Power From the People - Draft Report

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]

http://www.vcec.vic.gov.au/

mailto:[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

http://en.wikipedia.org/wiki/Solar_radiation

http://en.wikipedia.org/wiki/Electricity

http://en.wikipedia.org/wiki/Semiconductor

http://en.wikipedia.org/wiki/Solar_panel

http://en.wikipedia.org/wiki/Solar_cell

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


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 engagement by Distribution Network Service Providers


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


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:


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



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


through the retail electricity market.




agreement

ensure that FiT prices are published by the Australian Energy Regulator under the

requirements of the National Electricity Customer Framework.



which would be consistent with a fair and reasonable offer —updated at regular

intervals


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.


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


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


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.


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


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.

http://www.solaraccreditation.com.au/


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.


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


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.


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


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


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


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.


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


(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.


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.


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


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).


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


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


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.


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


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.



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



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.



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


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


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.


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).


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).


Figure 2.5 Wind power cost projections


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



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.


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.


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.


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.


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.


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:


… 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.


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:


… 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:


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


‘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


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


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).


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.


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)


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.


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


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:


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


enhancing contestability and competition through

– freeing market entry

– informing business and consumer decisions


– 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 ‘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.

http://en.wikipedia.org/wiki/Peak_demand

http://en.wikipedia.org/wiki/Marginal_cost

http://en.wikipedia.org/wiki/Marginal_cost


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


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).


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


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.


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.


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)


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


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


* This applies to


resolution

Agree

d


Not agreed

Legend


Regulator


Service Provider


DNSP has 5 days to

provide information




potential applicant

wishing to connect

Applicant lodges

application on form

determined by DNSP



needed


deficiency



service


by AER


submitted




possible changes &

expenses


offer

Option of dispute


through AER

Offer terms form

connection contract





application*





connection offer



may be available


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))


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.



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 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


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).


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.



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)


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).


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)


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


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).


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



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 engagement by Distribution Network Service Providers


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


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)


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:


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).


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


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:


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.



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.



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:


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)


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)


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.


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


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).


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


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.


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:


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



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.


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


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.


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.


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).


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.


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).


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.


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


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.


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).


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


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).


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.


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)


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


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).


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?


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)


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.


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)

http://www.symex.com.au/


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).


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


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


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


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


through the retail electricity market




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):


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.


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.


(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).


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.


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).


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.



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.


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


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.


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)


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.


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



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)


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.


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.


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


– 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.


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


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).


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


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:


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


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).


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.


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


agreement

ensure that FiT prices are published by the Australian Energy Regulator under

the requirements of the National Electricity Customer Framework.


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


reasonable criteria, redefined to be based on the wholesale price of electricity

(the energy value).


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.


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.


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


Table A.1 Submissions received (cont.)


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


Table A.1 Submissions received (cont.)


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


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





Table A.4 Consumer groups roundtable


Gerard Brody Consumer Action Law Centre

Gemma Dodson Consumer Affairs Victoria

David Standford Consumer Utilities Advocacy Centre

Dean Lombard Victorian Council of Social Service



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)


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.


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).


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).


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



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


Semi-scheduled:


nameplate rating of 30 MW

or greater or group of

generating units



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:


nameplate rating of less

than 30 MW or a group of

generating units



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


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:


– 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).


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).


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


(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


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.


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.


Figure B.1 Connection process for distributed generation

under chapter 5A

Source: Commission analysis of chapter 5A NER.

* This applies to


resolution

Agree

d


Not agreed

Legend


Regulator


Service Provider


DNSP has 5 days to

provide information




potential applicant

wishing to connect

Applicant lodges

application on form

determined by DNSP



needed


deficiency



service


by AER


submitted




possible changes &

expenses


offer

Option of dispute


through AER

Offer terms form

connection contract





application*





connection offer



may be available


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


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


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.


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).


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


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


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


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.


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.


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:


– 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.


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.


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.


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.


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).


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.


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‘.


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:


– 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.


Figure B.2 Simplified example of the application process for

feed-in tariffs for a solar PV system


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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Power From the People - Draft Report

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