. In addition some retailers already offer some FiTs that are above the regulated
minimum (section 5.4.1).
But most of this evidence is based on competition in the part of the retail market that
supplies electricity, rather than distributed generation. Currently, retailers appear far less
responsive to customers with distributed generation. The processes for connecting and
transferring customers with distributed generation tend to be much slower and more
complex than those applying to retail customers. Also a common criticism from
distributed generators who are not eligible for a regulated FiT was that they are unable
to find a retailer willing to purchase their electricity (sections 5.4.1 and 6.1.2). These
experiences raise questions about whether behaviour in the part of the retail market
dealing with distributed generation is currently sufficiently competitive to be confident
that fair and reasonable FiTs will be offered.
Barriers to a market determined FiT
Setting aside the appropriateness of existing FiT schemes, there are several potential
barriers to retailers offering an efficient, market determined FiT (chapters 5, 6). Many of
these barriers are short term and in time will reduce as other reforms bed down or the
market matures:
Information and transactions costs — there are concerns that, especially for
proponents of small-scale distributed generation, information is difficult and costly
to obtain and is not always clear and accessible to the customer. These costs are
compounded by the newness of some technologies and uncertainty caused by
changing national regulation. But with a benchmark that initially provides guidance
on the level of a fair and reasonable FiT and ensuring FiT information is published on
the Australian Energy Regulator price comparison website ‘Energy Made Easy’,
these information and transactions costs should reduce over time.
Market power issues (vertical integration of retail energy businesses) — there are
significant ownership links between the energy retail market and upstream energy
production that may impact on the incentives for retailers to engage and
negotiate a FiT with distributed generators. But over time new retailers could enter
the market, or the proposed rule change allowing aggregators to act on behalf of
distributed generators could be accepted, giving distributed generators options to
sell to businesses other than current retailers.
Limitations on time of use and locational pricing — not all Victorians have meters
which collect time of use and location aspects of their power use and production
(such as smart meters). This limits the ability to develop FiTs that better reflect the
value of distributed generation. Smart meters are now being rolled out across the
state, although there is a ban on time of use pricing until at least 2013.
The Commission therefore concludes that while the Victorian retail market is
competitive there are some concerns about whether currently this competition is fully
reflected in retailers’ negotiations with distributed generators. On its own none of the
above barriers would prevent competitive outcomes from emerging (provided
adequate consumer protection, transparency and information are available).
However, combined they are likely to present significant short term constraints until key
reforms are in place, including through the Commission’s draft recommendations and
national reforms to the national electricity consumer framework (NECF).
XXVIII POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
Weighing up these considerations, the Commission suggests a managed transition to a
fully competitively determined price for energy from distributed generation that
incorporates a relatively rapid adjustment to market-based FiTs.
Future Victorian FiT arrangements
The Commission has assessed the design, efficiency and effectiveness of feed-in tariff
schemes, including market-based gross FiT schemes, in the context of a national
carbon price. The Commission’s conclusion on the best objective and role of FiTs is
summarised in box 2.
Box 2 The design, efficiency and effectiveness of feed-
in tariff schemes
The Commission’s response to the terms of reference on the design, efficiency and
effectiveness of feed-in tariff (FiT) schemes (including gross FiT schemes) may be
summarised as follows:
With the advent of the carbon tax, and given the retail market for electricity is
competitive, the energy value for distributed generation output is best captured
through a wholesale-based price set by the competitive market. The role of a
FiT is to recover this value.
FiT schemes should:
– be based on such market prices, and be part of a transition to a fully
market-based approach for pricing energy from distributed generation
– provide an indicative benchmark range with periodic updates until market
FiTs are reasonably established
– not exceed such a market-based price, because this would mean
cross-subsidies from customers without distributed generators to customers
with distributed generators, and this would be regressive
– be technology neutral so that the most efficient choices among generation
technologies can be made
– be confined to ‘household scale’ distributed generation of 100 kW or less, as
larger-scale producers are better placed to compete in the market.
Adopting time based pricing is desirable where feasible, because it provides a
stronger economic signal to distributed generators of the value of production
when overall electricity demand is high.
While there are arguments in favour of gross FiT schemes, there would be
significant costs in replacing recently installed smart meters and changing
retailers’ supporting infrastructure and computer systems to adopt such
schemes. Therefore, while not ruling out gross FiTs if they arose in the
marketplace as a result of competition, the Commission sees no clear value in
mandating them.
Turning to the terms of reference on recommending changes to existing Victorian FiTs,
the Commission proposes that the current Victorian regulated FiTs be phased out and
that future prices of distributed generation be determined by retail market competition.
Market determined FiTs would not discriminate against particular technologies or
customers, rather they would be based on the value of the electricity supplied by
distributed generators (which would include the impact of the carbon tax) The
Commission has concluded that efficient FiTs should be technology neutral, but its draft
SUMMARY REPORT XXIX
recommendations focus on low emission and renewable technologies consistent with
reference to these technologies in the terms of reference.
The Commission’s proposed approach would be supported by consumer protection
and information measures and be phased in to maintain certainty that the market
would continue to offer a competitive FiT. The approach would also support time of use
pricing for distributed generation.
In summary, the Commission’s draft recommendation is:
That, to improve the efficiency and effectiveness of the operation of FiTs in Victoria, the
Victorian Government:
close the TFiT, either by 31 December 2013 or once the 75 MW capacity is reached
(as currently provided in legislation), whichever occurs first
amend the SFiT to require that Victorian electricity retailers with 5000 or more
customers offer fair and reasonable prices for electricity exported to the grid by all
small low-emissions or renewable distributed generators (100 kW or less) until 31
December 2015
establish a fair and reasonable price for energy supplied by distributed generators
through the retail electricity market
define low-emissions technology as generators that produce 50 per cent or less of
the emissions intensity of electricity generation in Australia
allow market-determined arrangements based on gross payments by mutual
agreement
ensure that FiT prices are published by the Australian Energy Regulator under the
requirements of the National Electricity Customer Framework.
That the Essential Services Commission:
publish information on the likely range of wholesale market-based net FiT payments
which would be consistent with a fair and reasonable offer — updated at regular
intervals
consider the extent to which FiT market offers are consistent with fair and
reasonable criteria, redefined to be based on the wholesale price of electricity (the
energy value).
The terms of reference state that ‘any changes to existing arrangements would not be
applied retrospectively’. The Commission understands this to mean that customers
currently on PFiT would remain on this tariff until its contracted expiry date on 1
November 2024. Similarly, customers currently on the TFiT, and new customers entering
the scheme prior to its proposed closure on 31 December 2013 would remain on the TFiT
until its contracted expiry date 31 December 2016. This non-retrospectivity approach
would also apply to SFiT customers. Customers on the SFiT would remain on any
contracted terms of this tariff until the expiry of such contracts, and there would be no
new entrants to the amended SFiT scheme after 31 December 2015. The Commission
will look further at the transition issues for existing SFiT customers in the final report.
XXX POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
Recovering the network value
The Commission’s draft recommendation for the future of Victorian FiTs would ensure
that distributed generators receive a ‘fair and reasonable’ price reflecting the energy
value of the power they produce. However, distributed generators can also create a
network value which arises if the generator enables planned network augmentation to
be deferred.
Measuring the network value is difficult because it depends on the location of the
generation, whether it is large enough to delay investment in the network and whether
it can be relied on when needed. While ACIL Tasman (2012) discussed previous
estimates that quantify network value, it acknowledges that if distributed generation
does not delay network upgrades the network value may be zero or even negative.
Because the network value arises from delaying planned network investment, it is by
nature a time and location specific capital value that is unrelated to the actual
quantity of electricity generated. Such a value is not readily reflected in a FiT and in the
Commission’s view it should be dealt with outside the FiT payment.
There are however, barriers to a market determined network value flowing to
distributed generators:
monopoly network owners have an incentive to retain any network value and not
pass it back to distributed generators
there are information asymmetries as proponents of distributed generation may not
know where there are network constraints and hence where the network value of
distributed generation is highest
the current regulatory regime guarantees network owners a regulated rate of
return on their assets. It therefore rewards distribution network owners for investing
their network rather than deferring network augmentation by encouraging
distributed generation (section 6.2.1).
There is a number of possible options for addressing this network value issue:
Doing nothing and assuming the network value is zero, given the difficulty and costs
of trying to calculate it.
Improving the way distribution businesses are regulated so they have more
incentive to reveal the network value, distributed generators have more bargaining
power to recover that value, and distribution businesses seek out distributed
generation where it is an efficient alternative to augmenting the network.
The value could be estimated and spread across all distributed generators and
reflected in FiT payments, but as noted above this is not an accurate reflection of
the network value and is therefore not the Commission’s preferred approach.
In the short term enhancing the awareness and bargaining position of distributed
generators would improve their capacity to negotiate with distribution businesses. The
Commission is aware of several initiatives and trends that will help address market
power concerns and improve distributed generator’s capacity to access and use
information. They include:
the information available on where network investment is needed is increasing.
Sustainability Victoria has published maps that will help identify areas where
distributed generation could help defer network investment
SUMMARY REPORT XXXI
the proposal (currently being considered by the AEMC) to allow aggregators to act
on behalf of groups of smaller generators would enhance their bargaining power
and introduce a party into the negotiation with the capacity and expertise to
negotiate with distribution businesses about distributed generation based network
solutions
improved connection processes for distributed generation (consistent with the
Commission’s draft recommendations) would make it easier to incorporate other
issues, such as network benefits, into those negotiations.
While these initiatives are likely to strengthen the negotiating position of distributed
generators, they are unlikely to change the underlying regulatory incentives that
discourage distribution businesses from looking proactively at distributed generation as
an alternative to expanding capacity through network investment.
The Commission is seeking feedback on where the Victorian Government can
advocate for further reform in the national electricity market across these and other
approaches to capturing network value and removing barriers to efficient market
incentives for investment in distributed generation.
Connection issues
The terms of reference require the Commission to identify State and/or local regulatory
and other barriers to the development of a network of distributed renewable and low
emission generation in Victoria, including co-generation and tri-generation.
Apart from pricing issues, barriers to connection were the most common barriers to
distributed generation identified by participants in this inquiry. The issues generally
varied according to the scale of generator.
medium-sized distributed generators (greater than 100 kW and generally less than
5 MW). This includes co-generation and tri-generation plants in factories, shopping
centres, office blocks and hospitals. Capacity is often between 1 and 5 MW.
household-sized distributed generators (100 kW or less). Largely comprised of solar
PV systems owned by households, small businesses and community organisations
with an average capacity of 2 kW.
Medium-scale connection
The complexity of the connection process was raised by medium-scale distributed
generators as the largest barrier to efficient investment in distributed generation.
Distributed generators require access to the networks for a range of reasons including
to buy electricity, balance system loads and selling surplus power (ClimateWorks et al.
2011, p. 9).
The processes for connecting distributed generators are, from 1 July 2012 regulated
nationally, through chapters 5 and 5A of the national electricity rules. The Australian
Energy Regulator is responsible for administering these rules and has released guidelines
on connection charges. The process for connecting medium-scale distributed
generation is illustrated in figure 2.
XXXII POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
Figure 2 Connection process for medium-scale distributed
generation
Source: Commission analysis.
* This applies to
negotiation, not dispute
resolution
Agree
d
Offer open for 20 days
Not agreed
Legend
AER – Australian Energy
Regulator
DNSP – Distributed Network
Service Provider
Additional information required
DNSP has 5 days to
provide information
Application incomplete
Site visit, if needed
Preliminary inquiry from
potential applicant
wishing to connect
Applicant lodges
application on form
determined by DNSP
DNSP informs applicant of
additional information
needed
DNSP informs applicant of
deficiency
Basic connection service
or standard connection
service
Use agreement approved
by AER
Completed application
submitted
Not approved service.
DNSP notifies applicant of
the negotiation process &
possible changes &
expenses
Negotiated connection
offer
Option of dispute
resolution reduction
through AER
Offer terms form
connection contract
Application complete
DNSP uses best endeavours
to make offer within 65 days
of receiving completed
application*
DNSP has 10 days to advise
whether the service is covered
by an approved connection
process and, if so, make a
connection offer
offer open for 45 days
expedited connection
may be available
SUMMARY REPORT XXXIII
A number of elements of this process make it complex, uncertain and costly, including
the need for expensive network upgrades in some areas before distributed generation
can be connected.
This complexity is, however, unlikely to be resolved by the market. The AEMC
conducted a review in 2009 which concluded that there are regulatory barriers that
prevent the efficient connection of distributed generators (AEMC 2009b, p.76). While it
is difficult to estimate the loss to Victoria from poor connection processes, the delays
can be large. A report by ClimateWorks, Seed Advisory and the Property Council of
Australia (PCA) noted that distribution businesses claim it takes up to 12 months for a
simple connection and up to two years for a more complex one (ClimateWorks et al.
2011, p.23). Participants in a distributed generators’ roundtable held by the Commission
claimed it can take longer than four years for some to get connected, while others
received an answer in two weeks.
The main barriers to connection identified by participants were:
information and planning
right to connect
costs of connection: process, timelines and uncertainty
costs of connection: sharing network costs, benefits and risks.
While the Victorian Government does not directly control these processes, the
Commission considers they are likely to be significant issues for medium-scale distributed
generators in Victoria. The Commission is therefore seeking to identify those areas where
the Victorian Government might focus in advocating for change in national
arrangements.
Information and planning
Participants indicated that information on network capacity by location could help
inform better siting of distributed generation, assist negotiation and reduce connection
costs. Information on network capacity includes where distributed generation can be
tolerated and where network constraints restrict further expanding distributed
generation. Such information would reduce problems where the costs of connection
are unknown until distributed generators have spent significant time and money on the
application process (ClimateWorks et al. 2011, p.24).
The Commission agrees that improved spatial information on network constraints and
fault levels would improve negotiation and siting of investment, and reduce connection
costs. This information would allow distributed generators to make judgements about
likely connection costs and manage the risks of pursuing projects that are less likely to
proceed.
The Commission is seeking feedback on its conclusion that the AEMC’s proposed
Distribution Annual Planning Report will include sufficient information on network
constraints and planning by location to inform decision making and negotiation by
distributed generation proponents.
Right to connect
Medium-scale distributed generators claim they will be treated less favourably than larger
and smaller generators under new national regulations because they do not have an
automatic right to connect once predetermined standards are met. In negotiating with
medium-scale distributed generators individual distribution businesses have discretion in
XXXIV POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
setting minimum technical standards and distributed generators must pay for network
studies and the network reinforcement required to meet those standards.
In contrast household-scale distributed generation has an automatic right to connect for
units that meet Australian Standard AS4777. Large generators that meet predetermined
standards also have an automatic right to connect under chapter 5 of the NER.
The Commission sees merit in devising practical and efficient arrangements for
automatically connecting distributed generators that meet predetermined standards
and pay for legitimate network costs (the allocation of such costs is discussed below).
Distributed generators may then make commercial decisions to connect or not based
on predetermined standards. Those who do not meet the standards could choose not
to connect or negotiate a tailored connection service.
ClimateWorks, Seed Advisory and the PCA have made a rule change request to the
AEMC that could result in common standards and an automatic right for connection
for medium-scale distributed generators.
An automatic right to connection for standard embedded generators
should be available to plants that meet an automatic access standard. This
automatic access standard would be established to ensure that only plants
that will not compromise the integrity of the grid are granted automatic
access. (ClimateWorks et al. 2012, p.14)
Costs of connection: process, timelines and uncertainty
The connection process itself was raised by many participants as a source of
uncertainty and delay and therefore a key barrier to distributed generation. As noted
above, participants were concerned about the time it takes to connect but also
uncertainty about the process, which can be different for each distribution business.
Regulation of the connection process is being transferred to the AER, and the specificity
around this process and its timeframes is again less for medium-scale generation than
for either large or small generators.
The Clean Energy Council (CEC), for example, claimed that the new chapter 5A
covering these connection processes overlooked the needs of medium-scale
distributed generation.
The CECs primary concern with Chapter 5A is that … the industry has
learned some of the most significant lessons since the consultation process
closed in early 2010. The NECF [National Energy Customer Framework]
consultation process was flawed as a result and has completely failed to
meet the needs of the small scale embedded generation market or indeed
take account of this stakeholder group. (CEC sub. 76, p. 7)
Participants identified causes of delay and uncertainty at each stage of the
connection process (box 3).
SUMMARY REPORT XXXV
Box 3 Concerns about the connection process for
distributed generation
Participants argued that distribution businesses can:
delay the process by avoiding the triggers that start formal negotiations and
require them to respond within regulated timeframes
manipulate timeframes by, for example, requesting more information on the
19th day of a 20 day decision-making period and therefore restarting the 20
day period.
Others suggested that dispute resolution processes would be ineffective because
concerns about the ramifications for their other dealings with network businesses
would stop distributed generators from taking a dispute to the Australian Energy
Regulator (MEFL sub. 75, pp. 9-10). There were also concerns about distribution
businesses not having the capacity and skills to deal effectively with connection
inquiries from distributed generators (ClimateWorks et al. 2012, p.22).
Participants in the Commission’s environmental inquiry claimed planning application
and approvals processes add further complexity, cost and time risk (VCEC 2009,
pp.382–383).
From a distribution business perspective, distributed generators often do not
understand the connection process, network implications or what is required for
them to connect (ACIL Tasman 2011a, pp.29–30).
The ClimateWorks, Seed Advisory and the PCA rule change request for connecting
embedded generators has, in the Commission’s view, the potential to address many of
the above concerns, including a standardised process with specific timeframes and
information provision, and a right to connect for distributed generators that meet
predetermined standards.
The Commission has made a draft recommendation that to facilitate efficient
connection of medium-scale distributed generators up to 5 MW, the Victorian
Government support the Proposal to amend the National Electricity Rules for
connecting embedded generators submitted to the AEMC, with specific support for:
improved information on connection processes
an automatic right of connection based on meeting standard technical criteria
a standard connection process
improved engagement by Distribution Network Service Providers (DNSP)
specific timelines, including limits on how information requests can impact on
overall timelines.
The Commission has further suggested in its draft recommendation that should these
issues not be resolved through the national rule change process within 12 months, the
Victorian Government add a licence condition requiring DNSPs in Victoria to establish
such standards and rights by incorporating them into standard connection services that
are submitted to and approved by the AER.
XXXVI POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
Costs of connection: sharing network costs, benefits and risks
Barriers to connecting distributed generation are not confined to the connection
process but also extend to the cost of connection. The largest connection cost is
reinforcing the network or installing specialised equipment when augmentation is
needed to accommodate the distributed generator. These costs can be substantial,
running into millions of dollars (CEC sub. 76, p.7). But the problem is complex and as
noted by distribution businesses there is no easy way to remove fault level barriers (UE
sub. 77, p. 5). Maintaining the quality and safety of the network is a key performance
requirement.
Participants claimed that lack of transparency makes it difficult for distributed
generators to evaluate cost estimates and the generators’ share of the costs of network
augmentation. They must also negotiate connection with a monopolist whose
incentives for efficient augmentation through distributed generation, as noted above,
are further dampened by the approach to regulation.
Access to information will however improve with the AEMC’s proposed Distribution
Annual Planning Report which will identify where network constraints are greatest. The
proposal by ClimateWorks and others to change to the NER for connecting embedded
generation will also support these negotiations.
That said, the Commission considers information and process improvements alone will
not fully address barriers to efficient sharing of costs, benefits and risks. A particularly
vexed issue is who should pay for network augmentation. While a single distributed
generator may trigger the need to augment the network the subsequent investment is
likely to accommodate a range of users. As noted by the AEMC ‘it is difficult to
distinguish the causes of the increased need of augmentation in a meshed network’
(AEMC 2012c, p.173). Additional investment could be needed to accommodate new
distributed generation from several sources or changes in the use of electricity, such as
increased population density.
These barriers are material. For example, Melbourne’s CBD has high demand for
distributed generation and the network is constrained. When CitiPower proposed to
address this issue by levying distributed generators and charging on other users the AER
was of a different view and CitiPower withdrew the proposal (ACIL Tasman 2011a,
pp.19–20). This process illustrates that there is no agreed framework on how these costs
should be allocated and shared.
The main channel open to the Victorian Government on this matter is advocating
reforms to the NEM.
The Commission has therefore made a draft recommendation that to clarify the
circumstances and conditions in which network reinforcement costs can be spread
across new distributed generators and other users and that the Victorian Government:
in addition to the draft recommendation to improve the connection process for
medium-scale distributed generation, make a submission seeking reform in cost
sharing arrangements to the AEMC’s consideration of the Proposal to amend the
National Electricity Rules for connecting embedded generators. The Department of
Primary Industries in consultation with the AER, distribution network service providers
and distributed generation proponents would prepare this submission
advocate to the AER to prepare and provide guidelines on cost sharing
arrangements for the connection of distributed generators before the next round of
network distribution pricing determinations expected in 2015.
SUMMARY REPORT XXXVII
The Commission is seeking further information on whether the Proposal to amend the
National Electricity Rules for connecting embedded generators is the best vehicle for
addressing cost sharing issues and invites feedback on this or other options, for example,
that the Victorian Government submit a separate rule change request to the AEMC.
Connecting household distributed generation
While the technical issues in connecting household-size distributed generation to the
network are much simpler than for medium-sized systems there was still widespread
agreement among retailers, installers and consumer representatives that the processes
are overly complex and costly.
Box 4 Complicated connection process
There was consensus across stakeholders on the complexity of the connection
process for household-size distributed generation:
Retailers
Customers are required to sign a feed-in tariff (FiT) contract with their retailer before
the metering can be configured for solar and again each time the customer changes
retailers or moves into a property with solar. This process often delays the customer
receiving the FiT. In other states the processes are simpler. (AGL, sub. 72, p. 4)
Installers
Installing small-scale PV is an involved process which can include a solar company,
electrical retailer, electrical distribution company, solar design and installer and
solar inspector. This does not take into account government departments and
agencies, the Clean Energy Council and green certificate traders. With so many
participants customers are often confused about who is responsible for which part
of the installation process. (NECA, sub. 37, p. 5)
Customer representatives:
The application of FiTs is sometimes delayed because customers do not know that
several forms need to be completed. Delays and errors were frequent, with some
customers missing out on PFiT because the electricity retailer or distributor:
lost paperwork
delayed raising service orders or raised incorrect service orders
delayed completing service orders to upgrade or re-configure the meter
provided incorrect or untimely advice about eligibility, timeframes and
requirements. (OWOV, sub. 48, p. 2)
Source: Submissions
The connection process involves three separate but related processes — physical
connection, signing up for a FiT including having a smart meter installed and obtaining
small-scale technology certificates. It also involves two levels of government and
multiple government bodies.
This complexity imposes considerable cost on the consumers and businesses involved,
particularly installers who often mediate the process on behalf of the owners of PV
systems. Other states have far simpler processes.
To address these barriers and remove unnecessary administrative costs imposed on
people wishing to install distributed generation, the Commission has made a draft
XXXVIII POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
recommendation that the Victorian Government amend the Electricity Industry Act
2000 (Vic) and associated regulations, codes and guidelines to:
clarify roles and responsibilities of the parties involved
reduce duplication, such as the installer providing the Electrical Work Request and
Certificate of Electrical safety to the retailer who provides it to the DSPN
remove or reduce the impact of unnecessary or burdensome steps
establish contestability for meter installation.
The Commission intends to consult further on the specific changes that could be made
to simplify the connection process.
DRAFT RECOMMENDATIONS AND INFORMATION REQUESTS XXXIX
Draft Recommendations and information requests
The four recommendations and 10 information requests are listed in the order they
appear in the report, and need to be understood in the context of the discussion in
respective chapters.
Connecting generators to the distribution network
Information request
The Commission seeks feedback on its conclusion that recently implemented and
proposed changes to national electricity regulation will address many of the barriers to
connection of distributed generation. These changes include the new chapter 5A
connection process in the National Electricity Rules, the Australian Energy Market
Commission’s (AEMC) Power of Choice review and the following AEMC rule change
requests:
Proposal to amend the National Electricity Rules for connecting embedded
generators
Distribution Network Planning and Expansion Framework
Small Generator Aggregator Framework.
The Commission seeks feedback on its conclusion that the proposed Distribution Annual
Planning Report includes sufficient information on network constraints and planning by
location to address the barriers to informed decision-making and effective negotiation
by distributed generator proponents. The proposed report is included in the AEMC’s
proposed rule on Distribution Network Planning and Expansion Framework.
Draft Recommendation 4.1
That, to facilitate efficient connection of medium-scale distributed generators up to
5MW, the Victorian Government support the Proposal to amend the National Electricity
Rules for connecting embedded generators submitted to the AEMC, with specific
support for:
improved information on connection processes
an automatic right of connection based on meeting standard technical criteria
a standard connection process
improved engagement by Distribution Network Service Providers
specific timelines, including limits on how information requests can impact on
overall timelines.
Should these issues not be resolved through the national rule change process within 12
months, the Victorian Government add a licence condition requiring distribution
network service providers in Victoria to establish such standards and rights by
incorporating them into standard connection services that are submitted to and
approved by the AER.
XL POWER FROM THE PEOPLE: AN INQUIRY INTO DISTRIBUTED GENERATION
Draft Recommendation 4.2
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:
in addition to Draft Recommendation 4.1, make a submission seeking reform in cost
sharing arrangements 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 to prepare and provide guidance on cost sharing
arrangements for the connection of distributed generators before the next round of
network distribution pricing determinations expected in 2015.
Information request
The Commission is considering whether the Proposal to amend the National Electricity Rules
for connecting embedded generators is the best vehicle to address the sharing of the costs
of network reinforcement and invites feedback on this or other options, for example, that
the Victorian Government submit a separate rule change request to the AEMC.
Draft recommendation 4.3
That to facilitate the connection of household distributed generation to the network the
Victorian Government amend, where relevant, the Electricity Industry Act 2000
(Victoria) and associated regulations, industry codes and guidelines to:
clarify roles and responsibilities of the parties involved
reduce duplication, such as the installer providing the Electrical Work Request and
Certificate of Electrical safety to the retailer who provides it to the distribution
network service provider
remove or reduce the impact of unnecessary or burdensome steps
establish contestability for meter installation.
Information request
The Commission seeks views on how the connection process for household-scale
distributed generation can be improved, and what is required to give effect to such
improvements. The Commission plans to conduct further consultation on specific
changes to this process.
Victorian feed-in tariffs: selling electricity
Information request
Does the process for applying for an individual retail exemption under the Australian
Energy Regulator’s Exempt Selling Guideline (2011) address the regulatory constraints
on distributed generators who on-sell electricity? If not, what changes might be made
to reduce those constraints without compromising competition and contestability in the
retail electricity industry?
DRAFT RECOMMENDATIONS AND INFORMATION REQUESTS XLI
Future Victorian feed-in tariff arrangements
Information requests
The Commission proposes that the eligibility for low-emissions technology be defined as
technologies that produce 50 per cent, or less, of the emissions intensity of electricity
generation in Australia, as recommended by the Clean Energy Finance Corporation
Expert Review. Is this an appropriate definition to apply to distributed generation?
In adopting this definition, are there any practical issues that will need to be
addressed?
To what extent do current billing and payment practices by Victorian retailers impact
on customers’ ability to access fair and reasonable value for the electricity supplied by
their distributed generator?
Several current and proposed incentive schemes and regulatory changes aim to
improve incentives for distribution network service providers to engage with distributed
generators to reduce network costs. Which initiatives should the Victorian Government
initiate or make submissions to in order to most effectively reduce the barriers to
distributed generation?
Draft recommendation 6.1
That, to improve the efficiency and effectiveness of the operation of feed-in tariffs (FiTs)
in Victoria, the Victorian Government:
close the Transitional FiT, either by 31 December 2013 or once the 75 MW capacity
is reached (as currently provided in legislation), whichever occurs first
amend the Standard FiT to require that Victorian electricity retailers with 5 000 or
more customers offer fair and reasonable prices for electricity exported to the grid
by all small low-emissions or renewable distributed generators (100 kW or less) until
31 December 2015
establish a fair and reasonable price for energy supplied by distributed generators
through the retail electricity market.
define low-emissions technology as generators that produce 50 per cent or less of
the emissions intensity of electricity generation in Australia
allow market-determined arrangements based on gross payments by mutual
agreement
ensure that FiT prices are published by the Australian Energy Regulator under the
requirements of the National Electricity Customer Framework.
That the Essential Services Commission:
publish information on the likely range of wholesale market-based net FiT payments
which would be consistent with a fair and reasonable offer —updated at regular
intervals
consider the extent to which FiT market offers are consistent with fair and
reasonable criteria, redefined to be based on the wholesale price of electricity (the
energy value).
XLII POWER FROM THE PEOPLE: AN INQUIRY INTO DISTRIBUTED GENERATION
Information requests
Given that there is effective competition in the electricity retail market, is it necessary to
retain an ‘obligation to offer’ a price for the purchase of electricity supplied by
distributed generators within the transitionary period? Why?
Are there any significant costs of retaining the ‘obligation to offer’? If so, what are they?
Is the three year transition to market determined feed-in tariffs appropriate? If not, what
might be a more appropriate transition period?
A preliminary view is that the TFiT cut-off should be based on the lodgement of relevant
paperwork with the retailer by a specific date.
Are there other options that the Commission could consider to ensure an orderly and
fair phase-out of the TFiT?
What information should be provided by DPI about transitional arrangements, when
should it be provided, and how should the information be disseminated?
Are there any SFiT, TFiT or PFiT contractual issues that the Commission should be aware
of in its consideration of transitional matters? What are they?
INTRODUCTION 1
1 Introduction
1.1 Background to the inquiry
Along with many other jurisdictions, Victoria has in place policies and programs to
reduce greenhouse gas emissions and facilitate adjustment towards a low-emissions
economy.
Renewable and low emission generation has a role to play in reducing greenhouse gas
emission and ensuring a diverse and competitive electricity sector. In many cases
installing distributed generation capacity makes commercial sense to the household or
business installing the capacity. Distributed generation enables them to offset their
electricity costs by using their own power (in place of purchasing it from a supplier) and
they may earn additional income by selling unused power back into the grid.
Interest in installing distributed generation in Victoria has been growing, but there are
concerns that there are unnecessary barriers to its use and about how electricity fed
into the gird will be priced.
A key consideration for households is the price paid for the electricity they produce. For
larger distributed generation projects, the timeliness and cost of the connection process
is the key concern, in addition to the price received for electricity to the network. The
prices paid per unit of energy for the electricity sold by distributed generators are
referred to as feed-in tariffs (FiTs). In the past, these FiTs were closely related to the
objective of reducing greenhouse gas emissions and were intended to encourage the
installation of renewable energy or low-emission generators, including photovoltaic (PV)
cells, on homes and other buildings. Businesses may also install renewable energy or low
emissions generation that is not covered by FiT schemes, but the price paid for their
electricity is determined by negotiation with the electricity company.
However, with the introduction of a national carbon tax, the justification and design of
State Government greenhouse gas policies may need to be reconsidered. The terms of
reference for this inquiry look at the policies that relate to distributed energy generation
and have two main elements:
assessing the design, efficiency, effectiveness and future of FiT schemes and to
recommend any changes to current FiT arrangements
identifying barriers to connecting distributed renewable and low emission
technologies into the distribution system.
1.1.1 What is distributed generation?
The terms of reference direct the Commission to look into regulatory and other barriers
to the development of a network of distributed renewable and low emission generation
in Victoria. There does not appear to be a standard definition of distributed generation,
however, and reports that analyse distributed generation (or embedded generation)
use varying definitions.
While the Commission does not need to settle on an authoritative definition of
distributed renewable or low-emissions generation, it does need to define the scope of
its inquiry. This inquiry will focus on generation with the following characteristics:
2 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
the energy is generated by households, businesses or community groups who
primarily intend to use the energy on-site or to supply people or organisations close
by, and includes co-generation and tri-generation systems
the generator is connected into the electricity grid through the distribution network,
not the transmission network. In some cases the system may be stand alone
energy in excess of the needs of the generation owner may or may not be sold
(exported) into the grid
the energy could be from renewable sources such as solar, wind, bio gas or waste,
but may also be low emission fossil fuels such as natural gas
the total amount of energy generated is small to medium scale.
The Commission‟s definition was generally supported by many inquiry participants. The
Clean Energy Council (CEC) noted that:
The CEC is generally comfortable with the characteristics of distributed energy
systems and low emissions generation proposed by the Commission. However,
the combined definitions of both distributed and embedded generation
require consideration in this case. While used broadly to define generation
which is not centralised, „distributed generation‟ has no clear definition.
Conversely, „embedded generation‟ is defined in the National Electricity Rules
(rules) as being a generator “connected within a distribution network and not
having direct access to the transmission network”. (sub. 76, p. 1)
Similarly, Ceramic Fuel Cells Limited noted that it agrees with the Commission‟s
qualitative criteria for defining distributed and low-emission generation and:
… particularly that the energy is generated by households, businesses or
community groups who primarily intend to use the energy on-site or to
supply people or organisations close by, and includes cogeneration
systems; and that the total amount of energy generated is small to medium
scale. (sub. 41, p. 9)
1.1.2 What are feed-in tariffs?
FiT is a price paid per unit of energy „fed in‟ to the grid (distribution network) by small to
medium distributed generators. FiT arrangements provide for customers to enter into a
contract with their electricity retailer to receive payments for the electricity generated
by small-scale renewable generators at their premises.
FiTs may be either net or gross. Under a net FiT, a price is paid for any solar energy that
goes back into the grid from the premises, and so the customer is paid only for the
surplus energy generated. Under a gross FiT the customer is paid for every unit of
electricity generated, regardless of whether it goes into the grid or is used at the
premises, and they then pay separately for all the energy they use including that
supplied to them from the grid. All Victorian FiTs are net.
In Victoria, there are three arrangements that regulate FiTs under the Electricity Industry
Act 2000 (Vic):
the general feed-in tariff scheme, also known as the standard feed-in tariff (SFiT)
scheme established in 2004
the premium solar feed-in tariff scheme (PFiT) introduced in 2009 and now closed to
new customers
INTRODUCTION 3
the transitional solar feed-in tariff (TFiT) scheme to replace the premium solar feed-in
tariff scheme.
All electricity retailers with 5000 customers or more are required to make offers to
eligible customers under these three schemes. Electricity retailers with less than 5000
customers can choose to make offers under these schemes, in which case the relevant
statutory requirements apply.
The details of these schemes are discussed further in chapter 2 and appendix B.
1.2 Context and why this inquiry is important
Previously, PFiT and TFiT were regulated to encourage the installation of PV cells and
thereby increase the amount of energy generated through PV renewable technologies.
SFiT was available to a wider range of low emission and renewable technologies. More
recently, however, the Commonwealth has legislated to tax carbon emissions. The
Commonwealth‟s Clean Energy Future legislation will, among other things, impose a fixed
carbon price of $23 a tonne from 1 July 2012, moving to a flexible price after three years.
The Commonwealth also has a target that 20 per cent of Australia‟s electricity supply
will come from renewable energy by 2020. This target is supported by other assistance,
some of which is targeted specifically at small-scale renewable energy. Since
January 2011 households, small businesses and community groups installing small-scale
renewable energy technologies have been eligible to receive financial credits in the
form of small-scale technology certificates. Additional credits are available to
encourage further the installation of small-scale renewable generators, such as roof-top
PV or wind generators (DCCEE 2011).
The introduction of a price on carbon has led to some, including the Council of
Australian Governments (COAG), to argue that subsidies through policies such as FiTs
should be discontinued. South Australia and New South Wales recently held inquiries to
establish the future framework for setting „fair and reasonable‟ FiTs in their jurisdictions.
The terms of reference for this inquiry note that:
In the context of the implementation of a national carbon price, it is
appropriate that the Commission undertakes a review of Victoria‟s feed-in
tariff schemes.
More generally, the introduction of a price on carbon will encourage more energy
generation from renewable and low emissions sources. However, there may be
regulatory or other barriers that prevent or hinder the move to low emission sources of
energy. As noted in the terms of reference:
Addressing any state and local regulatory or other barriers to the uptake of
low emissions generation, including co-generation and tri-generation, is also
important to ensure that any transition to low emissions generation occurs
as smoothly and as cost-effectively as possible.
This inquiry investigates the barriers that apply to renewable and low emissions
distributed energy.
4 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
1.3 The Commission’s approach
The Commission‟s task is to answer its terms of reference.
In answering its terms of reference the Commission has considered a number of matters
to help structure its analysis and guide the type of evidence it needed to collect
through the public inquiry process.
The first is to consider the objectives of policies impacting on distributed generation and
how these may have changed overtime. The Commission notes that these objectives
also need to be consistent with the overall objectives of the National Electricity Market.
The Commission then considers the barriers to distributed generation achieving its
potential within the National Electricity Market and what role FiTs should play in the
policy framework.
Central to the Commission‟s analysis is a consideration of where there may be market
failures or other barriers that prevent the market signals faced by participants from
resulting in an efficient structure for the supply of electricity. In the Commission‟s view,
removing these barriers in a way that reinforces choice and competitive incentives
could help deal with many of the complexities identified and increase the efficiency of
decisions for investment in and use of network and generation infrastructure.
Efficient FiTs play an important role in providing market signals to drive investment and
the use of different forms of distributed generation. An important question considered
by the Commission is what is the role of FiTs in reducing greenhouse gas emissions in the
context of other state and national climate change policies.
In the absence of a role for FiTs in dealing with greenhouse gas emissions, the
Commission considers that FiTs should create the correct incentives for the installation of
distributed generation in Victoria‟s electricity system where the benefits of this form of
generation outweigh the costs.
1.4 Inquiry process
The Commission advertised the inquiry in the press and by circular to those who,
according to a preliminary analysis, were likely to be interested. The terms of reference
and inquiry particulars were listed on the Commission‟s website (www.vcec.vic.gov.au).
In February 2012, the Commission released an issues paper and invited submissions to
the inquiry.
During the inquiry, the Commission met with a number of individuals and organisations
— including community groups, consumer representative groups, industry experts,
government departments, and State and Commonwealth regulatory bodies — to
identify and assess the issues relevant to this inquiry. The Commission also conducted a
short Victorian Energy Retail Business Survey to assist its analysis of current and future
Victorian feed-in tariff arrangements. In addition, the Commission held three
roundtables, and received 85 individual submissions from interested parties, including
businesses, unions and private individuals. The Commission also received 718 proforma
submissions supporting the retention of FiTs sent via the Environment Victoria website
and a further 126 additional proforma submissions where the submitters had added
additional comments. Detailed information about the consultation process is available
in appendix A.
The Commission also engaged ACIL Tasman to advise on the advantages and
disadvantages of different methodologies for valuing electricity from distributed
INTRODUCTION 5
generation and model one of these methodologies. The ACIL Tasman report is
available on the Commission‟s website (www.vcec.vic.gov.au).
The Commission also surveyed electricity retailers to gather information to inform its
analysis of FiTs.
The Commission would like to thank those who have participated in its consultation
process and made a submission to the inquiry. The Commission has been pleased by
the quality of many of the submissions, reflecting the thought and effort which has been
put into their preparation.
The Commission took account of the Charter of Human Rights and Responsibilities Act
2006 (Vic) and considers that this report is consistent with the human rights set out in the
Charter.
1.5 Structure of the report
The report is structured as follows:
Introduction (chapter 1)
Distributed generation in Victoria (chapter 2)
The Commission‟s approach (chapter 3)
Connecting distributed generators to the distribution network (chapter 4)
Victorian feed-in tariffs: selling electricity to the grid (chapter 5)
Future Victorian feed-in tariff arrangements (chapter 6).
Appendix A provides information on parties consulted during the course of the inquiry
through meetings, roundtable discussions and submissions. Appendix B provides more
information on the regulatory structure.
DISTRIBUTED GENERATION IN VICTORIA 7
2 Distributed generation in Victoria
2.1 The Victorian electricity industry
The market structure for electricity in Victoria can be defined by interactions through
physical energy flows and financial transactions between market participants
(figure 2.1). The key participants in the Victorian electricity industry are summarised in
box 2.1.
Figure 2.1 Market structure
Source: Commission analysis.
Box 2.1 Electricity industry key participants
The key participants in the Victorian electricity industry are:
Generators — supply electricity to the transmission or distribution system. Most of
the generation capacity in Victoria is privately owned. The major companies
are AGL Energy, International Power, TRUenergy, and Alinta Energy.
Transmission network service providers (TNSPs) — transport electricity from
generators to distribution network service providers and large end users through
high voltage transmission lines to substation transformers that lower the voltage
for distribution. The Victorian TNSP in the National Electricity Market (NEM) is
owned and operated by SP AusNet.
Distribution Network Service Providers (DNSPs) — link the transmission systems to
end users (including households) through distribution lines that carry low voltage
electricity. In Victoria DNSPs are CitiPower, Powercor, Jemena, SP AusNet and
United Energy. Each DNSP is responsible for a defined region.
physical
electricity flows
transmission network distribution network
generators AEMO
schedules
wholesale market
retailers consumers
physical electricity
flows
dispatch
orders
supply
offers electricity settlement payments
electricity settlement payments feed-in tariff
electricity payments financial contracts
8 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
Box 2.1 Electricity industry key participants (cont.)
Retailers — act as an interface between the electricity wholesale market and
customers. They manage customer transfers, connections, billing, complaint
handling, and service information. They also deliver a range of Commonwealth
and state programs, including community service obligations, energy efficiency
schemes, hardship schemes and renewable and other energy generation
schemes. Retailers operating in Victoria include: AGL, Australian Power and
Gas, Click Energy, Dodo Power and Gas, Energy Australia, Lumo Energy,
Momentum Energy, Neighbourhood Energy, Origin Energy, Powerdirect, Red
Energy, Simply Energy and TRUenergy. Retailers are not constrained to operate
in a particular region and are free to compete for customers.
Consumers — purchase and use electricity.
These assets and businesses physically operate in Victoria and are governed by the
rules of the NEM which is a wholesale market for the supply of electricity to retailers
and end-users. The NEM consists of five interconnected regions (essentially
Queensland, New South Wales, Victoria, South Australia and Tasmania). The NEM is
operated by the Australian Energy Market Operator (AEMO) under the National
Electricity Law and Rules.
Source: Commission analysis.
2.1.1 Market for distributed energy
The Victorian energy market has historically been shaped by large brown coal energy
generation in the La Trobe Valley, with large transmission lines to distribution networks.
This network reflects system design decisions made in the 1920s and a legacy structure
that has been adapted somewhat over the ensuing years. Since privatisation, smaller
gas fired generators have increasingly played a part in the energy market and, more
recently, large-scale wind and small-scale solar capacity have grown. The growth of
renewable technology reflects a number of factors including increased climate
change awareness and a response to a number of government policies.
Distributed generation occupies a specific niche in the broader electricity market. The
market for distributed generation sees the crossroad of energy retailers, technology
producers and installers, small- and medium-scale generators, and energy distributors.
Distributed generation is a diverse sector of the electricity market, with a wide range of
energy sources and producers, ranging from micro size (households) to medium size.
The distributed generation market is made more complex by a slew of standards,
regulations, policy and legislation imposed by various levels of government.
While exact figures on market characteristics depend on definitions of distributed
generation, such generation already appears to play a role in the energy market.
Energy Supply Association of Australia (ESAA) figures suggest ‘embedded and non-grid
generation’ account for 7.2 per cent of Victoria’s installed capacity (ESAA 2011, pp. 18,
20). The Institute for Sustainable Futures (ISF), however, suggests that while Australian
distributed generation is growing in absolute terms, it has shrunk as a proportion of
installed capacity (Dunstan et al. 2011, p. 42).
Small-scale distributed generation
Victorian small-scale distributed generators include homes, business and community
groups that produce energy primarily for their own use. The overwhelming majority of
small-scale generators use solar photovoltaic (PV) technology. Many Victorian
electricity retailers are active in the small-scale solar market, having published offers
DISTRIBUTED GENERATION IN VICTORIA 9
under the standard, premium and transitional feed-in tariff schemes (SFiT, PFiT and TFiT).
Indeed, electricity retailers with more than 5000 customers are required to offer feed-in
tariffs (FITs), and have to do so using a variety of packages and terms and conditions
(DPI 2012c). The number of PFiT customers and installed capacity (kW) in the various
Victorian electricity distribution networks is shown in table 2.1.
Table 2.1 Premium solar feed-in tariff scheme uptake (at 31
October 2010)
SP Ausnet Jemena Powercor CitiPower UED Total
Number of PFiT Customers 9 152 2 467 7 259 1 451 5 236 25 565
Installed capacity (kW) 12 953 3 969 10 648 1 654 7 977 37 201
Source: (DPI 2011b, p. 153).
As well as retailers, the small-scale solar market also comprises producers and installers
of solar panels. There are a significant number of solar PV cell and panel producers
worldwide, many of which sell their products in Australia.
A number of energy retailers also supply and install solar systems, including to customers
who purchase their electricity from other retailers. This includes selling a range of system
configurations with different panels and inverters, arranging for finance, arranging
installation by licensed accredited installers, organising applications for appropriate
government rebates, and providing advice and assistance for the installation of
appropriate meters by the relevant distributers (Origin 2011; TRUenergy 2011).
In Australia, all installed solar PV cells and panels must be certified and approved to
AS/NZS5033 standards. These guidelines are set by Standards Australia. The Clean
Energy Council (CEC) also runs an industry accreditation program,1 and there are now
more than 3000 accredited installers of PV systems who are certified and trained.
To be eligible for the Commonwealth rebates and Renewable Energy Certificates
(RECs), solar PV systems must be designed and installed by accredited CEC installers.
Each installation must have a completed report before the system has been
commissioned and RECs can be applied for up to 12 months after the date of
installation.
The market for non-solar, small-scale distributed generation operates in a similar fashion.
While the premium and transitional FiTs are limited to solar, the SFiT applies to other
renewable energy sources provided the system size is less than 100kW (table 2.5).
Again, Commonwealth rebates and RECs are issued where an accredited system is
installed.
Medium-scale distributed generation
Medium-scale distributed generation encompasses customers such as hospitals, office
blocks and manufacturers. Many medium-scale generators produce electricity primarily
for private use, although some export their excess electricity into the grid, and, for
others, selling electricity is their primary focus. Medium-scale distributed generation
includes a wide variety of energy sources including renewable and non-renewable
energy and encompasses co-generation and tri-generation facilities.
1 See http://www.solaraccreditation.com.au for more details.
10 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
Larger distributed generators can be expensive and the connection process can be
long and costly. Most businesses interested in installing distributed generation will
therefore engage an electrical contractor to oversee the process. The contractor will
assess the businesses’ energy requirements and capacity to generate electricity, and
determine the feasibility of a generator through consultation with a number of parties.
These include local and international technology manufacturers and accredited
installers. Once the project is approved the contractor engages the relevant energy
distributor to establish a connection to the energy grid.
Take up of distributed generation
While exact figures on market characteristics depend on definitions of distributed
generation, ESAA figures suggest ‘embedded and non-grid generation’ account for 7.2
per cent of Victoria’s installed capacity (approximately 5.7 per cent from renewable
distributed energy generation and 1.6 per cent from non-renewable distributed energy
generation) (table 2.2; (ESAA 2011, pp. 18, 20)). The majority of embedded generation,
by volume, is medium-scale.
Table 2.2 Capacity of embedded and non-grid generation
in Victoria — June 2010
All embedded/non-grid MW Non-hydro renewable
embedded/ non-grid MW
Natural gas 133 Black liquor 55
Waste gas 45 Landfill gas 40
LPG 0.6 Sewage gas 22
Hydro 103 Solar 75
Non- hydro renewable 619 Wave 0.2
Wind 428
Solar hot water 131,000 units
Total 900 Total 619
Note: Embedded generators are those connected directly to the distribution network, with no direct
connection to the transmission network; solar hot water is not included in total.
Source: (ESAA 2011, pp. 20-21; CEC 2011a).
Importantly, the ISF notes that:
In absolute terms, installed DG [distributed generation] capacity has
increased in Australia by about 20% between 2006 and 2010 … however this
has not kept pace with the national average increase in installed capacity.
(Dunstan et al. 2011, p. 42)
Unfortunately, a lack of data makes it difficult to assess the uptake and system impact
of small-scale distributed generation. While solar PV installations are well documented it
would useful to understand what proportion of small-scale distributed generation they
account for. Furthermore it would be useful to track the impact of various FiT schemes
on the uptake and impact of non-solar distributed generation. This would help assess
the extent to which FiTs detract from the uptake and impact of other distributed
generation technologies in favour of solar PV.
Figure 2.2 shows the capacity of solar PV installed annually, and highlights the impact of
the PFiT.
DISTRIBUTED GENERATION IN VICTORIA 11
Figure 2.2 Annual capacity of solar PV installed in Victoria
(MW)
Source: (CEC 2011a, p. 34).
Although there are only around 30 co-generation facilities in Victoria they produce a
significant amount of energy (DPI 2012a). While data depend on definitions and
sources, non-renewable co-generation contributed around 478MW of Victoria’s
electricity generation in 2010 (table 2.3).
Table 2.3 Co-generation in Victoria — 2010
MW
Brown coal 195
Natural gas 124
Waste gas 45
LPG 0.6
Bioenergy 113
Total 478
Note: the 195MW Morwell brown coal co-generation power station is classed as a ‘principal power
station’ and does not appear in Table 2.2.
Sources: (ESAA 2011, p. 21; CEC 2012a).
a
SFiT introduced PFiT introduced TFiT introduced
a Forecast based on first 8 months
12 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
Pricing electricity
The retail price of electricity reflects four elements — the wholesale cost of electricity,
network service, retail service, and capital change and investment in the network.
According to the Australian Energy Regulator (AER), the average electricity bill reflects
a cost breakdown of 42 per cent wholesale costs, 47 per cent network costs and 11 per
cent retail costs (AER 2011b, p. 2)2.
Wholesale electricity price
Within the National Electricity Market (NEM), exchange between electricity producers
and consumers occurs within a pool in which output from all generators is aggregated
and scheduled to meet demand. Wholesale electricity trading is conducted in a spot
market in which supply and demand are matched instantaneously. At five-minute
intervals, generators bid to supply the market a specific amount of electricity at a
specific price. AEMO determines the most cost-effective generators to meet demand
and dispatches them into production. The cost to supply the last megawatt of
electricity to meet demand (within the five minute period) is deemed the ‘dispatch
price’ and applies to all generators in production, regardless of their original bid. The
‘spot price’ of Victorian electricity for a 30 minute trading interval is the average of the
previous six dispatch prices.
The Rules set a maximum spot price (market price cap) at $12 500 per MWh. This is the
maximum price generators can bid into the system, and automatically triggers AEMO
to request customer electricity supply be interrupted to maintain supply and demand
balance. The Rules also limit the minimum spot price (market floor price) at $1 000 per
MWh. Market non-scheduled small generators are said to be ‘price takers’ in the NEM.
That is, while they cannot set the spot price, they receive it for any electricity exported
into the grid.
AEMO determines the liabilities of all market participants daily and settles trade
transactions in the NEM weekly. NEM financial settlement operates on a four week
delay. The settlement price for generators and market customers equals the amount of
energy consumed or supplied multiplied by the spot price and any loss factors (AEMO
2010a).
Network tariffs
Network tariffs recover the cost of transporting electricity from generator to customer.
This takes places through the transmission network (high voltage power lines which
transport energy long distances) and the distribution network (lower voltage power lines
which deliver electricity to homes and businesses). Network tariffs are regulated by the
AER and include the cost of:
maintaining, replacing and extending infrastructure
metering
operating the network business (including labour, material and compliance with
reliability and safety standards)
financing the installation of new equipment
complying with government legislation (AER 2011b, p. 3).
2 Based on the average customer bill in the Australian states where network prices are set by government.
DISTRIBUTED GENERATION IN VICTORIA 13
Retail services
Electricity retailers purchase wholesale electricity in the NEM, pay the owners of
distribution and transmission networks to transport electricity, and bill customers for their
electricity use. Retail services include customer information and billing. Retail service
costs include:
running customer service centres, advertising and selling electricity contracts
complying with government legislation (AER 2011b, p. 3).
Unlike other states, the price of Victorian retail services is unregulated. Instead electricity
prices are directly determined by retailers.
All customers must install equipment which monitors their consumption and measures
electricity use. This equipment is provided by local network service providers and is
registered and audited by AEMO. Currently, under the National Electricity Rules (NER)
there is no obligation for decentralised generators to install remotely-read interval
meters. Where these are not used, generators may not receive accurate settlement
statements as actual output may not be incorporated into the settlement cycle until
revision (up to 30 weeks after billing).
2.2 Regulation of distributed generation in Victoria
Regulation of the electricity sector in Victoria is complex, comprising a combination of
national and State-based regulation. The trend in recent years has been towards an
increasingly national regulatory framework with the economic package of national
reforms completed in 2008. The non-economic package of national reforms will
commence from 1 July 2012, by creating a single national framework for energy
distribution networks and retail markets. This reform process is known as the National
Energy Customer Framework (NECF). These reforms have significant implications for
distributed generators wishing to connect to the distribution network.
This section provides an overview of:
the regulatory framework governing the NEM (section 2.2.1)
connecting to the distribution network (section 2.2.2)
selling surplus electricity generated (section 2.2.3)
how regulation of the electricity sector impacts distributed generation and the
implications this has for the inquiry (section 2.2.4).
A more detailed discussion of the framework regulating distributed generation in
Victoria can be found in appendix B: Regulation of the electricity sector.
2.2.1 Regulation of the NEM
Current regulatory framework
The NEM is the wholesale market for the supply of electricity to retailers and end-users in
all states and territories except Western Australia and the Northern Territory. The NEM’s
high level regulatory structure is outlined in figure 2.3.
The regulatory framework for the electricity market in Australia is governed by the
Council of Australian Governments (COAG) and is developed under the guidance of
the Standing Council on Energy and Resources (SCER). The AER regulates the NEM. The
14 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
AEMC makes rules in response to requests for rule changes, usually from NEM
participants. The AEMO manages and operates the NEM and coordinates planning of the
market. Appeals are considered by the Australian Competition Tribunal.
The NER are made under the National Electricity Law (NEL). The NER are maintained and
developed by the AEMC and enforced by the AER. The lead legislation for the NEL is
the National Electricity (South Australia) Act 1996 (SA). This legislation is applied in
Victoria by the National Electricity (Victoria) Act 2005 (Vic).
The current national regulatory framework for distribution and transmission is
supplemented by Victorian legislation. The Electricity Industry Act 2000 (Vic) (EI Act)
includes a licensing regime for those generating electricity for supply or sale, and the
Victorian FiT arrangements for the PFiT, TFiT and SFiT schemes. The Victorian Essential
Services Commission (ESC) administers the licensing and price and service standard
provisions of the EI Act.
Figure 2.3 Electricity regulatory structure
Source: Commission analysis.
Standing Council on
Energy & Resources
Council of Australian
Governments (COAG)
Participants & Consumers
Australian Energy
Market Operator
(AEMO) System operator and
planning
Australian Energy
Market Commission
(AEMC)
Rule maker and adviser
Australian Competition & Consumer
Commission (ACCC)
Australian Energy
Regulator (AER)
Economic regulator of
transmission and
distribution networks
Essential Services
Commission (ESC)
Licensing and service
standards
DISTRIBUTED GENERATION IN VICTORIA 15
Regulatory framework after 1 July 2012
The NEL and NER are complemented by the NECF which will commence nationally on
1 July 2012. The NECF regulates the sale of energy to retail customers through the
National Energy Retail Law (NERL) and National Energy Retail Rules (NERR). It also
amends existing national regulation, including introducing chapter 5A into the NER,
which regulates electricity connections for retail customers (including embedded
generators). The lead legislation to implement the NERL has been passed in South
Australia. The NECF will be applied in Victoria by the National Energy Retail Law
(Victoria) Bill 2012, which is currently being debated by the Victorian Parliament.
Although the agreed commencement date of the NECF is 1 July 2012, cl 2 of the
National Energy Retail Law (Victoria) Bill 2012 provides that it will commence on a day
to be proclaimed. This ensures that if another jurisdiction’s application Act is delayed, a
later commencement date can be coordinated between participating jurisdictions
and the NECF will not become operational in Victoria before other jurisdictions
(Explanatory Memorandum 2012, p.1; O’Brien 2012, p.1447).
2.2.2 Connecting to the distribution network
The process for connecting connection applicants (CAs) to the distribution network will
change with the commencement of the NECF. As of 1 July 2012, there will be two
separate processes under the NER for connecting distributed generation to the
distribution network:
a process for registered generators or generators exempt from registration by
AEMO under chapter 5
a process for retail customers (including generators who do not intend to
participate directly in the NEM and instead intend to sell electricity through a direct
contract with a retailer) under chapter 5A.
Each connection process sets the rights and obligations for those seeking connection to
the distribution network and specific sizes/types of generators may be excluded from,
or find it more difficult to access, one or other of these connection processes. There are
various fees and charges associated with connecting distributed generators to the
distribution network applied by DNSPs. These costs vary depending on the size/type of
generator being connected and type of connection. With the commencement of the
NECF, fees and charges will be regulated nationally by the AER through the NER.
Connecting distributed generation under chapter 5
To be connected under chapter 5, registration as a generator is required unless AEMO
grants an exemption from registration (NEL, s 11; NER, cl 2.2.1). A Standing Exemption
exists for generating systems with a nameplate rating of less than 5 MW (AEMO 2010b,
p.36). In certain circumstances, AEMO may also exempt generators less than 30 MW
from registration on a case-by-case basis.
Generator classification has significant implications for participation in the NEM.
Registration as a ‘market generator’ is required to sell electricity in the NEM through the
spot market. The consequences of generator classification for distributed generators
wishing to sell excess electricity generated are discussed in section 2.2.3.
Connection under chapter 5 is a negotiated process. However, there is an automatic
right of connection if automatic access standards outlined in sch 5.2 are met. These
automatic access standards apply to larger registered generators. Generators of less
than 5 MW capacity must negotiate the terms of a connection agreement, including
technical standards, with their DNSP on a case-by-case basis.
16 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
Connecting distributed generation under chapter 5A
The chapter 5A connection process is designed primarily for retail customers seeking to
buy electricity, but it also applies to distributed generators wishing to connect to the
distribution network and sell electricity directly to a retailer. Chapter 5A provides for
three types of connection service for ‘retail customers’.
(1) A basic connection service which will cover retail customers, including those who
are micro-embedded generators (but not larger embedded generators). DNSPs
must have a model standing offer for basic connection services that has been
approved by the AER. Micro-embedded generators are not defined in chapter 5A
according to generator size. The NER merely state that a micro EG
(micro-embedded generator) connection is ‘of the kind contemplated by
Australian Standard AS 4777 (Grid connection of energy systems via inverters)’ (cl
5A.A.1).
(2) A standard connection service which can cover the terms and conditions for
different classes of connection services or different classes of retail customers
(including non-registered embedded and micro-embedded generators). DNSPs
can choose to prepare a model standing offer for such services and have it
approved by the AER.
(3) A negotiated connection contract which covers services that are not subject to a
basic or standard connection standard offer, or where a basic or standard
connection service is sought but the CA elects to negotiate the terms and
conditions of the connection agreement. The terms and conditions for such
services are negotiated and if agreement cannot be reached the dispute can be
arbitrated by the AER. The DNSP must use its 'best endeavours' to make a
negotiated connection offer within 65 business days. A CA is an applicant for a
connection service that is a retail customer (including an embedded generator), a
retailer or other person acting on behalf of a retail customer, or a real estate
developer.
Table 2.4 compares the connection processes under chapters 5 and 5A of the NER. See
appendix B for a detailed discussion on the connection processes under chapters 5
and 5A of the NER for distributed generators.
DISTRIBUTED GENERATION IN VICTORIA 17
Table 2.4 Connection process for distributed generators from 1 July 2012
NER Applies to Generator type Connection Right to connect?
Chapter 5 Registered generators
Generators exempt from registration:
– generators <5 MW (must meet
Standing Exemption criteria)
– other generators <30 MW on a
case-by-case basis (includes
generators >5 MW and <30 MW
capacity which export <20 GWh in
any 12 month period)
Various
combinations of:
scheduled,
semi-scheduled
and
non-scheduled
market and
non-market
Negotiated — cl 5.5
outlines access
arrangements for
embedded
generators wanting
to connect to the
distribution network
Yes — if automatic access standards
are met (sch 5.2)
No — if CA wishes to negotiate any
access standards or if the generator is
exempt or eligible for exemption from
registration, automatic access
standards do not apply and there is no
automatic right to connect
Chapter 5A
(excludes
registered
generators)
Retail customers who are
micro-embedded generators
Generator size not
specified but must
meet Australian
standard AS4777
Basic connection
service
Yes — DNSP must provide model
standing offer
Retail customers
(includes non-registered embedded
generators and micro-embedded
generators)
Not specified Standard
connection service
Yes — but only if the DNSP provides a
relevant model standing offer (DNSPs
may, but are not required to, provide
model standing offers)
Connection is neither basic nor
standard connection service, or
Basic or standard connection service is
sought but CA elects to negotiate
terms and conditions
Not specified Negotiated
connection
contract
Unclear — DSNP must use its ‘best
endeavours’ to make a negotiated
connection offer within 65 business
days. The AER will arbitrate where
agreement cannot be reached
Source: Commission analysis of chapters 5 and 5A NER.
18 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
2.2.3 Selling excess electricity generated
National regulation
Under the NER, distributed generators wishing to sell surplus electricity into the
distribution grid currently have two options.
(1) Sell through the NEM at spot prices: each generating unit that receives payment
from AEMO for sent out electricity must be registered as a ‘market generator’,
regardless of generating unit size. This would include generators of less than 5MW
capacity that would otherwise be eligible for an exemption from registration under
the Standing Exemption (although the Commission understands it is rare for this to
occur in practice). Substantial registration and participant fees apply.
(2) Sell through a private bilateral agreement outside of the NEM, generally for an
agreed fixed price: applies to registered ‘non-market’ generating units and
generating systems exempt from registration. All sent out generation must be
purchased in its entirety by a local retailer or customer located at the same
connection point. A ‘connection point’ is the agreed point of supply established
between a DNSP and distributed generator.
In the future, there may be a third option for distributed generators wishing to sell surplus
electricity generated. AEMO recently submitted a rule change to the AEMC to
introduce a new category of market participant into the NER called a 'small generation
aggregator'. This will allow a small generation aggregator to have market responsibility
for the participation of multiple generating units in the NEM and will only require a single
registration. Separate registration of each of the generating units will not be required,
significantly reducing costs and improving access to the market. This will allow
aggregated generators to more easily enter and sell in the NEM (AEMC 2012a, pp.1–5).
However, registered small generation aggregators would not be eligible for the simpler
chapter 5A connection process and would instead have to connect through
chapter 5.
Victorian regulation
Licensing
The EI Act prohibits the generation of electricity for supply or sale unless the generator is
licensed or has been exempted from the requirement to hold a license for the
generation of electricity for supply and sale (s 16(1)). Under s 17 of the EI Act, the
Governor in Council can make an Order in Council exempting a person from the
requirement to obtain a licence. An Exemption Order exists for distributed generators
with a capacity of less than 30MW (ESC nd, p.1; Order in Council 2002).
Victorian feed-in tariff schemes
In Victoria, certain types of distributed generators connected to the distribution network
are able to sell surplus electricity generated back into the distribution grid through FiT
schemes under Division 5A of the EI Act. The PFiT and TFiT are paid as a credit against
the amount owing under the FiT customer’s electricity bill. The SFiT is usually paid by way
of a credit to the customer’s electricity bill (NERA & AAR 2011, pp.62, 70, 79). Victorian
distributed generators receiving a FiT are exempt from the requirement to obtain a
licence by the Exemption Order. Under the NECF, the State-based retail licensing
regime will be replaced by a national retailer authorisation framework. The retail
licensing provisions under the EI Act will therefore be repealed, and current licence
DISTRIBUTED GENERATION IN VICTORIA 19
conditions that regulate FiTs will become direct statutory obligations under an
amended EI Act.
There are three FiT schemes operating in Victoria and each has specific eligibility criteria
restricting the size of generator, type of technology and type of customer that can
participate. Licensed electricity retailers are required to publish the terms and
conditions of their FiT offers. The EI Act provides that the Minister for Energy and
Resources may refer a matter to the ESC for assessment if not satisfied that the terms
and conditions of a licensed retailer’s FiT offer are ‘fair and reasonable’ (s 40I). Table 2.5
summarises the FiT schemes that operate in Victoria. See appendix B for a more
detailed discussion of the Victorian FiT arrangements.
20 POWER FROM THE PEOPLE: AN INQUIRY INTO DISTRIBUTED GENERATION
Table 2.5 Victorian feed-in tariffs schemes
Feed-in tariff Applies to Technology Generator size Tariff Other terms and
conditions
Premium FiT
(closed to
new
applicants)
householders claiming
one solar PV at principal
place of residence, or
persons (such as small
businesses and
community
organisations)
occupying one or more
properties (other than as
a place of residence)
that claim one solar PV
at each property and
consume 100MW hours
or less per year.
Solar PV 5 kW or less 60c/kWh statutory minimum consistent with
statutory minimum
conditions
‘fair and
reasonable’ where
terms and
conditions are not
statutory minimum
conditions
average cost per
customer of
electricity per year
arising from the TFiT
scheme cannot
exceed $5.
Transitional FiT 25c/kWh statutory minimum
Standard FiT generation companies,
or
persons generating
electricity for supply or
sale.
Small
renewables,
including:
wind
solar
hydro
biomass
other
(specified).
Less than 100 kW
(excludes solar
PV of 5 kW or
less)
A ‘fair and reasonable’ price:
ESC guidance states that this
means the rate offered to
the customer must be not
less than the rate the
customer pays to buy
electricity from the retailer
range of offers from 18.99 to
29.03c/kWh available as of
30 March 2012.
Terms and conditions
must be ‘fair and
reasonable’.
Source: Commission analysis of Division 5A of the Electricity Industry Act 2000 (Vic).
DISTRIBUTED GENERATION IN VICTORIA 21
2.2.4 What does this all mean for the inquiry?
The regulatory framework governing the Victorian electricity sector, and distributed
generation in particular, has significant implications for the growth of distributed
renewable and low emission generation in Victoria. Although the electricity sector is
increasingly nationally regulated, some areas of Victorian-specific regulation — such as
the FiT schemes — will remain after the commencement of the NECF on 1 July 2012. In
reviewing how the framework applies to distributed generation, the Commission has
found that the regulation is complex, and has identified aspects that are inconsistent
and where the rationale for regulating similar activities differently is unclear.
The regulatory framework is complicated
Regulation of the Victorian electricity sector comprises national and Victorian-based
regulation. The present regulatory framework is changing, with transfer of current state
and territory responsibilities to a new national regulatory regime governing the supply
and sale of energy to retail customers, to commence on 1 July 2012. This means that a
significant amount of State-based electricity regulation in Victoria will become
redundant. However, Victoria regulation will continue to govern distribution,
transmission and generation licensing, and FiTs.
Under the NECF, a distributed generator can potentially be required to enter into four
separate contractual arrangements, each of which is subject to separate terms and
conditions:
a contact for retail services with a retailer governed by the NERL Pt 2
a contract with a DNSP for initial connection services governed by the NER chapter
5 or 5A
a (deemed) contract with a DNSP for ongoing energisation services governed by
the NERL Pt 3
a Victorian FiT contract with a retailer who is retailing to Victorian customers,
governed by the EI Act Div 5A.
The regulation that governs these contractual arrangements distinguishes between
specific categories of customer and/or types of generator. These categories are not
consistent.
The regulatory framework is, in some respects, inconsistent and
discriminatory
Processes for connecting distributed generation to the distribution network and for
receiving a regulated FiT for selling surplus electricity generated, contain detailed and
inconsistent generator eligibility criteria. Only certain types/sizes of generators and/or
types of technology can connect under chapter 5, access the new chapter 5A
simplified connection process, and participate in a Victorian FiT scheme to sell
electricity. In addition, individual DNSPs have their own requirements and procedures.
To connect under chapter 5, a generator must be registered or exempt from
registration by AEMO under the NER chapter 2. A Standing Exemption exists for
generators of less than 5MW capacity.
Connection services under chapter 5A are restricted to specific types of retail
customers that are not registered with AEMO. Micro-embedded generators are
guaranteed connection through a basic connection service. Other embedded
generators are only guaranteed connection through a standard connection
22 POWER FROM THE PEOPLE: AN INQUIRY INTO DISTRIBUTED GENERATION
service if a DNSP chooses to provide a model standing offer for that particular class
of connection service or retail customer.
The PFiT and TFiT schemes are reserved for solar PV systems of up to 5 kW capacity.
The SFiT scheme applies to specified small renewable energy generating facilities of
less than 100 kW capacity (greater than 5 KW and less than 100 kW for solar PV
systems).
As a result of the various size thresholds and eligibility criteria that have emerged over
time, the rationale for why some generators and not others have access to certain
regulated rights is unclear and can conflict across the different areas of regulation.
Registration is a high entry barrier to participation in the NEM
Any distributed generator wishing to sell through the NEM at spot prices must be
registered as a ‘market generator’ with AEMO, regardless of the size of the generator.
Registered generators are unable to connect through the new simpler processes in
chapter 5A and must therefore connect under the chapter 5 process. Similarly, the
proposed introduction of a new category of registered market participant — a ‘small
generation aggregator’ — will also be restricted to connecting under the more
complicated chapter 5 process.
The registration process is designed for larger generators and, therefore, can be
complex and time consuming. AEMO has advised that it may take a proponent up
to three months to prepare the documentation necessary for registration (AEMO
2011, p.4).
The chapter 5 connection process is generally lengthier, more costly and uncertain
than the process under chapter 5A because there is no mandated statutory
timeframe within which a DNSP must make an offer to connect. In addition,
registered generators are subject to significant registration and participant fees.
Electricity sold outside the NEM must be purchased in its entirety by a local retailer
or customer located at the same connection point. Distributed generators can
therefore only sell their sent out generation to market participants through a retailer
(AEMC 2012c, p.174). Although distributed generators may enter into a private
agreement with their local retailer, retailers are not obliged to purchase electricity
in this way. Micro to small distributed generators in Victoria therefore often rely on
the State-based FiT scheme arrangements to sell surplus electricity generated.
Connection and selling regulation does not cater for all distributed
generators
Certain customers, generator types/sizes and forms of technology are restricted,
excluded from or find it more difficult to access current connecting and selling
arrangements.
An automatic right to connect exists for larger generators (with a capacity of 5 MW
or greater) that meet the automatic access standards under chapter 5. Similarly,
micro-embedded generators have an automatic right of connection through a
basic connection service under chapter 5A. However, other small to medium
generators will only be guaranteed an automatic right of connection if DNSPs
choose to provide a relevant model standing offer for standard connection
services under chapter 5A.
Generators unable to connect through a basic or standard connection service
under chapter 5A need to negotiate their connection arrangements with a DNSP
under chapter 5 or 5A. Connecting through a negotiated connection contract
DISTRIBUTED GENERATION IN VICTORIA 23
under chapter 5A is more a complex process than simply accepting a basic or
standard connection service model standing offer. Negotiating access under
chapter 5 is even more time consuming, costly and difficult for a CA. Table 2.6
summarises the connecting options available to distributed generators from 1 July
2012.
Non-renewable and low-emission generation, and renewable generators with a
capacity of 100 KW or greater, are excluded from participating in the Victorian FiT
arrangements. These forms of distributed generation/larger sized generators are
restricted to selling through the NEM at spot prices, or through a private bilateral
agreement outside of the NEM with a local retailer or customer located at the
same connection point. Table 2.7 summarises the selling options available to
various distributed generator types/sizes and forms of technology.
Solar PV systems of 5 kW or less are only eligible for the PFiT (closed to new
applicants) or TFiT if they meet specific customer eligibility criteria. Householders
must be claiming only one solar PV system on a property that is their principal place
of residence. The PFiT and TFiT are also available to people that occupy one or
more properties (other than as a place of residence), claim only one solar PV
system at each of those properties, and their annual consumption rate of electricity
is 100 MWh or less. If these criteria are not satisfied, customers with solar PV systems
of 5 kW or less are unable to access a regulated FiT. This, however, does not
preclude retailers from offering an unregulated FiT if they choose to do so.
24 POWER FROM THE PEOPLE: AN INQUIRY INTO DISTRIBUTED GENERATION
Table 2.6 Connecting options for distributed generation from 1 July 2012
Micro to small generators <100 kW Small to medium generators
100 kW to 5 MW
Medium generators
>5 MW to <30 MW
Chapter of
the NER Chapter 5Aa Chapters 5 and 5A Chapters 5 and 5A
Registration
required?
No Under chapter 5A: no
Under chapter 5: yes — registration or
exemption from registration is required.
A Standing Exemption applies for
generators <5MW
Under chapter 5: yes — registration or
exemption from registration is required
Type of
connection
Basic connection service,
standard connection service or
negotiated connection contract
Under chapter 5A: standard connection service or negotiated connection contract
Under chapter 5: negotiated
Automatic
right to
connect?
Yes — for basic connection
services a DNSP must provide a
model standing offer.
Yes — for standard connection
services if a DNSP provides a
model standing offer for a
relevant standard connection
service.
Unclear — for negotiated
connection contracts a DNSP
must use its ‘best endeavours’ to
make a negotiated connection
offer, AER has the power to
arbitrate where agreement
cannot be reached
Under chapter 5A:
Yes — if a DNSP provides a model standing offer for a relevant standard connection
service.
Unclear — for negotiated connection contracts a DNSP must use its ‘best endeavours’ to
make a negotiated connection offer, AER has the power to arbitrate where agreement
cannot be reached
Under chapter 5:
No — there are no automatic access
standards for generators of <5MW.
Access standards must be negotiated
on a case-by-case basis
Under chapter 5:
Yes — if automatic access standards are met
No — if connection applicant wants to
negotiate any of the access standards
DISTRIBUTED GENERATION IN VICTORIA 25
Table 2.6 Connecting options for distributed generation from 1 July 2012 (cont.)
Micro to small generators <100 kW Small to medium generators
100 kW to 5 MW
Medium generators
>5 MW to <30 MW
Statutory
timeframe
mandated?
Yes — for basic and standard
connection services a DNSP has
10 days to make a model
standing offer. Expedited
connection is available.
No — for negotiated connection
contracts a DNSP must use its
‘best endeavours’ to make a
negotiated connection offer
within 65 days
Under chapter 5A:
Yes — for standard connection services a DNSP has 10 days to make a model standing
offer. Expedited connection is available.
No — for negotiated connection contracts a DNSP must use its ‘best endeavours’ to make
negotiated connection offer within 65 days
Under chapter 5:
No — preliminary program of milestones agreed between parties
Cost of
connecting
Subject to AER connection
charge guidelines
Under chapter 5A: subject to AER connection charge guidelines
Under chapter 5:
fees and charges specified in
chapter 5
registration and participant fees
apply to registered generators
exempt generators (excludes
generators <5MW subject to the
Standing Exemption) must pay a
registration fee
Under chapter 5:
fees and charges specified in chapter 5
registration and participant fees apply to
registered generators
exempt generators must pay a registration
fee
Notes: a Although it is unlikely to occur in practice, micro-embedded generators will also be technically able to apply for connection under chapter 5 of the NER.
Source: Commission analysis.
26 POWER FROM THE PEOPLE: AN INQUIRY INTO DISTRIBUTED GENERATION
Table 2.7 Selling options for distributed generation in Victoria
Technology Micro to small generators Small to medium generators Medium generators
5 kW or less <100 kW 100 kW to 5 MW >5 MW to <30 MW
Solar Solar PV:
Premium FiT (closed to
new customers)
Transitional FiT for new
customers
Standard FiT Registered generators
can sell through the NEM
at spot prices
Non-market and exempt
generators can sell
through a private
agreement outside the
NEM to a local retailer or
customer located at the
same connection point
Registered generators
can sell through the NEM
at spot prices
Non-market and exempt
generators can sell
through a private
agreement outside the
NEM to a local retailer or
customer located at the
same connection point
Wind Standard FiT Standard FiT
Hydro
Biomass
Other forms of renewable
energy specified in an Order
in Council
Low emission No FiT schemes exist for these forms of technology
Registered generators can sell through the NEM at spot prices
Non-market and exempt generators can sell through a private agreement outside the NEM to a local retailer
or customer located at the same connection point
Non-renewable
Note: Distributed generators eligible to participate in a Victorian FiT scheme also have the option of purchasing electricity under national regulation (as registered generators
through the NEM, or as non-market or exempt generators through a private agreement outside the NEM to a local retailer or customer located at the same connection
point). However, it is unlikely that eligible distributed generators would choose this option in practice.
Source: Commission analysis.
DISTRIBUTED GENERATION IN VICTORIA 27
2.3 Policies for distributed generation and
renewable energy
Policies regarding distributed generation form part of a broader policy framework
designed to reduce greenhouse gas emissions and facilitate an adjustment towards a
low emissions economy. This framework comprises state and national policies, programs
and legislation. Contributing to the complexity, a number of programs overlap, and
there is little sense of overarching policy rationale.
The Commonwealth emissions trading scheme, renewable energy target (RET) and
Clean Energy Finance Corporation (CEFC) are Australia’s main policy measures for
reducing carbon emissions. The fundamental purpose of these policies is to increase the
cost of carbon-intensive energy, thus making low-carbon energy a more attractive
alternative.
The renewable energy target encourages distributed generation by providing
payments to households and other small producers of renewable energy. The emissions
trading scheme will apply to larger co-generation plants: ‘in general, a threshold of
25,000 tonnes of CO2-e will apply for determining whether a facility will be covered by
the carbon pricing mechanism’ (Commonwealth Government 2011, p. 105).
2.3.1 Commonwealth policies
Recently, the Commonwealth Government attempted to clarify its climate change
agenda with the publication of the Clean Energy Plan. The plan details the
Commonwealth’s climate change strategy as well as households’ transition to clean
energy, and investment in low-emissions technology. The Commonwealth proposed
four key drivers of a transition to clean energy:
(1) introducing a carbon price
(2) promoting innovation and investment in renewable energy
(3) encouraging energy efficiency
(4) creating opportunities in the land sector to cut pollution (Commonwealth
Government 2011, p. 17).
Carbon price
The cornerstone of the Clean Energy Plan, the carbon tax will be introduced from 1 July
2012. As legislated, the carbon price will initially be fixed at $23 per tonne, to increase
by 2.5 per cent per year in real terms (from 1 July 2012). Following this, the price will be
determined by the market through an emissions trading scheme with the government
capping the number of permits issued each year. In its Clean Energy Plan the
Commonwealth Government stated a carbon price would create incentives for
business to ‘find the cheapest and most effective way of reducing carbon pollution,
rather than relying on more costly approaches such as government regulation’.
(Commonwealth Government 2012a)
Renewable Energy Target
The RET scheme is a market-based measure to increase the share of electricity
consumption derived from renewable energy resources. The current RET supersedes the
Victorian RET and mandatory RET with a commitment that 20 per cent of Australia’s
energy will come from renewable sources by 2020. The Government predicts the
28 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
scheme will generate approximately $20 billion of investment in renewable energy by
2020 (Commonwealth Government 2011, p. 64).
Under the RET scheme, tradeable Renewable Energy Certificates (RECs) are created by
eligible renewable energy sources, based on the amount of electricity they produce or
displace. RECs are then traded (sellers and purchasers directly negotiate the price),
with electricity retailers and electricity wholesale purchasers mandated to surrender
their RECs into their holding account each year in proportion to their acquisitions of
electricity.
From 2011 the RET has been separated into two components: the Large-scale
Renewable Energy Target (LRET), and the Small-scale Renewable Energy Scheme (SRES)
(Clean Energy Regulator 2012a, p. 6).
Large-scale Renewable Energy Target
The LRET supports the deployment of renewable energy projects. The most common
examples of these are wind farms, commercial solar, and geothermal power stations.
The target also extends to energy produced by ocean waves and tides, geothermal-
aquifers, wood waste, gas waste, bagasse, black liquor and landfill gas.
In accord with the target, accredited renewable energy power stations generate
renewable large-scale generation certificates (LGCs). One LGC is equivalent to 1 MWh
of renewable energy generated above the power station’s baseline. LGCs are traded
in the LGC market with prices determined by supply and demand. Liable entities are
legally required to surrender a prescribed number of LGCs to the Office of the
Renewable Energy Regulator annually (Clean Energy Regulator 2012a, pp. 7–10).
Small-scale renewable energy scheme
The SRES was designed to support the installation of small renewable energy systems.
These are most often rooftop PV panels or solar water heaters, but can include wind
turbines, micro-hydroelectric systems and heat pump water heaters.
The scheme assists households, small businesses and community groups by reducing the
upfront cost of installing these systems. Under the SRES, small-scale technology certificates
(STCs) are generated for eligible installations. Installers can claim a set number of STCs
based on electricity generated or displaced over the system’s lifetime (where one STC is
equivalent to 1 MWh of electricity). These certificates are tradeable commodities and the
government legislates their demand by mandating liable entities surrender a prescribed
number of STCs quarterly (Clean Energy Regulator 2012a, pp. 11–14).
Solar credits
Solar credits work in conjunction with STCs. Solar credits provide additional support for
the installation of small-scale renewable energy units by increasing the number of STCs
created for eligible installations. Solar credits apply to the first 1.5kW of installed
capacity for systems connected to the main electricity grid, and up to the first 20kW of
installed capacity for off-grid systems (Clean Energy Regulator 2012a, p. 12).
Renewable energy bonus scheme
The renewable energy bonus scheme (REBS) is a rebate designed to decrease carbon
emissions and electricity costs associated with household water heaters. Under the
REBS, eligible households can claim $600 for a heat pump hot water system or $1 000 for
a solar hot water system (that replaces an electric hot water system). The
DISTRIBUTED GENERATION IN VICTORIA 29
Commonwealth Government recently announced the REBS will cease on 30 June 2012
(Rheem Australia 2012).
Clean Energy Finance Corporation
As part of its Clean Energy Plan, the Commonwealth announced the creation of, and
$10 billion investment in, the CEFC. The Government predicts transforming the Australian
energy sector will require $100 billion in renewable energy, and additional investment in
new manufacturing technologies and improving energy efficiency. The
Commonwealth Government believes it plays ‘an important role in facilitating and
coordinating investment in technologies that financial institutions may not be familiar
with’(Commonwealth Government 2012b, p. 4). The CEFC therefore, aims to leverage
private funding for renewable energy and clean technology, as well as remove barriers
to funding large-scale renewable energy projects.
The Report of the Export Review Panel clarified the CEFC’s focus. The CEFC will allocate its
funding into two streams — at least 50 per cent to renewable energy, and the remainder
to low-emissions and energy efficiency. The term ‘renewable energy’ is not prescriptive
and will adapt in response to technological evolution. The fund’s direct investment in
energy efficiency will focus on large-scale projects, while small-scale projects may be
funded indirectly if aggregated through a third party. Co-generation units are eligible for
funding as either energy efficiency projects or low-emissions technology. Although it
acknowledges demand managements is distinct from energy efficiency, the report
argues demand management lowers the cost of transitioning to clean energy by
reducing network upgrade costs and deferring investment in new generation.
Technologies associated with demand management will therefore be funded from the
energy efficiency stream. (Commonwealth Government 2012c, pp. 13–16).
2.3.2 State policies
Under the Climate Change Act 2010 (Vic) s5(i), Victoria set an emissions reduction
target of 20 per cent by 2020 (based on 2000 levels). In light of the Commonwealth’s
Clean Energy Act 2011 (Cth) and the introduction of a carbon price, a recent review
found that separate state-based targets were unnecessary (DPC 2011, p. 14). A number
of state-based renewable energy policies initiated under the Victorian Act have been
aligned with national schemes and emissions reductions targets.
Victorian Energy Efficiency Target
The most powerful State policy is the Victorian Energy Efficiency Target (VEET).
Promoted as the energy saver initiative, the VEET commenced in 2009 and is legislated
to continue in three-year phases until 2030. The purpose of the scheme is to:
reduce greenhouse gas emissions
encourage the efficient use of electricity and gas
encourage investment, employment and technology development in industries
supplying goods and services which reduce the use of electricity and gas.
Under the scheme, large energy retailers are liable to surrender a specific number of
energy efficiency certificates annually. These Victorian energy efficiency certificates
(VEECs) each represent one tonne of abated greenhouse gas. The VEECs are created
when accredited entities help consumers make energy efficiency improvements to
their homes. The energy generated through the sale of VEECs allows entities to make
special offers to consumers, thus reducing the cost of undertaking energy efficiency
improvements.
30 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
Currently, VEECs are created for around 30 prescribed energy efficiency
enhancements. These range from the installation of high efficiency hot water systems,
to draught proofing and the purchase of high efficiency appliances (ESC 2012).
Victorian Renewable Energy Target
Established under the Victorian Renewable Energy Act 2006 (Vic), the Victorian
Renewable Energy Target (VRET) aimed to encourage generation of electricity from
renewable resources. This was to be achieved through a mechanism of tradeable
renewable energy certificates, created by eligible sources of renewable energy. These
certificates were traded at market prices and surrendered by liable entities annually
(ESC 2009b). In January 2010 Victoria transitioned VRET into the expanded
Commonwealth RET (DPI 2012e).
Large-scale solar feed-in tariff
In 2010, the then Victorian Government announced an extension of the solar feed-in
tariffs to include large-scale solar generation (DPC 2010, p.15). This announcement was
never implemented.
2.4 Future trends
2.4.1 Cost trends
Cost estimates for renewable energy are based on a number of factors.
Fundamentally, they rely on learning curves (experience curves) which map the
relationship between knowledge and experience in production, and technology costs.
While these curves provide useful trendlines, a number of other factors influence costs.
These include government policy, supply and demand, and broader market dynamics.
As the bulk of renewable energy technology components are produced overseas,
international trends have the greatest impact on technology price. The following
describes some cost trend forecasts for renewable energy.
The past decade has seen a substantial increase in the installed capacity of solar PV
cells. As the industry has grown, cost has decreased along a common learning curve —
with cost reductions of approximately 22 per cent for every doubling of cumulative
capacity. Cost strayed from this curve from 2003 to 2008 due to a supply bottleneck
and market dynamics (MEI 2011, p. 2).
The Melbourne Energy Institute (MEI) argued that increased production capability,
improved supply chains and economies of scale will lead to further cost reductions. It
contended that China’s massive increase in production capability will continue to
reduce prices, while an increase in silicone production capacity will alleviate supply
constraints (MEI 2011, p. 2)(figure 2.4).
DISTRIBUTED GENERATION IN VICTORIA 31
Figure 2.4 Solar PV cost projections
Note: direct normal irradiation = 2445 kWh/m2/yr
Source: (MEI 2011, p. 2).
Wind energy capacity has also doubled every three years over the past decade.
Capital costs have generally followed the expected learning curve (MEI 2011, p. 3).
However, supply chain bottlenecks and commodity constraints slowed price
reductions. A shift to more large-scale (and automated) production has alleviated this
slow down recently.
MEI contends economies of scale and continuing industry expansion internationally will
continue to deliver modest cost reductions for wind technology. It suggests incremental
technological improvements represent a significant potential for cost reductions
(figure 2.5).
32 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
Figure 2.5 Wind power cost projections
Source: (MEI 2011, p. 3).
As concentrating solar thermal power is still a relatively new technology, sources
suggest it has a significant cost reduction potential. This cost reduction should be driven
by known technical improvements, economies of scale and industry learning (MEI 2011,
p. 4). It is expected that concentrating solar thermal power cost will follow a similar
learning rate to those observed for solar PV and wind power (figure 2.6).
Figure 2.6 Concentrating solar thermal power cost
projections
Note: direct normal irradiation = 2445 kWh/m2/yr
Source: (MEI 2011, p. 4).
DISTRIBUTED GENERATION IN VICTORIA 33
The CSIRO modelled the price of key technologies under various carbon price paths.
Figure 2.7 demonstrates the long run marginal cost of these technologies under the
highest and lowest carbon prices. The first carbon price path would lead to a 5 per
cent reduction in Australian emissions below 2000 in 2020. The second would lead to a
25 per cent reduction in Australian emissions below 2000 in 2020. Both assume Australia
meets its commitment to 20 per cent energy from renewable sources by 2020.
Figure 2.7 Long run marginal cost ($/MWh 2009) of
technologies in 2050
Notes: a pulverised fuel; b carbon capture and storage
Source: (Hayward et al. 2011, pp. 29, 32).
The most significant difference between these two scenarios is the price of black coal
pulverised fuel. Under the higher carbon price, black coal is projected to become over
50 per cent more expensive than it would be under the lowest carbon price. The CSIRO
hypothesises that the increased price of black coal would lead to a far greater
distribution of renewables than under any other carbon price (Hayward et al. 2011, p.
52).
2.4.2 Improved metering technology
By the end of 2013, the Victorian Government plans to roll-out smart meters to all Victorian
homes and businesses. Smart meters will measure and record electricity usage throughout
the day and communicate this information to electricity distributors. The intent is to provide
customers with more accurate and detailed information about their electricity use. This
increased awareness is expected to lead to reductions in electricity use.
Furthermore, the increased information smart meters provide should make it easier for
consumers to compare pricing offers from competing providers. The introduction of
smart meters is expected to lead to a number of customers switching from fixed to
flexible pricing. Making consumers aware of the large fluctuations in electricity price is
expected to produce a shift in electricity consumption as consumers seek low cost, low
demand periods.
34 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
Smart meters are also capable of measuring two-way electricity flow. Thus, households
or businesses that generate electricity will be credited for the electricity they export
back into the grid. (DPI nd)
2.5 Conclusions
Distributed generation is a relatively new part of Victoria’s electricity industry and, as
such, does not always fit neatly into Victoria’s traditional electricity market. Although it
currently accounts for only a small portion of Victoria’s energy generation,
decentralised energy capacity is increasing. Furthermore, changes to government
policy and consumer choices, together with a reduction in technology prices are
expected to encourage further installation of decentralised generators.
Some government policies encouraging distributed generation have increased its
uptake. But without substantial analysis, it is difficult to determine how successful and
cost effective these have been. Many of these policies favour specific technologies
and an observed increase in the uptake of one technology may mask a shift from other
renewable energy sources.
If the market for decentralised energy is to continue growing, it is important to consider
the current state of the market and, where possible, simplify entry to and participation
in it. Complex regulatory arrangements governing the generation and sale of electricity
are tolerable by large electricity companies; however they may not be to independent
generators. Distributed energy is diverse and many generators are managed by
households or small businesses with little knowledge of electricity regulations.
THE COMMISSION’S APPROACH 35
3 The Commission’s approach
3.1 Introduction
To address its terms of reference, the Commission has developed an analytical
approach to help structure its analysis of distributed generation and feed-in tariffs (FiTs)
and provide guidance on the relevant issues. This chapter therefore:
summarises the high level issues and problems raised by participants in submissions
and consultations, as well as those identified by the Commission through
desk-based research
categorises the issues raised according to whether they relate to connection to the
distribution network (section 3.2.1) or selling power (section 3.2.2)
develops a framework for analysing the issues further in subsequent chapters of the
draft report (section 3.3).
3.2 Issues raised by participants
Many potential issues were identified by participants and by the Commission’s
research. They range from very specific technical issues to wider concerns about the
operation and regulation of the electricity industry in Victoria and nationally. Past work
by the Commission also highlighted issues relevant to this inquiry. For example,
participants in the Commission’s 2009 inquiry into Victoria’s environmental regulations
claimed examples of barriers to investment in distributed energy generation systems
included:
complex network connection and access requirements (for example, requirements
for detailed network connection studies) — that add substantially to overall project
costs
existing market rules of electricity distribution — that do not adequately set price
signals that reflect the security and competition benefits that come from clean
energy generation
technical performance standards — that must be met for renewable generators to
be registered
existing structure of the electricity market — that discourages energy efficiency
more generally, for example, retailers have an incentive to sell more electricity,
while distributors have little incentive to encourage energy efficiency
electricity distribution businesses have been set up on the basis of centralised
electricity generation — and so resist connection by small-scale generation which is
typically located away from current power stations
planning application and approvals processes — that adds complexity, cost and
time risk (VCEC 2009, pp.375 –376).
This section summarises the issues raised across the sector in the context of this inquiry
(substantive issues and possible recommendations to deal with them are explored in
subsequent chapters). The Commission’s previous work suggested that the issues would
be wide ranging and therefore, to focus the analysis, and help structure the discussion,
the Commission has categorised the issues raised by participant into two groups:
connecting to the network
selling power from distributed generators into the grid.
36 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
Whilst the classification is intended to aid the discussion of issues, the Commission notes
that there may be some overlap between the issues and a particular issue may not fit
only into one category, for example, FiT issues may also incorporate elements of the
connection process. That said, the two group classification is consistent with the views
of many inquiry participants. For example, Exigency argued that:
The key barriers to establishing distributed generation could be simply
summarised as revenue certainty and grid connection on reasonable terms.
(sub. 4, p. 3)
In summarising issues raised by participants, the Commission has also identified, where
possible and relevant, where issues differ according to size of the market participant
and location.
3.2.1 Connecting to the network
The most commonly raised immediate barrier to greater adoption of medium-scale
distributed energy is the process for connecting these systems into the electricity
network. There are various technical standards to be met and contractual
arrangements that must be in place before distributed generation, such as a co-
generation or tri-generation system, can be connected to a Distribution Network
Service Provider’s (DNSP) network. These are required to ensure the DNSPs meet their
safety and reliability of supply obligations.
Connection costs, performance standards for distributed generators, conditions and
the negotiation timeframes can have a major impact on the financial viability of
embedded generation projects. These costs are project specific, depending on various
characteristics and location of the proposed distributed generation. In addition, local
land planning rules may play a part in limiting embedded generation projects.
The Commission has structured the discussion by identifying the critical issues raised by
participants at each stage of considering whether, and how, to connect distributed
generation. This involves consideration of:
information on where distributed generation is needed
the right to connect
costs of connection
regulatory issues
technical issues.
Information and network plans
Participants argued that there was a lack of public and accessible information on
where distributed generation was needed in the network and where there were
network constraints on adding further distributed generation.
The benefit of distributed generation in deferring network costs increases if it is installed
in areas where the network is constrained or close to capacity. However, some
participants argued that there was insufficient information about the location of
network constraints. In addition, there are some parts of the network where increasing
distributed generation is impractical without additional investment because it would
contribute to already high fault levels.
THE COMMISSION’S APPROACH 37
Making this information more widely available may encourage more targeted
proposals for the installation of distributed generation. Proponents of distributed
generation projects can more readily identify those locations where connecting further
distributed generation is likely to be difficult. Proposals may also be more likely to
proceed as market participants are more aware of and, therefore, able to share the
benefits of the savings from deferred network augmentation. Retailers and network
owners would therefore face positive incentives to encourage and accept distributed
generation connection.
Right to connect
Some participants argued that there are no incentives for distributors to connect
distributed generation to the network. In the Clean Energy Council’s (CEC) view:
There is presently no incentive for a DNSP to process a connection
application; rather it is an obligation of the DNSP’s Distribution Licence. In
conjunction the introduction of a generator has the effect of reducing the
DNSP’s revenue from energy delivered, whilst increasing complexity (and
hence cost) of their network assets. (sub. 76, p. 6)
This apparent lack of incentive to connect distributed generation to the network has
lead a number of participants to suggest that there should be an automatic right to
connect to the network. For example, WattSource argued that:
It [the right to connect] should be automatic for every person, household and
business (no negotiations, no approvals, no special contracts) so power
companies have access to renewable energy at competitive wholesale prices
from small, medium and large contributors around the nation. (sub. 2, p. 1)
The Property Council of Australia (PCA) also argued for automatic connection rights for
distributed generation (ClimateWorks et al. 2011).
The issue is complicated because some types of distributed generation already have
an automatic right of connection. For example, smaller PV solar systems have an
automatic right to connect through both the standard and transitional feed-in tariff
schemes. However, while there is a right to connect a number of participants noted
that the process can be cumbersome and time consuming because of the paper work
and number of agents involved in the transaction. The Energy and Water Ombudsman
Victoria noted, for example, that:
Delays in the application of FiTs sometimes occurred because customers
did not know that several forms needed to be completed. (sub. 48, p. 2)
Others participants, such as Jemena (sub. 79), suggested that connection should be
subject to consideration of any technical and commercial issues and may therefore not
necessarily be automatic. In some cases it may be appropriate to refuse connection of
distributed generation. Technical issues are discussed further later in this chapter.
Costs of connection
The costs incurred in connecting to the distribution network were cited by many
participants as a barrier to further distributed generation. These costs include the direct
financial cost involved in connecting to the network and the time taken to complete
the process — but most of the participant comments focused on the process and on
the time taken from requesting connection to it being done.
38 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
Participants suggested that the time taken to negotiate and affect a connection for a
distributed generation unit varied from a few months to several years. In addition, in
some cases the negotiations were not completed and connection did not occur.
The problem is compounded by different distributors having different requirements and
processes to connect distributed generation. It was argued that the different processes
did not reflect technical or locational issues – for example, Ironbark Sustainability
(sub. 50, p. 9).
Groups such as the PCA have claimed that, despite the national regulatory changes,
barriers to connecting small- to medium-scale distributed energy will persist
(ClimateWorks et al. 2011, p. 11). In particular, while the proposed national changes
establish automatic access standards for micro generators, other small to medium
generators do not have similar rights (ClimateWorks et al. 2011, p. 36). These
considerations have led the PCA and some other bodies to propose a rule change to
the AEMC to address these barriers.
In response to these issues a number of participants, for example, the Moreland Energy
Foundation (sub. 75), have argued in favour of standardised and predetermined
processes to ensure the timely and cost effective connection of distributed generation
to the network. The PCA advocated a national, standardised connection process with
automatic connection rights and practical district level licensing frameworks
(ClimateWorks et al. 2011), and has made a proposal for a draft rule change to address
this issue (chapter 4).
In terms of the direct financial and administrative costs, there were fewer participant
comments. However, Erwin Boermans of Comfortid.com (sub. 1, p. 1) suggested that a
major barrier to connecting renewable power sources to the grid was the ‘extreme
connection fees charged by grid monopolist’ owners and the ‘very high priced
generator-permits for medium or large scale solar’. The cost of meeting technical
requirements as a condition of connection are discussed in the later section on
technical issues.
Regulatory issues
The industry is subject to extensive regulation, and many participants suggested that
the existing regulatory framework can act as a barrier to connecting distributed
generation.
Many of the regulatory issues relate to the requirement to meet technical standards
(discussed in the following section) but some have claimed that additional
requirements have been added by retailers and distributors. For example, Ironbark
Sustainability argued that:
In this context, incentives for efficient DG [distributed generation] may be
viewed as a secondary objective of regulation, with the localised nature of
DG posing challenges for the regulations. The regulations are often not
conducive to ease of installation of DG and provide substantial market
impediments through metering, connection and pricing requirements. DBs
are obliged to meet minimum technical standards for connection, detailed
in the Victorian Electricity Distribution Code, however they can also add
additional requirements effectively resulting in no standard process for
gaining approval to connect cogeneration systems to the electrical
network across the network providers. (sub. 50, p. 9)
The regulation of network investment has also been raised as an issue. It has been
argued that there is a lack of incentive for networks to connect distributed generation.
THE COMMISSION’S APPROACH 39
In particular, it is claimed that the current regulatory environment rewards investment in
network assets rather than in distributed generation which reduces the need for such
investment (CEC, sub. 76). This is consistent with the Australian Energy Regulator’s (AER)
more general views that there is a systemic bias towards inflated expenditure estimates,
disincentives for efficient investment and process biases in favour of the service provider
that can lead to excessive payment by users (AER 2011e).
Without efficient incentives for investment generally, DNSPs will have weak incentives
for efficient investment in distributed generation. Improving the incentives for DNSPs
more broadly would have implications for electricity prices and the broader economy
beyond distributed generation.
Other regulatory issues including planning concerns, especially around the construction
of new distributed generation in particular areas, were also raised in submissions. The
construction of new wind farms has been one such issue in Victoria. Union Fenosa Wind
Australia (UFWA) observed that:
The Victorian government and councils should remove or reduce planning
laws that are particularly onerous, and are not based on economic,
scientific or environmental criteria. The recent changes to the Victorian
planning laws for utility scale wind farms that apply noise, setback and right
of veto powers that are significantly above criteria for all other
developments are not in the interests of the Victorian community. UFWA
respects the right of the Victorian government to apply rigid objective
criteria for development but the same criteria should be consistently
applied to all developments i.e. the criteria for noise, visual amenity and
setback should apply to all developments including small and large scale
generation, and others such as coal mines, gas wells, sewerage facilities,
piggeries, and farming facilities that have far more relaxed planning
requirements. (sub. 71, p. 4)
Other local government regulations can also be a barrier to the installation of
distributed generation. For example the National Electrical and Communications
Association noted that:
In some cases, such as those residents who live in a heritage overlay area,
they are required to seek planning approval from their local Council to
install a solar PV system on their premises. This has created another barrier to
the installation of distributed energy. (sub. 37, p. 5)
Regulatory issues also arise when distributed generators are required to be licenced as
generators. In Victoria the Electricity Industry Act 2000 (Vic) (EI Act) regulates the
Victorian electricity supply industry. The EI Act supplements the national electricity
regulatory framework regulating various matters, including providing for, among other
things, a licensing regime for people who generate electricity for supply or sale, or the
transmission, distribution, supply or sale of electricity. The Essential Services Commission
administers the provisions of the EI Act and licensing of generators. The legal framework
and process is described in more detail in appendix B.
Technical issues
Technical issues need to be addressed when considering whether to connect
additional distributed generation to the network. These arise because the connection
of distributed generation can impact on the reliability and performance of the
electricity network. Jemena (JEN) stated that:
40 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
… connection of medium and large scale rotating equipment to the
distribution network generally contributes to the fault level energy that flows
into the network when a localised network fault occurs. Distribution
networks are designed with a maximum fault level limit. Exceeding the
network’s designed fault level limit will increase the risk to the reliability and
safety of the distribution system.
The Electricity Distribution Code issued by the Essential Services Commission
of Victoria requires that embedded generators (DG) design and operate
their plant so as not to cause fault levels on the distribution network to
increase above specified levels. Additionally, the NER [National Electricity
Rules] advises fault levels which should not be exceeded for
sub-transmission systems. While supportive of renewable energy initiatives,
JEN by necessity has a stronger commitment to safety and reliability of
electricity supply.
Accordingly, JEN must have regard for maintaining fault levels within safe
limits that are consistent with the provision of a reliable and secure supply of
electricity to their customers. (sub. 79, p. 7)
Similarly, the Energy Supply Association of Australia argued that:
… the process to connect to a Distribution Network Service Provider’s
(DNSP) network is to ensure the safety and reliability of supply. This should
remain the primary concern of a regulatory process. Rather than being a
barrier to distributed generation, this process is essential to maintain the
integrity of the system. (sub. 74, p. 3)
An alternative view expressed by some is that technical issues are overstated and used
as a barrier to connect distributed generation. For example, Ironbark Sustainability
observed that:
In some cases DB’s [distribution businesses] require the installation of
prohibitively expensive equipment in the distribution network to
accommodate increased fault levels. (sub. 50, p. 9)
It may not always be clear to the proponent of the distributed generation whether
these requirements are justified. Professor Alan Pears noted the asymmetrical treatment
of electricity consumers and those generating electricity, and argued that:
… any small consumer is free to install energy consuming equipment that
causes significant impacts on local power quality (such as low Power Factor
equipment), increases pressure on local network capacity, creates
harmonics or causes power surges. Dealing with these kinds of problems is
seen as the ‘normal’ business of the electricity supply industry, and the costs
of doing so are smeared across all customers. Yet, if similar impacts are
caused by a small distributed generator, the electricity supply industry can
insist on expensive remedies. (sub. 44, p. 2)
The issue that the Commission must address is the extent to which the technical
requirements are justified on the grounds of safety and network stability or are being
used as an unnecessary barrier to the introduction of distributed generation. In addition,
the Commission must consider how the necessary technical (safety and network
stability) requirements can be addressed at least cost to proponents of distributed
generation projects.
THE COMMISSION’S APPROACH 41
3.2.2 Selling electricity
Issues around selling electricity raised by participants often focused on the price paid
and the way it was calculated. However, participants also raised other issues, which are
discussed below and expanded on in chapters 5 and 6.
Right to sell
A number of participants, especially households with solar PV installations, argued that
there should be an automatic right to sell their excess power and that retailers should
be obliged to accept such power. In effect this is related to the right to connect issue
raised in the previous section.
Prices
The price paid for generated and/or exported electricity is a key concern for many
participants in this inquiry. The prices paid per unit of energy for the electricity sold by
distributed generators are referred to as FiTs. Those wanting to encourage distributed
generation, often solar, argued for higher FiTs, while others argued for unregulated or
market-based tariffs. Still others argue in favour of a ‘fair and reasonable’ tariff that is
sustainable, but definitions of ‘fair and reasonable’ differed.
The principal original objectives for ‘premium’ FiTs were to encourage the uptake of
zero emission generation to help reduce greenhouse gas emissions and to encourage
industry development. For example, Ceramic Fuel Cells Limited argued that:
Where feed-in tariffs have become clouded is that the design and rate of
the tariff have been set to achieve other objectives, notably to support the
solar PV industry as a form of industry development (and as a subsidiary
goal, to reduce greenhouse gas emissions). (sub. 41, p. 10)
Others, for example Jill Dumsday (sub. 3), argued that a premium FiT was necessary to
ensure that the capital cost of installing solar panels incurred by households was paid
back within a reasonable period. A shorter payback period was regarded as a major
incentive to install solar panels.
In contrast to the view of many participants that FiTs are meant to encourage the
uptake of low emissions generation technology, the Alternative Technology Association
(sub. 73, p. 1) argued that it is a ‘misconception that the objective of FiT policy is
primarily one associated with the delivery of emissions reduction’, contending:
… the primary objective of a well designed and structured FiT mechanism is
to correct market failure — and to capture costs benefits and other
potential benefits (e.g. carbon) of a particular policy choice, where the
market alone cannot realise those benefits, or indeed is actively preventing
them from occurring. (sub. 73, p. 2)
Similarly, Exigency argued that:
Any change to feed-in tariff structures should address free-rider issues,
including the use of the distribution network as a back-up supply. (sub. 4, p.2)
If there are market failures then some participants considered that the case for
government intervention and the setting of regulated FiTs is strengthened. Jemena
argued that:
42 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
… regulated feed-in tariffs are not an efficient way of achieving the FiT
objectives. However, JEN would support a level of regulation if it can be
demonstrated that competitive prices are not being offered or are below
the value of energy in the market … (sub. 79, pp.5-6)
Regardless of the justification used, if FiTs are to be regulated, submissions have
suggested a number of different methodologies that could be used to calculate the
FiT. Some of the more commonly suggested approaches include:
economic/market-based price
payment of a ‘fair and reasonable price’
paying a ‘one for one’ price based on the retail price of electricity
payment based on the estimated return needed to payback investment in
distributed generation technology
payment of a premium tariff.
Other issues raised in submissions in relation to regulated FiTs include:
Should they be calculated on a gross or net basis?
Should FiTs be calculated in such a way as to treat generators of a different size or
type differently?
Over what time frame should regulated FiTs be held constant to provide certainty
for investment decision-making?
On the other hand other participants have argued for market-based FiTs, for example
AGL argued that:
It is critical that the tariff paid by retailers to embedded and distributed
generators be determined by the market. Regulating such a tariff would be
a significant retrograde step in relation to microeconomic reform of
Australia’s energy markets. (sub. 72, p. 1)
Market determined FiTs may still need to be assessed to ensure that they are ‘fair and
reasonable’ and there may need to be regulation to ensure that, especially smaller
generators, are covered by adequate consumer protection.
Billing and administrative arrangements
Billing and administrative arrangements are of particular concern to smaller distributed
generators, such as households with solar PV panels. Concerns were raised regarding
the amount of paper work required to enter into an agreement with an electricity
retailer and problems with delays and lost paperwork. How distributed generators were
paid for the power they exported was also a concern for some households.
In relation to the paper work burden imposed on those wanting to set up distributed
generation, AGL noted that:
The current Victorian feed-in tariff schemes place an unnecessary level of
administrative burden on retailers and customers. (sub. 72, p. 4)
The Energy and Water Ombudsman Victoria noted that on the basis of complaints
received one of the main consumer concerns related to:
THE COMMISSION’S APPROACH 43
Incorrect or confusing information about the solar process, or about the
billing of FiTs [which] had often been provided to customers by their
electricity retailer, distributor or solar installer. (sub. 48, p. 2)
In relation to a larger co-generation project, BRT Consulting stated that:
The administration charges are greater than the off peak feed in tariff and
therefore costs to sell energy. (sub. 8, p. 2)
Another issue is how those producing distributed generation are paid for their power
exported into the grid. This is an issue of particular concern to smaller household
producers who may be concerned about whether they are paid directly for their
power or offered a credit on their account. Depending on their personal
circumstances, some consumer may prefer payments, while others may prefer an
amount to be credited to their electricity account.
Other conditions or constraints
Other issues related to selling electricity produced by distributed generation include:
scope to aggregate smaller generators to enhance seller bargaining power and to
provide more scope to argue for compensation for delaying network
enhancement
the complexities around to whom the distributed generator can sell its power. For
example, a distributed generator cannot sell directly to a neighbour without
obtaining a retail licence or meeting the associated consumer protection
regulations (and incurring the associated costs of that application) (ClimateWorks
et al. 2011, p.30)
the regulation that guarantees retail contestability for tenants has been an issue for
larger distributed generation projects, including co-generation and tri-generation.
3.3 A framework for analysis
The terms of reference direct the Commission to:
assess the design, efficiency, effectiveness and future of FiT schemes and
recommend whether existing FiTs should be continued, amended or discontinued
identify barriers to connecting distributed renewable and low-emission technologies
into the distribution system.
To analyse the issues raised by participants and respond to its terms of reference, the
Commission has developed an analytical framework and a set of principles to help
guide policy selection. The Commission’s framework is built around a set of questions
and issues which guide its analysis:
What are the objectives of policies impacting on distributed generation, how have
they changed over time and how do they relate to the overall objectives of the
national electricity market?
What are the barriers to distributed generation and efficient and effective FiTs? In
the Commission’s view well-functioning markets offer the most efficient outcomes
but markets can fail and this may provide scope for government policy
interventions.
The terms of reference also specify that the Commission is to examine barriers to
renewable and low-emission technologies. The terms of reference does not define
44 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
‘low-emission’ technologies. The Commission notes that the recently completed Clean
Energy Finance Corporation Expert Review has recommended that the eligibility for low
emissions technology be defined as technologies which produce 50 per cent, or less, of
the emissions intensity of electricity generation in Australia (Commonwealth
Government 2012c, p.15). The Commission is considering adopting this definition of ‘low
emission’. This issue is discussed further in chapter 6, and the Commission is seeking more
information on whether this is an appropriate definition.
In the following section this framework is distilled into a set of criteria that is used to
analyse the barriers to distributed generation and FiTs in subsequent chapters.
3.3.1 What are the policy objectives?
Currently, the policy objectives around distributed generation are not clear and
appear to have changed over time. The diversity of views on the role of FiTs discussed in
section 3.2.2 illustrates the lack of clarity around objectives. It is therefore not clear
whether distributed generation policies have achieved their current objectives
effectively or whether those objectives are appropriate going forward. The Commission
also notes that distributed generation is part of the National Electricity Market. Many
consider (CSIRO 2009) that the importance of distributed generation in that market will,
and should, grow. The objectives of distributed generation policy therefore also need to
be consistent with the overall objectives of the National Electricity Market.
There is a number of objectives assigned to encouraging distributed generation and
the use of FiTs. In chapter 5 the historical objectives of FiTs are discussed and their
continued validity analysed. This analysis shows that the main claimed objectives of FiTs
are to:
reduce greenhouse gas emissions, including assisting households to make a
personal contribution to environmental outcomes and reducing greenhouse gas
emissions
support innovation and the development of a new industry by stimulating the
demand for investing in distributed generation by more efficiently allocating risks,
including risks to customers and energy market risks to small-scale solar PV investors
ensure fair payments for electricity from small-scale solar PV investments.
These objectives have also historically applied to distributed generation more generally.
In the Commission’s view a number of these objectives appear to be based on
previously identified issues or problems that are no longer relevant to FiT policy
(chapter 5). In particular:
reducing greenhouse gas emissions — this objective has been overtaken by the
Commonwealth’s carbon pricing policy and other greenhouse gas reduction
initiatives
industry support — where FiTs do not cover all technologies, the outcome is likely to
be a highly distortionary policy and stifle innovation in low-emission and other
renewable distributed generation technologies.
The objective of ensuring fair payments for electricity — which reflect the value of
distributed generation — is an important objective for future FiT arrangements and is
considered further in later chapters.
The Commission considers that an efficient electricity system should take account of
the full value of distributed generation and this value should be reflected in price signals
THE COMMISSION’S APPROACH 45
and other incentives faced by market participants. There are three elements of value
from distributed generation (chapter 6):
the energy value — which is the value of the energy delivered by the distributed
generator. This is a price per unit of energy delivered and would be time and
location specific
the network value — which is the value of (net) avoided capital spending to
augment the network (this value is time and location specific)
externalities — the value of greenhouse gas reductions (which with the carbon tax
will be reflected in the market determined energy value).
The Commission considers that the objective of ensuring fair, market determined
payments for electricity would encourage efficiency in the development and use of
the electricity system. This means that distributed generation polices should focus on
ensuring that there is investment in distributed generation when it is the most efficient
option to enhance the electricity system. Such an objective does not preclude the
growth of distribution generation technologies or those technologies playing an
important part in the adjustment to a low carbon economy. Rather it would mean that
distributed generation polices would be more sustainable and predictable. The
incentives to use distributed generation to reduce greenhouse gas emissions would be
strongest when distributed generation is the most cost-effective way of reducing
emissions. The CSIRO concludes that distributed generation:
… has a bridging role in transitioning from the current coal dominated
centralised system while large-scale renewable and near zero emission CCS
[carbon capture and storage] technologies are either too expensive or
unproven. (CSIRO 2009, p.353)
The resulting policies would be fairer, as they would also not impose higher electricity
prices on those who do not, or cannot afford to, install distributed generation.
The Commission considers that distributed generation polices should be designed and
implemented in such a way as to achieve this efficiency objective:
efficiently
effectively
in an equitable manner
as administratively simple as possible
in a manner which fits well with existing institutional arrangements and national
policy directions.
Subsequent chapters of this draft report analyse distributed generation polices and FiTs
and make recommendations to achieve this outcome.
The Commission considers its approach in this draft report is fully consistent with the
objectives of the national electricity market, which are to:
To promote efficient investment in, and efficient operation and use of,
electricity services for the long term interests of consumers of electricity with
respect to –
a) price, quality, safety, reliability, and security of supply of electricity; and
46 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
b) the reliability, safety and security of the national electricity system.
(National Electricity Law s 7)
In the context of this market efficiency objective, the Commission’s approach is then to
consider what are the barriers and market failures that may distort choices and
investment in the most efficient distributed generation technology. This consideration
also includes the equity implications of distributed generation polices.
3.3.2 Barriers to distributed generation
The following analysis examines the barriers to distributed generation achieving its
potential within the national electricity market and the role FiTs should play in the policy
framework. This analysis explicitly addresses the terms of reference relating to the
identification of barriers to distributed generation and the design, efficiency and
effectiveness of FiT schemes.
In some cases the perceived barriers to distributed generation are driven by the cost of
distributed generation, and reflect the fact that distributed generation may not be best
option in all circumstances. In other cases, the barriers to distributed generation may
relate to the industry’s:
regulation and market structure
market conditions.
Regulation and market structure
The structure of Victoria’s electricity market has been determined, at least in part, by
the current regulatory structure and reflects long standing investments in infrastructure.
The industry is structurally separated (retailers, distributors and network service providers)
and some parts are highly regulated while others are more competitive. The resulting
arrangements were designed to facilitate competition in the broader electricity
industry, but they may have led to misalignments of incentives between distributed
energy proponents, distribution businesses and retail businesses. There are also
significant disparities in market power. This structure, and resulting incentives, may make
responding to new entry of distributed generation difficult.
Uncertainty caused by frequently changing regulation has also created barriers to
distributed generation. Individuals and businesses wanting to install distributed
generation want a degree of certainty so that they can make an informed investment
decision. For example, Ceramic Fuel Cells Limited noted that to be effective, distributed
generation policies, and in particular FiTs need:
… to give certainty over the long term, rather than be susceptible to ‘boom
and bust’ cycles. (sub. 41, p. 11)
Market conditions
The Commission’s starting point is that well-functioning competitive markets are the best
means of achieving efficient outcomes that ultimately protect the long-term interests of
consumers (and society more generally) (box 3.1).
THE COMMISSION’S APPROACH 47
Box 3.1 Market-based prices
Market-based price signals and the actions of market participants will result in an
efficient take up of distributed generation and development of the electricity
network. In such circumstances the case for government intervention is weak. In
competitive markets potential sellers of electricity will negotiate the conditions and
price under which their exported electricity will be purchased. Those considering
installing distributed generation will be able to assess the benefits (energy costs
saved and returns from selling excess electricity) and make an informed decision as
to the desirability of installing generation capacity. The buyers will offer a price
which reflects the value of the electricity to them. If the market is well-functioning
the price offered will be economically efficient. Price signals will guide investment in
generation and the development of network assets.
Source: Commission analysis.
A number of participants argued that the electricity market is sufficiently well-functioning
for such an efficient price to be the outcome. For example, AGL argued that:
It is critical that the tariff paid by retailers to embedded and distributed
generators be determined by the market. Regulating such a tariff would be
a significant retrograde step in relation to microeconomic reform of
Australia’s energy markets. (sub. 72, p. 1)
In addition, AGL suggest that one of the reasons for concluding that the rate should be
market-determined is because:
AGL believes that no market failure has been identified which justifies
additional mandated feed-in tariff policies being introduced or maintained.
(sub. 72, p. 2)
However, there is evidence of disparities in market power among market participants,
including local monopoly in distribution businesses and the limited capacity to pass
through from distribution businesses to the retail markets any price signals reflecting
scarcity of localised network capacity.
It is argued by some participants, that the evidence that markets are functioning
effectively in Victoria includes that some retailers currently offer FiTs higher than the
regulated rates. Others, however, contest this view (chapter 5).
In a competitive market it would be expected that different technologies would be
treated neutrally. Technology neutrality with differences in policy or approach (only
justified on technical or other appropriate grounds) would help support efficient market
outcomes by ensuring that the relative merits of all technologies are considered and no
single approach is advantaged over another.
A number of participants supported this view, for example, the Energy Supply
Association of Australia (ESAA) argued that as a:
… technology neutral association, esaa considers that it would be
preferable not to specify eligible technologies. This will allow for innovation
and new technologies to enter the marketplace. (sub. 74, p. 2)
48 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
3.3.3 How might markets fail to achieve efficient outcomes?
Central to the Commission’s analysis of why distributed generation may not be
appropriately incorporated into Victoria’s electricity sectors is the identification of
market failures or other barriers that prevent the market signals faced by participants
from resulting in an efficient structure.
Efficient outcomes are predicated on the market functioning effectively. If there are
any ‘market failures’, market outcomes may not be efficient and there may be scope
for government intervention. That said, even in the presence of market failures it is
necessary to consider whether the cost of intervention outweighs the benefits. The
existence of market failure is not in itself sufficient to justify government intervention and
regulation.
Participants have suggested there are market failures that justify policies to encourage
distributed generation and the regulation of FiTs. For example, the Dandenong Ranges
Renewable Energy Association argued that:
… we believe this inquiry should not recommend amending current feed-in
tariffs in a way which requires retailers to offer a feed in tariff but does not
regulate the actual price paid. Instead we think that the system should be
regulated to avoid market failures and ensure a set premium is paid for
green power. (sub. 10, p. 2)
Similarly, Moreland Energy Foundation Limited argued that regulated FiTs were
necessary to:
Address market failures that prevent distributed generators from receiving
the full benefits of the electricity they produce, and from having certainty
about receiving these full benefits over the life of the system. (sub. 75, p. 5)
Participants have cited apparent failures in the current electricity market which may
justify regulating FiTs. For example Ceramic Fuel Cells Limited argued that:
In our view the problem that feed-in tariffs should address, in simple terms, is
that ordinary homes and businesses who have excess electricity to sell
cannot efficiently participate in the energy market. There are many reasons
for this, which are well known from other markets — high transaction costs,
imperfect and asymmetric market information, imbalance of market
position etc. This is the core market reality that a feed-in tariff is designed to
address — and a well designed feed in tariff is a very effective tool to
address this problem. (sub. 41, p. 10)
The Commission considers that the market failures relevant to this inquiry include:
existence and opportunities, and incentives to exploit market power;
when a party to a transaction has incomplete information (information asymmetries
or deficiencies); or
when the parties to a transaction do not account for the full effects of their actions
on others (spillovers or externalities)
high transactions costs where it is difficult for dispersed parties to combine to
negotiate joint benefits.
THE COMMISSION’S APPROACH 49
Market power concerns
Market outcomes will not be efficient if one or more of the participants has market
power which he or she is able to exercise during price negotiations. An electricity
service provider (such as a network operator) with market power is able to charge a
higher price for the services it sells (compared with the price which would have been
offered in a competitive market) to the detriment of the buyer of those services. It also
leads to an inefficient use of resources between generators, distributed generation, and
transmission and distribution infrastructure.
Several participants expressed concern that some market participants did have market
power and that regulation of FiTs and connection was therefore warranted. For
example, the Australian Solar Round Table noted that one of the problems that FiTs are
intended to address is that:
The market for power from distributed and embedded generation is
distorted by an imbalance of market power. A small number of players
dominate the market. (sub. 56, p. 9)
Similarly, Professor Alan Pears also noted that the network operators have market power
and that this can distort the role of distributed generation (sub. 44, p. 2).
The degree of potential market power available to monopoly distribution businesses is
likely to be much higher than that available to retailers who operate in a more
competitive market and where entry by new businesses is possible. However, it is also
the case that some retailers (although not all) also own generation assets. This may
affect their incentives to encourage more distributed generation as it may represent
increasing the number of competitors to their own generation businesses.
To address market power concerns some submissions have argued in favour of
mandated FiTs, not just general guidance on what might be a ‘fair and reasonable’ FiT.
Incomplete information
Markets work best when those participating in the market have sufficient information to
make decisions that maximise their welfare and best reflect their individual
circumstances. Information is important in helping to make decisions that may have
long-term implications for those considering whether to invest in a distributed
generation unit.
Moreland Energy Foundation Limited argued that there is a need for certainty and that:
Without a feed-in tariff, a person or business considering investment in a
distributed energy system cannot be certain that they will receive the true
value of the electricity produced by their system over the life of the system.
A feed-in tariff can provide this certainty, with appropriate mechanisms for
adjustment of the feed-in tariff rate. (sub. 75, p. 3)
There are also concerns that the availability of information and ability to understand
and use it may vary according to the size and sophistication of the entity installing the
distributed generation unit. For example, Moreland Energy Foundation Limited argued
that:
Nor is there any guarantee without regulation that the characteristics of
feed-in tariffs provided voluntarily by market participants will be useable by
50 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
the significantly smaller, less sophisticated, less knowledgeable and less well-
resourced distributed generation owners. (sub. 75, p. 8)
Information is also required to ensure an efficient connection process for distributed
generation. Distributed generation proponents argue they need access to information
on where the distributed generation is most highly valued and the nature of any
network constraints that may impact on the cost and viability of the project.
Lack of information does not necessarily justify government intervention in the
operation of the market. In some cases, information concerns can be overcome by
private intermediaries, for example, in the case of financial services, loan and insurance
comparison services provide information to consumers to help them make informed
decisions.
Spillovers and externalities
Spillovers and externalities occur when the activities of one agent in the market affect
another in ways that are not taken into account by the market. For example, in the
absence of any tax on pollution a producer will not take into account the cost of
pollution in production decisions.
Ironbark Sustainability identify one of the market failures resulting in a barrier to
distributed generation is that:
Savings related to avoiding upgrades to the grid (ie, DG systems may not
require investment in poles and wires) are not captured in the current
regulatory environments, meaning DG providers accrue the risks but none
of the savings. (sub. 50, p. 12)
It has also been argued that more distributed generation benefits electricity users by
reducing reliance on a small number of larger generators. It is argued that continuity of
electricity supply can be vulnerable to the failure of a large generator. Ironbark
Sustainability argued that a benefit of distributed generation is that:
DG provides the opportunity to reduce the negative consequences from
potential outages of escalations in energy costs. A large number of smaller
units using varied energy sources represents a lower output at risk per
installation, as opposed to outages at centralised plants that have massive
output at risk, for example, through accident, terrorism, maintenance.
(sub. 50, p. 10)
Reduced network losses is another benefit of distributed generation. Energy is lost from
the system as electricity is transported over long distance in the transmission network
and these losses are averaged over customers in a particular area. It is argued that by
locating generation capacity closer to the electricity user these losses are reduced. For
example, the CSIRO also argued that distributed energy generation improves system
efficiency due to:
… the reduction of network losses by generating energy close to the point
of consumption, or improving the utilisation of a fuel by capturing more of
the energy available as occurs through co-generation and tri-generation.
(CSIRO 2009, p. 18)
Overall, the existence of spillovers and externalities and resulting market failures may
justify additional support for distributed generation. For example, United Energy stated
that:
THE COMMISSION’S APPROACH 51
Incentive schemes are required to encourage distributed generation
because in general distributed generators don’t receive a financial reward
that reflects the full benefits they provide to the network and wider
community. (sub. 77, p. 1)
High transactions costs
The costs of negotiating individual contracts and arrangements can be a problem for
households and owners of smaller distributed generation units. Transaction costs can
also affect the willingness of retailers and distributors to connect small-scale distributed
generation if they have to deal with a large number of potentially diverse and
geographically spread suppliers. These costs may mean that transactions which would
have been mutually beneficial to all parties, including the community as a whole do
not take place — representing a market failure.
Regulating FiTs and the terms and conditions of connection and supply can reduce the
transactions costs faced by both the seller and buyer of electricity. This point was
recognised by the Australian Solar Round Table who argued that FiTs address a number
of problems including ‘transaction costs of the individual transactions’ (sub. 56, p. 9).
During consultations, John Daly of the Grattan Institute noted another form of
transactions costs relating to the acceptance of new technologies. He argued that
there is a ‘first mover’ disadvantage for those trying to introduce new generation
technologies. The transactions costs involved in getting new technologies accepted
within the system are high but are not ongoing. The first mover incurs these costs but
later entrants using the same technology do not.
The impact of addressing market failures
In the Commission’s view, to the extent that these market failures are valid, addressing
them, when the benefits of intervention outweigh the costs, and encouraging a more
competitive market, make decisions on connection of distributed generation and
network development more efficient. Dealing with market failures would involve:
embedding efficient price signals — this is complex and involves sending efficient
signals to all participants in the market and ensuring that the value of distributed
generation is reflected in the actions of market players. The value of distributed
generation differs among industry participants:
– to retailers — the value of distributed generation is their savings from buying less
electricity on the wholesale market. This value should be reflected in the price
of electricity per unit exported. Competitive prices should reflect the
opportunity cost of electricity generated by different types of generation and
not subsidise or favour any particular technology
– to distributors — the value of distributed generation results from the value of
any capital expenditure to augment the network which is avoided as a result of
distributed generation. But, must also include the cost of any capital
enhancement necessary for the connection of distributed generation. An issue
with current arrangements is that the value to the distributor is not passed back
to retailers and therefore customers and not reflected in their decision to install
distributed generation
enhancing contestability and competition through
– freeing market entry
– informing business and consumer decisions
52 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
– improving the efficiency of administration and decision making processes
– allowing the most efficient technologies and scale to emerge
increasing predictability for business and consumers in the long run.
It is achieving this outcome that is the focus of the Commission’s analysis and draft
recommendations in the following chapters. However, the Commission is cognisant that
it may not be possible to recommend a perfectly efficient and equitable FiT
methodology even if these market failures are addressed. ACIL Tasman, in its
assessment of different methodologies for calculating FiTs concluded that:
In summary, none of the methodologies for calculating FiTs satisfy the
efficiency or effectiveness criteria and all have adverse equity implications.
(ACIL Tasman 2012, p. 71)
The Commission’s task is therefore to develop recommendations that achieve the best
possible outcome given Victoria’s circumstances. The draft recommendations in
chapters 4 and 6 reflect the Commission’s current views, and it seeks views and
information from interested parties on them.
3.3.4 Equity considerations
There are conflicting views about the impact of FiTs on public welfare, which is a matter
the Commission is required to consider under its Order in Council.
A number of submissions to the inquiry and some academic papers suggest that
schemes such as the Premium FiT (PFiT), which set a FiT price above competitive market
levels, result in regressive outcomes. For example Nelson, Simshauser and Kelley (2011)
argue the extra costs associated with premium FiT schemes result in above market costs
that are passed on to all electricity customers in the form of higher electricity prices. In
effect, distributed generators are cross subsidised by other electricity consumers.
Furthermore, the authors argue that this is regressive because it is primarily higher
income households that are able to afford distributed energy systems and therefore
capture the benefits, while lower income consumers, who cannot afford these systems,
face higher costs. This is also facilitated by the restriction to only allow the various
distributed generator rebates to apply to those consumers who hold the title deed to
property and therefore less affluent consumers (such as renters) are unable to access
the benefits. Nelson, Simshauser and Kelley (2011) also present some quantitative
evidence, based on the NSW FiT schemes and AGL data, to support the theory.
However, Grosche and Schroder’s (2011) evaluation of the German FiT schemes
conclude that while FiTs are regressive, the redistributive effects are quantitatively small.
The Alternative Technologies Association (sub. 73) also supports the view that provided
the overall cost of the FiT scheme is low, and that the broadest base of electricity
consumers are levied, the final cost to average consumers should remain insignificant.
In contrast to these views, others have argued that FiT schemes can have a positive
impact on welfare. The contrary view is that as embedded generators increase in the
market — the two fold effect of increased supply of energy and reduced demand (as
generator owners consume energy they generate) could lower electricity prices for all
electricity consumers (the merit order effect). In addition, the potential for embedded
generators to improve the cost-effectiveness of the electricity network (for example
through reduced transmission losses or need to augment the network) can also
facilitate lower electricity prices.
THE COMMISSION’S APPROACH 53
The ‘Merit Order Effect’1, it is argued offsets any form of cross-subsidisation. The
submission from Beyond Zero Emissions (sub. 64, p. 5) asserts that increasing the amount
of renewable energy on sale lowers the average price per unit of electricity because it
counteracts the effects of peak demand.
However, others have observed that as renewable energy sources tend to be more
expensive than the non-renewable alternatives the effect is to increase the total cost of
producing power. They argue that the merit order effect represents a shifting of costs
among market participants but does not lower the overall cost of electricity. For
example in a paper by Nelson, Simshauser, and Kelley (2012) quoted in the submission
by AGL the authors conclude that:
… the result is nothing more than a short term wealth transfer from existing
electricity producers to consumers and a long run increase in overall costs
leading to a loss of consumer (or taxpayer) welfare. (sub. 72, p. 4)
Another equity consideration is that under current regulatory arrangements, distributed
generators pay less for their ongoing access to the network. As the amount of
distributed generation increases over time the cost of network access will be spread
across a smaller number of customers. These customers will therefore be disadvantaged
relative to those with distributed generation.
It is not clear from the literature or submissions alone which argument is more pertinent.
It is possible the differing views can be reconciled due to intertemporal differences. In
the short run, where embedded generation isn’t common, the costs associated with FiT
schemes result in increased electricity prices and the associated welfare transfers.
However, in the longer run, where the benefits of distributed generation (including
improved network effectiveness and the merit order effect) are realised, this may result
in lower electricity prices and improved consumer welfare. This assumes that the
broader benefits of distributed generation are passed on to all consumers and that
distributed generators still contributes to the costs of continued access to the network.
In the Commission’s view, the equity impact of FiTs will depend on pricing policies and
the nature and extent of any resulting subsides to particular groups. An efficient
distributed generation model that is free of cross-subsidies will have positive long-term
benefits for all energy users.
3.4 Conclusion
Participants and the Commission’s research identified many issues relevant to the terms
of reference during the course of this inquiry. Therefore, to focus the analysis, and help
structure the discussion, the Commission has categorised the issues raised by
participant into two groups:
connecting to the network
selling power from distributed generators into the grid
The Commission’s approach was then to examine the barriers to distributed generation
achieving its potential within the National Electricity Market to achieve its objectives
and the role FiTs should play in the policy framework. In some cases the perceived
1 The merit order is a way of ranking available sources of energy in ascending order of their short-run marginal
costs of production, so that those with the lowest marginal costs are the first ones to be brought online to
meet demand, and the plants with the highest marginal costs are the last to be brought on line.
54 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
barriers to distributed generation are driven by its cost, and reflect the fact that
distributed generation is not be best option in all circumstances. In other cases, the
barriers to distributed generation may relate to the industry’s:
regulation and market structure
market conditions.
Removing or addressing these barriers would reinforce market signals and help ensure
that decisions on investment in and location of distributed generation are consistent
with the objective of having an efficient electricity sector in Victoria.
The Commission’s analysis and recommendations in the following chapters are
intended to achieve this outcome.
CONNECTING GENERATORS TO THE DISTRIBUTION NETWORK 55
4 Connecting generators to the distribution
network
Although distributed generation can have many advantages, it does not always easily
fit into today’s centralised power systems. While it is often argued that distributed
generation can reduce network costs, in many cases networks need to adapt, incurring
additional costs. Thus the net benefits, or net costs, of distributed generation vary from
case to case depending on network constraints, size, technology and operation. Even if
the overall benefits are positive, additional network costs can represent a disincentive
for network operators to connect a distributed generator. It is therefore not surprising
that the most commonly raised immediate barrier to greater adoption of medium-scale
distributed generation appears to be the process for connecting these systems into the
electricity network.
The terms of reference of the inquiry ask the Commission to identify barriers to distributed
generation and this chapter examines whether there are barriers to efficient connection.
First, the chapter sets out the regulatory context along with work currently underway to
address connection barriers. Section 4.2 outlines the barriers to efficient connection,
sections 4.3 and 4.4 examine the evidence of barriers presented to the inquiry and
section 4.5 makes conclusions and considers the materiality of these barriers.
4.1 Context
Connection of distributed generation is predominantly governed by national
arrangements. The national connection arrangements outlined in appendix B include
the connection elements of the COAG principles for Feed-in-Tariffs and from 1 July 2012
chapter 5 and 5A of the National Electricity Rules (NER) and the National Customer
Energy Framework (NECF). Chapter 5A of the NER will provide for three types of
connection service:
(1) A basic connection service, which will cover retail customers including those with
generally household-scale distributed generation. Distribution Network Service
Providers (DNSP) must have a model standard offer for basic connection services
that has been approved by the Australian Energy Regulator (AER).
(2) A standard connection service, which can cover the terms and conditions for
different classes of connection services or customers. DNSPs can choose to prepare
a model standing offer for such services and have it approved by the AER.
(3) A negotiated connection contract, which covers services that are not subject to a
basic or standard connection standard offer. The terms and conditions for such
services are negotiated and if agreement cannot be reached the dispute can be
arbitrated by the AER.
In the 2009 Australian Energy Market Commission (AEMC) conducted a Review of
Energy Market Frameworks in Light of Climate Change Policies. The AEMC concluded
that regulatory barriers prevent the efficient connection of distributed generators and
that addressing these barriers is likely to further the National Electricity Objective (NEO)
(AEMC 2009b, p.76). Many actions have been implemented or initiated to address
these barriers (table 4.1).
56 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
Table 4.1 Actions to address barriers to distributed
generator connection
Date Action Details
Jul 2010 AEMO Small Generator
Framework Design
Sets out principles that aim to
minimise barriers to
cost-effective small generator
participation in the NEM.
Jul 2011 Proposal by Minister for Energy
and Resources (Victoria) Total
Factor Productivity (TFP)
approach to network pricing
regulation
Aims to improve the incentives
for DNSPs to invest more
efficiently in general. AEMC
concluded the TFP approach
has merit but that practical
implementation issues exist.
Dec 2011 Inclusion of distributed
generators in the Demand
Management Incentive
Scheme (DMIS)
The AEMC completed a rule
change process to include
distributed generation in the
DMIS
Apr 2012 Proposal to the AEMC to
amend the NER for connecting
embedded generators
Proposal by ClimateWorks,
Seed and the PCA to
streamline connection
processes and improve DNSP
incentives for engagement
Jun 2012 Publication by AEMC of draft
rule change determination
from MCE on Distribution
Network Planning and
Expansion Framework
Main components are an
annual planning and reporting
process; a Demand Side
Engagement Strategy; and a
Regulatory Investment Test for
Distribution (RIT-D).
1 Jul 2012 Commencement of Chapter
5A of the NER
Expands the NER for
connection of household and
medium-scale distributed
generation.
Sep 2012 Finalisation of AEMC Demand
Side Participation (DSP) Stage 3
Review: The Power of Choice
Aims to improve opportunities
for DSP
Sep 2012 Outcome of AEMO Small
Generator Aggregator
Framework rule change request
to AEMC
Aims to simplify registration of
distributed generators
Apr 2013 Final Report of Productivity
Commission inquiry into
electricity network regulation
Seeks to, among other things,
address barriers to distributed
generation
Proposed, no
definite timeframe
National feed-in tariff (FiT) A consistent national approach
to FiT
Note: Australian Energy Market Operator (AEMO), Australian Energy Market Commission (AEMC), Ministerial
Council on Energy (MCE), National Electricity Market (NEM), Property Council of Australia (PCA)
Source: Commission analysis
CONNECTING GENERATORS TO THE DISTRIBUTION NETWORK 57
4.2 Overview of barriers to efficient distributed
generation connection
Investment in distributed generation is efficient and effective when the private and
system benefits are greater than the costs, including all relevant charges and
connection costs. In an efficient system distributed generation is likely to form part of a
suite of solutions that includes traditional investments in ‘poles and wires’ and demand
side participation (DSP) such as contracts to reduce demand and time of use pricing.
Connection of distributed generation is of particular interest to this inquiry because the
connection processes and costs can have significant impacts on the efficiency and
viability of medium-scale distributed generation projects. A particular challenge exists
because of barriers to transparent and market based capture of the potential network
value of all sizes of distributed generation.
Distributed generators require access to distribution networks for a range of reasons
including selling electricity and balancing system loads (ClimateWorks et al. 2011, p.9).
Distributed generation can have the following effects on the network and the network
operator:
causing additional costs, both operational and capital expenditure
entailing network benefits, such as increased reliability, smaller incremental cost
than centralised energy supply solutions and relieving network constraints
reducing the volume of electricity sold over the network
replacing or deferring network investments. (Bauknecht & Brunekreeft 2008, p.480)
Given the cost of connecting distributed generators to the network varies significantly,
recovering connection costs can help inform efficient choices between locations
where new investment will not exacerbate transmission constraints and locations where
they will. This is consistent with the AER’s view:
The AER maintains its initial views that non-registered embedded generators
should pay for the cost of removing specific output constraints, unless there
is a demonstrable net benefit to other network users. (AER 2011a, p.64)
From an economic perspective, connection may be associated with a number of
complex markets failures and other problems:
Asymmetric information and market power: monopoly DNSPs hold information,
have market power and as monopolies have an incentive to exploit information
asymmetry in negotiation, especially if there are weaknesses in the regulatory
framework.
Administrative burden: overly prescriptive and complicated processes can add
significant costs.
Risk and cost sharing for incremental infrastructure investment: if a new distributed
generator will use 10 per cent of the upgraded fault level headroom should they
pay 100 per cent of the upgrade? If the DNSP pays, what happens if the other
expected distributed generation projects do not arrive?
Simultaneous optimisation problem: efficient investment in distributed generation is
a function of network capacity, including highly localised capacity bottlenecks,
and efficient investment in network capacity is a function of the demand for
distributed generation. This is exacerbated by the fact that using distributed
generation to defer network investment can create a coordination problem, i.e.
58 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
distributed generation has higher value to the DNSP if its operation alleviates
network stress and the DNSP may have limited or indirect control over operation.
Regulatory incentives: as natural monopolies, electricity distribution networks are
highly regulated and the challenge for regulators is to design incentives for efficient
connection of distributed generators. The regulatory system was designed when
energy supply was dominated by centralised generation and the incentives built
into this regulation do not readily reward consideration of distributed generation as
an alternative supply source. The Victorian Government can influence these
arrangements through its role in the development and evolution of national
electricity regulation.
These barriers indicate a probable underinvestment in distributed generation in Victoria,
primarily at the medium-scale where these connection barriers are more significant
(section 4.5 discusses the materiality of these barriers).
Efficient connection would mean DNSPs have incentives to ensure no artificial barriers to
entry, with efficient costs, timing and risk allocation. The Commission supports the position
of the AER and the AEMC (AER 2010b, p.293; AEMC 2011e, p.26) that the incentives
should be neutral, rather than providing positive incentives or unnecessary barriers. While
there are material barriers to connection, these can be addressed at two levels:
(1) The process for connection: the Commission considers there are clear barriers in the
connection process which could be addressed now. These changes are necessary,
would move the industry towards more neutral choices between distributed
generation and other options for achieving the NEO, and hence more efficient use
of distributed generation. The Commission considers these important barriers should
be the primary focus for this chapter.
(2) Clarity and efficiency of incentives for DNSPs to plan and manage the system to
accommodate distributed generation and for distributed generators to invest in
locations where network benefits are highest: many argue that addressing the
connection process alone will not be sufficient to guarantee efficient use of
distributed generation. The Commission considers that some of these issues are
longer term but that they have a strong impact on the barriers to distributed
generation. The Commission is examining these barriers, makes draft
recommendations on some of the more immediate actions and identifies areas
where longer term action may be needed.
Sections 4.3 and 4.4 examine medium-scale and ‘household-scale’1 distributed
generation respectively, given each have different connection processes, the
proponents have different capacity to deal with DNSPs and scale creates different
kinds of connection issues. The Commission defines medium-scale as greater than
100kW and generally less than 5MW and household-scale is 100kW or less.
4.3 Barriers to medium-scale distributed generation
The process for seeking medium-scale connection is illustrated in figure 4.1. There is
some evidence of challenges in connection negotiations with a survey of completed
distributed generation connections by Senergy finding a range of issues, although the
1 ‘Household-scale’ includes small-scale distributed generators owned by small business and community
groups.
CONNECTING GENERATORS TO THE DISTRIBUTION NETWORK 59
survey did not seek the views of the DNSPs (box 4.1). A survey conducted by Entura for
Sustainability Victoria also found that:
The majority of survey respondents and interviewees found their working
relationship with the DNSP to be average or below ‘normal’
expectations and believed that this resulted in longer project
implementation times and increased costs.
There is a clear relationship between the perceived working relationship
with the DNSPs, and the number of grid connection problems faced,
the technical requirements needed and the cost of grid connection.
(SV 2010, p.i)
Box 4.1 Senergy report on distributed generation
connection experiences
Senergy conducted a survey of distributed generator proponents after the connection
process was completed. Distribution network service providers (DNSP) were not
involved in the survey. The main concerns highlighted by respondents in the interface
between the DNSP and the customer included:
access to the appropriate DNSP representatives for connection related issues (e.g.
legal or technical staff)
excessive response times from DNSPs for relatively straight forward queries
lack of transparency in and understanding of connection process
fear that accessing dispute resolution services would have a negative impact on a
distributed generation project or even the proponent’s distributed generation
project portfolio.
In addition, even though the regulatory instruments define some aspects of the connection
process, respondents said that DNSPs often fail to meet their obligations, including:
inadequate and/or delayed connection enquiry responses
insufficient detail provided on the DNSP’s management of the process or
scheduling of connection related activities
lack of commitment to firm delivery dates for connection offers, or to meet such
milestones if they are committed to, and a lack of understanding of the
importance of such milestones
inadequate provision of data (both in detail and timing) required to fully assess the
commercial significance of a connection offer, despite the Rules requiring this data
to be provided
not paying avoided use of system charges as required by the current legislation
issues respondents raised about the negotiation process included:
– DNSPs using their information to advantage during the connection process
– unwillingness to negotiate terms in the offer and significant delays in responding
to requests to reconsider terms, often leading to non-preferred agreement
terms being signed due to external commercial pressures. These terms included
open ended liability on the distributed generator
– not providing access to DNSP legal representation
– insufficient information on cost estimates and work scopes for applicants to
assess their fairness or reasonableness.
Source: (senergy 2011, pp.3–4)
60 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
As discussed in chapter 3, key issues and material barriers to distributed generation
identified by the Commission’s analysis and through submissions are:
information and planning on network capacity
right to connect
costs of connection: process, timelines and uncertainty
costs of connection: sharing network costs, benefits and risks
regulatory incentives for efficient connection.
As mentioned in table 4.1, several processes are in progress or will soon be
implemented to address the barriers to distributed generation connection. The AEMC
considers ‘it is likely that the combination of the new chapter 5A arrangements and the
proposed Distribution Network Planning and Expansion Framework rule change can
reduce the barriers to demand side participation, especially for distributed generation’
(AEMC 2012b, p.39).
Information
request
The Commission seeks feedback on its conclusion that recently
implemented and proposed changes to national electricity
regulation will address many of the barriers to connection of
distributed generation. These changes include the new chapter 5A
connection process in the National Electricity Rules, the Australian
Energy Market Commission’s (AEMC) Power of Choice review and
the following AEMC rule change requests:
Proposal to amend the National Electricity Rules for connecting
embedded generators
Distribution Network Planning and Expansion Framework
Small Generator Aggregator Framework.
4.3.1 Information and planning
Many participants indicated that information on network capacity by location could
help inform better siting of investment in distributed generation, assist with negotiation
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
constitute a significant barrier to efficient distributed generation investment.
Where distribution networks have capacity to accommodate distributed generation
the costs are restricted to the ‘shallow’ costs of physical connection and are both
relatively low and straight forward to calculate. Connecting distributed generation to a
constrained network, can require costly augmentation of fault level, voltage or thermal
capacity and the cost sharing arrangements become both more important and more
complicated. These are the so-called ‘deep’ costs. In parts of Melbourne’s CBD, for
example, connection of a distributed generation project can impose millions of dollars
in network reinforcement costs and there is high demand for connection from backup
generators and green building rating incentives (ACIL Tasman 2011a, p.7). Currently,
there is limited information on network capacity for distributed generation, the
information is costly and time consuming to obtain and the impact of network
constraints on connection costs is substantial:
For both cogeneration project owners and distributors, the cost of
connecting cogeneration systems often remains unknown until significant
CONNECTING GENERATORS TO THE DISTRIBUTION NETWORK 61
time and money has been invested in the application process itself.
(ClimateWorks et al. 2012, p.24)
Distributed generation can impose costs on networks but can also defer network
investment and as discussed in section 4.3.4 a lack of information on where these
opportunities exist will impact on proponents’ siting decisions and negotiation capacity.
Figure 4.1 Connection process for medium-scale distributed
generation
Source: Commission analysis
* This applies to
negotiation, not dispute
resolution
Agree
d
Offer open for 20 days
Not agreed
Legend
AER – Australian Energy
Regulator
DNSP – Distributed Network
Service Provider
Additional information required
DNSP has 5 days to
provide information
Application incomplete
Site visit, if needed
Preliminary inquiry from
potential applicant
wishing to connect
Applicant lodges
application on form
determined by DNSP
DNSP informs applicant of
additional information
needed
DNSP informs applicant of
deficiency
Basic connection service
or standard connection
service
Use agreement approved
by AER
Completed application
submitted
Not approved service.
DNSP notifies applicant of
the negotiation process &
possible changes &
expenses
Negotiated connection
offer
Option of dispute
resolution reduction
through AER
Offer terms form
connection contract
Application complete
DNSP uses best endeavours
to make offer within 65 days
of receiving completed
application*
DNSP has 10 days to advise
whether the service is covered
by an approved connection
process and, if so, make a
connection offer
offer open for 45 days
expedited connection
may be available
62 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
In the longer term, the distribution network could be planned better to accommodate
distributed generation. Jemena noted:
Smart networks of the future are designed with DG [distributed generation]
in mind. However the transition of the existing distribution networks to smart
networks would have to occur, by necessity, over a relatively long period of
time due to the significant investment required. The pace of transition can
vary depending on government policy. (JEN, sub. 79, p. 8)
The longer terms incentives for efficient investment to accommodate distributed
generation also relate to the regulatory incentives for DNSPs more broadly. These are
briefly considered in section 4.3.4. The related issues of incentives for DNSPs to reward
distributed generators for deferred network investment are addressed in chapter 6.
Opportunities for improvement
Many participants 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 (Ironbark Sustainability, sub. 50, CEC, sub. 76).
In the UK, DNSPs submit information strategies for regulatory approval (ACIL Tasman
2011a, p.30). Ironbark Sustainability suggested maps of network constraints could
reduce barriers to distributed generation (sub. 50, p. 14) and 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, the Commission notes that the SV report does not contain information
on fault levels, the main driver of distributed generation connection costs in Melbourne.
Exigency’s submission claimed 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)
Consistent with these calls, the AEMC is 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 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))
CONNECTING GENERATORS TO THE DISTRIBUTION NETWORK 63
The Commission’s view
The Commission considers improved spatial information on network constraints and
fault levels would improve contestability through fairer negotiation, 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. The
Commission considers the AEMC’s proposed Distribution Annual Planning Report is the
most appropriate mechanism to deal with this issue if data required by S5.8(2)(v) is
reported by location. The Commission notes that while fault levels and voltage levels
are currently an issue, thermal capacity is a potential issue in other countries
(Bauknecht & Brunekreeft 2008) and could be monitored to determine whether it
should be incorporated into the reporting requirements in the future.
The Commission also expects better information would lead to better planning. The
AEMC’s consideration of the rule change request on the Distribution Network Planning
and Expansion Framework requires review of a greater number of issues with improved
transparency, and may lead to better long-term planning.
The Commission considers competition can be enhanced in Victoria if the AEMC’s
proposed Distribution Annual Planning Report contains sufficient detail on network
constraints and planning by location. Information can support proponents to make
informed decisions and to negotiate more effectively with DNSPs where reporting
exemptions do not compromise the usefulness of information available. The
Commission considers this AEMC process appears to have the capacity to address
information barriers but is interested in participants’ views.
Information
request
The Commission seeks feedback on its conclusion that the
proposed Distribution Annual Planning Report includes sufficient
information on network constraints and planning by location to
address the barriers to informed decision-making and effective
negotiation by distributed generator proponents. The proposed
report is included in the AEMC’s proposed rule on Distribution
Network Planning and Expansion Framework.
4.3.2 Right to connect
There is currently no automatic right of connection for medium-scale distributed
generation. Rather, DNSPs have discretion in setting minimum technical standards and
distributed generators must pay for network studies and for network reinforcement. The
AEMC concluded this arrangement is a key barrier to connection of distributed
generation (AEMC 2009a, p.28) and inquiry participants supported this view.
As a priority, enabling automatic access for cogeneration systems up to
5MW should be immediately implemented because, relative to the size of
their installation, the costs of connection and the current connection
process are very high. (ClimateWorks et al. 2011, p. 36).
This contrasts with household-scale distributed generation, where there is an automatic
right to connect. Large generators that meet predetermined standards also have an
automatic right to connect under chapter 5 of the NER.
64 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
Opportunities for improvement
An automatic right of connection for medium-scale distributed generation based on a
specific process or technical standards, as advocated by some participants, is one way
to establish an equivalent connection process across all sizes of generation.
The soon to be implemented chapter 5A of the NER provides for a standard connection
service which would allow for DNSPs to offer a standardised process and automatic
connection. United Energy (UE) stated they will not establish standard contracts given
the vast differences between connections.
UE note that NECF is expected to commence on 1 July 2012 in Victoria and
that there may be a perception that automatic access may be provided
via the NECF standard connection offer contracts. UE has considered this
approach and has not progressed contracts in this area due to the need to
standardise the technical and cost arrangements in these contracts, nor do
we believe that there is a high volume requirement in the UE distribution
area. (sub. 77, p. 5)
The AEMC identified technical standards as a key barrier to distributed generation
projects:
The AEMC's Stage 2 Review of Demand Side Participation found that the
flexibility given to DNSPs to determine minimum technical standards is
causing delays and increasing costs for DG [distributed generation]
projects. In that review, we recommended that the Reliability Panel be
asked to consider the minimum technical standards that apply to DG
projects less than 5 MW. The SCER supported this recommendation in its
response to our Stage 2 Review of Demand Side Participation. (AEMC
2012c, p.160)
CSIRO previously identified options for access standards and outlined four options:
continue to grant exemptions from the registration and access
standard requirements for small generators (current practice)
develop new access standards tailored for small generators
change the exemption process so that smaller generators are required
to register and meet the current access standards
pool the small generators in a specified geographical area and require
that the pooled generation satisfy the access standard requirements.
(CSIRO 2009, p.461)
As noted, ClimateWorks, Seed and the PCA recently submitted a rule change to the
AEMC which addresses minimum technical standards for medium-scale distributed
generation, which may be the mechanism the AEMC uses to address minimum
technical standards (ClimateWorks et al. 2012).
The Commission’s view
The Commission considers that if automatic connection based on minimum technical
standards is possible for large-scale and small-scale generators then such a process
should be possible for medium-scale. Minimum technical standards could reduce the
costs and delays involved in connecting distributed generation and the developers of
equipment also need to know DNSP requirements to improve system integration
(Bauknecht & Brunekreeft 2008, p.485). The key question is the efficiency of establishing
CONNECTING GENERATORS TO THE DISTRIBUTION NETWORK 65
such an arrangement. Large scale power stations must undertake significant amounts
of preparatory work to meet minimum standards which guarantee a right of
connection. Household-scale connection, particularly through an inverter, imposes
smaller impacts on the network. Medium-scale distributed generation can have costly
impacts on the network that can vary greatly from place to place.
The Commission considers that while there are currently barriers to distributed
generation, a prudent approach would recognise the high costs of inadvertently
stimulating investment in places where it has a large adverse impact on the safety and
reliability of the network. Investment in distribution networks is a major driver of rising
electricity costs and significant network investment may be required to accommodate
large penetration of distributed generation in some locations.
The Commission considers there is merit in exploring arrangements for automatic
connection where the distributed generator meets specified standards and is required
to meet all appropriate costs. Distributed generator proponents may then make
commercial decisions to connect or not connect based on predetermined standards.
Those who do not meet the standards could choose not to connect or negotiate a
tailored connection service.
The ClimateWorks, Seed and PCA rule change request to the AEMC could result in
common standards and an automatic right for connection.
An automatic right to connection for standard embedded generators
should be available to plants that meet an automatic access standard. This
automatic access standard would be established to ensure that only plants
that will not compromise the integrity of the grid are granted automatic
access. (ClimateWorks et al. 2012, p.14)
If the ClimateWorks, Seed and PCA rule change request is unsuccessful, the Victorian
Government could effect an automatic right of connection based on technical
standards through lighter or heavier interventions:
voluntary Victorian standards
rule change request to the AEMC
requiring, as a licence condition, that DNSPs submit to the AER and have approved
a standard connection service offer.
In the absence of a national approach, Victoria could pilot, monitor and review
arrangements for an automatic right of connection with a view to incorporating this
process into national arrangements after consultation with other jurisdictions (see draft
recommendation 4.1).
4.3.3 Costs: process, timelines and uncertainty
The connection process itself was raised by many participants as a key source of
uncertainty and delay and therefore as a key barrier to distributed generation. In one
extreme case ‘the owner received approval of its connection application, only to have
it subsequently withdrawn, without explanation for the change of approach’
(ClimateWorks et al. 2011, p.24). In the Commission’s distributed generators roundtable,
participants identified poor information exchange as a key driver of uncertainty. DNSPs
can ask for more information partway through the process, so distributed generator
proponents do not know where they stand. The connection process is inconsistent
across DNSPs which adds further uncertainty (ClimateWorks et al. 2011, p.11).
66 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
Distributed generator proponent participants noted that long delays impact on the
viability of proposals and can impose high costs on other aspects of an investment. For
example, CBD high-rise commercial property developers require timeframes of around
12 weeks to avoid high cost impacts on other aspects of their development
(ClimateWorks et al. 2011, p.23). DNSPs claim it can take up to 12 months for a simple
connection and up to two years for a more complex one (ClimateWorks et al. 2011,
p.23). Distributed generator roundtable participants, however, mentioned that while it
can take longer than four years to get a connection, there are examples of DNSPs
providing an answer within two weeks.
Participants identified key causes of delay and uncertainty at each stage of the
process:
Initial inquiry stage: which has no overall timeframes and the DNSPs can delay
connection in the step prior to the regulated time period.
Information requests: a key source of delay in the initial inquiry stage is the ability to
restart the clock on decision-making timeframes. If the DNSP requests more
information on the 19th day of a 20 day decision making period this can restart the
timeframes.
Negotiation/arbitration costs and processes: many participants identified that
distributed generator proponents are concerned about the potential adverse
ramifications of using dispute resolution systems through the AER.
For all distributed generators, a lack of an effective consumer protection
framework and complaints resolution process is an additional barrier, in light
of the power and information asymmetries between distributed generators
and electricity market participants such as retailers and distribution network
service providers. (MEFL, sub. 75, pp. 9–10)
No standard process: each DNSP has its own process and medium-scale projects
are assessed on a case-by-case basis.
Rules are not designed for medium-scale generators: the rules view co-generation
systems as equivalent to major power stations (AEMO 2010c, p.10).
DNSP skills/capacity: ‘once a connection enquiry has been made, DNSPs are not
adequately equipped nor given enough incentive to respond to connection
enquiries in a manner that reduces the potential for surprises.’ (ClimateWorks et al.
2011, p.22)
Complexity: distributed generator proponents often do not understand the
connection process (ACIL Tasman 2011a, pp.29–30).
DNSP participants recognised the potential benefits of distributed generation but raised
concerns about the impact on their networks. CitiPower/Powercor ‘support the
connection of distributed generation to their distribution systems, including windfarms,
provided that these connections promote the National Electricity Objective and the
Businesses’ safety obligations’ (sub. 80, attachment 1, p. 5). United Energy (UE) had
similar views, and while recognising the benefits of distributed generation, stated:
UE understand that customers perceive these legitimate technical issues as
a barrier to connection and we will be seeking to improve in this area.
(UE,-sub. 77, p.5)
As mentioned in section 4.3.1, the impact of a proposed distributed generation project
on the network is unknown until both the DNSP and project proponent commit
significant time and resources to assess these impacts.
CONNECTING GENERATORS TO THE DISTRIBUTION NETWORK 67
Opportunities for improvement
The impact of the connection process on distributed generation is well recognised and
some stakeholders suggested the introduction of chapter 5A in the NER may address
some of these issues.
The most common barrier identified by various bodies to the incorporation
of distributed generation is the connection process. It is noted that the new
Chapter 5A of the NER is designed to provide some relief in this area.
(UE, sub. 77, p. 5)
Groups such as the PCA, however, claim that despite the introduction of chapter 5A
and other changes, barriers to connecting small- to medium-scale distributed energy
will persist (ClimateWorks et al. 2011, p. 11). The Clean Energy Council (CEC) identified
that one of the key issues is the timing of the rule change:
The CECs primary concern with Chapter 5A is that… in conjunction the
industry has learned some of the most significant lessons since the
consultation process closed early in 2010. The NECF consultation process
was flawed as a result and has completely failed to meet the needs of the
small scale embedded generation market or indeed take account of this
stakeholder group. It will result in the formulation of a new chapter in the
rules which strongly supports the position of DNSPs and fails to resolve any
issues which were already present in the relevant jurisdictional legislative
instruments. (CEC sub. 76, p. 7)
The evidence before the Commission highlights a number of remaining opportunities for
improvement after the introduction of chapter 5A, such as information provision,
including standard processes and timeframes. Participants also raised issues with
dispute resolution.
Information on connection processes
The Commission notes several bodies have developed connection guidelines to
support distributed generator proponents and DNSPs to navigate the complex
connection process, including:
CitiPower/Powercor: Customer Guidelines for Sub-transmission Connected
Embedded Generation (CitiPower & Powercor Australia 2010)
Electricity Networks Association: ENA Guideline for the Preparation of
Documentation for Connection of Embedded Generation within Distribution
Networks
The report, Unlocking the Barriers to Cogeneration states that ‘in other states, it is almost
standard for DNSPs to provide online information, an information line and a form
outlining the connection process’ (ClimateWorks et al. 2011, p.22).
Standard process
In some other countries there is a standard connection process and participants
suggested this approach could work in Victoria:
International jurisdictions, such as New Zealand and the United Kingdom,
have implemented and benefited from a requirement by networks to
publish standard connection contracts, standard connection processes
and published connection charges and tariffs. (Exigency sub. 4, p. 3)
68 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
The rule change request by ClimateWorks, Seed and the PCA (box 4.2) and many
submissions to this inquiry advocate for a national, standardised connection process
and practical district level licensing frameworks (ClimateWorks et al. 2011). In addition
to the calls in this inquiry, the AEMC in its Power of Choice Review received a number of
submissions calling for a standardised connection process (AEMC 2012c, p.166).
Timeframes
Distributed generator proponents participating in the inquiry suggested the connection
timeframes could be substantially shortened.
The case study proponents consider that a timeframe of between one and
three months for completing the connection application process would be
consistent with the wider commercial building development process, with
an outer limit of six months in extreme cases. (ClimateWorks et al. 2011, p.23)
The PCA rule change request outlines a 20 day connection decision for standard
connections and a 65 day connection decisions for non-standard connection
(ClimateWorks et al. 2012, p.11).
Dispute resolution
Many participants indicated distributed generator proponents are unwilling to use
dispute resolution through AER arbitration, as it may negatively impact on the DNSP’s
willingness to work with them and on their chance of connecting future distributed
generation projects.
The DNSP may not like the outcome which could in turn have a negative
impact on the project due to adverse ‘retaliation’ from the DNSP. This could
impact the project or even the developer’s project portfolio. While difficult
to prove there is suspicion amongst the industry that this is a real threat.
(CEC sub. 76 attachment 3, p. 9)
The Moreland Energy Foundation Ltd (MEFL) recommended that the government
should ‘establish a connection ombudsman or other dispute resolution process to
resolve disputes arising out of connection processes’ (MEFL sub. 75 attachment 1, p. 2).
The ClimateWorks, Seed and PCA rule change request submitted to the AEMC aims to
address many of the connection process barriers raised in this inquiry. The rule change
request does not, however, address dispute resolution processes (box 4.2).
CONNECTING GENERATORS TO THE DISTRIBUTION NETWORK 69
Box 4.2 Proposal to amend the National Electricity Rules
for connection of embedded generators
On 18 April 2012, the AEMC received a rule change request from ClimateWorks
Australia, Seed Advisory and the Property Council of Australia. The applicants argue
that the National Electricity Rules (NER) deter distributed generators from
connecting to the electricity grid, as the connection process is uncertain, complex,
burdensome, time consuming, inefficient and costly.
The application proposed that the NER be amended to:
(1) Provide an automatic right of connection to the grid and standard access
terms. This would apply to generators that meet ‘Automatic Access Standards’.
(2) Enable embedded generators a right to export electricity to the grid.
(3) Provide an improved connection process for embedded generators that are
ineligible for automatic access and a right to export electricity to the grid.
(4) Allow DNSPs to charge an optional fee-for-service. This is to promote
collaboration with proponents during the connection process.
(5) Oblige DNSPs to publish annual network reports identifying where capacity is
limited.
The chart below summarises the proposed new connection process with rule
changes.
The proposed changes aim to replace case-by-case negotiations with a
standardised process that is clearer, more certain and efficient. The declared
intention of the proposal is to encourage distributed generation without
compromising the integrity of the national electricity grid.
Source: (ClimateWorks et al. 2012)
The Commission’s view
Efficient and clear processes can reduce time and uncertainty and thereby support the
efficient entry of distributed generation, resulting in effective competition in related
markets. The outcomes of efficient connection processes include early withdrawal of
unsound proposals and improvements to sound proposals (such as redesign to reduce,
mitigate or avoid costly network reinforcement). An efficient process would also enable
a progressively sharper focus on the key issues and collection of data.
Connection Enquiry
Connection Application
Connection
Agreement Offer
Automatic
Access
Submit Connection Enquiry
May invite DNSP to advise
on connection issues in
design phase on a fee-for-
service basis
Connection Application
proceeds under specified
timeframe in amended Ch 5
Offer required to be made
no more than 65 days after
full application
Opt-in boilerplate contract
terms common across DNSPs
Automatic
Access
Site satisfies automatic
access standards in
amended Ch 5
Received within 20 day
maximum time, as entitled
to automatic connection
for standard fee, amended
in Ch 5
Standard connection agreement
Submit Connection Enquiry
May invite DNSP to advise
on connection issues in
design phase on a fee-for-
service basis
70 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
As illustrated in figure 4.2, an improved process would permit a progressive reduction in
the number and scope of issues about which there is genuine uncertainty, rather than
lingering uncertainty as is currently the case. Distributed generator proponents would
normally prefer to delay outlays on the project until such uncertainty is reduced, to
avoid the risk of wasting money if, for example, the assessment indicates the project
needs redesigning or cannot proceed. DNSPs would also benefit as relevant
information would be provided more quickly on higher quality more viable proposals.
The Commission has identified changes that would improve the current process, and
reduce uncertainty, timeframes and costs to business:
Improved information on the connection process: information on minimum
technical standards (section 4.3.2), network condition (section 4.3.1), clarity around
the process and information required from distributed generator proponents would
help to streamline connection and reduce uncertainty.
Improved engagement: DNSPs currently have limited incentive to engage with
distributed generator proponents to help improve their applications and identify
information needs during the preliminary inquiry stage and during negotiation. A
lack of engagement during the preliminary inquiry stage ‘could be easily resolved,
as UBC [Unlocking the Barriers to Co-generation] project owners have indicated
they would be prepared to pay on a fee for service basis to ensure this
engagement process occurred’ (ClimateWorks et al. 2011, p.23). The rule change
request by ClimateWorks, Seed and PCA includes such a proposal (ClimateWorks
et al. 2012).
Clarity around timeframes: establishing negotiated, project-specific time limits to
each stage of the connection process, and reporting performance against these
time limits. Also establishing processes that allow the ‘clock to stop’ while the
distributed generator proponent responds to information requests, but not to be
reset would encourage early identification and communication of information
requirements so DNSPs retain sufficient time to subsequently reach a decision.
Improved integration: integrating, at an operational level, the processes of the
connection approval with the broader project approvals, for example, that
distributed generator connection can progress at the same rate as a broader
commercial building approval process.
Several participants argued for improvements to dispute resolution, including an
ombudsman or similar (for example, MEFL, sub. 75 attachment 1, p.2). The Commission,
however, considers that as conflict resolution arrangements are transitioning from the
Essential Services Commission (ESC) to the AER, they are untested and there is not a
clear case of a problem in this area. The Commission accepts that DNSPs, as monopoly
businesses, may have an incentive to exploit asymmetric information and market
power but considers improved information, better engagement and the proposed
arbitration processes could address these problems. If there is evidence of a problem in
dispute resolution, the use of commercial mediation in advance of arbitration may help
remove barriers to distributed generation.
The Commission considers that the Proposal to amend the NERs for connecting
embedded generators by ClimateWorks, Seed and the PCA has the potential to
address many of the opportunities for improvement, including information on processes,
standardised processes and specific timeframes (ClimateWorks et al. 2012, pp.7, 15 & 26).
As noted this proposed amendment also has the potential to establish an automatic
right to connect for distributed generation projects that conform to specified standards
(section 4.3.2).
CONNECTING GENERATORS TO THE DISTRIBUTION NETWORK 71
Figure 4.2 Framing the connection process from a business
perspective
Current process under Ch5A
Unlimited
x 5 days
Unlimited
x 10 days
Clock stop/reset with information
request/network study
Possible improvement to the process
One timeframe with no resets, clock stop permitted
Note: Negotiated (negotd); preliminary inquiry (Prelim. Inq); expected cost (exp. Cost).
Source: Commission Analysis
Application Preliminary
inquiry
Information
request/site
visit
Negotiation
DNSP advises
standard or
negotd process,
expected costs
Offer
Agree
Dispute
resolution
Application
Preliminary
inquiry w/better
engagement
Information
request/
site visit
DNSP advises
standard or
negotd process,
expected costs
Negotiation
Agree
Dispute
resolution
Offer
72 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
Draft Recommendation 4.1
That, to facilitate efficient connection of medium-scale distributed generators up to
5MW, the Victorian Government support the Proposal to amend the National
Electricity Rules for connecting embedded generators submitted to the AEMC, with
specific support for:
improved information on connection processes
an automatic right of connection based on meeting standard technical criteria
a standard connection process
improved engagement by Distribution Network Service Providers
specific timelines, including limits on how information requests can impact on
overall timelines.
Should these issues not be resolved through the national rule change process within
12 months, the Victorian Government add a licence condition requiring distribution
network service providers in Victoria to establish such standards and rights by
incorporating them into standard connection services that are submitted to and
approved by the AER.
4.3.4 Costs: sharing network costs, benefits and risks
Participants identified key cost and risk sharing issues involving incremental network
costs and transparency.
Incremental network cost
Where a network is constrained, the distributed generators may have to pay the full
cost of network reinforcement to 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
2012c, p.270)
The DNSPs themselves consider this a complex problem:
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)
Network augmentation costs can have a significant impact on distributed generation
projects:
… if it is established that there is not enough network capacity, the costs of
network augmentation are not transparent and are often prohibitively
expensive – costing more than the cogeneration system itself.
(ClimateWorks et al. 2011, pp.24–25)
CONNECTING GENERATORS TO THE DISTRIBUTION NETWORK 73
Where network reinforcement does occur, there is no mechanism to charge
subsequent distributed generation projects for their share of that reinforcement.
Another aspect of the incremental network reinforcement cost is identifying who
benefits. Growth in demand, for example, also naturally leads to the need for increased
fault level capacity. As growth in energy demand increases due to population growth,
more energy-intensive appliances and changing land use (such as higher density
housing), new substations are required to accommodate increased energy from the
transmission network and this 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 2011a, 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 2012c, p.174)
As noted in section 4.2, 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 2011a, p.64). Various methods of recognising the
network benefits of distributed generation are discussed in chapter 6.
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,
distributed generation 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 2012c,
p.173)
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. The incentives
depend on the form of regulation and the current full cost pass through (so called z-
factor) does not necessarily provide efficient incentives for connection:
74 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
The DNSP does not carry any risk and would lack the incentive for efficient
DG [distributed generation] connections and will be tempted to game.
They will try and label costs that are not to do with DG as DG-related costs
and shift costs from the general expenditure to the special DG regime.
(Bauknecht & Brunekreeft 2008, p.490)
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 2012c, p.135). The AEMC also concluded DNSPs have strong
incentives to concentrate on security concerns, and weak incentives to connect
distributed generation (AEMC 2009a, p.28).
Opportunities for improvement
There are three main apparent opportunities for improvement.
(1) Improved information on the opportunities and constraints in the network
There are some moves to improve access to information and this is an important step.
Ironbark Sustainability proposed that transparency could be improved by establishing
regulations that compel the DNSPs to provide information in sufficient detail to inform
negotiation (sub. 50, p. 14, sub. 76, p. 6), and any new arrangements should take
account of the fact that DNSPs are monopoly businesses (CEC, sub. 76, p. 6). As noted
in section 4.3.1, the AEMC is proposing that DNSPs should publish a Distribution Annual
Planning Report which would help address these issues (AEMC 2011a).
(2) Providing greater clarity on when and how costs can be shared
The current system for dealing with network costs is also problematic. CitiPower
proposed a levy on distributed generators for the 2010-15 price determination. Part of
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 2011a, 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 2011a, p.20)
This process illustrates that there is no agreed framework on how these costs should be
allocated and shared.
(3) Regulatory framework for DNSPs to recover system reinforcement costs from
distributed generation
Addressing barriers in regulatory incentives involves changing the regulatory incentives
themselves and there are several means of achieving improved incentive compatibility
for connection cost recovery. One is to implement a dedicated distributed generation
connection incentive scheme and the AEMC proposes to consider these types of
schemes in the Power of Choice review (AEMC 2012c). A number of proposals for
distributed generation incentive schemes have been identified by the Commission in
the course of this inquiry:
CONNECTING GENERATORS TO THE DISTRIBUTION NETWORK 75
Unlimited Demand Management Incentive Scheme (DMIS): In response to
consultation on the DMIS
‘SP AusNet submitted that DNSPs do not have incentives to adopt
innovative solutions because of a lack of competitive pressures to do so (as
it is a regulated business). It further stated that capping a broad-based
demand management scheme to the level proposed by the AER won’t
encourage significant innovation as the development (and testing) of new,
technologically advanced equipment is costly. Hence, SP AusNet considers
that the DMIA2 should be uncapped, as the current capped arrangement
will not encourage spending in this area.’ (AER 2009, pp.16–17)
Modified CitiPower/Powercor levy: the AER rejected a distributed generation
connection cost recovery proposal by CitiPower/Powercor in the most recent price
determination (ACIL Tasman 2011a, p.20). ACIL Tasman has suggested a modified
form of this:
– Only charge the levy to new distributed generation locating in areas
where fault levels are at or above fault ratings
– Estimating the levy based on the costs of bringing forward works to
increase the fault ratings
– Providing a discount on the levy if the embedded generator agrees to
be disconnected from or provide support to the network on days of
peak demand
– Applying a cap and floor on the rate of return from the levy to ensure
no over or under recovery of costs associated with increasing fault
levels. (ACIL Tasman 2011a, p.36)
Menu of sliding scales: combining the elements of a number of different schemes
can achieve a self-selection scheme. If the regulator does not know the costs of
distributed generator connection faced by the DNSP, the regulator can design an
incentive compatible mechanism which triggers the DNSP to reveal the costs
truthfully. The impact of hidden information is very substantial as the cost of
distributed generation on the DNSP is strongly case sensitive. The regulator sets a
price cap and the DNSP chooses a sliding scale which determines the cost pass-
through (the price cap should be an increasing function of the cost pass-through).
A DNSP with high connection costs would choose a low price cap and high-cost
pass-through and vice versa. (Bauknecht & Brunekreeft 2008, pp.492–493)
Another option is to modify network regulation to create a more fundamental change
in incentives:
Total factor productivity and distributed generation included in price
determinations with benchmarking: the main objective of incentive regulation is to
increase the efficiency of the network, so the analysis of a DNSP’s efficiency and its
potential to increase efficiency should incorporate the costs of distributed
generation (Bauknecht & Brunekreeft 2008, pp.491–492).
2 Demand Management Incentive Allowance.
76 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
The Commission’s view
The Commission considers asymmetric information, lack of clarity around sharing
network reinforcement costs and the regulatory framework pose barriers to distributed
generators negotiating efficient connection agreements.
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 (see also
chapter 6). Therefore, information alone will not fully address barriers to efficient sharing
of costs, benefits and risks. As noted, the Distribution Annual Planning Report will provide
information that would assist negotiation, and the proposed amendments to the NERs
for connecting embedded generation would support negotiations by improving DNSP
engagement.
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. It also means DNSPs are less likely to plan
distribution networks to accommodate distributed generation. These barriers are
material as the Melbourne CBD has high demand for distributed generation, the
network is constrained and the process for sharing network costs has significant impact.
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 and results 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. 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 stakeholders.
CONNECTING GENERATORS TO THE DISTRIBUTION NETWORK 77
Draft Recommendation 4.2
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:
in addition to Draft Recommendation 4.1, make a submission seeking reform in
cost sharing arrangements 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 to prepare and provide guidance on cost sharing
arrangements for the connection of distributed generators before the next
round of network distribution pricing determinations expected in 2015.
Information
request
The Commission is considering whether the Proposal to amend the
National Electricity Rules for connecting embedded generators is
the best vehicle to address the sharing of the costs of network
reinforcement and invites feedback on this or other options, for
example, that the Victorian Government submit a separate rule
change request to the AEMC.
4.4 Barriers to efficient connection of household-
scale distributed generation
One of the major drivers of connection costs for medium-scale distributed generation is
the impact on the network, which some participants did not consider a barrier for
household-scale distributed generation. Medium-scale distributed generation often
involves greater size, greater network impacts and constrained networks, whereas
household-scale distributed generation units usually have less impact on the distribution
network:
From JEN’s perspective, there are no barriers to connecting micro DG
[distributed generation] units to the grid. (JEN sub. 79, p. 7)
Small systems are also not likely to require any upgrade or changes to the
distribution network, meaning the requirements for the network company to
dedicate resources should be minimal. (CFCL sub. 41, p. 9)
The Electricity and Water Ombudsman of Victoria (EWOV) identified that there is
currently good information provided on the Department of Primary Industries (DPI)
website which includes information on the connection process:
The DPI website remains the hub of solar information. It is a centralised and
trusted source of information for EWOV, customers, electricity retailers and
distributors. (OWOV sub. 48, p. 3)
Participants identified barriers that exist for household-scale distributed generation
generally relate to the connection process which involves three separate but related
processes:
78 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
Physical connection: wiring a household-scale distributed generator into the
distribution network is governed under chapter 5 of the NER and soon under the
basic connection offer in chapter 5A requiring an Electrical Work Request (EWR)
and Certificate of Electrical Safety (CES).
Signing up for the feed-in tariff contract: while arguably an aspect of selling
electricity (chapter 5), the connection process as currently arranged includes
connection steps which involve the installer, and requirements such as to have a
smart meter installed to secure a feed-in tariff contract.
Small-scale technology certificates (STC): to be eligible for STCs, the installer must
have CEC accreditation and the homeowner must sign the Commonwealth Solar PV
STV Assignment and Written Compliance Statement (Clean Energy Regulator
2012b).
These processes are described in more detail in box 4.3.
Box 4.3 What is the process for installing solar power?
The overall process for installing solar power includes the following steps:
First decide whether solar power is financially suitable for you.
Check with your electricity retailer about whether you are eligible for a
feed in tariff for the excess electricity you export back to the grid. If you
are satisfied with the retailer’s feed in tariff offer and the associated
terms and conditions, ask them about signing up for it. You will not
automatically start receiving a feed in tariff simply because you have
installed a system.
Check with your retailer whether you are likely to need a new meter
and about any changes to your electricity consumption tariff structure
and rate. You can shop around for a better deal from another electricity
retailer at any time.
Choose a reputable solar supplier - the company that will sell you a solar
PV [photovoltaic] system and install it for you. Check whether the
company uses accredited designers and installers. You have to use an
accredited installer to get a benefit from the Federal Government’s
Small-scale Renewable Energy Scheme (SRES). You can use this to
reduce the upfront cost of your system.
The solar power system is then installed by the solar power supplier.
Check with the supplier about all the paperwork that goes to your
distributor (the company that owns all the electricity poles and wires).
The paperwork includes a solar connection form (SCF), an electrical
works request (EWR), and a certificate of electrical safety (CES).
A Certificate of Electrical Safety is provided by your solar power supplier.
A copy should go to your distributor (the company that owns the poles
and wires that supplies your power)
Your electricity meter might need to be changed by your distributor to
be able to measure the excess solar power you sell to your retailer.
Advise your retailer that you have solar power and apply for a feed in
tariff.
Source: (ESC undated, p.7)
CONNECTING GENERATORS TO THE DISTRIBUTION NETWORK 79
Participants identified several barriers in the current arrangements:
Incorrect or confusing information: about the solar process, or about the billing of
FiTs, had been provided to customers by their electricity retailer, distributor or solar
installer (OWOV sub. 48, p. 2).
Complicated processes: there is a relatively high administrative burden, many
parties are involved and roles and responsibilities are not clear (box 4.4).
Planning barriers: those who live in heritage areas are required to seek local
government approval to install solar PV. ‘It is absurd that for such a small investment
that all three level of government should be involved’ (NECA sub. 37, p. 5). It is not
clear, however, whether such problems are isolated or widespread.
CEC accreditation: some participants consider CEC accreditation a costly and
unnecessary step in the connection process.
Licensed electricians in Victoria are already qualified to install solar PV but
the federal government has created another level of bureaucracy by
insisting electricians obtain CEC accreditation to be able to install solar PV
systems and claim solar credits for their customers. The CEC are a barrier
because the accreditation fees far outstrip those that licensed electricians
pa Energy Safe Victoria (ESV). Not only are the fees a barrier but the
process of obtaining accreditation is complicated and protracted.
(NECA sub. 37, pp. 5-6)
Victoria is obliged to address barriers to the streamlining and simplification of
connection process as the COAG FiT principles state:
… connection arrangements for small renewables customers should be
standardised and simplified to recognise the market power imbalance
between small renewable customers and networks. (COAG 2008, p.2)
80 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
Box 4.4 Complicated connection process
One aspect of the submissions was the consensus across stakeholder groups on the
complexity of the connection process:
Retailers
Customers are required to sign a feed-in tariff contract with their retailer before the
metering can be configured for solar and again each time the customer changes
retailers or moves into a property with solar. This process often delays the process for
a customer to have the feed-in tariff applied. In other states the feed-in tariff
payments are regulated through legislation and the electricity retail contract, with
scheme payments applied as a pass through of distribution tariffs, plus any retailer
premium payments. (AGL, sub. 72, p. 4)
Installers
The installation of small-scale PV is an involved process which can include a solar
company, electrical retailer, electrical distribution company, solar design and
installer and solar inspector. This does not take into account government
departments and agencies, the Clean Energy Council (CEC) and green certificate
traders. With so many participants a customer can be forgiven for being confused
about who is responsible for what in the whole installation process.
(NECA, sub. 37, p. 5)
Customer representatives:
Delays in the application of FiTs sometimes occurred because customers did not
know that several forms needed to be completed. Delays and errors were frequent,
with some customers missing out on PFiT because the electricity retailer or distributor:
lost paperwork - which caused delays in the completion of the solar
process
delayed raising service orders or raised incorrect service orders
delayed completing service orders to upgrade or re-configure the meter
provided incorrect or untimely advice about eligibility, timeframes and
requirements. (OWOV, sub. 48, p. 2)
Source: Submissions.
Opportunities for improvement
Many participants highlighted connection processes in other states which are simpler,
quicker, more predictable and less costly. The CEC’s flow charts for connecting
small-scale renewable energy generators to the electricity grid (CEC 2012b) show that
the South Australian and New South Wales connection processes offer examples of how
the Victorian process could be streamlined:
one connection process for all Victorian DNSPs
no requirement for a connection agreement with the DNSP
no retail contract
installer deals directly with the DNSP for the Electrical Work Request (EWR), rather
than the electrical contractor engaging with the retailer and then the retailer
contacting the DNSP
CONNECTING GENERATORS TO THE DISTRIBUTION NETWORK 81
In NSW Accredited Service Providers (ASP) can act on behalf of the DNSP to obtain
and install a meter as well as installing the PV system. The Ceramic Fuel Cells Limited
(CFCL)(sub. 41, p. 17) supported the adoption of a similar process in Victoria.
In South Australia the DNSP collects the CES onsite, while in Victoria the installer
gives a copy to the retailer, who gives it to the DNSP.
More generally, participants argued that in the Victorian process for connecting
household distributed generation there was a need to:
clarify roles and responsibilities (NECA, sub. 37, p. 5)
reduce duplication (CFCL, sub.41, p. 17)
remove or reduce unnecessary steps (Origin, sub. 81).
The Commission’s view
In section 4.3.3 the Commission outlined the rationale for improving the connection
process for medium-scale distributed generation and the same rationale applies to
household-scale connection. The Commission concurs with the submissions that the
household-scale connection process is unnecessarily complicated and contains
unnecessary steps. This imposes considerable cost on the consumers and businesses
involved, particularly installers who often mediate the process on behalf of the owners
of PV systems.
Lack of clarity around roles and responsibilities is a key driver of errors and delays in the
connection process. There are steps which pose barriers to communication between
key parties, such as the installer not being able to deal with the distributer and the roles
and responsibilities need to be clarified.
The Commission considers duplication could be removed, such as the installer providing
the EWR and the CES to the retailer who then provide them to the DNSP. Double
handling of paperwork is an ineffective way to ensure all parties are informed. The
Commission is attracted to the CFCL’s proposal for an online system to automate and
streamline the process, allowing the customer, retailer and distributor to share
information and provide sign-off (CFCL sub. 41, p. 17).
As well as removing duplication, some steps could be truncated or removed. The retail
FiT contract, for example, offers certainty to consumers and retailers:
customers cannot have their FiT changed without their written consent
facilitates referral to the ESC
establishes a specific start date
greater certainty over terms and conditions than is contained in the supply
contract (DPI 2012b).
But other states have achieved adequate consumer protection in other ways, and
these could be reinforced such as through greater detail in the NECF. In NSW the
market contract (supply contract) is also the FiT contract, they are not separate. IPART
made recommendations to strengthen consumer protection by:
improving information provided by retailers under the NSW Marketing Code of
Conduct
improving disclosure through the Retail Pricing Information Guidelines made under
the National Energy Retail Law and AER publication of comparison information
82 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
encouraging the NSW Government and the solar industry to provide clear
information on small-scale solar PV including potential financial implications(IPART
2012, p.11).
Victoria could take a similar approach. Not only would this allow the removal of a
burdensome step in the connection process, but would allow for greater national
consistency of consumer protection for FiT customers.
In Victoria a PV installer must coordinate with the DNSP to arrange meter installation
and connection of the system to the distribution network (CEC nd). In New South Wales,
ASPs can perform some of the functions of the DNSP and can also install PV systems (for
example, Trinity electrical services 2012). The Commission considers there is merit in
increasing contestability and reducing barriers to innovative business models in network
services and PV installation.
Draft Recommendation 4.3
That to facilitate the connection of household distributed generation to the network
the Victorian Government amend, where relevant, the Electricity Industry Act 2000
(Victoria) and associated regulations, industry codes and guidelines to:
clarify roles and responsibilities of the parties involved
reduce duplication, such as the installer providing the Electrical Work Request
and Certificate of Electrical safety to the retailer who provides it to the
distribution network service provider
remove or reduce the impact of unnecessary or burdensome steps
establish contestability for meter installation.
Information
request
The Commission seeks views on how the connection process for
household-scale distributed generation can be improved, and
what is required to give effect to such improvements. The
Commission plans to conduct further consultation on specific
changes to this process.
4.5 Impact of removing barriers to connection of
distributed generators
As noted, the Commission’s terms of reference require it to identify any state and/or
regulatory and other barriers to the development of a network of distributed renewable
and low emissions generation. This chapter has identified connection processes as a
key source of such barriers. Another key barrier, the difficulty in realising the network
value of distributed generation, is discussed in chapter 6.
Connection related barriers are greatest for medium-scale generators. The connection
process for these generators is lengthy, complex and uncertain. Medium-scale
generators also have problems:
accessing information on network constraints and the connection process and
timeframes
getting clarity on the technical standards required for them to connect to the
network.
CONNECTING GENERATORS TO THE DISTRIBUTION NETWORK 83
The system for meeting network augmentation costs to accommodate distributed
generation is also an important barrier. Recovery of these costs is regulated by the AER
but there is no agreed framework on how these costs should be shared when
augmentation is needed to accommodate several future distributed generation
projects or other load users on the network.
For household-scale generation the process is also complex, involving three interrelated
processes, numerous parties and requirements from at least two levels of government.
This complexity is exacerbated by:
lack of clarity in the roles and responsibilities of the parties involved
duplication and unnecessary steps I the process
lack of contestability in the provision of services such as meter installation.
The impact of removing barriers to connection of distributed generation also differs
between medium-scale and household-scale. Barriers to efficient connection of
medium-scale distributed generation can have a major impact on the financial viability
of projects. These costs are project-specific and depend on location, technology and
size.
Over half the total DG [distributed generation] project costs are associated
with the grid connection process, including power systems studies,
application and network augmentation costs. Therefore the average grid
cost for small installation in Victoria was approximately 50 per cent of overall
cost. (SV 2010, p.i)
Any unnecessary increase to these connection costs is likely to be a major barrier to
investment.
There is significant opportunity for cost-effective distributed energy in Victoria.
Distributed generation already makes up seven per cent of Victoria’s installed capacity
(chapter 2) and this likely to increase in response to climate change policies (AEMC
2012c). Distributed generation appears to offer a number of key advantages as part of
a portfolio of greenhouse gas emissions reduction options:
numerous low-emission distributed generation technology options are available
and commercially viable
the short lead times and scale of distributed generation can better match
incremental demand than large additions to centralised power
some distributed generation technologies use fuel that is not economic for large
centralised power generation(e.g. landfill gas, waste streams, some forms of
biomass)
distributed generation has reduced transmission losses and potential distribution
network benefits (CSIRO 2009, p.353).
The realisation of many of these opportunities will require connection of distributed
generation systems to the network.
Under some scenarios, the nation could cumulatively invest between $68 and $74 billion
to build between 39 000 and 42 000 MW of lower emissions installed capacity by 2030
(Garnaut 2011, p.30). Reducing the barriers to different kinds of low-emissions
technology can increase competition and reduce the adjustment costs of moving to a
lower-emissions generation mix. The Institute for Sustainable Futures (ISF) found that in
Victoria strategically planned and implemented decentralised energy projects could
84 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
reduce electricity sector emissions by 6.2 per cent and save consumers about $437
million per annum by 2020 (ISF 2012). The Commission advises caution on these the ISF
figures because while distributed generation has grown at less than the rate of growth
of all energy generation in the last decade the effect of removing barriers is difficult to
quantify. The Commission considers that while it is difficult to quantify precisely the
impact of connection barriers the current capacity of installed distributed generation,
potential future growth and the significant nature of the barriers all support a
conclusion that barriers to medium-scale distributed generation are material.
While the barriers to connection of small-scale distributed generation are less severe,
removing administrative burden in the connection process, is likely to provide significant
relief to industry and consumers. During industry consultation participants stressed that
household-scale distributed generation installers currently bear significant levels of red
tape as a result of the current connection processes.
VICTORIAN FEED-IN TARIFFS: SELLING ELECTRICITY 85
5 Victorian feed-in tariffs: selling electricity
5.1 Introduction
This chapter provides an overview of the current Victorian feed-in tariffs (FiTs) and, to
the extent possible, identifies and assesses the key objectives of the FiT schemes. In
particular, it seeks to establish whether the objectives are appropriate in light of the
planned introduction of a price on carbon, and the extent to which the FiTs represent
the best instrument to achieve other stated policy objectives.
Given that the Victorian FiTs operate in the context of the National Electricity Market
(NEM) it is important that they are consistent with, and support, the overarching
National Electricity Objectives (NEO) set out in the National Electricity Law.
Acknowledging the important role of competition in the Victorian electricity market, this
chapter considers whether there are any barriers that may prevent the full benefits of
competition being realised in relation to establishing fair and reasonable FiTs. It also
discusses some of the potential issues within the broader energy regulatory framework,
whilst acknowledging that many of these issues are currently subject to major reviews.
5.2 Victorian feed-in tariffs
5.2.1 Overview
As discussed in chapter 2 there are three Victorian FiT schemes. All electricity retailers
with 5000 customers or more are required to make offers to eligible customers under
these three schemes:
(1) Standard feed-in tariff (SFiT): requires retailers to publish the prices, and terms and
conditions under which they will purchase electricity supplied by generators. This FiT
varies among retailers according to their business strategy and applies to
renewable technologies (including solar). It is available to specified households,
community organisations and small businesses with a solar generation capacity
greater than 5 and less than 100 kW in size, and is also available to eligible
customers generating other forms of renewable energy, such as wind, hydro or
biomass, with a system size of less than 100 kW.
(2) Premium feed-in tariff (PFiT): This scheme (now closed to new applicants) provided
participating households, businesses and community organisations (all of whom
operate solar photovoltaic (PV) systems of 5 kW or less) a credit of at least 60 cents
per kWh for excess electricity fed back into the grid. This net tariff was calculated to
provide a 10 year payback period for a small-scale solar system. When the PFiT was
first introduced, solar system costs were significantly higher than current costs.
(3) Transitional feed-in tariff (TFiT): Under the TFiT scheme, households receive a
minimum of 25 cents for every kilowatt hour they feed back into the grid. It is only
available to new solar PV customers with systems of 5 kW or less. The TFiT
commenced 1 January 2012 and is available for five years or unless a capacity limit
of 75 MW is reached or $5 per customer cost is reached.1
An explicit minimum feed-in net tariff is established within the PFIT and TFIT which only
applies to solar PV technology. There is no minimum FiT for other technologies except to
1 This caps the extent to which the costs of the FiT scheme are borne by other electricity users at $5 per bill.
86 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENEATION
the extent that the prices and terms and conditions must be fair and reasonable.
However, the Commission notes that a guidance paper, released by the Essential
Services Commission (ESC) outlines the methodology for the assessment of ‗fair and
reasonable‘ FiTs and includes that an offer (by a retailer) must:
Specify that the retailer will pay or credit the customer, for electricity
supplied by the customer under a feed-in contract, at a rate not less than
the rate the customer pays to buy electricity from the retailer. (DPI 2011f)
In effect this sets a minimum FIT for renewable technologies and is considered further in
section 5.4.
5.2.2 Objectives of the three feed-in tariff schemes
The importance of having clear public policy objectives is emphasised by AGL who
commented that:
There is a lack of overarching public policy objectives unpinning the
development of feed-in tariff policies throughout Australia. AGL believes
that the lack of underlying public policy objectives being determined
before the implementation of FiT policy is the main driver of the poor
outcomes experienced in most jurisdictions in relation to FiT policy.
(sub. 72, p. 1)
Ceramic Fuel Cells Limited (CFCL) also suggested that:
Where feed-in tariffs have become clouded is that the design and rate of
the tariff have been set to achieve other objectives, notably to support the
solar PV industry as a form of industry development (and as a subsidiary
goal, to reduce greenhouse gas emissions). (sub. 41, p. 10)
Table 5.1 highlights that each of the FiTs has different objectives and would therefore
appear to be seeking to address various problems that may have been identified at
the time the FiTs were designed.
VICTORIAN FEED-IN TARIFFS: SELLING ELECTRICITY 87
Table 5.1 Objectives of Victorian Feed-in tariffs
Type of FiT Established Original Objectives
Standard FiT 2004
Develop Victoria‘s substantial wind energy resource
Ensure timely and efficient connection of wind energy
generators
Address problems where the benefits and costs of
connecting wind farms are not shared equally
amongst market participants
Remove market barriers that constrain the
development of a small wind turbine industry in
Victoria
Premium FiT 2009
Reduce cost barriers to installing small-scale solar PV
systems
Encourage the continued uptake of solar PVs as part
of a greenhouse gas abatement strategy for Victoria
Modernise the regulatory approach to crediting and
qualifying customers
Assist households to make a personal contribution to
tackling climate change
Ensure certainty for owners of solar PV systems
Ensure certainty for retailers and distributors
Support the solar industry
Transitional FiT 2011
Ensure that the level of subsidy is equitable, given the
cost to electricity users, including those on concessions
Support renewable energy in the transition to a lower
emissions future
Provide a fair and reasonable price to households
feeding solar back into the grid
Manage changing prices as PV costs have dropped
by around 50 per cent
Reduce the boom and bust cycle for the solar panel
industry
Provide an average payback period of less than 10
years.
Source: (Brumby 2004; Batchelor 2009; O’Brien 2011).
Overall the objectives cited for FiT schemes in the past appear to fall into three
categories:
reduce greenhouse gas emissions, including assisting households to make a
personal contribution to environmental outcomes
support innovation and the development of a new industry by stimulating the
demand for investing in distributed generation by more efficiently allocating risks,
including risks to customers and energy market risks to small-scale PV investors
ensure fair payments for electricity from small-scale PV investments.
88 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENEATION
The ongoing relevance of these objectives needs reconsideration in light of the
introduction of a price on carbon and the maturing of distribution generation
technologies.
5.2.3 Objective of reducing greenhouse gas emissions
Central to considering a FiT objective of reducing greenhouse gas emissions is the
introduction of a national approach to the pricing of carbon.
On 10 July 2011, the Commonwealth Government announced a ‗price on carbon
pollution‘ as part of its climate change plan, which will come into effect from 1 July
2012. Under this pricing mechanism, around 500 of Australia‘s largest carbon emitters
will be required to pay for each tonne of carbon pollution they release into the
atmosphere.
Recent data (table 5.2) reported by corporations under the requirements of the
National Greenhouse and Energy Reporting Act 2007 (Cth) indicate a number of large-
scale generators will be subject to the carbon pricing mechanism.
Table 5.2 Greenhouse gas emissions (by registered
corporation) – Top 10 by Total Scope 1 Gas
emissions
Registered corporation Example of generators
owned by the corporation
Greenhouse gas
emissions (t CO2-e)
Macquarie Generation Lidell power station
Bayswater power station 20 330 773
Delta Electricity
Mount Piper Power Station
Munmorah Power Station
Vales Point Power Station
Wallerawang Power
Station
19 792 536
Great Energy Alliance
Corporation Pty Ltd Loy Yang A Power Station
19 378 906
International Power
(Australia) Holdings Loy Yang B Power Station
16 764 353
TRUenergy Holdings Pty Ltd Yallourn Power Station 16 143 406
CS Energy Limited
Callide Power Station
Kogan Creek Power
Station
Wivanhoe Power Station
14 880 516
Eraring Energy Eraring Power Station 11 725 490
BlueScope Steel Limited 11 371 293
Loy Yang Holdings Pty Ltd 10 165 819
Oz Gen Holdings Australia
Pty Ltd
9 717 866
Source: (Clean Energy Regulator 2012c).
VICTORIAN FEED-IN TARIFFS: SELLING ELECTRICITY 89
From 1 July 2012 a price of $23 per tonne of carbon pollution will apply. It is also
intended that by 2015 the price on carbon will be determined by market forces. The
price on carbon is a mechanism that provides a market-based incentive to reduce
carbon pollution.
Explicitly pricing carbon ensures all companies and individuals either
explicitly or implicitly factor into decisions the costs of greenhouse gas
emissions. Companies and individuals do not need to make complex
calculations about the emission intensity of particular goods, as the price of
the goods will reflect that key information.
Over time, as prices reflect the emission content of goods, producers and
consumers will have an incentive to find ways to reduce emissions. For
instance, electricity producers will look to reduce the use of emission-
intensive fossil fuels to generate electricity and consumers will be
encouraged to use less electricity. (Commonwealth Treasury 2011, p. 19)
The Productivity Commission (PC) found that the costs of reducing emissions are lower
when consumers and producers make the decision, rather than government (PC 2011).
Looking at over 1000 carbon policy measures across nine countries the PC also found
that:
Emission trading schemes were found to be relatively cost effective, while
policies encouraging small-scale renewable generation and biofuels have
generated little abatement for substantially higher cost. (PC 2011, p. xiv)
More importantly, stylised modelling by the PC for Australia suggests that relative to a
price-based approach ‗the abatement from existing policies for electricity could have
been achieved at a fraction of the cost‘ (PC 2011, p. xiv).
Implications for Victorian feed-in tariffs
One of the objectives of establishing the premium and transitional FiTs was to reduce
greenhouse gas emissions at a time when there was great uncertainty regarding any
national approach. From a regulatory design perspective it is important to ensure that
the most appropriate regulatory instrument is assigned to a given problem — provided
that the case for government intervention is established. It is also important to ensure
consistency with national electricity objectives as previously stated.
The Commission notes that work by the Commonwealth Government and the PC
indicates that the objective of reducing greenhouse gas emissions is most appropriately
addressed through a price on carbon.
If the objective of the FiT was to reduce greenhouse gas emissions then it would appear
that this objective is no longer valid, on the grounds that a more appropriate regulatory
(market-based) instrument will operate shortly. It is also the case that FiTs will not be
necessary as a complementary policy. As noted by ACIL Tasman ‗if distributed
generation is not the lowest cost of abating greenhouse gas emissions, but a FiT is
designed to include this objective, it will increase the cost of meeting greenhouse gas
emissions reduction targets.‘ More importantly, ‗this would cause electricity prices to be
higher than necessary…it would be contrary to the NEO and the long term interests of
consumers‘ (ACIL Tasman 2012b, p. 38).
There are also other Commonwealth initiatives that seek to achieve environmental
objectives similar to those of the Victorian FiTs.
90 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENEATION
The Renewable Energy Target
The Renewable Energy Target (RET) is designed to deliver the Commonwealth
Government's commitment to ensure that 20 per cent of Australia's electricity supply will
come from renewable sources by 2020 and consists of the Large-scale RET (LRET) and
the Small-scale Renewable Energy Scheme (SRES). These schemes create a financial
incentive to invest in renewable energy sources through the creation and sale of
certificates. The purposes of the schemes are to:
encourage additional generation of electricity from renewable sources
reduce emissions of greenhouse gases in the electricity sector
ensure that renewable energy sources are ecologically sustainable.
This is achieved by the creation of online certificates by eligible renewable energy
sources based on the amount of electricity either generated (by a renewable energy
power station, or small-scale solar panel, wind or hydro system) or displaced by a solar
water heater or heat pump. A legal obligation is placed on electricity retailers to
purchase and surrender a certain amount of these certificates each year.
The LRET creates a financial incentive to establish and expand renewable energy
power stations, such as wind and solar farms, or hydro-electric power stations. It does
this by legislating demand for Large-scale Generation Certificates (LGCs). These LGCs
are created based on the amount of eligible renewable electricity produced by the
power stations. LGCs can be sold or traded to liable entities (usually electricity
retailers2), in addition to the power station‘s sale of electricity to the grid. RET liable
entities have a legal obligation to buy LGCs and surrender them to the Clean Energy
Regulator annually (Clean Energy Regulator 2012a).
SRES provides a financial incentive to install small-scale renewable energy systems
including solar panel systems, small-scale wind systems, and small-scale hydro systems.
Under this scheme Small-scale Technology Certificates (STCs) are created (with the
number of certificates relating to the amount of electricity produced or displaced),
which are bought by RET liable entities who are legally bound to do so. Further to this,
‗Solar Credits‘ increase the number of STCs able to be created for eligible installations
of small-scale solar panel, wind or hydro systems by multiplying the number of
certificates for which the system would normally be eligible. Solar Credits apply to the
first 1.5 kW of on-grid capacity installed in an eligible location or to the first 20 kW of
capacity for off-grid systems.
Some inquiry participants argued that the Clean Energy Act 2011 (Cth) and the
Renewable Energy Target are more efficient than mandated FiT schemes in terms of
their likely impact on changes to greenhouse gas emissions. For example, Simply Energy
noted:
… the Clean Energy Act and the LRET scheme will drive change in the mix
of generation capacity and achieve that change in a more efficient
manner than mandated FiT schemes. The advantages that the carbon
price and LRET scheme have are that they are generally broad-based and
not technology specific and are thus more likely to produce efficient
outcomes without the perverse social outcomes generated by mandated
FiT schemes ...
2 For more detailed information refer to ss 25 and 31 of the Renewable Energy (Electricity) Act 2000 (Cth).
VICTORIAN FEED-IN TARIFFS: SELLING ELECTRICITY 91
The Clean Energy Act removes the case for FiT schemes as an instrument to
reduce greenhouse gas emissions. A price on carbon will force business and
consumers to factor the cost of climate change into their investment and
purchasing decisions and will likely transition the economy to make more
energy efficient or cleaner energy choices. (sub. 58, p. 1-2)
However some participants questioned whether the price on carbon reduces the need
for a Victorian FiT.
We do not believe the emissions trading scheme, or the introduction of a
carbon price generally is sufficient or adequate to remove the need for a
FiTs, or to encourage distributed renewable energy generation. It is our
understanding that the emissions trading system will simply penalise carbon-
intensive forms of wholesale generation. Whilst this will have a small impact
on retail prices, we do not believe the connection is sufficiently strong to
overcome the needs of small to medium generators ... (Warburton
Community Hydro Project, sub. 69, p. 3)
While there are mixed views from participants regarding whether Commonwealth
policies adequately deal with greenhouse gas emission issues, the Commission
considers that the combined effect of these policies is likely to be substantial and
provide additional assistance for households to make a personal contribution to
reducing greenhouse gas emissions (an objective of the PFiT).
Given current Commonwealth policies in this area the Commission is of the view that
the Victorian FiT(s) are no longer an appropriate regulatory instrument to assign to the
objective of reducing greenhouse gas emissions, particularly noting the cross-subsidies
and potential inequities inherent in the current FiT. (chapter 3). This does not preclude
distributed generation from helping in the adjustment to a low carbon economy. The
Commission envisages that the current and imminent Commonwealth programs,
combined with improvements proposed in this draft report will result in incentives to
invest in distributed generation when it is a cost-effective way of reducing greenhouse
gas emissions.
5.3 Industry support
A further objective often cited in support of regulated FiTs is the development of, or
support for, a particular industry. Current Victorian FiTs are skewed towards very small
solar PV technology, and to other forms of distributed renewable generation
technology. This is achieved through the tariff and eligibility criteria.
Several options are available to assist customers to minimise their expenditure on
energy, including:
purchasing and using energy efficient appliances (lighting, heating, cooling) or
production processes
reducing demand for energy at times where energy from the grid is more costly
investing in technologies to generate electricity, which may also include on-site
storage and /or export to the grid
substituting between different fuel sources.
In a competitive market, customers would optimise between the various options
available to minimise their spend on energy.
92 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENEATION
The PFiT and TFiT are higher than a market determined price, and therefore assist the
solar PV industry. This assistance can change the way customers decide between the
energy saving options highlighted previously. For example, a higher FiT for solar PV
makes this option more attractive than would otherwise be the case, and potentially
crowds out alternatives. This reduces the demand for other industries such as those
supplying energy saving technologies and those building and operating large-scale
renewable generators.
More generally the current SFiT arrangements are specifically targeted towards
‗renewable‘ generation technologies. This may implicitly disadvantage other possible
technologies that have ‗low-emission‘ characteristics. Electricity generated from fuel
cells, for instance, is not considered a ‗renewable‘ form of distributed generation as it
relies on gas (a non-renewable energy source) to produce electricity and heat.
However, it is considered to be low-emission and highly efficient.
CFCL argued that:
In terms of choice for consumers who want to provide their own electricity
or who want to reduce greenhouse gas emissions, under the current feed-in
tariff regime the only effective choice is to install solar PV panels or not.
CFCL believes that small business, householders and community groups
should be given a wider choice – the choice to generate their own
electricity using a high efficiency fuel cell. By giving consumers this choice,
the government would allow business and householders the ability to
rationally decide between installing a renewable energy generator (solar
PV) or a low emissions generator (fuel cells) - or of course installing neither
and continuing to buy power from the grid. (sub. 41, p. 4)
While additional assistance to solar PV (through the PFiT and TFit) may benefit the solar
PV industry, it is likely to be at the expense of other distributed generation technologies
(or more generally to other industries supplying innovative energy efficiency related
products or services). As outlined in the Commission‘s inquiry into the Victorian
manufacturing industry, ‗selective assistance that lowers the costs of a particular firm or
industry may improve its competitiveness, but at the expense of other sectors‘ (VCEC
2011, p. 90). Industry assistance, through regulated tariffs and discriminatory eligibility
criteria, may not be the most appropriate way to support the establishment of a
sustainable industry, particularly when (in the case of the solar PV industry) the industry is
already reasonably well established. The industry support argument is also undermined
by uncertainty created by previous FiTs, which have been subject to significant change
at short notice.
5.4 Providing a ‘fair and reasonable’ price
One of the objectives cited in support of FiT schemes is to ensure that households and
small businesses have access to a fair and reasonable price for the electricity that they
export into the grid.
The Commission is of the view that this is the most relevant objective for Victorian FiTs
and is consistent with COAG national FiT principles. However, the mechanism for
achieving this objective may not require a FiT to be specified and regulated.
The following discussion relates to current Victorian FiT arrangements which cover
generation capacity of up to 100 kW. Under these arrangements the owner of a
distributed generator has a relationship with (and is a customer of) an energy retail
business. The Commission understands that the policy intent of Victorian FiTs (particularly
VICTORIAN FEED-IN TARIFFS: SELLING ELECTRICITY 93
the SFiT) was to encourage system installations where generating capacity is
proportionate to the electricity consumption at the site — for instance it was not
intended to capture installations that are primarily solar generators.
Consistent with COAG national principles for FiT schemes, the Commission considers that
micro and small generators of electricity exported to the grid (or distribution system)
should receive a fair and reasonable price. The key question is how ‗fair and reasonable‘
is defined, especially in view of the proposed appropriate objective for a FiT.
From submissions it appears that views on what constitutes ‗fair and reasonable‘ fell into
one of two basic groups:
(1) providing consumers with a rate of return on their investment in solar PV and
therefore providing an incentive to invest
(2) providing a price that reflects the full value of the energy exported to the grid,
noting that there were some significant differences in views on what constitutes full
value.
The Commission‘s view, as noted in chapter 3, is that the main remaining appropriate
objective for a FiT is to provide a price signal to investors in micro/small distributed
generators, that will help achieve efficient use of distributed generation in a
competitive energy market. The Commission sees little value in providing additional
State-based incentives for development of renewable generation technology.
Accordingly, the Commission accepts the second approach, namely that the term ‗fair
and reasonable‘ refers to a price that reflects the value of the energy exported to the
grid and that would encourage efficient use of resources in the electricity industry,
including the economic use of distributed energy.
In the past, fair and reasonable has been accepted as at least a one-for-one tariff.3 This
arrangement resulted in a tariff that is greater than a market-determined price, and is
likely to overstate the energy value of distributed generation, particularly if it is based on
a retail price that incorporates network components. In some cases, retailers may vary
their retail prices based on customer characteristics (residential or small business for
example) which is independent of the network value of the distributed generation.
There are also other potential issues with a one-for-one FiT, especially that it can lead to
inequitable outcomes. Under a scenario where the FiT is greater than its value to the
network, the gap between the FiT and the market value of the electricity needs to be
funded by someone, which in general will be other electricity customers.
ACIL Tasman also noted that:
Even if the FiT payment is equal to the sum of the network and energy value
of distributed generation, an X for one FiT causes equity issues. These arise
because customers who generate electricity and use it on site reduce the
amount of network charges they pay (because these are charged on a per
kWh basis). However, there is no particular reason to expect that the
network value provided by a distributed generator will increase in
3 Section 40I of the Electricity Industry Act 2000 (Vic) enables the Minister for Energy and Resources to refer
retailer FiT offers to the ESC for assessment when not satisfied that a term or condition is ‗fair and reasonable‘.
A guidance paper which outlines the methodology for the assessment of fair and reasonable FiTs and terms
and conditions was released by the ESC in March 2008 which refers to a one-for-one tariff.
94 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENEATION
proportion to the reduction in that customer’s electricity use … regardless of
whether X for one FiTs are efficient, they are inequitable. (ACIL Tasman
2012b, pp. 61–62)
As discussed in chapter 3, efficient FiTs have equity benefits whereas cross-
subsidised FiTs risk creating inequitable outcomes. In the Commission‘s view, the
equity impact of FiTs will depend on pricing policies and the nature and extent of
any resulting subsides to particular groups. An efficient distributed generation
model will have positive long-term benefits for all energy users.
5.4.1 Is there competition within the Victorian electricity
retail market?
In a competitive and well informed energy market it is reasonable to assume that
competition between the various energy retailers would lead to efficient price and
service outcomes. In an ideal scenario price would reflect the true value of the
electricity supplied taking into account factors such as the time and location the
electricity is produced, and the demand at that time and location. If the price is
determined within a competitive retail market, it is reasonable to assume that this would
be consistent with a ‗fair and reasonable‘ price.
It is relevant therefore to consider whether there is effective competition within the
Victorian electricity retail market.
Since 2002, when full retail competition commenced, Victorian electricity customers
have had the opportunity to choose their preferred electricity retailer from an
increasingly larger pool of energy retail businesses. The objective of this move toward
retail competition was to deliver efficient prices and services to energy customers and
the opportunity for customers to exercise choice among competing retailers and their
price and service offerings. The extent to which consumers are exercising choice is
partly reflected in the volume of transfers occurring between the various retail
businesses. Recent data showing small consumer transfers each month is shown in the
figure 5.1 below.
Table 5.3 Transfer statistics – February 2012
NSW Qld SA Vic
Small consumer transfers
completed in February
2012
44 220 19 808 16 350 51 983
Total number of
consumers transferred in
the NEM to date
3 038 602 1 391 268 1 189 291 5 085 079
1 month annualised
transfer rate 16% 12% 23% 23%
Source: (AEMO 2012).
VICTORIAN FEED-IN TARIFFS: SELLING ELECTRICITY 95
Figure 5.1 Monthly small customer transfers between
retailers: February 2010 to February 2012
Source: (AEMO 2012)
Recent reviews of the effectiveness of retail energy market competition
in Victoria
Following reviews of the effectiveness of energy retail competition in Victoria by the ESC
in 2002 and 2004, the Australian Energy Market Commission (AEMC) released its final
report of a Review of the Effectiveness of Competition in Electricity and Gas Retail
Markets in Victoria in 2007.
The AEMC found that competition in the Victorian electricity retail sector was effective.
In particular it found that:
The majority of energy customers are participating actively in the
competitive market by exercising choice among available retailers as well
as price and service offerings. There is strong rivalry between energy
retailers, facilitated by the current market structures and entry conditions.
Customers are demonstrating a clear willingness to participate in the
competitive retail market if approached directly by a retailer ...
… retailers have a strong incentive to be pro-active in seeking and retaining
customers in competition with other rivals. [With] evidence of vigorous
marketing rivalry between retailers who are contacting customers directly.
Retailers are offering customers discounted tariffs together with a range of
non-price incentives in an effort to differentiate their energy services from
those of their rivals …
The current market conditions encourage efficient entry, thereby creating a
credible threat of competition from actual or potential new retailers and
constraining the pricing and output decisions of existing retailers. (AEMC
2007, p.vii, ix–x)
5000
10000
15000
20000
25000
30000
35000
40000
45000
50000
55000
60000
65000
70000
75000
Ma
r-1
0
Ap
r-1
0
Ma
y-1
0
Jun
-10
Jul-1
0
Au
g-1
0
Se
p-1
0
Oc
t-1
0
No
v-1
0
De
c-1
0
Jan
-11
Feb
-11
Ma
r-1
1
Ap
r-1
1
Ma
y-1
1
Jun
-11
Jul-1
1
Au
g-1
1
Se
p-1
1
Oc
t-1
1
No
v-1
1
De
c-1
1
Jan
-12
Feb
-12
Ma
r-1
2
VIC NSW QLD SA
96 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENEATION
The Commission notes that the review undertaken by the AEMC was in the context of
the market for the retail supply of electricity and not in the Victorian FiT market. While it
may be useful to rely on the AEMC finding as a proxy to infer that there is effective
competition in Victorian FiT market, the Commission notes that, in practice, retailer
processes and responsiveness to attracting new customers appear to be more active in
the retail electricity supply market than for distributed generation. Some reasons why
this may be the case include:
The complexity of the decisions involved in assessing the case for installing
distributed generation and selling the excess electricity is greater than for
purchasing electricity alone
There is currently a lot of change in the broader regulatory environment for retail
customers, including distributed generators. This is likely to add to the uncertainty
and confusion in the market in the near term
Many retailers and most, if not all, major retailers own centralised generation assets
which may affect their incentives to offer competitive tariffs to distributed
generation that potentially competes with their own generation businesses
Some sectors of the market have only emerged recently. Consumers and retailers
have not had the opportunity to develop systems and expertise and gain the
experience needed to operate in a competitive market.
Removal of electricity retail price regulation in Victoria in 2009
The findings of the review undertaken by the AEMC formed the basis for the removal of
electricity (and gas) retail price regulation in Victoria in January 2009. The Commission
notes that s 13 of the Electricity Industry Act 2000 (Vic) (EI Act) allows for the
reintroduction of price regulation in the event that the AEMC concludes that
competition in the retail market for electricity is not effective and recommends price
controls be reintroduced. (This would be based on the findings of a, MCE directed,
review by the AEMC).
In a submission to the Independent Pricing and Regulatory Tribunal (IPART) review of
solar FiTs, Origin Energy noted that ‗the nature of the feed-in tariff ―market‖ is very
different from energy supply to a small customer as a result of retailers being the
consumers of the energy exported by PV customers‘. However, IPART did not accept
this view ‗given that customers purchase both ―services‖ — the services being the retail
supply of electricity and the provision of feed-in tariffs for electricity exported to the
grid‘ (IPART 2011, p. 129). IPART also noted:
If the NSW Government determines that the [NSW retail electricity] market is
sufficiently competitive to remove retail price regulation, then arguably,
there would be no need to provide a regulatory framework for feed-in
tariffs. (IPART 2011, p. 16)
Current feed-in tariff offers
Current FiT legislation requires electricity retailers to publish their FiT offer terms and
conditions relating to each of the FiT schemes in the Government Gazette and on their
website.
AGL made the point that most energy retailers are voluntarily offering a FiT for
renewable embedded generation. AGL stated that it ‗believes that no market failure
has been identified which justifies additional mandated feed-in tariff policies being
introduced or maintained‘ (sub. 72, p. 2).
VICTORIAN FEED-IN TARIFFS: SELLING ELECTRICITY 97
The information provided on Victorian electricity retailer websites and in the
Government Gazette is summarised below (table 5.4). The Commission notes that some
retailers are offering FiTs that are greater than the TFit and PFiT statutory minimum tariff
price. The additional or ‗top up‘ amount ranges between 2 and 8 cents per kWh — this
may reflect the additional value of the solar PV generated electricity to the retailer.
Table 5.4 Example of retailer feed-in tariffs
Retailer Distribution zone Standard FiT
c/kWh
Transitional
FiT c/kWh
Premium FiT
c/kWh
AGL All 33 68
Jemena – Domestic General 21.38
Jemena – Small Business 24.79
United Energy – Domestic
General 20.61
United Energy – Small Business 26.32
CitiPower – Domestic
General 18.99
CitiPower – Small Business 23.19
Powercor – Domestic
General 22.01
Powercor – Small Business 23.63
SP Ausnet – Domestic
General 22.47
SP Ausnet – Small Business 29.03
Australian Power
and Gas 25 60
Click Energy 25 60
Country Energy 31 60
Diamond Energy 33 68
Dodo 25 60
Energy Australia 25 60
Lumo 25 60
Momentum 25 60
Neighbourhood
Energy 25 60
Origin All 23.5 31 66
Powerdirect 31 68
TRUenergy SP Ausnet 22.5 25
CitiPower 19.4
United 20.5
Red Energy All 27.5 62
Jemena 27.28
CitiPower 23.32
Powercor Zone 1 25.96
Powercor Zone 2 26.51
SP Ausnet 23.1
United Energy 19.91
Simply Energy 31 66
Note: As at 30 March 2012
Source: (DPI 2012d) and Commission analysis.
98 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENEATION
In contrast to the point made by AGL, some participants argued that from their
experience retailers are reluctant to offer a FiT if there is no requirement to do so. For
example, CFCL commented that with the exception of Origin Energy in the context of a
particular demonstration project:
… based on our discussions with many retailers over several years we do not
believe that retailers would offer a fair and reasonable rate without being
required to. (sub. 41, p. 16)
Warbuton Community Hydro Project also referred to some difficulties in reaching
agreement with retailers:
… our project has had some difficulty in identifying retailers willing to enter
into an agreement with us under the SFiT. This is in large part due to the lack
of similar projects as ourselves, and the overwhelming number of
households seeking connection under the PFiT. In large retailing
organisations it has been difficult to find the person or team responsible for
SFiT‘s, even when they publicly publish documents on websites stating they
do offer such arrangements in line with the legislation. Those that do offer
them often limit them in terms of MWHrs annually, which seems to us not to
be in the intent or legislation of the SFiT. (sub. 69, p. 3)
In the presence of a competitive market for electricity from distributed generation,
there is no rationale for government intervention, unless it can be demonstrated that
there are significant impediments (market failures) that would lead to inefficient
outcomes. While there is sufficient evidence to suggest that the retail electricity market
is competitive, participants were concerned that retailers are not as responsive to
distributed generation. For example, unlike the process for changing retailers to supply
electricity, signing up to a FiT is complex and lengthy.
These experiences raise questions about whether the behaviour in the market for
electricity from distributed generation reflects that which would be expected in a
competitive market that would set ‗fair and reasonable‘ FiTs. The potential barriers are
discussed further below.
5.5 Are there barriers preventing the establishment
of ‘fair and reasonable’ feed-in tariff prices?
5.5.1 Structural issues
The current regulated structure of the electricity industry contains impediments to the
establishment of fair and reasonable FiTs. The current structure separates retail,
distribution and generation businesses. Furthermore, while distributors and transmission
businesses operate under a price or revenue cap, the retail sector operates in a
competitive market. These structures can impact the incentives faced by retailers,
particularly when they may not be able to access the full benefits of electricity
exported by distributed generators.
It is important to note that due to the disaggregated centralised energy
supply chain in Australia, no one business in this supply chain can capture
the full value of the distributed energy. This acts to dilute the incentive to
invest, and has the potential to result in significant investments that do not
achieve socially efficient energy supply. (CSIRO 2009, p. 40)
VICTORIAN FEED-IN TARIFFS: SELLING ELECTRICITY 99
Given these structural realities, there is potential that retail businesses will not be in a
position to offer of FiT that is truly reflective of the value of the electricity to the network.
For instance, retailers may not be able to access monetary rewards for the broader
system benefits (such as reduced augmentation of the network) attributable to the
installation of distributed generators. This results in a FiT that will be less than the true
value of the electricity generated in those locations where distributed generation has
network benefits.
However, the potential solution(s) to this issue are likely to be resolved through
amendments to the broader network regulatory arrangements which will ensure that
appropriate incentives exist to efficiently accommodate distributed generation. In
relation to this issue, ACIL Tasman noted:
Our view is that it would be more appropriate to address any shortcoming
in the economic regulatory regime by changing those arrangements than
by adding to the complexity of regulated FiTs. (ACIL Tasman 2012b, p. 43)
For the reasons outlined in chapter 6, the Commission‘s view tis hat a FiT is not the
appropriate regulatory instrument to resolve these, more fundamental issues, which
may be improved by various reform processes currently being pursued at a national
level (for example, by the AEMC). Processes for providing value to distributed
generators for network benefits are discussed in chapter 6.
Impacts of other policy settings
In relation to medium-scale distributed generation, there may be some concern from
distributed generation proponents regarding:
the ability to attract a retail FiT
barriers to selling (exporting) electricity — a need to obtain a retail licence to on-sell
electricity through the grid, and regulations that support retail contestability (which
constrain distributed generation proponents‘ ability to require local users to take up
locally generated electricity).
These constraints increase the commercial risk associated with distributed generation
projects. Not being able to require local users (such as building tenants or users in a
defined precinct) to take distributed generation as a condition of locating in the area
makes it difficult to estimate and guarantee base-load demand. Combined with the
potential difficulty in establishing a FiT for surplus electricity, this makes demand
uncertain and can lead to the scale of projects being smaller than technically efficient
(particularly in the case of co-generation). In the case of distributed generation for an
office or commercial building, for example, distributed generation units may be scaled
so they do not generate the full building load to avoid the risk of underutilisation of
capital and sub-optimal financial returns, which may occur if tenants choose a
network-based retailer.
While retail contestability rules are designed to increase competition, the Commission is
considering whether the Victorian Government should consider mechanisms that allow
building owners to sign new tenants to an agreed electricity contract for distributed
generation as a condition of their tenancy.
On-selling of distributed generation from 1 July 2012
When the National Energy Customer Framework (NECF) commences on 1 July 2012,
electricity retailers will be regulated by a retailer authorisation and exemption regime,
administered by the AER. Under this framework, sellers of electricity are required to have
100 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENEATION
a retailer authorisation or be exempt from the requirement to have an authorisation.
The AER has published an Exempt Selling Guideline (2011c), which sets out its approach
to retail exemptions and the types of available exemptions: deemed, registrable and
individual exemptions. The AER may grant a retail exemption subject to specific
conditions.
Retail exemptions commonly apply where electricity is being ‗on-sold‘ within an
embedded network. For example, shopping complexes, caravan parks, retirement
villages and bodies corporate (AER 2011c, pp.2–3). Under the National Energy Retail
Law (NERL), the AER must consider a number of policy principles (including choice of
retailer) and may consider exempt seller characteristics and customer-related factors,
in determining retail exemptions (s 114).
The AER considers that exempt selling is often not in the long term interests
of customers. We have seen particular growth in on selling within high
density residential developments such as apartment buildings. We do not
want on selling to be a motivating factor for developers in deciding how
these developments are structured… The most effective way of affording
customers the right to a choice of retailer is to ensure that network
configuration and metering arrangements for new developments and
redevelopments facilitate customer choice of retailer going forward. (AER
2011c, pp.3, 8)
The Exempt Selling Guideline advises that decentralised energy (including on-site
co-generation and tri-generation) will be treated as an ‗exempt seller characteristic‘ and
on-site distributed generators will need to apply for an individual retail exemption on a
case-by-case basis. The Guideline states that the AER ‗will grant exemptions in these
situations where the initiative is in the long term interests of energy consumers having
regard to all of the criteria and factors we are required to assess‘ (AER 2011c, p.17).
The regulatory constrains to on-selling of distributed generation appear to have been,
or are in the process of being, addressed in the United Kingdom and Sydney (box 5.1).
VICTORIAN FEED-IN TARIFFS: SELLING ELECTRICITY 101
Box 5.1 On-selling of distributed generation in the United
Kingdom and Sydney
As part of the consultation process to develop the Exempt Selling Guideline, the
Australian Energy Regulator published an issues paper on retail exemptions in June
2010 and invited submissions from interested parties. A submission from the City of
Sydney discussed the Woking and London models in the United Kingdom (UK) and
the proposed Sydney model, part of the municipality‘s Decentralised Energy Master
Plan 2010-2030.
In the UK, decentralised energy was stimulated by the Electricity
(Exemption from the Requirements for a Licence) Order 2001 which led
to the Woking private wire and other decentralised energy systems.
These were class exemptions, so permission was not required from any of
the vested interest energy players, including the distribution network
operator, or the regulator – the Office of Gas and Electricity Markets
(Ofgem). Compliance with the order was sufficient to implement
decentralised energy projects.
The exemption supply limits were 50 megawatts (without Secretary of
State approval) or 100 megawatts (with Secretary of State approval) for
each generation site over private wires. This enabled significant growth
in non-residential supply. However, the exempt limit for home use was
only one megawatt (about 1,000 homes) for each generation site with
limited exempt aggregated supply over public wires. This enabled the
growth of decentralised energy in towns and cities such as Woking and
London and led to the enactment of the Electricity Supply Licence
Modification 2009 or local electricity supplier licenses to retail electricity
over the local public wires distribution network based on the ‗virtual
private wire‘ over public wires principle…
The City of Sydney model will utilise and take advantage of the
knowledge and features of both the Woking and London models but
adapted for the City of Sydney environment. The barriers to
decentralised energy and the solutions to those barriers are very similar
to those encountered in the Woking and London models.
Therefore, the strategic direction for the City’s own trigeneration and
renewable energy projects for its own property portfolio will need to
follow the foregoing principles by establishing decentralised energy
projects specifically designed to trade electricity with each other across
the local distribution networks using the ‗virtual private wire’ concept
and to utilise and incorporate other related monitoring and control
systems, such as Building Energy Management Systems, monitoring and
targeting software and metering, to provide a ‗smart grid’ approach to
delivering the Sustainable Sydney 2030 targets.
Source: (City of Sydney 2010, pp.3–4, appendix 1: 10–11; AER nd).
Information
request
Does the process for applying for an individual retail exemption
under the Australian Energy Regulator‘s Exempt Selling Guideline
(2011c) address the regulatory constraints on distributed generators
who on-sell electricity? If not, what changes might be made to
reduce those constraints without compromising competition and
contestability in the retail electricity industry?
102 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENEATION
5.5.2 Information and transaction costs
In a well-functioning market, both the sellers of electricity (the owner of the distributed
generator) and the purchaser (the retail energy business) would have access to
sufficient information to make informed decisions and complete transactions. While
having access to information is critical, it is also important that the information is in a
form that is clear and accessible to the customer.
As noted by the AEMC:
When consumers are unable to access necessary information, or the
information which is available is perceived to be complex and costly to
decipher, there is a risk that consumers (or specific groups of consumers)
are not sufficiently well-informed. Consequently, consumers may make
inefficient decisions. (AEMC 2011d, p. 29)
Two potential problems may arise. First, information may be costly to obtain, particularly
for individuals participating in the small-scale distributed generator market. Without
adequate information, individuals may decide to not participate in the market, leading
to less than optimal levels of distributed generation. Alternatively, they may make poor
decisions where the products they purchase do not deliver the outcomes they expect.
Second, there may be information asymmetries, where one side of the market (for
example, the retailer) is more informed about the value of the benefits and costs of the
electricity being fed into the distribution system.
ACIL Tasman noted that:
Distributed generators, particularly residential and small business customers,
generally do not have perfect information as to the true value of the
electricity they would export to the grid ... (ACIL Tasman 2012b, p. 40)
This additional information could be used by the retailer to negotiate a price that is
lower than what would have been achieved if all parties had access to the same
information.
The Energy and Water Ombudsman Victoria (EWOV) noted that:
Between 1 January 2011 and 31 December 2011, EWOV received 8,524
solar cases and registered 17,993 solar case issues. During this period, 21%
of these cases - 1,805 cases and 3,229 issues - were about issues with the
application of the Premium Feed-in Tariff (PFiT) and Standard Feed-in Tariffs
(SFiT). (sub. 48, p. 1)
A case study provided by EWOV highlights some of the difficulties faced by consumers,
particularly when incorrect information is provided.
The customer owns two properties and decided to place solar panels on his
holiday home after his electricity retailer confirmed in writing that he will be
able to receive PFiT credits for this property. However, after the panels were
installed he received a PFiT form that stated eligibility required the residence
to be the primary residence of the customer. The electricity retailer
subsequently confirmed that he will not be able to receive PFiT credits for
this property. As a result of EWOV's investigation, the electricity retailer paid
the customer $2,800 in recognition of providing incorrect information.
(sub. 48, p. 3)
VICTORIAN FEED-IN TARIFFS: SELLING ELECTRICITY 103
The Commission notes cases come to EWOV only after customers have been unable to
resolve their complaint directly with their electricity retailer or distributor and have
subsequently chosen to take the complaint further.
Ideally data would be publicly available to allow FiTs to be compared. In this regard,
the Commission notes that the EI Act currently requires Victorian retailers to publish FIT
information (including tariffs and terms and conditions) as part of their retail licence
conditions.
The Commission has undertaken desktop research to determine the extent of
information on FiT offer terms and conditions available online. A number of
non-governmental organisations and businesses publish price comparator information,
including the Moreland Energy Foundation (Moreland Energy Foundation 2009) and
Energy Matters (Energy Matters 2009). However, much of this information is out of date.
The ESC‘s ‗YourChoice‘ website, allows comparison of retail electricity supply offers, but
does not allow direct comparison of FiTs.
The Commission has also visited electricity retailer websites to compare the information
available on FiT offers. The Commission notes that individual retailers present the terms
and conditions of their FiT offers in different formats and it is often hard to find
information on specific terms and conditions, making it difficult to compare offers
across retailers. In some cases electricity retailers have combined all offers into one set
of terms and conditions; in others they have separated the offers into discrete terms
and conditions.
This is consistent with observations made by the IPART in relation to information
disclosure by retailers operating in New South Wales:
We are concerned that the current practices of retailers in disclosing the
key features of their [FiT] offers are not assisting customers to assess these
offers and make well informed decisions. (IPART 2012, p. 99)
The Commission notes that IPART, in recommending a benchmark range for a ‗fair and
reasonable‘ FiT, argued that:
… our recommended form of regulation needs to be supported by actions
to improve the quality and accessibility of information available to
customers about the financial consequences of installing PV generation
and retailers‘ voluntary feed-in tariff offers. (IPART 2012, p. 98)
Information and transaction cost issues — including those resulting from the complexity
of the market, changing regulatory environment and the potential barriers to
competition resulting from the industry‘s structure — were discussed in section 5.5.1. In
addition, consumer regulation in the retail electricity market is in a state of flux as
responsibility shifts to the AER and new connection processes and charging regimes are
introduced. These changes add further to uncertainty in the market.
104 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENEATION
5.5.3 Market power issues: vertical integration of retail
energy businesses
There are significant ownership links between the energy retail market and upstream
energy production (including in renewable energy) (box 5.2).
Box 5.2 Examples of ownership links between energy
retailers and upstream energy production
AGL Energy
owns a number of wind farms
owns 10 hydro-electric generating schemes (comprising 16 power stations in
Victoria and New South Wales)
owns and operates two gas fired electricity generation plants in South Australia
and Victoria
has a 32.5 per cent equity investment in Loy Yang Power( one of Australia‘s
largest coal-fired power stations)
owns and operates several renewable landfill gas and biogas (sewage)
generation facilities
owns and operates a 4.4 MW gas fired cogeneration plant at Symex Holdings in
Port Melbourne
owns one large scale solar electricity generator.
Origin Energy
Has a generation portfolio of 5,310 MW
operates eight power stations (mainly gas fired)
has a 50 per cent interest in three cogeneration plants
owns a wind farm facility.
TRUenergy
owns and operates a portfolio of electricity generation facilities, including coal
(Yallourn in Victoria), gas and wind assets
Snowy Hydro
owns Red Energy
Hydro Tasmania
owns Momentum Energy
Source: Commission analysis of retailer websites.
Some participants claimed vertical integration of retail energy businesses with upstream
generation facilities may impact on the incentives retailers face when engaging and
negotiating a FiT with small-scale (or aggregated groups of) generators. A view was
expressed by the Australian Solar Roundtable that:
The market for power from distributed and embedded generation is
distorted by an imbalance of market power. A small number of players
dominate the market. (sub. 56, p. 9)
VICTORIAN FEED-IN TARIFFS: SELLING ELECTRICITY 105
The Commission considers that following a transition period, this issue is not likely to
represent a significant barrier to the establishment of ‗fair and reasonable‘ FiTs.
5.5.4 Limitations on time of use and locational pricing
Electricity use varies widely depending on the time of day and season. At times there
are large peaks in demand which drive much of the cost of generating and supplying
electricity. Large peaks in demand may cause network congestion in particular
locations, and lead to increases in the wholesale price of electricity when this is
supplied from more expensive peak supply sources (for example, gas-fired generators).
Time of use and location have two elements that impact on the value of distributed
generation:
Network value — at locations where the network is congested there is additional
value to distributed generation that produces at times when the extra local supply
delays network investment. The Commission has concluded that FiTs are not a good
way to approximate or reward distributed generation for this capital value
(chapter 6)
Energy value — output from distributed generation will have more value in
locations where the system losses from transporting electricity from centralised
generators are high and at times when demand is at its peak so the costs of
purchasing electricity on the wholesale market are high. These values should be
reflected in an efficient FiT and provide incentives for people to invest in distributed
generation.
Smart meters can allow consumers to monitor their electricity use more closely and
make more informed decisions about when and how they use electricity. Having
access to time of use and locational pricing information would also allow customers
considering installing distributed generation technology access to better information to
guide their decision-making process.
As noted by ACIL Tasman:
Peak demand, or a closer proxy such as the maximum electricity consumed
in any half hour interval, will be able to be measured with the smart meters
that are currently being installed in Victoria. However, there is currently a
moratorium presenting the additional information collected by these meters
being used in retail electricity pricing, although it has recently begun to be
used in settling the wholesale market. Customers with smart meters are
being billed as if they had the historic type of meters. This will continue for as
long as the moratorium is in effect, until 2013. (ACIL Tasman 2012b, p. 26)
Access to better information (price signals), within a competitive electricity market is
likely to lead to FiTs that better reflect the value of distributed generation. The
Commission notes that there is currently a ban on the rollout of time of use retail prices
before 2013. Modelling undertaken by Deloitte Access Economics indicated that
banning time of use tariffs until at least 2013 delays about 24 per cent ($490 million) of
the estimated benefits of smart meters, the proportion of the benefits attributable to
time of use tariffs and demand management (DAE 2011, p. 13).
106 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENEATION
5.5.5 Conclusion on fair and reasonable prices
While there is sufficient evidence to suggest that the retail electricity market is
competitive, participants were concerned that retailers are not as responsive to
distributed generation. For example, unlike the process for changing retailers to supply
electricity, the processes for signing up to a FiT is complex and lengthy. And DG
proponents, particularly in area not subject to regulated FiTs, have found it difficult to
negotiate a FiT for electricity fed into the network. These experiences raise questions
about whether the behaviour in the market for electricity from distributed generation
reflects that which would be expected in a competitive market that would set ‗fair and
reasonable‘ FiTs.
The Commission considers the underlying causes of these difficult, complex and lengthy
processes are likely to include:
structural issues relating to the separation of distributors and retailers
information and transactions costs
market power issues
limitations on time of use and locational pricing
uncertainty of the regulatory environment, coupled with the transition to a national
regime.
While on its own none of the above factors constitute a market barrier sufficient to
prevent competitive outcomes from emerging (as long as adequate consumer
protection, transparency and information is provided) combined they are likely to
present significant short term barriers.
A number of the changes in the NEM that are underway or have been foreshadowed
are likely to reduce these barriers, as will the Commission‘s draft recommendations in
chapter 4, if accepted. Other aspects can be addressed through consumer protection,
reasonable access to information and maturing of the market. Accordingly, the
Commission considers a market-based FiT is likely to provide the most efficient outcome
in the long term. However, there are important transition issues and in the short term
moving too rapidly to market determined FiTs may cause unnecessary disruption and
hinder the transition to a fully competitive market. These issues are discussed further in
chapter 6.
5.6 Conclusion
The objectives for feed-in tariffs going forward
Victorian FiTs have a number of objectives which appear to be based on previously
identified issues or perceived problems. One of the main drivers appears to be related
to reducing greenhouse gas emissions. However, given the introduction of a ‗price on
carbon pollution‘ by the Commonwealth Government and other current
Commonwealth initiatives (for example, RET, LRET and SRES), the Commission considers
the Victorian FiT(s) are not the most appropriate regulatory instrument to assign to this
objective. It should also be noted that given the carbon tax will affect the wholesale
price of electricity, it will be automatically incorporated into the value of a market-
based FiT.
Supporting the development of a particular industry (for example, solar PV) appears to
be a further objective of the current FiTs. The Commission‘s view is that pursuing this
objective is likely to be highly distortionary. From a solar industry perspective this may
VICTORIAN FEED-IN TARIFFS: SELLING ELECTRICITY 107
create significant benefits. However pursuing the development of one industry (either
through a higher regulated FiT for solar PV, or through eligibility criteria which favours
solar PV) can be at the expense of other distribution generation technologies, or more
broadly other industry sectors that supply innovative approaches to minimising
electricity usage.
Ensuring that households and small businesses have access to a fair and reasonable
price for exported electricity is an important FiT objective, and is the most relevant
objective underpinning any future FiT arrangements. This is consistent with COAG
national FiT principles.
Tariff/price component
Victorian FiTs establish a minimum price for electricity exported to the grid whether it is
60 cents per kilowatt hour under the PFiT, 25 cents per kilowatt hour under the TFiT or a
one-for-one price under the SFiT. The Commission considers these prices are probably
above what would be expected in a well-informed competitive market. Given current
eligibility criteria which favour solar PV and to a lesser extent other ‗renewables‘ it could
be expected that this will artificially increase the take up of these technologies, and
impose increases in electricity prices for non-users of solar PV. These cross-subsidies are
regressive to a greater or lesser extent.
The regulated PFiT and TFiT are based on an assumed payback period for solar PV
systems. This is inconsistent with the Commission‘s view that the price for exported
energy should be based broadly on the value of the electricity to the network, and that
this price should be determined within a well-informed competitive retail electricity
market. Market determined FiTs would be consistent with a fair and reasonable price.
Feed-in tariff eligibility
The main FiT eligibility criteria relate to both the capacity or size of the distributed
generation system and the technology (table 5.5).
Table 5.5 Feed-in tariff eligibility – technology and capacity
Type of FiT Eligible technology System capacity
PFiT Solar PV 5kW or less
TFiT Solar PV 5 kW or less
SFiT Small renewable energy generation
facilities (solar, wind, hydro and biomass)
connected to the distribution network
Less than 100 kW (excludes
solar PV with a capacity of
5kW or less)
Notes: See Appendix B for greater detail on the various FiT schemes
Source: Commission analysis
As noted in chapter 3, the Commission considers that FiTs should not unnecessarily
favour one technology over another. There should be technology neutrality, with
differences in policy or approach only justified on technical or other appropriate
grounds. This would help support efficient market outcomes by ensuring that the
relative merits of all technologies are considered and no single approach is
advantaged over another. The terms of reference for this inquiry refer to renewable
and low-emission technologies, and it is these that the Commission has focused on —
that is that eligible technology embraces at least renewable and low-emission
distributed generators.
FUTURE VICTORIAN FEED-IN TARIFF ARRANGEMENTS 109
6 Future Victorian feed-in tariff arrangements
The terms of reference require the Commission to:
(1) assess the design, efficiency and effectiveness of feed-in tariff (FiT) schemes,
including market-based gross FiT schemes, in the context of a national carbon price
(2) provide a recommendation as to whether existing FiT arrangements should be
continued, phased out or amended. Where phase-out of existing arrangements is
proposed, the appraisal should give consideration to whether any transitional
arrangements may be necessary. Any changes to existing arrangements would not
be applied retrospectively.
This chapter addresses these two issues.
In approaching these issues the Commission considers the key policy objective in
relation to distributed generation (including renewable and low-emission technologies)
is to contribute to achieving the National Electricity Objective (NEO), in a way that
achieves efficiency and effectiveness without cross-subsidies.
The key to this matter is to identify the sources of economic value from distributed
generation and strengthen the competitive frameworks for achieving that value,
having regard to the impending introduction of the carbon tax from 1 July 2012.
The two key components of value from distributed generation are the energy value
(which will shortly incorporate the carbon tax) and the network value. The energy value
refers to the value of the electricity actually generated, for which price (or FiT in the
case of ‗household‘ scale generators) is the right mechanism. The Commission
considers determining this price in competitive markets, with appropriate safeguards, is
most likely to result in prices that are efficient, do not result in regressive cross-subsidies
from one class of consumer to another, and are technology-neutral. Previous and
current FiTs do not meet these tests. In this context, well-designed market-based FiTs can
play a useful role in a relatively quick transition to a competitively determined price for
‗household‘ scale distributed generation.
While market-based gross FiT schemes have merit, Victoria is at a point where moving to
such schemes would carry significant costs. However, such price schemes may
ultimately emerge from a competitive process and should not be ruled out. These
matters are addressed in detail in section 6.2.
Moving to efficient, market-determined prices for distributed generation would best
capture the energy value. A key policy challenge is how best to capture the network
value, which the Commission considers may be significant in some locations, but not all.
Network value is a capital value that is location specific and time dependant in that it
arises from the value of deferring network investment. The value is not captured through
a price of energy generated — indeed attempting to do so would lead to regressive
cross-subsidies from some groups of consumers. Proposed reforms to the National
Electricity Market (NEM) will help to reduce the current barriers, and enable the network
value to be better realised. However, this is likely to be a challenge in the absence of
more fundamental changes to incentives for key market agents, especially distribution
businesses. Network value is considered in further detail in section 6.2.
The Commission, in chapter 5, noted that distributed generation can contribute to
reducing greenhouse gas emissions. But, in the context of a price on carbon from 1 July
110 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
2012, reducing emissions is no longer a valid objective of Victorian FiT schemes on the
grounds that a more appropriate policy (market-based) instrument will operate shortly.1
Once the carbon tax is in place it will increase the wholesale price of electricity which
would be used to determine a fair a reasonable FiT.
Turning to the second term of reference, the Commission recommends that over time
the current Victorian regulated FiTs should be phased out. Future FiTs — more
accurately reflect the energy value of electricity for household-scale distributed
generation — should be determined by retail market competition. Market determined
FiTs would not discriminate against particular technologies or customers, rather they
would be based on the value of the electricity supplied by distributed generators
(which would include the impact of the carbon tax). This deregulation would be
supported by consumer protection and information measures and be phased in to
maintain certainty that the market will continue to offer a competitive FiT. Existing
contractual arrangements would be maintained.
Transitional arrangements should not unnecessarily impede the move to market-based
FiT arrangements. In summary, the Commission recommends a transitional arrangement
to improve the efficiency and effectiveness of the operation of FiTs in Victoria,
comprising:
That the Victorian Government:
close the Transitional FiT (TFiT), either by 31 December 2013 or once the 75 MW
capacity is reached (as currently provided in legislation), whichever occurs first
amend the Standard FiT (SFiT) to require that Victorian electricity retailers with 5 000
or more customers offer fair and reasonable prices for electricity exported to the
grid by all small low emissions or renewable distributed generators (100 kW or less)
until 31 December 2015
establish a fair and reasonable price for energy supplied by distributed generators
through the retail electricity market
define low-emissions technology as generators that produce 50 per cent or less of
the emissions intensity of electricity generation in Australia
allow market-determined arrangements based on gross payments by mutual
agreement
ensure that FiT prices are published by the Australian Energy Regulator (AER) under
the requirements of the National Electricity Customer Framework (NECF).
That the Essential Services Commission (ESC):
publish information on the likely range of wholesale market-based net FiT payments
which would be consistent with a fair and reasonable offer — updated at regular
intervals.
assess, as required, the extent to which FiT market offers are consistent with fair and
reasonable criteria, redefined to reflect the wholesale value of electricity (the
energy value).
1 The Commission notes that distributed generation would still assist in reducing greenhouse gas emissions.
FUTURE VICTORIAN FEED-IN TARIFF ARRANGEMENTS 111
6.1 Design, efficiency and effectiveness of feed-in
tariff schemes
This section addresses a range of design, efficiency and effectiveness issues including:
the value of distributed generation
market-based FiTs
eligibility
metering
information provision
billing arrangements.
6.1.1 The value of distributed generation
In chapter 5 the Commission concluded that the most appropriate objective of FiT
schemes is to ensure that households and small business have access to fair and
reasonable prices for electricity produced by distributed generators.
This objective raises a question regarding the value of distributed generation. ACIL
Tasman (2012) suggest that the value of distributed generation comprises:
The energy value2 of distributed generation, which arises when actual output from
a distributed generator reduces the amount of electricity that must be purchased
on the wholesale electricity market. The energy value of distributed generation is
based on the wholesale price of electricity adjusted for avoided network losses.
The network value of distributed generation, which arises when capacity from a
distributed generator enables a planned network augmentation to be deferred.
The network value of distributed generation is the difference between upgrading
the network sooner, and upgrading it later, taking into account the costs that a
distributed generator may impose on the network. The network value of the
distributed generator would be zero (or negative) in areas where the network is not
constrained. (ACIL Tasman 2012b, p.vii)
ACIL Tasman note that the FiT payment is better able to reflect the energy value of
electricity exported to the grid by a distributed generator, while a separate payment
(discussed in section 6.2) may be needed to reflect the network value of distributed
generation.
There are several FiT methodologies that have been used in Australian jurisdictions
which have been evaluated by ACIL Tasman on behalf of the Commission. These
include:
2 ACIL Tasman (2012b, p.14) note that the energy component of the cost of supplying electricity consists of:
the cost of purchasing electricity in the wholesale electricity market; the cost associated with emitting
greenhouse gases (from 1 July 2012); the cost associated with losses in transporting electricity from the
generator to customers; the cost of hedging the risk associated with purchasing electricity in the wholesale
market; and the cost associated with purchasing Renewable Energy Certificates.
112 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
(1) An X for one FiT — where the FiT payment is a multiple of the retail price of
electricity
(2) A payback FiT — where the FiT payment is calculated to ensure that a distributed
generator, ‗pays for itself‘ within a targeted period
(3) A wholesale market based FiT – where the FiT payment is based on the components
of the wholesale price of electricity that are avoided by the distributed generation.
Based on an assessment of these methodologies against efficiency, effectiveness,
equity and administrative simplicity criteria, ACIL Tasman concluded that:
None of the methodologies for calculating FiTs satisfy the efficiency or
effectiveness criteria and all have adverse equity implications.
The main issue is the inability of any of these FiTs to send appropriate signals
regarding the network value of distributed generation. Depending on
consumption and generation profiles, they exacerbate the inefficiency
arising from network pricing and create cross subsidies.
That said, the wholesale market based FiT is an efficient representation of the
energy value (only) of distributed generation. (ACIL Tasman 2012b, p.viii)
A summary of the assessment is shown in table 6.1.
Table 6.1 Assessment of feed-in tariff methodologies
Methodology Efficiency and
effectiveness Equity
Administrative
simplicity
X for one 1 1 4
Payback period 2 1 2
Wholesale price 3 3 3
Note: Score out of five, where a higher number implies a higher ranking.
Source: (ACIL Tasman 2012b, p.71).
FUTURE VICTORIAN FEED-IN TARIFF ARRANGEMENTS 113
Table 6.2 Example of feed-in tariff methodology strengths
and weaknesses
Methodology Strengths Weaknesses
X for one Administratively
simple
Overstates the energy value of distributed
generation particularly if x is set at 1
inequitable if payment exceeds sum of
energy value and network value of
distributed generation.
Payback period Degree of
certainty for
distributed
generator
investors
Determined without regard to the impact
the distributed generator has on the
electricity supply system
inefficient — they pay more for
generators with higher costs and less for
generators with lower costs
inequitable — if the payments are more
than the value of the distributed
generation and are funded by electricity
customers, this amounts to a
disproportionate burden on electricity
customers that do not have distributed
generation.
Wholesale price Provides a more
efficient payment
for the energy
exported to the
grid
Efficiency and effectiveness of the FiT is
limited by the assumptions that are
necessarily used in forecasting the value
of the electricity generated — the
forecast may or may not be an accurate
reflection of the actual costs avoided
customers with distributed generation
that are paid a wholesale market-based
FiT avoid paying for electricity they
generate and use on-site. In doing this,
they avoid the network component of
the retail price of electricity as well as the
energy component
more difficult to administer — need to
account for characteristics of different
generation technologies.
Source: (ACIL Tasman 2012b, pp.60–66).
The Commission requested that ACIL Tasman (2012b) provide indicative estimates of
the potential size of FiTs based on a wholesale price methodology. In moving to such a
methodology it is important to note that the wholesale price can vary dramatically
across different times of the day and year. The generation profile of different
technologies also varies with some producing more electricity when demand, and
hence the wholesale price, is highest. Therefore, if a FiT is set at a single rate, regardless
of the time of day or the level of the wholesale price, that rate would need to be
different for different technologies. To illustrate this point ACIL Tasman estimated FiTs for
various generation technologies (which have different generation profiles)3:
3 See ACIL Tasman (2012b) for a more detailed discussion on methodology and underlying assumptions.
114 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
Flat generation profile: represents a generator that generates constantly
throughout the year. This profile is presented mainly to illustrate the difference in
value between this generation profile and others, which target higher price periods.
Therefore, it was not adjusted for on-site consumption. This profile could be used to
represent a gas fired (or similar) generator in ‗always on’ mode or a fuel cell.
Solar generation profile: reflects a representative solar photovoltaic (PV) system
installed by a representative residential customer. It is assumed that the PV system
is 2.5 kW in capacity and, therefore generating 2.95 MWh each year based on the
number of small-scale technology certificates a system of that size is deemed to
produce.
Storage device: which imports electricity from the grid at one time of day (when
the electricity price is low) and exports it at another time (when the electricity price
is high). This profile is based loosely on the possible capabilities of an electric car.
Peak generator profile: represents a distributed generator that targets high price
periods. This profile could represent a stand-alone gas fired co-generation unit (or
similar) or a co-generation unit whose operator reduces demand during high price
periods to maximise electricity exports when prices are high. Three thresholds were
calculated so that the generator generated whenever the wholesale price
exceeded, $50 per MWh, $100 per MWh and $150 per MWh. The results for a
generator generating when the wholesale price is $100 per MWh are presented in
table 6.3.
From table 6.3 it can be seen that the estimated average energy value of distributed
generation in 2013 (for flat rate and solar PV generators most commonly used by
households) is the range of 5.7 – 7.8 cents per kWh depending on the distributed
generation technology. This range reflects the locations of the distributed generator. For
example, Yallourn represents a distributed generator (and relevant transmission and
distribution loss factors) nearest to existing centralised brown coal generators. For
Yallourn the transmission and distribution loss factors are therefore minimal compared
with Red Cliffs which is furthest from the Latrobe Valley.
Table 6.3 Estimated average energy value of distributed
generation for various generation profiles (nominal)
Generation Location 2013
cents per kWh
2014
cents per kWh
2015
cents per kWh
Flat Yallourn 5.7 6.5 6.9
Keilor 6.1 6.9 7.3
Red Cliffs 6.8 7.7 8.2
Solar PV Yallourn 6.6 9.7 11.7
Keilor 7.0 10.2 12.4
Red Cliffs 7.8 11.4 13.8
Storage device (battery) Yallourn 11.4 14.2 16.0
Keilor 12.0 15.0 16.9
Red Cliffs 13.4 16.8 18.9
Peak $100 Yallourn 58.8 75.8 49.9
Keilor 62.1 80.1 63.3
Red Cliffs 69.4 89.5 70.8
Source: (ACIL Tasman 2012b, p.81).
FUTURE VICTORIAN FEED-IN TARIFF ARRANGEMENTS 115
High FiTs do not necessarily lead to large incomes from selling electricity from the
distributed generator because the amount of electricity sold may be small. For
example, based on the 2013 estimates for a 1 kW generator, ACIL Tasman estimated
the average annual revenue for solar PV selling at a FiT of 7 cents per kWh, would be
$145. This compares with $46 for a peaking plant that sells electricity at 62 cents per
kWh when the wholesale price rises above $100 per MW –– see table ES 1 (ACIL Tasman
2012b, p.x).
The Commission encourages inquiry participants to review the ACIL Tasman report,
which is available on the Commission‘s website www.vcec.vic.gov.au, and welcomes
feedback on the methodology and estimates provided above.
The solar PV estimate provided above is within in a similar range to recent estimates for
solar PV by IPART in New South Wales and ESCOSA in South Australia (IPART 2012; ACIL
Tasman 2011b).4 These are shown in table 6.4.
The Commission observes that while the value of energy estimates differ (and may
represent variations in methodology) among the three jurisdictions, they are broadly of
a similar magnitude. Moreover, it is clear that these estimates for 2012 are well below all
three Victorian FiTs (60 cents per kWh, 25 cents per kWh and the current range of SFiT
offers, see chapter 5).
Table 6.4 IPART final estimates of the value of PV exports to
retailers (c/kWh, $2011/12)
Method used 2011/12 2012/13
Wholesale market value 5.2 – 7.0 7.5 – 9.8
Direct financial gain to retailers 8.3 – 10.3 TBC
Source: (IPART 2012, p.44).
4 The ACIL Tasman estimate is at the bottom end of the IPART estimate and below that of ESCOSA.
116 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
Table 6.5 ESCOSA value of exported PV output (nominal
cents per kWh)
2011 2012-13 2013-14
Both
scenarios
Carbon
scenario
No carbon
scenario
Carbon
scenario
No carbon
scenario
Reduced wholesale
electricity cost 6.4 8.9 8.1 10.2 9.0
Avoided losses 0.6 0.8 0.7 0.9 0.8
Market and
ancillary service
fees
0.1 0.1 0.1 0.1 0.1
Total 7.1 9.8 9.0 11.2 9.9
Source: (ACIL Tasman 2011b, p. iv)
In South Australia, all electricity retailers are required to provide the ESCOSA determined
FiT premium to solar customers. In addition to the FiT premium, the electricity distributor,
ETSA Utilities, is also required to provide a FiT to solar customers for electricity fed into its
network. The FiT amount provided by ETSA Utilities varies depending on the date at
which a solar customer is connected to its network. This requirement for the electricity
distributor to provide a FiT will cease for solar installations after 30 September 2013 —
with a retailer FiT payment (based on energy value) remaining.
Table 6.6 Summary of South Australia FiT scheme –
including electricity distribution FiT (nominal
c/kWh, GST exclusive
Solar PV Cell Installation/
Approval Date 2011-12 2012-13 2013-14
Class 1
Before 1 October 2011
7.1 + 44 =
51.1 c/kWh
9.8 + 44 =
53.8 c/kWh
11.2 + 44 =
55.2 c/kWh
Class 2
1 October 2011 – 30 September 2013
7.1 + 16 =
23.1 c/kWh
9.8 + 16 =
25.8 c/kWh
11.2 + 16 =
27.2 c/kWh
Class 3
From 1 October 2013
N/A N/A 11.2 c/kWh
Source: ESCOSA 2011
6.1.2 Market-based feed-in tariffs
The Commission agrees that the energy value of distributed generation should be
based with reference to the components of the wholesale price of electricity. A key
question is the extent to which this value (or price) can be determined within the
competitive retail electricity market.
As discussed in chapter 5, the Commission is of the view that the competitive market
should determine the FiT payment, provided that competition within the retail energy
market is effective. Given that condition, it is reasonable to assume the market
determined FiTs would be ‗fair and reasonable‘ and are likely to be at least consistent
with the energy value of the electricity supplied by the distributed generator.
FUTURE VICTORIAN FEED-IN TARIFF ARRANGEMENTS 117
Allowing the market to determine the FiT is a natural progression of the Victorian energy
market. As highlighted in chapter 5, Victoria removed retail price regulation of
electricity (an essential service) in 2009 — leaving this to the market to decide (within a
customer protection framework). This is consistent with IPART which recently
recommended that the market set FiTs.
Participant views
Some participants were concerned that a unregulated feed-in tariff would lead to
retailers choosing not to offer fair and reasonable rates for electricity exported to the
grid (Environment Victoria, sub. 51, p. 6). Others (including Australian Photovoltaic
Association, sub. 67, p. 4 and Alternative Technology Association, sub. 73, p. 2) argued
that a regulated FiT created investment certainty for consumers and industry players:
Properly designed and implemented, feed-in tariffs (FiTs) offer the best
opportunity to capture the market failures that exist in the national electricity
market (NEM) with respect to the cost effective utilisation of demand side
activities such as distributed generation (DG). As a policy mechanism, FiTs
also offer the greatest potential for investment certainty for consumers and
industry players in the relevant technology space. (sub. 73, p. 2)
From a retail perspective AGL argued that market determined FiTs were more
appropriate in the current environment where jurisdictions were moving towards
removing price controls where competition is effective:
Regulating such a tariff would be a significant retrograde step in relation to
microeconomic reform of Australia‘s energy markets. The Australian Energy
Market Agreement clearly articulates the agreement among all jurisdictions
to remove existing price regulation where competition is demonstrated to
be effective. Accordingly, adding a further regulatory pricing structure to
existing markets would be in contrast to the intent of the Australian Energy
Market Agreement. (sub. 72, p. 1)
The possibility that regulated FiTs may undermine the effectiveness of retail competition
was raised by the Energy Supply Association of Australia:
Setting a regulated FIT raises many risks. Setting it too high could result in
retailers paying far more than is justified for solar PV-generated electricity.
This may disadvantage those retailers with a higher proportion of customers
with solar PV. It would also discourage retailers from competing vigorously
for customers who have PV installed. This could then undermine retail
competition. Solar PV or other technologies may have a greater benefit in
certain areas. The market should be free to offer higher FITs to customers
whose generation offers greater benefit. Adopting a fixed FIT value removes
this possibility. (sub 74, p. 2)
6.1.3 Eligibility
Distributed generator technology
The Commission considers that FiT regulation should not discriminate in favour of any
particular technology. This is especially the case in the presence of a carbon price
which will, through changing the relative prices of electricity from various generators,
create incentives for efficient choices, and investment in generation technologies.
Investment in small-scale renewable technologies is further encouraged by the
Commonwealth Small-Scale Renewable Energy scheme (chapter 5). The following
118 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
discussion, however, focuses on broadening eligibility criteria to include ‗low-emission‘
technologies as well as renewables — consistent with reference to these technologies
in the terms of reference.
The current Victorian SFiT specifically applies to renewable technologies generating less
than 100 kW, such as solar PV (between 5 kW and 100 kW), hydro, biomass and wind. The
current arrangements, however, do not refer to generation technologies that may be
considered ‗low-emission‘. This point was raised by Ceramic Fuel Cells Limited (CFCL):
Ceramic Fuel Cells believes the current Victorian standard feed in tariff
regime should be extended to require electricity retailers to offer a fair and
reasonable tariff to any distributed generator which is small scale (100kW or
less) and less emissions intensive than the current power grid.
Extending the feed in tariff to a broader range of low emissions
technologies gives homes and businesses a wider choice of on-site energy
generation products. (sub. 41, p. 1)
Similarly Jemena (JEN) stated that:
Currently, the SFiT is limited to renewable energy and the PFiT and TFiT
schemes are limited to photovoltaic (PV) systems only. JEN believes the
future FiT arrangements should be extended to include low emission
generation—that is, technology neutrality should be a key feature of future
FiT arrangements. (sub. 79, p. 3)
The Commission previously noted that low emission technologies (renewable or not),
which demonstrate a capacity to significantly reduce greenhouse gas emissions,
should not be disadvantaged when seeking to enter the electricity market (VCEC 2009,
p.381). This raises a question regarding what constitutes a low emission distributed
generation technology.
Moreland Energy Foundation suggested that:
Low emissions generation should exclude systems with higher greenhouse
gas emissions per kWh produced than a high efficiency combined heat
and power or co-generation system. (sub. 75, p. 3)
CFCL commented:
We suggest the tariff apply to any product with lower emissions than the
existing emissions intensity of the Victorian grid. The Victorian grid has an
emissions intensity of 1.35 t CO2-e per MWh. This figure is already measured
and used in Victorian Government energy regulations …
Translating this threshold into policy would require a product to meet certain
minimum efficiency or emissions standards to be eligible: for instance, total
efficiency of at least 70%. This is not overly difficult or costly: regulation
already requires minimum performance or efficiency requirements for many
products. This criteria could be administered by Government (e.g. Essential
Services Commission) or approved industry groups (e.g. Clean Energy
Council) or regulators (e.g. Australian Gas Association, Energy Safe Victoria
etc). (sub. 41, p. 12)
Table 6.7 shows average emission intensities for a number of generator fuels.
FUTURE VICTORIAN FEED-IN TARIFF ARRANGEMENTS 119
Table 6.7 Emission intensity of selected generators by fuel
type
Fuel Type Average kg CO2-e/GJ of fuel over all
power stations
Black coal 91.1
Brown coal 92.6
Hydro 0
Liquid fuel 68.8
Natural gas 51.3
Wind 0
Solar PV 0
Source: (ACIL Tasman 2012a).
As noted in chapter 3 the Clean Energy Finance Corporation Expert Review
recommended that the eligibility for low-emissions technology be defined as
technologies that produce 50 per cent, or less, of the emissions intensity of electricity
generation in Australia (Commonwealth Government 2012c, p.15). The Commission is
disposed to adopt this definition of ‗low-emission‘.
Information
request
The Commission proposes that the eligibility for low-emissions
technology be defined as technologies that produce 50 per cent,
or less, of the emissions intensity of electricity generation in
Australia, as recommended by the Clean Energy Finance
Corporation Expert Review. Is this an appropriate definition to
apply to distributed generation?
In adopting this definition, are there any practical issues that will
need to be addressed?
Distributed generator size
The current FiT arrangements (combined) apply to distributed generators less than
100 kW. According to CitiPower/Powercor:
The Businesses consider that the scale of generation activity under a FiT
scheme should be 100kW. This is consistent with the current scale criterion
for Standard FiTs. A proponent generating above 100kW would be
operating at capacity beyond that of a household or small business and
would be in a position to negotiate their own contract for the exported
energy, as opposed to relying on a FiT scheme. (sub. 80, p. 4)
An alternative view was expressed by other participants. For instance it was suggested
that all small-scale renewable generators should be included up to 30 MW (Reeves,
sub. 27, p. 1). Similarly Christine Easdown suggested:
While it is important that feed-in tariffs be regulated to ensure that the
community receive a fair and reasonable price for green electricity fed
back into the grid, it is important to maintain a feed in tariff that will
encourage both domestic and community based renewable energy
projects of all sizes. (sub. 32, p. 1)
120 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
The Commission‘s preliminary view is that owners of generators greater than 100kW are
likely to be larger businesses, or commercial entities that have access to sufficient
resources to enable them to negotiate a FiT payment with a relevant retailer or
establish alternative arrangements for selling surplus electricity.
The Commission notes that the Australian Energy Market Operator (AEMO) recently
submitted a rule change to the Australian Energy Market Commission (AEMC) to
introduce a new category of market participant into the National Electricity Rules
called a 'small generation aggregator'. AMEC has released a consultation paper on
the rule change and is seeking public submissions by 12 April 2012. Under the proposed
rule change, small generation aggregators will only have to register once with AEMO. A
small generation aggregator will have market responsibility for the participation of
multiple generating units in the NEM. Separate registration of each of the generating
units would not be required, significantly reducing costs and improving access to the
market. This would allow distributed generators to use an aggregator to more easily
enter and sell in the NEM (AEMC 2012a, pp.1–5).
In relation to the size criteria it has been suggested that it should be 100kW or less
(rather than the current less than 100kW requirement). David Sparks noted that
If a potential owner of an embedded generator sets out to purchase a
generator it will be quickly realized that such machines in the range of 100
kW would be typically 75, 80, 100, 120, 150 kW etc. Therefore to utilize the full
potential of the DPI criteria it would be necessary be a little deceptive and
purchase a 100 kW generator and declare that it is 99 kW.
This is a genuine problem which I have encountered with retailers. (sub. 43, p. 2)
From a practical perspective, the Commission is disposed to propose a size eligibility
criterion for the SFiT of 100 kW or less, which is a marginal adjustment to the current SFiT
criterion.
6.1.4 Metering arrangements
Several submissions queried whether the FiT should be based on net or gross metering.
Before turning to this question it is important to understand the difference between the
two arrangements.
Customers with small-scale distributed generators (solar PV for example) may generate
electricity to meet their own demand, import electricity from the network in cases where
demand is greater than that supplied by their generator and export electricity to the
network in cases where their demand is less than that supplied by their generator. To
facilitate payment between the retailer and customer (for electricity imported or
exported from the grid) a meter is needed to record the units of electricity exported to
and imported from the grid. The way in which this measurement occurs for billing
purposes depends on whether the customer has ‗net‘ or ‗gross‘ metering arrangements.
Gross metering
Under gross metering all of the electricity generated by a customer (through a solar PV
system for example) is measured as is all of the electricity consumed by that customer.
A gross FiT is applied to all of the electricity that is generated (that is, including energy
consumed on-site) and the relevant retail price is applied to all the electricity
consumed, regardless of where it is generated. Therefore the gross meter measures the
entire output of the distributed generator separately to electricity consumption.
FUTURE VICTORIAN FEED-IN TARIFF ARRANGEMENTS 121
Net metering
Under net metering the electricity generated by a customer and that customer‘s
consumption of electricity is combined to arrive at a net outcome. Electricity
generated and consumed at the time of generation is not metered — the customer
does not pay for this electricity, and is also not paid for the amount generated at this
time. The internally generated electricity consumed by the customer is valued at the
retail price of electricity, as this is the amount that the customer saves.
If the amount generated is greater than the amount consumed at a particular point in
time, this amount is exported and measured — for which the customer receives the
applicable feed-in tariff. If the amount generated is less that the amount consumed at
a particular point in time, the required amount of electricity is imported and measured
— with the customer paying the applicable retail tariff.
Metering arrangements in other jurisdictions
Many FiTs worldwide are based on gross metering (and gross FiTs). In some cases
renewable electricity generators are paid a base rate for all the electricity they
generate, and a premium for any electricity exported into the grid.
Germany‘s FIT scheme, considered to be the world‘s most developed, operates under a
gross tariff. Under this scheme, solar PV generators are paid for electricity generated and
used on-site (approximately 9 euro cents per kWh for the first 30 per cent of their annual
electricity generation, and approximately 13 euro cents per kWh thereafter). Any
electricity exported into the grid attracts a tariff of approximately 25 euro cents per kWh.
Similarly, in the United Kingdom, solar PV generators receive a gross tariff of 8.9 to 21.0
pence per kWh for all electricity produced. On top of this, any electricity exported into
the grid receives an additional tariff of 3 pence per kWh.
While its large-scale renewable energy generators receive gross FiTs, Japan‘s residential
solar PV generators are subject to a net FiT. Under this scheme, generators are paid a
tariff of 42 yen per kWh for electricity exported into the grid.
Table 6.8 Feed-in tariff schemes
Jurisdiction Implementation Tariff rate per kWh Gross/ net Duration Systems
included
Victoria January 2012 25 cents Net 5 years Solar <5kW
Northern
Territory
July 2011 19.77 Net Residential
solar
Queensland July 2011 44 cents Net 20 years Solar <5kW
Germany January 2012 8.05 euro centsa,
12.43 euro centsb
Gross 20 years Roof-top
solar <30kW
24.42 euro cents Net
UK April 2010 21 pence Gross 25 years Solar <4kW
24 pence Net
Spain Suspended:
January 2012
28.88 euro cents Gross 25 years Residential
solar
Japan July 2012 42 yen Net 10 years Residential
solar
Notes: a for first 30 per cent of total annual electricity generation; b for the remainder of electricity generated
Source: Commission analysis.
122 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
Participants’ views
While ACIL Tasman‘s preferred gross metered FiT may be more effective in reflecting
the energy value, Victoria‘s current FiTs are paid on a net basis. This implies significant
sunk costs in smart meters, billing systems and other administrative aspects. The
potential benefits of a gross tariff need to be weighed up against the additional costs
of change.
Jemena highlights that it has installed (single element) smart meters under the
Advanced Metering Infrastructure (AMI) program which can only support net metering.
Furthermore Jemena asserted:
To support gross metering, a dual element meter is required. While the cost
difference of a single-element and dual-element meter may be small
relative to the cost of a small-scaled DG [distributed generator], the
modifications to JEN‘s AMI IT systems to support gross metering would be
prohibitive. (sub. 79, p. 6)
Similarly United Energy (UE) believed that, while gross metering may offer improved load
forecasting at times of high demand, there may be additional costs:
The minimum standard of metering under the AMI program is single element
metering which enables a net feed in tariff as opposed to measuring the full
energy generated from the distributed generation which may occur with a
two element interval meter. Two element interval meters have only been
funded for UE in order to continue the metering configuration for dedicated
off peak circuits – hot water and slab heating customers. (sub. 77, p. 4)
Continuing the theme of minimising costs to relevant parties, Origin Energy supported
net metering arrangements for small distributed generation systems:
… as this provides incentives for customers to reduce their consumption and
maximise output of electricity to the grid. Furthermore, most jurisdictions
have implemented net metering schemes, the metering and wiring costs
are lower (because a second meter is not required) and the contribution of
DG to the grid can be measured accurately where interval meters are
installed. (sub. 81. p. 1)
In contrast, several submissions focused on the potential societal benefits of gross
metering. For instance Moreland Energy Foundation argued that:
Gross metering of distributed energy systems offers a number of benefits
over net metering, from greater fairness and equity, to greater financial
certainty when determining the return on investment for the distributed
energy system, to providing accurate and useful energy consumption
information and enabling simple energy auditing of a home or business.
(sub. 75, p. 6)
Environment Victoria also pointed to the broader benefits of gross FiTs that would be
supported by gross metering arrangements:
A gross feed-in tariff values the full contribution to the community,
environment and to our energy security, and pays a fair price based on
these factors to the generator for all of the electricity generated, regardless
of where it is used. (sub. 51, p. 5)
FUTURE VICTORIAN FEED-IN TARIFF ARRANGEMENTS 123
6.1.5 Information provision
As noted in chapter 5, it is important that electricity customers considering distributed
generation options have access to relevant information to be able to evaluate FiT
offers in a timely and cost-effective manner. Accessibility of information can be
improved by standardising FiT offers to allow customers to compare retailer offerings —
ultimately choosing the best offer that meets their needs, taking into account personal
preferences.
The Commission found in its desk-top reviews of retailer and other comparison sites that
it is often difficult to understand how FiT offers interact with other retail market offers,
terms and conditions. To improve customers‘ capacity to make well informed decisions
(from their perspective) it is important that they understand the financial implications of
the service packages they are being offered by retailers.
The Commission notes the National Electricity Customer Framework (NECF) is expected
to commence on 1 July 2012, and transfers the regulation of Victorian electricity
retailers to a national regime. The NECF requires retailers to comply with AER Retail
Pricing Information Guideline (2012a) published by the AER. In complying with this
guideline, electricity retailers will be required to provide relevant pricing information to
the AER which will be input into a price comparator website (maintained by the AER).
The Commission‘s view is that FiTs should form part of the pricing information provided
under the price disclosure guidelines, and be included on the AERs price comparison
site ‗Energy Made Easy‘. Furthermore, the Commission understands that the
requirement to publish FiT terms and conditions on retailer websites will remain, under
the requirements of the Electricity Industry Act 2000 (Vic).
To assist the market to transition to the new arrangement the Commission sees merit in
also establishing an indicative benchmark range for FiTs that provides customers a
starting point when seeking alternative offers from retailers. As shown earlier (table 6.3),
ACIL Tasman have provided indicative estimates of the value of distributed generation
for various generation profiles and technologies. The benchmark range would provide
customers with some basic cost information that they would have difficulty acquiring on
their own. This benchmark rate could be updated as appropriate over the short term
until market FiTs are reasonably established.
6.1.6 Billing arrangements
In looking at future Victorian FiT arrangements it was suggested that the Commission
consider billing and payment arrangements. The Minister for Energy and Resources
wrote to the Commission5 listing several issues including:
the retailer be required to pay the customer at the end of each normal billing
period any amount earned by the customer from the feed-in
that customers be paid in cash, not just credits that are wiped out if not used.
The Commission notes that the criteria applied by the ESC states that:
An offer must state that the retailer will pay or credit the customer for
electricity supplied under the feed-in contract with the same frequency as
the customer is billed for electricity supplied to the customer. (DPI 2011f)
5 The letter from the Minister for Energy and Resources is available on the Commission‘s website,
www.vcec.vic.gov.au.
124 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
An issue for further consideration is that under the Commission‘s proposed approach, a
FiT will be available to all distributed generators, including at locations other than the
principal place of residence. This may have implications for the way that retailers
structure their billing and payment arrangements with their customers. For instance, it is
conceivable that the value of the energy exported by distributed generators will be
greater than the value of the energy consumed (for example, holiday homes).
The Commission seeks further information on the extent to which current billing and
payment practices by Victorian retailers are causing significant problems, which impact
on the ability of customers to access fair and reasonable value for the electricity
supplied by their distributed generator.
Information
request
To what extent do current billing and payment practices by
Victorian retailers impact on customers‘ ability to access fair and
reasonable value for the electricity supplied by their distributed
generator?
6.1.7 The Commission’s view
An approach that specifies a specific FiT risks setting a price that is either too low or too
high (regulatory error), leading to inefficient investment in distributed generation. It may
also impose costs on other electricity consumers or impact on the competitiveness of
the retail energy market if retailers are obliged to offer FiTs that are higher than market
determined FiTs (or above the value of the distributed generation). This could result if
retailers attempt to avoid certain customers or classes of customers. This was noted by
the Australian Solar Roundtable:
… retailers may either try to avoid entering into market contracts with these
customers, or offer them higher retail electricity rates than other customers
(Australian Solar Energy Roundtable 2011, p.7)
The market determined FiT, in an effectively competitive environment, would reflect the
value of the generated electricity to the retailers, and would therefore avoid any
unintended cross subsidisation issues. How best to move Victoria to a more efficient
market-based FiT is discussed in the rest of this chapter.
As previously noted there are currently some impediments to an efficient market
determined FiT which appropriately rewards small distributed generators for the energy
value of the electricity that they produce, including:
Information and transaction costs: there are concerns that, especially for smaller
distributed generation proponents, information is difficult and costly to obtain and is
not always in a form which is clear and accessible to the customer. These costs are
compounded by the newness of some technologies and uncertainty caused by
changing national regulation.
Market power issues: vertical integration of retail energy businesses. There are
significant ownership links between the energy retail market and centralised energy
generation which may impact on the incentives retailers face when engaging with
and negotiating a FiT with small-scale (or aggregated groups of) generators.
Limitations on time of use and locational pricing: not all Victorians have access to
meters which collect time of use and location aspects of their power use and
production. This limits the ability to develop FiTs that better reflect the value of
distributed generation at different times and locations.
FUTURE VICTORIAN FEED-IN TARIFF ARRANGEMENTS 125
On their own none of the above factors constitute a market barrier sufficient to prevent
competitive outcomes from emerging (provided adequate consumer protection,
transparency and information is available). However, combined they are likely to
present significant short-term barriers until key reforms are in place, including through
the Commission‘s draft recommendations and the ongoing changes to the NEM and its
regulation.
In moving towards a market-based FiT it is important that customers (owners of small-
scale distributed generators) are well informed about the variety of service offerings by
electricity retailers. As noted in chapter 5, it is likely that current FiT information provided
by retailers is inadequate, and confusing in the manner it is presented. These
information shortcomings may reduce the likelihood of efficient participation in the FiT
market. Given the interrelationship between FiT offerings and retail market contracts for
the supply of electricity, more targeted and comparable information regarding FiT
offerings can support, rather than hinder, the further development of competition in the
retail electricity sector.
The Commission considers that future Victorian FiT arrangements be ‗administratively
simple, and capable of being implemented at low cost‘. Having regard to this, the
Commission notes that there has been significant investment in metering equipment
and systems that support the measurement of ‗net exports‘ of electricity from small-
scale distributed generators.
Given this, the Commission considers it is likely that mandating gross metering, which
supports gross FiTs, would increase costs and would therefore be inconsistent with the
guiding principles. The Commission also notes the value of supporting a nationally
consistent approach, provided that it is not detrimental to the welfare of Victorian
electricity customers. In this context the Commission notes that recent regulatory
changes in South Australia and New South Wales have implemented net FiTs. As the
role of distributed generation in the electricity market develops, however, there may be
broader benefits to the industry from adapting their systems to allow for gross metering.
Under the Commission‘s proposed market-based regulatory framework, this would
remain an option. The Commission‘s recommendations are not a barrier to gross
metering, the introduction of gross FiTs or businesses adapting their systems to
accommodate both.
6.1.8 Terms of Reference 1: The Commission’s summary
view
Drawing all these elements together, the Commission‘s view on the design, efficiency
and effectiveness of FiT schemes (including gross feed-in schemes) may be summarised
as follows:
With the advent of the carbon tax, and given the retail market for electricity is
competitive, the energy value for distributed generation output is best captured
through a wholesale-based price set by the competitive market. The role of a FiT
scheme is to recover this value.
FiT schemes should:
– be based on such market prices, and be part of a transition to a fully market-based
approach for pricing energy from distributed generation
– provide an indicative benchmark range with periodic updates until market FiTs are
reasonably established
– not exceed such a market-based price, because this would mean cross-subsidies from
customers without distributed generators to customers with distributed generators, and
this would be regressive to some degree
126 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
– be technology neutral so that the most efficient choices among generation
technologies can be made
– be confined to ‗household scale‘ distributed generation of 100kW or less, as larger scale
producers are better placed to compete in the market.
Adopting time based pricing is desirable where feasible, because it provides a
stronger economic signal to distributed generators of the value of production when
overall electricity demand is high.
While there are arguments in favour of gross FiT schemes, there would be significant
costs in replacing recently installed smart meters and changing retailers‘ supporting
infrastructure and computer systems to be able to adopt such schemes. Therefore,
while not ruling out such schemes if they were to arise in the marketplace as a result
of competition, the Commission sees no clear value in mandating them.
6.2 Network value of distributed generation
Ideally the payment made to distributed generators should reflect the two components
which contribute to the total value (that is, the energy value and the network value) of
electricity supplied by distributed generators. ACIL Tasman (2012, p. viii) recommends
that this could be achieved through a ‗hybrid FiT‘ which is paid to distributed
generators, with the energy value calculated using the wholesale market-based
approach, and a separate payment made to reflect the network value (net of the
costs of ‗accommodating‘ the distributed generator).
The network value of distributed generation stems from electricity being generated
close to the customer (or other customers) in areas where the network is constrained. It
therefore does not need to be transported through all of the various parts of the
network, and can defer the need for network augmentation. However, the value of the
distributed generation is driven by its capacity to support the network at the time the
network is constrained (which is at times of peak demand). ACIL Tasman notes:
… the network value of distributed generation is likely to vary significantly
from place to place due to the local nature of network constraints. It is also
likely to vary significantly for different generation technologies as the
certainty with which they can be relied upon to generate electricity during
times of peak demand varies. It is only efficient to use distributed generation
for its network value if the cost of doing so is less that the (avoided) network
solution. In determining this, the cost of ‗accommodating‘ the distributed
generation in the network must be taken into account. (ACIL Tasman
2012b, p.25)
A further issue is that, given electricity network business regulatory arrangements, the
network value of distributed generation is:
determined by the output that the DNSP [Distribution Network Service
Provider] expects a distributed generator to provide when peak demand
occurs. It is not affected by the actual output when peak demand occurs
because networks are planned and built based on demand forecasts.
(ACIL Tasman 2012b, p.82)
Advice provided to the Commission by ACIL Tasman suggests 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. The Commission‘s view is that this part of the network value is appropriately
dealt with outside of the FiT payment.
FUTURE VICTORIAN FEED-IN TARIFF ARRANGEMENTS 127
Taking account of this network value is important to ensure there are effective
incentives to invest in distributed generation.
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
generators. The Commission‘s draft recommendations 4.1 to 4.3 are relevant to this
point.
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.
The approach of assuming network value is effectively zero (for the purposes of
calculating FiTs for solar PV) has been adopted by IPART in New South Wales.
6.2.1 Incentives for investment in distributed generation
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.
Concerns have been raised about the extent to which there are sufficient incentives for
distribution businesses to 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
periods.
… 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.6 (ACIL Tasman 2011a, p.6)
6 ACIL Tasman noted that this was recognised by the ESC who allowed specific provision for demand
management initiatives of $0.6 million over five years for each distributor — with demand side activities and
128 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
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 2012b, p.48).
Currently there is an incentive scheme, the Demand Management Incentive Scheme
(DMIS), designed to encourage distributors to investigate demand management
options, including distributed generation. The scheme, as it applies to distributed
generation, has a number of shortcomings:
the amount provided to distribution businesses is too small to be effective
uncertainty associated with the ex-post assessment of the DMIS payment because
distributors have no certainty of recouping their costs
narrow focus of expenditure (ACIL Tasman 2011a, pp.17, 39)
The AER identifies that the ‗DMIS is not the sole or only incentive‘ and included $221
million for Demand Side Participation (DSP) in the Queensland DNSPs‘ price
determinations. While DSP includes distributed generation, most of the $221m in
Queensland was allocated to funding demand side participation (DSP) technologies
such as air-conditioning and pool filtration direct load control and some pilots of pricing
options (AER 2010a).
6.2.2 The Commission’s view
The Commission considers that misalignment between incentives for distribution
businesses and efficient distributed generator connection present a major barrier to
both efficient distributed generator connection and planning of networks to
accommodate distributed generation.
It is difficult to estimate the size of the network value because it depends on the
location of the generation, whether it is of sufficient capacity to delay the need to
invest in the network and whether it can be relied on at the time it is needed. Based on
a range of estimates on the network value of distributed generation ACIL Tasman
concluded 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… 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 augmentation
by three years, the network value is $375 per year for the three years for
which the augmentation is deferred. (ACIL Tasman 2012b, p.83)
But as noted above this value is not applicable to all generators and for many the
network value will be zero or negative.
The key to distributed generators being able to realise the network value of their
generation is ensuring there is sufficient information on where distributed generation
can substitute for network system investment, and clear incentives for distribution
network businesses to consider distributed generation as an alternative to additional
outcomes to be reported on. This specific reporting requirement did not eventuate in the transfer of the
economic regulatory regime to the AER (ACIL Tasman 2011a, p.6).
FUTURE VICTORIAN FEED-IN TARIFF ARRANGEMENTS 129
investment in the network. There is clearly already reform in train that will improve these
incentives.
The amount of information available on the locations where the network is
constrained is increasing — chapter 4 noted that Sustainability Victoria has
published maps that identify network constraints that can help inform where
distributed generation could result in savings from deferred network investment.
The proposal to allow aggregators to act on behalf of a number of generators will
introduce a party into the negotiation, with the scale and capacity to accumulate
the knowledge and expertise needed to negotiate with distribution network
businesses about distributed generation based network solutions.
Increasing and continued interest in distributed generation by industry, government
and regulators will help to embed it as a part of the energy network.
Improving information and connection processes for distributed generation
(chapter 4) will make it easier to incorporate other issues, such as benefits for the
network, into those negotiations.
In the short-term it may be possible to strengthen the capacity of distributed generators
to negotiate with distribution network businesses by further improving access to
information. In correspondence with the Commission ACIL Tasman suggested this could
be done by:
Developing a small number of case studies where local groups have
aggregated purchases of distributed generators in an area where there is a
network constraint to defer network augmentation. These case studies
could then be referenced by others. To expedite the development of the
case studies, the government could fund a liaison officer that would (a)
work the electricity distributors to identify the most prospective areas for
non-network solutions, (b) then work with the local council to identify the
most appropriate vehicle for aggregating the purchases… (c) liaise
between the identified local groups and the electricity distributors to ensure
that the required amount of small scale distribution generation is installed
and the participants are paid the network value. (ACIL Tasman 2012b, p.49)
It may also be possible to improve existing sources of information, for example by
improving the way information on areas which the network will need to be expanded
can be accessed and used. Such initiative improve market information and help
balance market power, but they do not ensure the regulatory environment includes
strong incentives for distribution businesses to seek out cost reductions regardless of the
source. Such changes would have broader benefits for the electricity market but would
take some time to design and implement.
The Commission notes that the AEMC conducted a review into the use of a total factor
productivity (TFP) methodology in determining regulated prices and revenues for
electricity and gas service providers. The AEMC noted that:
… use of a TFP methodology in setting the allowed revenue path has the
potential to create stronger incentives for service providers to pursue cost
efficiencies compared to the building block approach. This is because it
could provide higher returns to the service provider when it makes
investments and improves operating practices which deliver continuing
productivity improvements. There would be more pressure on all service
providers to out-perform, or at least maintain, the rate of industry group
productivity growth… Accordingly implementing a TFP methodology as an
alternative to the current building block approach could lead to increased
130 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
productivity and lower prices for consumers in the long term. Therefore such
a methodology could in principle contribute to the national energy
objectives.
However the AEMC found that:
… a number of conditions need to be satisfied for a TFP methodology to
work properly and promote efficient regulatory decisions. We find that such
conditions are not likely to be met at the present time. Crucially, the current
lack of a sufficiently robust and consistent data-set means that it could be
too problematic to reconstruct existing data for the purpose of a TFP
methodology… We advise that the initial focus should therefore be on
establishing a better, more consistent data-set. (AEMC 2011c, p.ii)
In summary the AEMC proposed a two stage process for Rule changes.
Firstly an initial Rule would be made which requires service providers to
provide specified regulatory data which would then permit the AER to test
for the conditions necessary for a TFP methodology and to undertake initial
paper trials of the calculations. Drafting of the detailed design of the TFP
methodology and making of the Rule – the second stage – should only
occur once both a) the necessary conditions can be, or are likely to be,
met and b) it is considered that introducing a TFP methodology would
contribute to the national energy objectives given the status of the market
at that time. (AEMC 2011c, p.ii)
While these are national issues, Victoria‘s next round of distribution business price
determinations is not expected until October 2015. This provides time to work on a
possible solution or solutions.
Information
request
Several current and proposed incentive schemes and regulatory
changes aim to improve incentives for distribution network service
providers to engage with distributed generators to reduce network
costs. Which initiatives should the Victorian Government initiate or
make submissions to in order to most effectively reduce the barriers
to distributed generation?
6.3 Implications for existing Victorian feed-in tariff
schemes
The terms of reference require the Commission to recommend whether existing FiT
arrangements should be continued, phased-out or amended. It also requires that
where phase-out of existing arrangements is proposed, the appraisal should consider
whether any transitional arrangements may be necessary.
The Commission‘s approach to future Victorian FiT arrangements reflects its view that
the retail market is sufficiently competitive that, with a transition to allow for changes in
consumer regulation and growth in market experience, this market is capable of setting
prices for the energy value of distributed generation that are in the long-term interests
of consumers and producers.
The Commission‘s approach is consistent with the COAG National Principles for Feed-in
Tariff Schemes, in particular:
FUTURE VICTORIAN FEED-IN TARIFF ARRANGEMENTS 131
That Governments agree that residential and small business consumers
with small renewables (small renewable consumers) should have the
right to export energy to the electricity grid and require market
participants to provide payment for that export which is at least equal
to the value of that energy in the relevant electricity market and the
relevant electricity network it feeds in to, taking into account the time of
day during which energy is exported. (Commonwealth Government
2012c, p.1)
Chapter 5 stated that the objectives of FiT policy should focus on ensuring that low-
emission and renewable small-scale generators receive fair and reasonable value for
the electricity exported to the grid.
The following guiding principles have been used to assist the Commission in its
consideration of future Victorian FiT arrangements. Specifically that the FiT
arrangements should:
(1) comply with good regulatory design principles
(2) support, rather than hinder (or distort), competition in the retail energy market
(3) be consistent with national agreements, including the COAG FiT principles and the
National Electricity Objectives
(4) correctly target the problems they are seeking to address and be the best
instrument to address those problems
(5) be administratively simple and capable of being implemented at a low cost
(6) be neutral to the type of generation technologies
(7) not lead to inequitable outcomes.
A key part of future FiT arrangements is the determination of the payment for electricity
generated by distributed generators. As previously noted, the Commission considers
that the energy value of distributed generation is best determined with reference to the
wholesale market-based approach, where the payment is based on the components
of the retail price of electricity that is avoided by the distributed generation. This should
be determined within a well-informed retail electricity market.
Taking into account the available evidence, and the start of the carbon tax on 1 July
2012, the Commission is disposed to recommend that the existing Victorian TFiT should
be phased out by 31 December 2013 or once the 75 MW capacity is reached (as
currently provided in legislation), whichever occurs first. This allows for an orderly
transition to a significantly amended SFiT. The amended FiT would be determined by
the market and expanded to cover renewable and low-emission technology. The
approach to phasing out of the TFiT also reduces the costs of future cross subsidisation
borne by those not participating in the FiT market.
Under the amended SFiT, retailers with more than 5000 customers would be required to
offer to purchase electricity supplied by low-emission and renewable distributed
generators of 100 kW or less. This price would be determined within the retail market
and would need to be fair and reasonable based on the energy value of the
distributed energy supplied to the grid. This last point would require changing the
guidance provided by the ESC on the meaning of fair and reasonable.
The Commission considers this is the appropriate next step towards phasing out
regulated FiTs, which the Commission suggest be done within three years, subject to the
satisfactory completion of the reforms to the NEM that are currently on foot. Consumer
132 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
protection, information provision and better connection processes are part of the
arrangements going forward.
The Commission sees merit in the Victorian Government, through the ESC, publishing
information on the likely range of prices that would be consistent with the fair and
reasonable value of electricity supplied by distributed generators. Retailers would
continue to be required7 to publish up to date information on their websites regarding
prices and terms and conditions for the purchase of electricity from distributed
generators, and would provide relevant pricing information to the AER consistent with
price disclosure guidelines. This information could then be used as an input into the
AER‘s price comparison website. During the transition the ESC would continue in its role
in considering the extent to which FiT market offers are consistent with an amended fair
and reasonable criterion that does not require a one-for-one tariff. Provided they are
fair and reasonable, retailers would be free to offer a range of tariffs that could vary
according to location and time of day.
Throughout this transition period the Victorian Government (Department of Primary
Industries (DPI)) should monitor the range of market offers that are made by retailers.
This information would be used to highlight any significant failings in the market that
might lead to a view that the obligation to offer should be retained post the transition
period.
As mentioned earlier, the Commission considers the SFiT should not be constrained to
the principal place of residence, as this would simply lead to greater administrative
complexity. Moreover, this would limit opportunities for distributed generation to
contribute to improving the performance of the electricity system.
The approach outlined above is consistent with the Commission‘s view that over time
the retail market is sufficiently competitive to support market determined FiTs, if
supported by consumer protection and access to relevant information. It recognises
that immediate deregulation could create significant disruption and, given the current
state of the market, a more managed transition to a competitive market would provide
greater net benefit as:
Changes to the national retail regulatory framework would have had time to bed
down, reducing uncertainty in the market.
Victoria would have had the opportunity to reduce the significant regulatory
burdens that arise from the current cumbersome processes for connecting
distributed generation and signing up for FiTs. These changes would make it easier
for consumers to choose, and reduce a major business cost on small installers
whose businesses would also be disadvantaged by any uncertainty in the transition
to deregulated FiTs.
Any consumer protection or information provision regulation could be bedded
down, including the proposed move to national information provision, to ensure
that these protections are sufficient to support effective competition.
Victoria could monitor deregulation in NSW and use the experience there to inform
and improve its FiT policy going forward.
For these reasons the Commission is proposing a transition where the distortions in prices
are removed in the first instance but certainty that the market will continue to offer
competitive FiTs is maintained. It is proposed that this guarantee be removed after
7 Under the Electricity Industry Act 2000 (Vic).
FUTURE VICTORIAN FEED-IN TARIFF ARRANGEMENTS 133
three years when the new market is expected to be mature enough to support
competitive outcomes.
Participants at the Consumer Group Roundtable suggested that consumers should
have the option of selecting a simple tariff structure that is easy to understand. It was
argued that FiTs are already complex and if the range of offers was even broader some
consumers would find it very difficult to make an informed choice, even if information
was available. At this stage it is not clear to the Commission:
whether a simple FiT would be automatically offered by retailers in a competitive
market
if such an offer needs to be regulated
whether regulation would be possible under a competitive market model.
Draft Recommendation 6.1
That, to improve the efficiency and effectiveness of the operation of feed-in tariffs
(FiTs) in Victoria, the Victorian Government:
close the Transitional FiT, either by 31 December 2013 or once the 75 MW
capacity is reached (as currently provided in legislation), whichever occurs first
amend the Standard FiT to require that Victorian electricity retailers with 5 000 or
more customers offer fair and reasonable prices for electricity exported to the
grid by all small low-emissions or renewable distributed generators (100 kW or
less) until 31 December 2015
establish a fair and reasonable price for energy supplied by distributed
generators through the retail electricity market.
define low-emissions technology as generators that produce 50 per cent or less
of the emissions intensity of electricity generation in Australia
allow market-determined arrangements based on gross payments by mutual
agreement
ensure that FiT prices are published by the Australian Energy Regulator under
the requirements of the National Electricity Customer Framework.
That the Essential Services Commission:
publish information on the likely range of wholesale market-based net FiT
payments which would be consistent with a fair and reasonable offer —
updated at regular intervals
consider the extent to which FiT market offers are consistent with fair and
reasonable criteria, redefined to be based on the wholesale price of electricity
(the energy value).
134 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
Information
request
Given that there is effective competition in the electricity retail
market, is it necessary to retain an ‗obligation to offer‘ a price for
the purchase of electricity supplied by distributed generators within
the transitionary period? Why?
Are there any significant costs of retaining the ‗obligation to offer‘?
If so, what are they?
Is the three year transition to market determined feed-in tariffs
appropriate? If not, what might be a more appropriate transition
period?
6.4 Transitional arrangements
The Commission is aware that the process for moving from current Victorian FiT
arrangements to what is set out in draft recommendation 6.1 requires careful
consideration. The Energy and Water Ombudsman Victoria (EWOV) highlighted some
of the issues and problems resulting from the closure of the PFiT and its replacement by
the TFiT. EWOV noted that:
… ―when the Transitional Feed-in Tariff (TFiT) expires in five years (as
intended) those customers would move onto the SFiT‖. Currently, however,
these two FiTs have different eligibility criteria. Customers who apply for TFiT
must not have a PV system greater than five kilowatts (kW), and customers
applying for SFiT must have a PV system greater than five kW but less than
100 kW. Based on this criteria, there are residential consumers who may miss
out on receiving a FiT entirely as they do not meet the current criteria
around the size of the PV System. This is one of the transitional issues that will
need to be considered by VCEC. (sub. 48, p. 4)
Reflecting on the experience with closing the PFiT, the Solar Energy Industries
Association suggested during consultation that greater clarity with respect to
information and time-paths were needed, and that a dedicated website be available
for clients to understand the changes (what is required, and who is responsible for
various installation and contract activity). As outlined in chapter 4, existing connection
and sign-up processes are complex involving installers, retailers and distribution
businesses, which would be addressed by the Commission‘s previous draft
recommendations.
FUTURE VICTORIAN FEED-IN TARIFF ARRANGEMENTS 135
Box 6.1 Energy and Water Ombudsman Victoria (EWOV)
case study
The customer submitted all the required solar paperwork prior to the cut-off date of
30 September 2011. Soon after she received a bill without a solar rebate and
immediately contacted her electricity retailer. Her electricity retailer initially advised
that it had not received the required paperwork. Dissatisfied with the response, the
customer made a complaint with EWOV. However, after the complaint was lodged,
it was confirmed by the electricity retailer that all paperwork was sent. It was
revealed that her electricity retailer had raised a service order to install a bi-
directional meter, which occurred on 20 July 2011, but had raised an incorrect
service order requesting SFiT instead of PFiT as the solar tariff. EWOV is continuing to
investigate this issue with the electricity retailer. It is unlikely that this customer will
receive PFiT, even though this was a retailer error, as the scheme is now closed to
new customers.
Source: sub. 48, p. 3.
The Commission is of the view that DPI should continue to provide FiT information on its
website, including links to relevant AER price comparison information.
During the transition to the proposed FiT arrangements DPI should also engage in an
information campaign and outline the changes and transitional arrangements
including:
relevant dates and cut off criteria
contact information (retailers, EWOV and so forth)
who is responsible for various activities
fact sheets and useful tips
outline of the new arrangements — what is different and the implications for
customers.
The Commission understands that the design of the cut-off trigger, which determines
whether the owner of a PV system is eligible for the TFiT when the scheme is being
closed to new entrants, has implications for the fairness and orderliness of the phase-
out. The Commission sees merit in basing the cut-off on the lodgement of relevant
paperwork with the retailer by a specific date. This design would minimise the number
of eligibility issues that are caused by factors outside of the control of the consumer.
The terms of reference specifically state that ‗any changes to existing arrangements
would not be applied retrospectively‘. The Commission understands this to mean that
customers who are currently on a PFiT would remain on this tariff until its contracted
expiry date on 1 November 2024. On expiry, these customers would be eligible for the
amended SFiT or market-based FiT. Similarly, those customers currently on a TFiT would
continue to remain on this tariff until its contracted expiry date on 31 December 2016.
This non-retrospective approach would also apply to customers currently on a SFiT. The
terms and conditions of existing SFiT contracts may be one means of managing this
transition. The Commission will look further at the issues for existing SFiT customers in its
final report.
The Commission is considering making recommendations on how to manage the
transition and welcomes further input from inquiry participants regarding the type of
information and criteria that would be most useful.
136 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
Information
request
A preliminary view is that the TFiT cut-off should be based on the
lodgement of relevant paperwork with the retailer by a specific
date.
Are there other options that the Commission could consider to
ensure an orderly and fair phase-out of the TFiT?
What information should be provided by DPI about transitional
arrangements, when should it be provided, and how should the
information be disseminated?
Are there any SFiT, TFiT or PFiT contractual issues that the
Commission should be aware of in its consideration of transitional
matters? What are they?
APPENDIX A: CONSULTATION 137
Appendix A: Consultation
A.1 Introduction
The Victorian Competition and Efficiency Commission (the Commission) received the
terms of reference to undertake an inquiry into feed-in tariff arrangements and barriers
to distributed energy on 13 January 2012. In keeping with its usual process to consult
extensively during public inquiries, the Commission advertised the inquiry in The Age,
Herald Sun and the Weekly Times in January and February 2012. The Commission also
published an issues paper in February 2012, which outlined:
the scope of the inquiry
how to make a submission
the Commission’s consultation process
the inquiry timetable.
The issues paper invited participants to register an interest in the inquiry and to make
submissions. The Commission received 1065 registrations of interest, including 86
individual and 844 proforma submissions via Environment Victoria, before the release of
the draft report (section A.2).
The Commission held three roundtables. The first roundtable was held on 8 March 2012,
with participants from the Energy Efficiency Council. Participants discussed issues
relating to connecting distributed generators to the distribution network and feed-in
tariff pricing. The second roundtable, held on 15 March 2012, focused on connecting
distributed generation and establishing fair and reasonable feed-in tariff prices from the
perspective of electricity retailers and distributors. It was attended by representatives
from electricity retail and distributor businesses. The third roundtable, held on 10 April
2012, discussed similar issues but from a consumer perspective. Roundtable participants
included government and non-governmental organisations that deal with, or advocate
for, consumer rights (section A.3).
The Commission consulted extensively (including meetings, visits and telephone
discussions) with Commonwealth, State and local government departments and
agencies, businesses, academics, associations and individuals (section A.4).
A.2 Submissions
The Commission received 86 submissions (table A.1). All submissions are public
documents that can be viewed on the Commission’s website.
Table A.1 Submissions received
No. Participant No. Participant
1 Comfortid.com Pty Ltd 2 WattSource
3 Jill Dumsday 4 Exigency
5 Gerard Noonan (1) 6 Gerard Noonan (2)
7 H Malcolm Walter 8 BRT Consulting Pty Ltd
9 Alistair Smith 10 Dandenong Ranges Renewable
Energy Association (DRREA)
11 Bill Grant 12 Jeremy Ashton
138 POWER FROM THE PEOPLE: AN INQUIRY INTO DISTRIBUTED GENERATION
Table A.1 Submissions received (cont.)
No. Participant No. Participant
13 Janet M Fitzwater 14 Lucinda Young
15 Solway Nutting 16 Jay Smith
17 Maria & Paul Hayes 18 Trish Sharkey
19 Nicole & Jason Drage 20 Johanna Winchcomb
21 Duncan Brown & Jeanette Gillespie 22 Lucy Armstrong
23 Gordon Donaldson 24 Patricia Rivett
25 Emerald for Sustainability 26 Roger Willshire
27 Mike Reeves 28 Louise Flaherty
29 Maria A Bell 30 Sandra Coventry
31 Dean Bridgfoot 32 Christine Easdown
33 Sally Kaptein & Jack Carolan 34 Robin Jensen
35 Fiona M Chant 36 Rebecca Edwards
37 National Electrical &
Communications Association 38 Dawn Gilson
39 Jenny Francis 40 Alan Jones
41 Ceramic Fuel Cells Limited 42 Neil Rankine
43 David Sparks 44 Prof Alan Pears
45 Climarte 46 Judy McShane
47 Frank Barbara 48 Energy & Water Ombudsman
Victoria
49 Mildura Development Corporation 50 Ironbark Sustainability
51 Environment Victoria 52 Saturn Corporate Resources Pty Ltd
53 Regional Cleantech Solutions 54 Susie Burke
55 LIVE 56 Australian Solar Round Table
57 Advance Solar Electrical 58 Simply Energy
59 South East Councils Climate
Change Alliance 60 Enviromate
61 Darebin City Council 62 Rachel Cook
63 Australian PV Association 64 Beyond Zero Emissions
65 F Lisner 66 David & Pamela Rothfield
67 APA Group 68 Alex Macleod
69 Warburton Community Hydro
Project 70 Liz Burton
71 Union Fenosa Wind Australia 72 AGL
73 Alternative Technology Association 74 Energy Supply Association of
Australia
75 Moreland Energy Foundation 76 Clean Energy Council
77 United Energy 78 Renewable Energy Solutions
Australia Holdings Ltd
79 Jemena 80 CitiPower & Powercor
APPENDIX A: CONSULTATION 139
Table A.1 Submissions received (cont.)
No. Participant No. Participant
81 Origin Energy 82 Graham Scarlett
83 Loy Yang Marketing Management
Company
84 Neilson Electronic Systems Pty Ltd
85 Lumo Energy 86 Grattan Institute
In addition, the Commission received 844 submissions from individuals submitted as an
Environment Victoria proforma submission. Of these, 718 submissions consisted of the
Environment Victoria proforma without any additional comments and 126 provided
additional comments or replaced the proforma. A list of Environment proforma
submitters can be found on the Commission’s website at www.vcec.vic.gov.au. A copy
of the Environment proforma submission and individual additional comments can also
be viewed on the Commission’s website.
A.3 Roundtables
The Commission held three roundtables in March and April 2012. Roundtable
participants are listed below (tables A.2, A.3 and A.4).
Table A.2 Energy efficiency roundtable
Participant Organisation
Simon Helps MWM
Randy Gadient Siemens
Bob Norris Dalkia
Ben Samways Honeywell
Brad Knowles Alerton
Mark Lampard AECOM
Dr Matthew Butlin Victorian Competition & Efficiency Commission
Deborah Cope Victorian Competition & Efficiency Commission
Table A.3 Retailers and distributors roundtable
Participant Organisation
Nicole Wallis AGL
Siva Moorthy Jemena
Alice Adriannse Lumo Energy
Ian Cupidon Lumo Energy
Annalisa Cattanach Powercor and CitiPower
Matthew Serpell Powercor and CitiPower
Julie Buckland SP Ausnet
Kate Jdanova SP Ausnet
Ross Evans TRUenergy
Dr Matthew Butlin Victorian Competition & Efficiency Commission
Deborah Cope Victorian Competition & Efficiency Commission
140 POWER FROM THE PEOPLE: AN INQUIRY INTO DISTRIBUTED GENERATION
Table A.4 Consumer groups roundtable
Participant Organisation
Gerard Brody Consumer Action Law Centre
Gemma Dodson Consumer Affairs Victoria
David Standford Consumer Utilities Advocacy Centre
Dean Lombard Victorian Council of Social Service
Dr Matthew Butlin Victorian Competition & Efficiency Commission
Deborah Cope Victorian Competition & Efficiency Commission
A.4 Stakeholder consultations
The Commission consulted with academics, businesses, industry associations and key
interest groups, and drew on the knowledge and expertise of Victorian,
Commonwealth and local government departments and agencies. In addition, the
Commission conducted a short Victorian Energy Retail Business Survey to assist its
analysis of current and future Victorian feed-in tariff arrangements. The Commission sent
a copy of the survey to all electricity retailers in Victoria, seeking their comments and
feedback. The survey responses form part of the Commission’s broader stakeholder
consultation process.
Table A.5 Consultation participants
Organisation or Individual Organisation or Individual
AGL Australian Energy Market Commission
Australian Energy Market Operator Australian Energy Regulator
Australian Petroleum Production and
Exploration Association Ceramic Fuel Cells Limited
City of Melbourne Clean Energy Council
Consumer Action Law Centre Consumer Affairs Victoria
Consumer Utilities Advocacy Centre Department of Business and Innovation
Department of Finance & Deregulation
(Cth) Department of Human Services
Department of Justice Department of Premier and Cabinet
Department of Primary Industries Department of Treasury and Finance
Energy and Water Ombudsman Energy Efficiency Council
Exigency Independent Pricing and Regulatory
Tribunal
Institute for Sustainable Futures (University
of Technology Sydney) Jemena
Lumo Energy Minister for Energy and Resources
Moreland Energy Foundation Office of the Renewable Energy Regulator
(Cth)
APPENDIX A: CONSULTATION 141
Table A.5 Consultation participants (cont.)
Organisation or Individual Organisation or Individual
Powercor and CitiPower Property Council of Australia (Victorian
Division)
Solar Energy Industries Association SP Ausnet
Sustainability Victoria Sustainable Melbourne Fund
TRUenergy Victorian Council of Social Service
APPENDIX B: REGULATION OF THE ELECTRICITY SECTOR 143
Appendix B: Regulation of the electricity sector
B.1 Victorian regulation
The Electricity Industry Act 2000 (Vic) (EI Act) and predecessor legislation have
regulated the Victorian electricity supply industry for almost two decades, following
privatisation of the State-owned electricity industry in the 1990s. The EI Act supplements
the national framework for economic regulation of transmission and distribution services
by regulating various matters including:
a licensing regime for those who generate electricity for supply or sale, or the
transmission, distribution, supply or sale of electricity
Victorian feed-in tariff (FiT) arrangements for the premium, transitional and standard
FiT schemes.
The Essential Services Commission (ESC), established by the Essential Services
Commission Act 2001 (Vic), administers the licensing, price and service standard
provisions of the EI Act. Box B.1 discusses the EI Act in more detail.
Box B.1 Electricity Industry Act 2000 (Vic)
The Electricity Industry Act 2000 (Vic) regulates the Victorian electricity supply
industry.
Part 2 Division 1 sets out the objectives of the Essential Services Commission
(ESC), which include promoting the development of full retail competition in the
electricity industry.
Part 2 Division 2 sets out ‗reserve‘ powers of the ESC with respect to charges for
connection to, and the use of, the distribution system. It also provides that the
ESC has the power to regulate tariffs for the supply of electricity (s 12(1)). The
Governor in Council may make an order to regulate tariffs for the sale of
electricity if the Australian Energy Market Commission concludes that
competition in a market for electricity is not effective (s 13).
Part 2 Division 3 requires the ESC to license people who generate electricity for
supply or sale, or the transmission, distribution, supply or sale of electricity unless
the person holds a relevant exemption. Division 3 provides for conditions that
regulate the conduct of licensees. Licences are transferable and the ESC can
suspend or revoke licences.
Part 2 Division 5 regulates the terms and conditions of sale and supply of
electricity. It deals with matters including the publication of tariff information,
and the terms and conditions for sale of electricity to certain customers.
Part 2 Division 5A governs Victorian feed-in tariff (FiT) schemes. It sets terms and
conditions for the purchase of small-scale renewable energy exports,
distinguishing between premium, transitional and standard FiT schemes. FiT
schemes are discussed in detail in section B.4.2.
Source: Electricity Industry Act 2000 (Vic).
A discussion of the national regulatory framework governing the national electricity
market (NEM) can be found in section 2.2.1 of this draft report.
144 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
B.2 Regulatory framework after 1 July 2012
With the commencement of the National Energy Customer Framework (NECF) on 1 July
2012,1 there will be significant changes to the regulation of the Victorian electricity
sector, with many Victorian responsibilities being transferred to a national framework.
The NECF includes the National Energy Retail Law (NERL), National Energy Retail Rules
(NERR), and amends existing national regulation, including introducing chapter 5A into
the National Electricity Rules (NER).
The NECF will be applied in Victoria by the National Energy Retail Law (Victoria) Bill
2012, which is currently being debated by the Victorian Parliament. The Bill proposes to
repeal a significant amount of Victorian energy regulation that will become redundant
after the NECF is applied. However, Victorian-specific energy legislation will still be
necessary in a number of areas after the NECF commences. The Department of Primary
Industries (DPI) intends, where feasible, to consolidate the remaining Victorian-specific
energy regulation (DPI 2011j; DPI 2011h). Importantly, in relation to the electricity sector:
The ESC will retain responsibility for licensing distribution, transmission and generation
activities in Victoria. However, although electricity retailers will no longer be
regulated through a State-based licensing scheme and will instead be governed
by a national retailer authorisation and exemption regime administered by the
Australian Energy Regulator (AER).
The NECF is silent on the issue of FiTs and the Victorian FiT schemes will continue
unaffected by the commencement of the NECF — although license conditions that
were linked to feed-in tariffs will become direct statutory obligations under an
amended EI Act (DPI 2011h; DPI 2011j; Explanatory Memorandum 2012, p.18).
B.3 Connecting to the distribution network
The process for connecting connection applicants (CA) to the distribution network will
change with the commencement of the NECF. As of 1 July 2012, there will be two
processes under the NER for connecting distributed generation to the distribution
network:
a process for registered generators or generators exempt from registration by the
Australian Energy Market Operator (AEMO), under chapter 5
a simplified process for retail customers (including non-registered embedded
generators who do not intend to participate directly in the NEM) under chapter 5A.
Each connection process has associated rights and obligations in relation to accessing
the distribution network and specific sizes/types of generators may be excluded from,
or find it more difficult to access, current connecting processes.
1 In the event that the commencement of the NECF is delayed in one or more participating jurisdictions, the
National Energy Retail Law (Victoria) Bill 2012 will commence at a later date agreed to among participating
jurisdictions. This will ensure that the NECF commences throughout Australia on the same day (Explanatory
Memorandum 2012, p.1; O‘Brien 2012, p.1447).
APPENDIX B: REGULATION OF THE ELECTRICITY SECTOR 145
B.3.1 Connecting registered generators under chapter 5
Registration as a generator
To be connected under chapter 5, registration as a generator in the NEM is required
unless AEMO grants an exemption from registration where an exemption ‗is not
inconsistent with the national electricity objective‘ (NER, cl 2.2.1(c)). Section 7 of the
National Energy Law (NEL) states:
The objective of this Law [the National Electricity Objective] is to promote
efficient investment in, and efficient operation and use of, electricity
services for the long term interests of consumers of electricity with respect
to—
(a) price, quality, safety, reliability and security of supply of electricity; and
(b) the reliability, safety and security of the national electricity system.
Clause 2.2.1 of the NER requires that:
each generating unit within a generating system must be classified as a
‗scheduled‘ generating unit, ‗semi-scheduled‘ generating unit or ‗non-scheduled‘
generating unit
each generating unit must be further classified as a ‗market‘ or ‗non-market‘
generating unit.
Generator registration has significant implications for participation in the NEM. The
consequences of generator classification for distributed generators selling excess
electricity into the distribution grid are discussed in section B.4.1.
Table B.1 provides typical definitions and examples of the available generator
classifications. Note that in certain circumstances, AEMO may approve a generating
unit classification, even though it does not meet the typical definition of a ‗scheduled‘,
‗semi-scheduled‘ or ‗non-scheduled‘ generator.2
2 See NER cl 2.2 and the NEM Generator Registration Guide (AEMO 2010b).
146 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
Table B.1 Categories of registration as a generator
Market:
A generating unit from
which the sent out
electricity is not purchased
in its entirety by the local
retailer or by a customer
located as the same
connection point
Non-market:
A generating unit from
which sent out electricity is
purchased in its entirety by
the local retailer or by a
customer located at the
same connection point
Scheduled:
A generating unit with a
nameplate rating of 30 MW
or greater or a group of
generating units
connected to a common
connection point with a
combined nameplate
rating of 30 MW or greater
Scheduled market
generator
Example: 2000 MW power
station from which all of the
electricity is sold via the
market
Scheduled non-market
generator
Example: 40 MW
generating system under
contract for all output to a
local retailer located at the
same connection point
Semi-scheduled:
A generating unit with a
nameplate rating of 30 MW
or greater or group of
generating units
connected to a common
connection point with a
combined nameplate
rating of 30 MW or greater
and the output of the
generating unit is
intermittent
Semi-scheduled market
generator
Example: 160 MW wind
farm from which all the
electricity is sold via the
market
Semi-scheduled
non-market generator
Example: 160 MW wind
farm under contract for all
output to a local retailer
located at the same
connection point
Non-scheduled:
A generating unit with a
nameplate rating of less
than 30 MW or a group of
generating units
connected to a common
connection point with a
combined nameplate
rating of less than 30 MW
Non-scheduled market
generator
Example: 10 MW
generating system from
which all of the electricity is
sold via the market
Non-scheduled
non-market generator
Example: 10 MW
generating system under
contract for all of its output
to the local retailer at the
same connection point
Source: (AEMO 2010b, pp.7–8).
Exemption from registration
Appendix 6: Guideline on Exemption from Registration as a Generator of the NEM
Generator Registration Guide (AEMO 2010b) provides guidance on the circumstances
in which AEMO may exempt a generator from registration. Where a Standing
Exemption applies, the generator is automatically exempt and there is no need to
apply to AEMO for an exemption from registration (AEMO 2010b, p.1).
A Standing Exemption exists for generating systems with a nameplate rating of less
than 5 MW, provided any of the following are met:
APPENDIX B: REGULATION OF THE ELECTRICITY SECTOR 147
– the generating system has a total nameplate rating at a connection point of
less than 5 MW
– the generating system is not capable of exporting to a transmission system or
distribution system in excess of 5 MW
– the generating system has no capability to synchronise or to operate
electrically connected to a distribution system or transmission system
– the sent out generation of the generating unit is purchased in its entirety by the
Local Retailer or by a Customer located at the same connection point (AEMO
2010b, p.36).
In exceptional circumstances, AEMO may also grant an exemption from registration
on a case-by-case basis. On application, AEMO may grant an exemption from
registration for generating systems of more than 5 MW and less than 30 MW
capacity which export (sell) less than 20 GWh in any 12 months (AEMO 2010b,
pp.36–37).
Registration process
Chapter 2 of the NER governs the registration of generators. The registration process is
lengthy and requires the CA to provide detailed documentary evidence that their
generating equipment will meet or exceed the technical requirements of chapter 5 of
the NER. It may take up to three months for a CA to prepare the documentation
required for registration as a generator (AEMO 2010b, p.4).
The registration process consists of four key steps:
(1) CA submits an application (using the appropriate form):
– for registration as a generator, accompanied by a registration fee (fees range
from $5000 to $7100 depending on generator classification) or
– for exemption from registration as a generator, accompanied by an exemption
from registration fee ($2000 for 2011-12).3
(2) AEMO reviews the application and responds within five business days.
(3) AEMO may request additional information or clarification of the information
contained in the application. If such a request is made, the CA has 15 business
days to supply the additional information or clarification.
(4) Within 15 business days of receiving the application or requested additional
information or clarification, AEMO will notify the CA of its determination. If
accepted, AEMO will notify the CA of the effective date of registration and of any
applicable conditions of registration (AEMO 2010b, pp.5–6).
Connection process
The connection process under chapter 5 requires the exchange of detailed technical,
prudential and commercial information, and extensive consultation between the CA
and the distribution network service provider (DNSP). The process can be summarised
into five main steps:
(1) Connection studies and enquiry: the CA conducts a network connection feasibility
study (which may include a network stability study) and approaches their local
3 See AEMO Schedule of Registration Fees 2011/12 (www.aemo.com.au/registration/0120-0031.pdf).
148 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
DNSP detailing the type, magnitude and timing of the proposed connection. The
information to be provided with the connection enquiry is set out in cl 5.3.4 and sch
5.4 of the NER.
(2) Response to connection enquiry: the DNSP will liaise with other network service
providers to determine the impact the proposed connection may have on existing
connection agreements. Within 10 business days, the DNSP must provide
preliminary information, including a preliminary program of proposed milestones for
the connection process. The DNSP has 20 business days to advise the CA of the
technical requirements and all further information required to enable an
assessment of the application to connect.
(3) Application to connect: the CA submits an application to connect accompanied
by the application fee. The application must include proposed technical standards.
The CA has an automatic right to connect if the relevant automatic access
standards are met. If the application to connect deviates from the relevant
automatic access standards, then there is no automatic right to connect, and the
parties need to negotiate each proposed technical standard in consultation with
AEMO.
– Schedule 5.2 sets out the automatic access standards for registered
generators. The automatic access standards do not apply to distributed
generators exempt from registration or eligible for exemption under Appendix
6: Guideline on Exemption from Registration as a Generator and where
connection is ‗unlikely to cause a material degradation in the quality of supply
to other network users‘ (NER cl S5.2.1(b)). This means that technical standards
for distributed generators of less than 5 MW capacity must be negotiated on a
case-by-case basis and there is no automatic right of connection for distributed
generators of this size.
– The negotiated access standards must meet at least the minimum access
standards specified in the sch 5.2 of the NER.
– In addition, the Electricity Distribution Code (ESC 2011a) published by the ESC,
outlines technical standards that embedded generators connecting to the
distribution system in Victoria must satisfy. The Commission understands that the
Electricity Distribution Code will become redundant with the commencement
of the NECF on 1 July 2012 but it is intended that certain provisions, including
those relating to technical standards for embedded generators, will be
retained in another form of Victorian regulation.
(4) Connection agreement and generator installation: once the access standards
have been agreed, the DNSP must prepare an offer to connect based on the
agreed standards within the timeframe specified in the preliminary program (or as
agreed between the parties). The CA and DNSP will execute the connection
agreement that describes the connection and outlines the applicable technical
and commercial conditions. AEMO is to be notified within 20 business days of the
execution of the connection agreement. The CA may then commence
construction and installation of the generator.
(5) Inspection and commissioning: Energy Safe Victoria will inspect and test the
installed generating system and issue a Certificate of Electrical Safety. A range of
connection tests will be performed with a DNSP representative present, before live
connection to the distribution network. After connection, an installation engineer
will test and commission the generator to ensure it is ready for regular service
(AEMO 2011).
APPENDIX B: REGULATION OF THE ELECTRICITY SECTOR 149
B.3.2 Connecting retail customers under chapter 5A
With the commencement of the NECF on 1 July 2012, responsibility for the sale and
supply of energy to retail customers — including new connections to distribution
networks — will be transferred to a national regulatory regime. This includes the
introduction of a new chapter (chapter 5A) in the NER, that provides for the electricity
connection of retail customers. The connection process under chapter 5A will vary
between DNSPs.
Chapter 5A applies to retail customers, including embedded generators, who are not
registered with AEMO (unless the registered participant is acting as the agent of a retail
customer). Retail customers connected under chapter 5A of the NER will have direct
contracts with their DNSP, as well as their designated retailer.
Small customers will have a contract with a designated retailer to provide customer
retail services (that is the sale of electricity) under a standard or market retail
contract, governed by Part 2 of the NERL.
Distribution services provided by DNSPs are divided into initial ‗connection‘ services
and ongoing ‗energisation‘ services that come into effect after connection. A retail
customer will have a distribution contract for connection under chapter 5A of the
NER and a separate (deemed) distribution contract for ongoing energisation
regulated by Part 3 of the NERL. At this stage it is unclear how these two sets of
distribution contracts will interact (Newman & McDermott 2010).
Types of connection service
Chapter 5A provides for three types of connection service for retail customers:
(1) A basic connection service, which will cover retail customers including those who
are micro-embedded generators. DNSPs must have a model standing offer for
basic connection services that has been approved by the Australian Energy
Regulator (AER). Micro-embedded generators (‗micro EG‘) are not defined in
chapter 5A according to generator size. The NER merely state that a micro EG
connection is ‗of the kind contemplated by Australian Standard AS 4777 (Grid
connection of energy systems via inverters)‘ (cl 5A.A.1). According to Standards
Australia, AS 4777 applies to inverter energy systems with ratings up to 10 kVA for
single-phase, and 30 kVA for three-phase, intended for connection to the low
voltage electricity distribution network. The Commission understands that AS 4777 is
currently under review (Queensland Government 2012).
(2) A standard connection service, which can cover the terms and conditions for
different classes of connection services or different classes of retail customers
(including non-registered embedded and micro-embedded generators). DNSPs
can choose to prepare a model standing offer for such services and have it
approved by the AER.
(3) A negotiated connection contract, which covers services that are not subject to a
basic or standard connection standard offer, or where a basic or standard
connection service is sought but the CA elects to negotiate the terms and
conditions of the connection agreement. The terms and conditions for such
services are negotiated and if agreement cannot be reached the dispute can be
arbitrated by the AER. In relation to a negotiated connection contract, a CA is an
applicant for a connection service that is:
– a retail customer (including an embedded generator)
– a retailer or other person acting on behalf of a retail customer, or
– a real estate developer.
150 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
DPI has advised the Commission that DNSPs in Victoria will not be required to have their
basic or standard connection service model standing offers approved by the AER until
1 July 2013. However, the requirement to have compliant offers published on a
distribution businesses‘ website will commence from 1 July 2012.
Connection process
The connection process under chapter 5A is broadly similar to the connection process
under chapter 5. The connection process consists of the following key steps:
(1) Preliminary enquiry: the CA makes a preliminary connection enquiry about
connection services. The DNSP has five business days (or longer agreed period) to
provide the enquirer with information required to make an informed application.
(2) Application to connect: once an application is made, the DNSP must advise the
CA if the application is incomplete and, if so, request the CA to resubmit it. The
DNSP may also request additional information if ‗reasonably required‘. The DNSP
has 10 business days after receipt of a complete application/requested additional
information (or some other agreed period) to advise the CA whether the proposed
connection is a basic connection service, standard connection service or neither.
A site inspection may be required for the DNSP to determine the nature of the
connection service sought by the CA.
(3) Connection offer where a basic or standard connection service is sought: within
those same 10 business days (from receipt of a complete application/additional
information) or other agreed period, the DNSP must make a connection offer
based on the relevant model standing offer. The offer remains open for
acceptance for 45 business days, unless extended by agreement.
(4) Expedited connection where a basic or standard connection service is sought:
where the CA requests an expedited connection and indicates that the terms of
the model standing offer would be acceptable in the connection application, the
DNSP is taken to have made, and the CA accepted, a connection offer according
to the terms of the relevant model standing offer on the date the DNSP receives the
connection application.
(5) Where a negotiated connection contract applies: the DNSP must advise the CA of
the negotiation process and related costs. The DNSP must use its 'best endeavours'
to make a negotiated connection offer within 65 business days. A negotiated offer
must comply with the minimum statutory requirements and remains open for
acceptance for 20 days (unless extended by agreement). In the event that the
DNSP and CA cannot reach an agreement — on the proposed or actual terms and
conditions of a negotiated connection contract, or the terms and conditions on
which a basic or standard connection service is to be provided — then the matter
can be arbitrated by the AER.
The introduction of chapter 5A into the NER is designed to simplify the connection of
small-scale retail customers, including those with distributed generation. However,
connection under chapter 5 will still remain an option and distributed generators
wishing to sell through the NEM are required to register and connect through the
chapter 5 connection framework (section B.4.1). The transparency of the process for
small distributed generators connecting under chapter 5A will depend in part on
whether DNSPs decide to provide model standing offers for standard connection
services. The Commission notes that in April 2012, a rule change request — designed to
facilitate the process for connecting embedded generators to the distribution grid —
was jointly submitted to the AEMC by ClimateWorks Australia, Seed Advisory and the
Property Council of Australia. This proposed rule change is discussed in chapter 4.
The process for seeking connection under chapter 5A is illustrated in figure B.1.
APPENDIX B: REGULATION OF THE ELECTRICITY SECTOR 151
Figure B.1 Connection process for distributed generation
under chapter 5A
Source: Commission analysis of chapter 5A NER.
* This applies to
negotiation, not dispute
resolution
Agree
d
Offer open for 20 days
Not agreed
Legend
AER – Australian Energy
Regulator
DNSP – Distributed Network
Service Provider
Additional information required
DNSP has 5 days to
provide information
Application incomplete
Site visit, if needed
Preliminary inquiry from
potential applicant
wishing to connect
Applicant lodges
application on form
determined by DNSP
DNSP informs applicant of
additional information
needed
DNSP informs applicant of
deficiency
Basic connection service
or standard connection
service
Use agreement approved
by AER
Completed application
submitted
Not approved service.
DNSP notifies applicant of
the negotiation process &
possible changes &
expenses
Negotiated connection
offer
Option of dispute
resolution reduction
through AER
Offer terms form
connection contract
Application complete
DNSP uses best endeavours
to make offer within 65 days
of receiving completed
application*
DNSP has 10 days to advise
whether the service is covered
by an approved connection
process and, if so, make a
connection offer
offer open for 45 days
expedited connection
may be available
152 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
B.3.3 Cost of connecting distributed generation
There are fees and charges associated with connecting distributed generators to the
distribution network. These costs vary depending on the size/type of generator being
connected and type of connection. Generally, connection charges apply to the
following four components of a typical connection:
(1) Direct connection assets — these are the premises‘ connection assets which run
from the connection point to the supply point and where applicable also include
the consumer mains.
(2) Extensions — an augmentation that requires the connection of a power line or
facility outside the present boundaries of the transmission or distribution network
owned, controlled or operated by a network service provider.
(3) Shared network augmentations — an augmentation of a distribution network
means work to enlarge the system or to increase its capacity to transmit or
distribute electricity, caused by the connection. This is all augmentations other than
extensions.
(4) Incidental costs — includes administration, design, certification and inspection fees
(AEMC 2012c, pp.171–172; AER 2011d, p.14).
Cost of connecting distributed generation under chapter 5
Chapter 5 of the NER provides that CAs are subject to fees and charges to cover direct
costs (such as an application fee) and indirect costs (such as a registration fee). These
costs of connecting under chapter 5 are summarised in table B.2.
Table B.2 Cost of connecting distributed generation under
chapter 5
Fee or charge Description
Registration fee Registered generators and exempt generators (not
subject to the 5MW Standing Exemption) pay a
registration fee to AEMO. The registration fee varies
depending on the type of generator registered
(see AEMO Schedule of Registration Fees 2011/12)
Participant fee Registered generators pay participant fees
determined by AEMO in accordance with the
NERs cl 2.11
Exempt generators do not have to pay
participant fees
Application fee (cl 5.3.4(b)) Payable on lodgement of application to
connect
‗No more than necessary to cover reasonable
costs‘ to assess application and prepare offer to
connect
Connection service charge
(cl 5.5(f)(1))
Paid by the connection applicant (CA) for the
connection assets provided by the distribution
network service provider (DNSP)
Use of system services charge
(cl 5.5(f)(3)(i))
Paid by CA for any required augmentations or
extensions to affected transmission and distribution
networks
APPENDIX B: REGULATION OF THE ELECTRICITY SECTOR 153
Table B.2 Cost of connecting distributed generation under
chapter 5 (cont.)
Fee or charge Description
Costs reasonably incurred to
provide distribution network
user access (cl 5.5(f)(4)(i))
Paid by the CA to the DNSP
Reasonable costs to address
impacts on the transmission
network (cl 5.3.5(e))
Paid by generating units with a nameplate rating of
10 MW or greater that impact on fault levels, line
reclosure protocols and stability aspects
Reasonable costs associated
with remote control equipment
and remote monitoring
equipment (cl 5.3.5(g))
Payment of these costs may be a condition of an
offer to connect
Fee for assistance in obtaining
approvals (cl 5.3.7(e))
DSNP may charge the CA a reasonable fee to
enable preparation of applications for
environmental and planning approvals
Source: Commission analysis.
Essential Service Commission guidance on connection costs
In addition, DNSPs are subject to guidelines issued by the ESC, including Electricity
Industry Guideline No. 14: Provision of Services by Electricity Distributors (ESC 2004b) and
Electricity Guideline No. 15: Connection of Embedded Generation (ESC 2004a). These
Victoria-specific guidelines were developed to clarify the connection process and
regulate connection charging for distributed generation. Guidelines No. 14 and 15
regulate pricing aspects of connection agreements between DNSPs and CAs,
including:
the charges under, and other terms and conditions of, connections agreements,
including the principles DNSPs must observe in setting those charges and other
terms and conditions (Guideline No. 15)
the payment to embedded generators of a share of DNSPs‘ avoided distribution
system costs (Guideline No. 15)
the payment to embedded generators of DNSPs‘ avoided customer transmission
use of system usage charges (Guideline No. 15)
the determination of customer contributions to the capital cost of new works and
augmentations to the network (Guideline No. 14).
In the discussion paper Victorian-Specific Regulatory Requirements Under the National
Energy Customer Framework (2011j), DPI concluded:
that with the insertion of chapter 5A into the NER, which provides a detailed
negotiation framework for connection contracts with embedded generators and a
connection charging regime, ‗Chapter 5A will effectively cover the field of
regulation covered by Guideline 15, and the guideline will therefore not be needed
under the NECF‘
that guidance on determination of customer contributions to the capital cost of
new works and augmentation contained in Guideline No. 14 will be also addressed
in the NECF or through AER guidelines and this guidance will therefore also be
redundant after 1 July 2012.
154 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
Cost of connecting distributed generation under chapter 5A
Embedded generators connected through the retail connection process under
chapter 5A may also be subject to connection costs. Under cl 5A.E.3(a), the AER is
required to develop and publish connection charge guidelines to assist DNSPs to
develop connection policies. Chapter 5A requires that DNSPs prepare a connection
policy that complies with the connection charge principles in cl 5A.E.1 and the AER‘s
connection charge guidelines. The AER may approve a DNSP‘s connection policy if
satisfied that it complies with these two requirements.
In addition, chapter 5A specifies that a DNSP may charge the following fees:
site inspection fee (cl 5A.D.4): DNSPs may charge 'reasonable expenses' if site
inspection is required to determine the nature of the connection service sought
negotiation fee (cl 5A.C.4(a)): DNSPs may charge 'a reasonable fee to cover
expenses directly and reasonably incurred' in assessing the connection application
and making a connection offer.
Australian Energy Regulator draft connection charge guidelines
The AER has released Draft Connection Charge Guidelines for Electricity Retail
Customers: Under chapter 5A of the National Electricity Rules (2011a) for public
consultation. Key aspects of the connection charging regime established under
chapter 5A and the draft connection charge guidelines are as follows:
Retail consumers (other than non-registered embedded generators or retail
developers) who apply for a connection service requiring an augmentation cannot
be required to make a capital contribution to the cost of the augmentation if it is a
basic connection service or below a threshold set in the DNSP‘s connection policy
(chapter 5A cl 5A.E.3(c)(4)). Under the AER draft connection charge guidelines,
DNSPs will have discretion to set multiple thresholds below which consumers will not
be charged for the costs of augmentation. However, the AER has proposed default
thresholds to apply where a DNSP cannot demonstrate that alternative thresholds
would satisfy the requirements of chapter 5A.
Retail consumers (which include micro-embedded generators) are required to pay
connection charges relating to extensions of the network and for direct connection
assets, even under a basic connection service.
Non-registered embedded generators or retail developers may be required to
make a capital contribution for a connection service requiring an augmentation
(but only if these costs have not been included in distribution use of system
charges).
Retail customers (includes non-registered embedded and micro-embedded
generators) are entitled to receive a refund where a dedicated connection asset
originally installed for a single user becomes used by other consumers (within seven
years of its installation) (AEMC 2012c, pp.172–173).
The draft connection charge guidelines provide that the total connection charge that
a CA will pay to a DNSP will be calculated according to a specific formula (box B.2).
APPENDIX B: REGULATION OF THE ELECTRICITY SECTOR 155
Box B.2 Total connection charge under chapter 5A
The connection charge that connection applicants (CAs) will pay to the distribution
network service provider (DNSP), may be made up of multiple connection services
and will be calculated in accordance with the following formula:
Connection Charge = AS + CC + PS
Where:
AS is the charge payable to the DNSP for all alternative control connection
services.
CC is the capital contribution payable to the DNSP for all standard control
connection services.
PS is the total payable to the DNSP, to account for any existing pioneer scheme,
applying to the assets to which the customer connects.
CAs may also be required to pay a security fee to the DNSP.
In determining the total connection charge, a DNSP must:
(1) Determine the charge for each component in a fair and reasonable manner.
(2) Calculate the charge for each component on the least cost technically
acceptable standard necessary for the connection service, unless:
– the CA requests a connection service or part thereof be performed to a
higher standard. In which case, the CA should contribute the additional
cost of providing the service to the standard requested
– the connection service involves augmentation to the shared network, in
which case the CA should be charged no more for this service than the
cost attributable to the CA‘s electricity demand.
Source: (AER 2011a, p.6).
In relation to embedded generation, the draft connection charge guidelines provide:
augmentation costs — non-registered embedded generators are not eligible for
the exemption from paying augmentation costs under cl 5A.E.3(c)(4) and so must
contribute to augmentation costs regardless of their size
shared network augmentation — where a non-registered embedded generator is
also a load customer, its shared network augmentation cost will be based on the
greater of either its load or generation capacity. Non-registered embedded
generators will not be charged a unit rate for shared network augmentation (based
on generation output) in accordance with s 5.2.6 of the draft connection charge
guidelines
removing specific network constraints — non-registered embedded generators
should pay to remove constraints on the network unless there is a demonstrative
net benefit of a shared network upgrade occurring (AER 2011a, p.19; AER 2011d,
p.18).
Connection charging from 1 July 2012
Both ESC Guidelines No. 14 and 15 and the AER draft connection charge guidelines
require that embedded generator connection charges are ‗fair and reasonable‘. The
major change proposed by the national connection charging framework is that
embedded generators will be liable for deep augmentation costs. Currently under ESC
156 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
Guideline No. 15 cl 3.3.2, embedded generators are only liable for shallow connection
costs of network augmentation. ‗Shallow connection costs‘ cover impacts up to and
including the first transformation in the distribution system, such as direct connection
assets and extensions (AEMC 2012c, p.173). ESC Guideline No. 15 cl 3.3.2(b)(1)(B)
specifies that embedded generators cannot be charged for deep augmentation costs.
The Joint Implementation Group responsible for coordinating the implementation of the
NECF has advised that each jurisdiction will institute transitional arrangements to ensure
the smooth implementation of the NECF from 1 July 2012. This will include transitional
provisions to govern the transition period for the connection charging regime under
chapter 5A of the NER (Joint Implementation Group 2012, p.2). An interim connection
charging regime will be inserted into chapter 11 of the National Electricity Rules, to
modify the operation of chapter 5A, so that its operation does not conflict with
electricity distribution price determinations. It is anticipated that chapter 5A will apply in
full at the commencement of the next AER price determinations.
DPI has stated that regulatory instruments currently governing charging in Victoria, in
particular ESC Guideline No. 14, underpin or are linked to the AER‘s Electricity
Distribution Price Determination 2011-15. Therefore, the current charging arrangements
will remain in place until 2015 (when the pricing determination ends) to ensure that
connection services are ‗delivered at the correct price‘ (DPI 2011h). As such, cl 38 of
the National Energy Retail Law (Victoria) Bill 2012 provides that in the interim connection
charging rules period (until 31 December 2015) transitional connection charging rules
under chapter 11 of the NER will apply instead of chapter 5A (Explanatory
Memorandum 2012, p.12).
B.4 Selling electricity generated
B.4.1 National regulation governing selling
Market generators and non-market generators
As noted in section B.3.1, distributed generators wishing to connect under chapter 5 of
the NER are required to be registered with AEMO, unless an exemption from registration
applies (cl 2.2.1 NER). Registered generating units must be classified as either ‗market‘
or ‗non-market‘ generating units (cl 2.2.1(f)). These classifications impose important
restrictions on the selling of surplus electricity generated and sent back into the grid.
Registration as a ‗market generator‘ is required to sell electricity through the NEM.
Market generating unit (cl 2.2.4) — a generating unit whose sent out generation is
not purchased in its entirety by the local retailer or a customer located at the same
connection point. A market generating unit must sell all sent out generation
through the spot market and accept payments from AEMO for sent out electricity
at spot prices applicable to its connection point. A ‗connection point‘ is the
agreed point of supply established between a DNSP and distributed generator.
Non-market generating unit (cl 2.2.5) — a generating unit whose sent out
generation is purchased in its entirety by the local retailer or a customer located at
the same connection point. A non-market generating unit is not entitled to receive
payment from AEMO for sent out generation at its connection point, except for any
APPENDIX B: REGULATION OF THE ELECTRICITY SECTOR 157
compensation that may be payable to it as a directed or affected participant (as
a consequence from a direction from AEMO under cl 4.8.9(a1)(1)).4
Non-market generators can sell sent out generation through a private bilateral
agreement outside of the NEM, for a (usually fixed) price agreed upon between
the non-market generator and a local retailer or customer located at the same
connection point. The entirety of a non-market generator‘s sent out generation
must be purchased in this way.
In Appendix 6: Guideline on Exemption from Registration as a Generator of the NEM
Generator Registration Guide (2010b), AEMO advises that:
Clause 2.2.4(a) of the Rules [NER] states that a generating unit whose sent
out generation is not purchased in its entirety by the Local Retailer or by a
Customer located at the same connection point must be classified as a
market generating unit.
This requirement applies regardless of the size of a generating unit.
One consequence of this requirement is that, where a person, who would
otherwise be eligible for exemption from the requirement to register as a
Generator, wishes to receive payment for electricity generated by their
generating unit through the NEM, they must apply to AEMO for registration
as a Market Generator and its generating unit must be classified as a
market generating unit. (AEMO 2010b, p.35)
Small generation aggregators
In the future, there may be a third option under national regulation for distributed
generators wishing to sell surplus electricity generated through the NEM. Currently, the
NER provide for the registration of intermediaries where a generating system involves
multiple parties in ownership, control and operator roles (cl 2.9.3). Generators ordinarily
required to register as a ‗market generator‘ can apply to AEMO for an exemption on
the basis that they have nominated another party to act as their intermediary.
However, the intermediary will need to apply to AEMO for registration as a generator
and each generating unit it is acting for will need to apply for an exemption from
registration under cl 2.9.3, incurring fees each time. AEMO will only allow an
intermediary exemption if the intermediary satisfies that, from a technical perspective, it
can be treated as a CA with respect to the generating system (AEMO 2010b, p.2).
However, where the ownership of generating units within a generating system is split,
each generating unit must be registered separately as a market generating unit in
order to sell through the NEM (AEMO 2010b, p.2; AEMC 2012a, p.2).
AEMO recently submitted a rule change to the AEMC to introduce a new category of
market participant into the NER called a 'small generation aggregator'. AEMC has
released a consultation paper on the rule change and is seeking public submissions by
12 April 2012.5 Under the proposed rule change, small generation aggregators will only
have to register once with AEMO. A small generation aggregator will have market
responsibility for the participation of multiple generating units in the NEM. Separate
registration of each of the generating units will not be required, significantly reducing
4 See Appendix 4: AEMO’s Policy on Registration as a Non-Market Generator of the NEM Generator
Registration Guide for the conditions that apply to registration as a non-market generator (AEMO 2010b,
pp.25–26).
5 See the AEMC‘s Small Generation Aggregator Framework website:
http://www.aemc.gov.au/electricity/rule-changes/open/small-generation-aggregator-framework.html
158 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
costs and improving access to the market. This will allow aggregated generators to
more easily enter and sell in the NEM (AEMC 2012a, pp.1–5). As registered participants,
small generation aggregators would be required to connect to the distribution network
through the NER chapter 5 process.
Distribution planning and reporting
DNSPs are required to consider the impacts of connecting distributed generation as
part of their distribution network planning. The national network planning and
development framework is supplemented by State-based planning and reporting
regulatory arrangements, which vary among jurisdictions (AEMC 2009c, pp.107–111;
AEMC 2011b, p.5). Note, however, that the AEMC is considering a rule change request
to amend the NER and establish a national annual distribution network planning and
reporting framework.6
The current distribution planning arrangements are as follows:
Chapter 5 of the NER requires that each DNSP review annually the expected future
operation of its distribution networks over the next five years, taking into account
forecast loads, future generation and market network services, and demand side
developments (cl 5.6.2(a) and (d)). The NER do not require that DNSPs publish
periodic planning reports (AEMC 2011b, p.5).
In Victoria, the Electricity Distribution Code (ESC 2011a) requires that DNSPs publish
annual distribution system planning reports (DSPRs) that plan for the next five
calendar years (cl 3.5). A DSPR must cover:
– historical and forecast demand
– feasible options for meeting forecast demand, such as opportunities for
embedded generation and demand management
– availability of contributions from the DNSP to embedded generators to reduce
forecast demand and defer or avoid augmentation of the distribution system.
The EI Act s 40FJ requires that, as a licence condition, licensed distributors must
regularly report7 to the Minister for Energy and Resources on:
– the number of solar photovoltaic (PV) systems connected to the distribution
network operated by the licensee
– the aggregate generating capacity of solar PV systems connected to the
distribution network operated by the licensee
– the total amount of surplus electricity generated by solar PV systems conveyed
along the distribution network operated by the licensee.
When the NECF commences on 1 July 2012, the reporting requirement in the
Electricity Distribution Code (ESC 2011a) will become a licence condition. This will
ensure that DSPRs continue to be completed by distribution businesses until the
AEMC‘s rule change process regarding a national reporting framework has been
completed.
6 See (AEMC 2011b) and the AEMC‘s Distribution Network Planning and Expansion Framework website:
http://www.aemc.gov.au/Electricity/Rule-changes/Open/Distribution-Network-Planning-and-Expansion-
Framework.html
7 On a six monthly basis for solar PV systems eligible for the premium feed-in tariff and on a monthly basis for
solar PV systems eligible for the transitional feed-in tariff. Feed-in tariffs are discussed is section B.4.2.
APPENDIX B: REGULATION OF THE ELECTRICITY SECTOR 159
These distribution planning and reporting obligations mean that DNSPs must consider,
plan for, accommodate and monitor the effects of distributed generators connecting
to, and sending surplus electricity generated back into, the distribution grid.
B.4.2 Victorian regulation governing selling
Licensing
The Victorian electricity industry is regulated through a licensing regime established
under Pt 2 of the EI Act and administered by the ESC. DPI noted that:
The licensing regime has also been utilised directly by Government as an
instrument to deliver on specific policies, placing statutory obligations on
licensed businesses while bringing compliance with those obligations into
the purview of the regulator. (DPI 2011i)
The licensing regime has a diverse range of functions, including:
limiting entry to the energy sector
imposing regulatory obligations on licensed businesses
imposing statutory obligations on licensed businesses
prohibiting cross-ownership between licensed businesses of different types
identifying energy businesses that may exercise special statutory powers
requiring exit from the energy sector (revocation)
funding regulatory activities (DPI 2011i).
Restrictions on selling electricity
The EI Act prohibits a person from generating electricity for supply or sale unless that
person has a license or is exempt from the requirement to hold a license (s 16(1)). Under
s 17 of the EI Act, the Governor in Council can make an Order in Council exempting a
person from the requirement to obtain a licence. An Exemption Order came into effect
on 1 May 2002 (ESC nd, p.1). Exemptions available include:
generators connected to the transmission or distribution network at a common
connection point with a capacity of less than 30 MW
the intermediary distribution and supply of electricity to a short term resident, long
term resident, small business customer or large business customer within the limits of
the premises owned or occupied by the person engaging in that activity
the metered intermediary sale of electricity within the limits of the premises owned or
occupied by the person engaging in that activity (Order in Council 2002; ESC nd, p.1).
The ESC is empowered by cl 5 of the Exemption Order to issue certificates of opinion
where it considers that a particular activity does or does not constitute:
the intermediary distribution or supply of electricity, or
the metered intermediary sale of electricity, and
if it does so, that activity does or does not, as applicable, constitute the
intermediary distribution or supply of electricity or the metered intermediary sale of
electricity for the purposes of the Exemption Order.
160 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
The ESC made a policy decision in 2011 to cease issuing these certificates, due to
confusion regarding their regulatory status (ESC 2011c).
Licensing from 1 July 2012
The commencement of the NECF on 1 July 2012 will introduce a national retailer
authorisation scheme, designed to replace the jurisdictional licensing schemes for
energy retailing currently in place in states and territories. In an issues paper discussing
Victorian licensing arrangements under the NECF, DPI has stated that:
It is assumed in this paper that commencement of the NERL in the retail
sector will see the complete removal of any requirement for a retailer to
maintain a Victorian retail licence to sell energy in Victoria.
On the other hand, there is no proposed replacement scheme for the
authorisation of distribution, transmission or generation activities at the
national level beyond what is already provided by market registration
requirements.
The regulatory requirements of the NECF itself do not hinge on the concept
of licensed energy businesses. Relevant entities covered by the NECF
include authorised retailers, entities that retail electricity but are exempt
from authorisation, electricity distributors who are Distribution Network
Service Providers (DNSPs) under the National Electricity Law, gas distributors
subject to access regulation under the National Gas law, and other
jurisdictionally nominated distributors. Therefore, from the point of view of
applying the NECF alone, no licensing regime is necessary. (DPI 2011i)
DPI has concluded that although the NERL includes a retailer authorisation and exempt
selling process, ‗small scale‘ generators who sell surplus electricity into the distribution
grid are not catered for under the national framework. As such, a Victoria specific
regime, regulated by the ESC, will continue to govern distribution licensing in Victoria.
DPI has noted its ‗concern that there is a high degree of regulatory fragmentation in
the area of licensing, authorisation and exemptions‘ and that it will ‗investigate
appropriate ways for rationalising this structure in the future‘ (DPI 2011i; DPI 2011h). The
Commission has been advised by DPI that the Exemption Order (in an amended form)
will also continue to exempt generators of less than 30 MW capacity from the need to
obtain a distribution license.
Feed-in tariffs
In Victoria, certain distributed generators connected to the distribution network are
able to sell surplus electricity generated into the distribution grid through FiT schemes
under Division 5A of the EI Act.
There are currently three FiT schemes operating in Victoria:
(1) Premium feed-in tariff (PFiT): started on 1 November 2009 and ended on 29
December 2011 (the declared scheme capacity day). The PFiT scheme is now
closed to new applicants. However, generators participating in the PFiT scheme
before the declared scheme capacity day can continue to participate for the 15
year duration of the scheme (until 30 October 2024).
(2) Transitional feed-in-tariff (TFiT): started on 1 January 2012 and is currently open to
new applicants. The TFIT scheme will run for 5 years from its commencement date
until 31 December 2016. The scheme can, however, be closed to new applicants
once certain discretionary trigger points are reached. The Minister for Energy and
Resources may declare a TFiT scheme end day if any of the following occur:
APPENDIX B: REGULATION OF THE ELECTRICITY SECTOR 161
– the aggregate generating capacity cap of 75 MW of installed scheme
generating capacity is met
– the average cost per customer of electricity per year arising out of the
operation of the TFiT scheme is $5 or more
– the Minister considers it appropriate to do so (s 40FEA, EI Act).
(3) Standard feed-in-tariff (SFiT): open to new applicants. The SFiT was initially
introduced in 2004 for wind energy generators and was extended to other forms of
small-scale renewable energy in 2007 (Batchelor 2007). Unlike the PFiT and TFiT
schemes, there is no end date.
In Victoria, to ensure that the customer is paid (in the form of a credit) for any surplus
energy generated that goes into the grid, licensed retailers are required to fund the SFiT
scheme. The PFiT and TFiT schemes are funded by a distributor ‗pass through‘ model.
Under this arrangement distributors apply the appropriate FiT rebates to electricity
retailers‘ network bills that, in turn, apply the credits to eligible customers‘ bills. The AER
regulates the distribution charge that licensed retailers pay the distributer.
Premium feed-in tariff scheme
Eligibility
All licensed retailers with more than 5000 customers were required to offer a PFiT to
qualifying customers. Licensed retailers with 5000 or less customers could choose to
offer a PFiT to qualifying customers. Note that the PFiT scheme closed to new applicants
on 29 December 2011. A ‗qualifying customer‘:
purchases electricity from a licensed retailer, and
engages in the generation of electricity using a solar PV system with a capacity of
5kW or less connected to the distribution network, and
for householders: is claiming only one solar PV system on a property that is a
principal place of residence, or
for persons that occupy one or more properties (other than as a place of
residence):
– is claiming only one solar PV system at each of those properties, and
– the person's annual consumption rate of electricity is 100 MWh or less, and
has been exempted by Order under s 17 from the requirement to hold a licence in
respect of the generation of electricity for supply and sale, and
has net metering in place.
Price, terms and conditions
The PFiT is prescribed as not less than 60 cents per kWh for surplus electricity fed into the
grid (s 40FA(2)(a) of the EI Act). A PFiT offer must comply with statutory minimum terms
and conditions. Other terms and conditions of a PFiT offer must be ‗fair and
reasonable‘. A number of electricity retailers have offered ‗top-up‘ over and above the
statutory minimum rate.
162 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
Transitional feed-in tariff scheme
Eligibility
All licensed retailers with more than 5000 customers must offer a TFiT to eligible
customers (‗TFiT scheme customers‘). Licensed retailers with 5000 or less customers may
choose to offer a TFiT to TFiT scheme customers. A ‗TFiT scheme customer‘:
purchases electricity from a licensed retailer, and
engages in the generation of electricity using a solar PV system with a capacity of
5kW or less connected to the distribution network on or after 1 January 2012, and
for householders: is only claiming one solar PV system on a property that is a
principal place of residence, or
for persons that occupy one or more properties (other than as a place of
residence):
– is only claiming one solar PV system at each of those properties, and
– the person's annual consumption rate of electricity is 100 MWh or less, and
has been exempted by Order under s 17 from the requirement to hold a licence in
respect of the generation of electricity for supply and sale, and
has net metering in place.
Price, terms and conditions
The TFiT is prescribed as not less than 25 cents per kWh for surplus electricity fed into the
grid (s 40FAB(2)(a) of the EI Act). A TFiT offer must comply with statutory minimum terms
and conditions. Other terms and conditions of a TFiT offer must be ‗fair and reasonable‘.
A number of electricity retailers have offered ‗top-ups‘ over and above the statutory
minimum rate.
Standard feed-in tariff scheme
Eligibility
All licensed retailers with more than 5000 customers must offer a SFiT to relevant
generators. A ‗relevant generator‘ is:
a generation company, or
a person engaging in the generation of electricity that has been exempted by
Order under s 17 from the requirement to hold a licence in respect of the
generation of electricity for supply and sale, and
engages in the generation of electricity using a small renewable energy generation
facility connected to the distribution network, with a capacity of less than 100 kW,
defined as:
– solar, wind, hydro and biomass generating facilities
– other forms of small renewable energy specified in an Order in Council
published in the Government Gazette. The Commission understands that the
power to extend the definition of ‗small renewable energy generation facility‘
has not yet been used.
APPENDIX B: REGULATION OF THE ELECTRICITY SECTOR 163
The SFiT specifically excludes:
energy created from the combustion of fossil fuels, or materials or waste products
derived from fossil fuels, and
since the commencement of the TFiT scheme, solar PV systems with a capacity of
5 kW or less, connected to the distribution system.
Price, terms and conditions
Unlike the PFiT and TFiT schemes, the SFiT price is not prescribed by the EI Act and each
licensed retailer has discretion to set its own tariff price. However, the EI Act requires
that the SFiT price and associated terms and conditions must be ‗fair and reasonable‘
(s 40FB). The ESC has interpreted a ‗fair and reasonable‘ price to mean that the rate
offered to the customer must be not less than the rate the customer pays to buy
electricity from the retailer (box B.3). Similarly, DPI‘s website states that SFiT customers
receive a ‗―one-for-one‖ payment rate for any excess electricity they feed back into
the state‘s electricity grid‘ (DPI 2011d).
Although not mandated by legislation, DPI‘s website also advises that:
The Standard Feed-in Tariff‘s threshold is not designed for system installations
where the generating capacity is significantly disproportionate to the
actual energy used.
This does not mean that the maximum system capacity must be in use at all
times, although the entire capacity should be required for a significant
portion of the year to offset your energy consumption. (DPI 2011d)
Obligation on licensed retailers to publish feed-in tariff offers
As discussed above, the EI Act regulates the electricity industry in Victoria through a
licensing regime that, amongst other things, imposes statutory obligations on licensed
businesses. This includes imposing a licence condition on electricity retailers to publish
FiT terms and conditions online. The EI Act requires that FiT offer information on licensed
retailers‘ websites must be kept up-to-date (ss 40N, 40NA and 40NB) but does not
provide any guidance on how this information must be presented.8
Licensed retailers that sell electricity to more than 5000 customers (‗relevant
licensees‘) must publish the terms and conditions of their PFiT, TFiT and SFiT offers
(ss 40FF and 40G).
Licensed retailers that sell electricity to 5000 or less customers (‗small retail
licensees‘) and choose to offer a PFiT and/or TFiT, must publish the terms and
conditions of their PTiT and/or TFiT offers. If a small retail licensee decides to no
longer purchase electricity through a PFiT and/or TFiT scheme, it may publish a
notice in the Government Gazette to that effect. The small retail licensee‘s
obligations under the PFiT and/or TFiT scheme will cease on the day such a notice is
published (s 40FG).
The terms and conditions of FiT offers take effect two months after publication, unless
they are referred to the ESC for assessment (s 40H). The criteria considered by the ESC in
8 Note that the obligation on licensed electricity retailers to publish tariffs and terms and conditions of sale
under ESC Guideline No. 19: Energy Price and Product Disclosure (2009a) — currently under review — does
not extend to feed-in tariff offers. See Guideline 19: Energy Price and Product Disclosure – Issues Paper (ESC
2011b).
164 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
assessing whether a FiT offer is ‗fair and reasonable‘ effectively prescribe the matters
that should be included in a fair and reasonable offer published by licensed retailers.
The role of the ESC is discussed below. The EI Act also sets minimum terms and
conditions for PFiT and TFiT offers (ss 40FA and 40FAB). These statutory conditions form
the required minimum content of a published offer.
Role of the Essential Services Commission
The EI Act provides that the Minister for Energy and Resources may refer matters to the
ESC for assessment if not satisfied that the terms and conditions of a licensed retailer‘s
FiT offers are ‗fair and reasonable‘ (s 40I):
for licensed retailers that have published their FiT terms and conditions — before the
PFiT, TFiT and SFiT terms and conditions take effect (published terms and conditions
take effect two months after publication)
for licensed retailers that have failed to publish the their FiT terms and conditions as
required — at any time.
The ESC must assess the referred terms and conditions and report to the Minister of its
assessment (s 40J). The ESC can recommend or determine:
the terms and conditions of a licensed retailer‘s PFiT and TFiT scheme are not ‗fair
and reasonable‘ and suggest alternative terms and conditions
the price, terms and conditions of a licensed retailer‘s SFiT scheme are not ‗fair and
reasonable‘ and suggest an alternative price, terms and conditions (ss 40J(2) and 40L).
A small number of referrals have been made under this mechanism.9 The meaning of
‗fair and reasonable‘ is discussed in box B.3.
Box B.3 Fair and reasonable feed-in tariff offers
The Department of Primary Industries (DPI) has published criteria for the assessment of
whether feed-in tariff (FiT) offers are ‗fair and reasonable‘. The DPI criteria outline the
rights and obligations of customers and licensed retailers that must be included for a FiT
offer to be ‗fair and reasonable‘. The DPI criteria require that an offer must, among
other things:
require that the retailer will pay or credit the customer, for electricity supplied under
a FiT contract, at a rate not less than the rate the customer pays to buy electricity
from the retailer
require the FiT will be credited with the same frequency as the customer is billed
and address billing arrangements
outline how the FiT credit will be calculated based on a reading of the customer‘s
meter
state all additional costs related to the FiT contract
provide for each parties‘ rights and obligations in relation to under and
overpayment of the FiT credit
cover variation and termination of the FiT contract.
9 See the ESC website: esc.vic.gov.au.
APPENDIX B: REGULATION OF THE ELECTRICITY SECTOR 165
Box B.3 Fair and reasonable feed-in tariff offers (cont.)
In a guidance paper Methodology for Assessment of Fair and Reasonable Feed-in
Tariffs and Terms and Conditions (2008b), the Essential Services Commission (ESC)
outlined its approach to evaluating FiT offers referred for assessment under s 40I of the
Electricity Industry Act 2000 (Vic). The ESC has clarified that it will apply the DPI criteria,
plus the following additional criteria, when assessing the fairness and reasonableness of
the terms and conditions of referred retailers‘ FiT offers.
(1) Cost of service provision — any charge and terms and conditions imposed under FiT
offers must be based on the reasonable costs that the retailer incurs in providing
goods or services to small renewable energy generators in relation to the purchase
of energy from such generators.
(2) Cost allocation — the costs that a retailer incurs in accepting supply from a small
renewable generator must not include costs not associated with accepting that
supply and only include an appropriate allocation of any common costs incurred
by the retailer in accepting that supply and in providing any other goods or
services in relation to that supply.
(3) Cost differentials — a retailer‘s FiT offer terms and conditions must be the same for
all small renewable energy generators unless there is a material difference in the
cost of accepting supply from and providing associated goods and/or services to
different small renewable energy generators or classes of small renewable energy
generators.
(4) Simplicity — the charges and terms and conditions for the FiT should be simple and
easy to understand.
Source: (ESC 2008b, pp.8–12).
Regulation of feed-in tariff schemes from 1 July 2012
Once the NECF commences on 1 July 2012, the regulation of electricity retailers will be
governed by a national regime and the Victorian retail licensing regime will be
repealed. Although current retail licence conditions relating to FiTs will continue to
operate unaffected in a practical sense, they will be enforced as direct statutory
requirements under the EI Act instead of licence conditions. Clauses 75 to 95 of the
National Energy Retail Law (Victoria) Bill 2012 propose consequential amendments to
the FiT provisions of the EI Act (Division 5A, ss 40F to 40NC) to reflect the repeal of
electricity retail licensing. The Explanatory Memorandum states:
Currently, the requirement for retailers to comply with the feed-in tariff
schemes is linked to their licences. The effect of the amendments made by
this clause [75], and by clauses 76 to 95, is to create a direct statutory
obligation for retailers to comply instead of the current deemed licence
condition. (Explanatory Memorandum 2012, p.18)
This means that under an amended EI Act:
the FiT scheme provisions — including the eligibility criteria, price, terms and
conditions — will be unchanged
electricity retailers will still be obliged to publish on their websites, and keep
up-to-date, their FiT offer terms and conditions
the ESC will continue to assess whether referred FiT offers are ‗fair and reasonable‘.
166 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
Publication of feed-in tariff information
After the commencement of the NECF, there will be extra obligations on electricity
retailers to publish information on their FiT offers.
From 1 July 2012, the AER‘s ‗Energy Made Easy‘ price comparator website will
become operational as part of the retail pricing information requirements under the
NERL (AER 2012b, p.5). Division 11 of the NERL also requires that the AER publish
retail pricing information guidelines. The AER released its final guideline, AER Retail
Pricing Information Guideline in January 2012. The Guideline aims:
… to assist small customers in readily comparing standing offer prices and
market offer prices offered by retailers, by specifying the manner and form
in which details of standing offer prices and market offer prices are to be
presented by retailers. (AER 2012a, p.2)
The NERL (s 63) and the Guideline require that retailers produce an ‗Energy Price
Fact Sheet‘ for each standing and market (contract) offer that a retailer offers to
small customers. These Fact Sheets will be generated on the AER‘s Energy Made
Easy price comparator website. Retailers are also required to publish Energy Price
Fact Sheets for each of their generally available contract offers on their websites.
The Guideline specifies what information must be included on each Energy Price
Fact Sheet and how it should be presented (AER 2012a). Although the Guideline
does not mention FiTs, the Commission understands that the obligation on retailers
to produce Energy Price Fact Sheets will extend to FiT offers but that only basic
information on FiT offers would be required. Retailers are not required to provide
detailed information on FiT offer terms and conditions on the Energy Price Fact
Sheets they submit to the AER.
The amended EI Act will contain new price comparator requirements (a substituted
Division 6). These provisions will require the ESC to maintain its own price
comparator website ‗YourChoice‘, to assist small customers to compare standing
offer and market offer retail prices required to be presented by the NERL and AER
Retail Pricing Information Guideline (2012a). It will also require that retailers provide
the ESC with information and data about standing and market offer prices
(Explanatory Memorandum 2012, p.20). The Commission is advised that ESC has no
intention to include FiT offers on the YourChoice website.
Feed-in tariff application process
The process of installing a small renewable energy generation facility or solar PV system
and applying for a FiT can be complex, and the terms and conditions in FiT contracts
will vary between retailers. Unlike the process for connecting distributed generation
under the national framework, the process for applying for a Victorian FiT is not
provided for by legislation.
Broadly, the process for installing a solar PV system and applying for a FiT involves a
number of key stages. Note that some of these stages (such as submission of forms to
the retailer and distributer) can be completed concurrently.
Arrange for design and installation: select a suitable solar PV system and arrange
for it to be installed by an accredited Clean Energy Council (CEC) installer. The
customer will also need to complete connection and approval processes with the
electricity retailer and distributor (section B.3).
Paperwork: all forms required for solar PV installation and connection, to apply for
any applicable rebates and to participate in a FiT scheme need to be completed.
All necessary paperwork must be complete in order for a FiT applicant to
participate in a FiT scheme. These include:
APPENDIX B: REGULATION OF THE ELECTRICITY SECTOR 167
– a Commonwealth Solar PV STC Assignment and Written Compliance Statement
to assign the right to create Small-Scale Technology Certificates (STCs) to the
retailer or installer, in return for an upfront discount or payment. Note that this is
not a requirement for a Victorian FiT, although most customers will wish to
complete this paperwork in order to obtain an upfront discount on their solar
PV system
– a Solar Connection Form to notify the distributor that a solar PV system will be
installed at the customer's address and to outline customer rights and
obligations in relation to this installation
– an Electrical Work Request (EWR) form and Certificate of Electrical Safety (CES),
which are usually completed by the installer and forwarded to the retailer, to
notify the retailer that the installed solar PV system has been wired and
inspected for safety
– a Victorian FiT contract with an electricity retailer must be entered into
– any other paperwork specific to the retailer and/or distributer must be
completed.
Installation: will generally occur before the customer enters into a FiT contract with
a retailer.
– Once the installation has been completed, an EWR and CES (including sign-off
from an licensed electrical inspector to vouch for the installation meeting all
safety requirements) needs to be lodged with the retailer. The FiT contract can
be entered into at the same time as the EWR and CES are lodged, however, it
will not become effective until the appropriate metering is in place and the
system is connected to the grid.
– After the EWR and CES are lodged, the installer completes the installation of the
solar PV system and arranges for bi-directional metering (such as an interval or
smart meter) to be installed and/or configured.
Metering upgrade/reconfiguration and connection: the solar PV system is
connected to the distribution network and is ready to produce electricity.
Feed-in tariff: the solar PV system starts generating electricity and receiving credits
for surplus electricity exported into the distribution grid (CEC 2011b, p.2; CEC nd; DPI
2011e).
A simplified application process for FiTs for a solar PV system is set out in figure B.2.
168 POWER FROM THE PEOPLE: INQUIRY INTO DISTRIBUTED GENERATION
Figure B.2 Simplified example of the application process for
feed-in tariffs for a solar PV system
Source: Commission analysis.
Costs associated with participating in a feed-in tariff scheme
The EI Act does not prescribe any fees or charges for applying for and participating in
the PFiT, TFiT or SFiT schemes. However, some electricity retailers may charge
administration fees as part of their FiT electricity contracts (DPI 2011g). In addition,
bi-directional metering is required to participate in a FiT scheme. Old style
accumulation meters are unable to measure electricity generated and sent into the
grid from distributed generators. Bi-directional meters allow two-way electricity flows
and the ability to record those flows on a half hourly basis (DPI 2011a; DPI 2011c).
The State Government is rolling out advanced metering infrastructure (AMI) across
Victoria. The rollout is scheduled to be completed by 31 December 2013. The regulatory
arrangements governing AMI are contained in several Orders in Council made under
ss 15A and 46D of the EI Act (‗original Order‘ dated 28 August 2007, ‗AMI specifications
Order‘ dated 12 November 2007 and ‗revised Order‘ dated 25 November 2008) (ESC
2008a, p.3). AMI installation is paid for by electricity consumers through a levy on all
household electricity bills (CALC 2011, p.1).
Choose your solar PV system and installer
Choose your electricity retailer
Submit Electrical Work Request and Certificate of
Electrical Safety forms with electricity retailer
Confirm installation with electricity distributor
Complete Commonwealth Solar PV STC
Assignment and Written Compliance Statement
for any applicable REC/Solar credits
CEC accredited installer assists with the design
and implementation of solar PV system
Negotiate feed-in tariff terms and conditions and
sign-off feed-in tariff contract with electricity
retailer
Submit Solar Connection form with electricity
distributor
The submission of forms to
the electricity retailer and
distributor may occur
concurrently
Other paperwork specific
to the retailer and/or
distributor may be required
REFERENCES 169
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