Gas Market Taskforce Supplementary Report
October 2013
Contents
About this report ................................................................................................................................... 1
Chapter 1: Introduction ........................................................................................................................ 2
About the Gas Market Taskforce ....................................................................................................... 2
Gas in Victoria....................................................................................................................................... 3
Gas as an energy source .................................................................................................................... 3
History of gas in Victoria ..................................................................................................................... 6
Australian gas markets ........................................................................................................................ 7
Market oversight and reforms......................................................................................................... 9
Commonwealth policy platform 2013 .......................................................................................... 10
Chapter 2: Overview of supply and demand .................................................................................. 10
About Chapter 2 ................................................................................................................................. 10
Global supply and demand ............................................................................................................... 12
Australian and eastern market supply............................................................................................. 14
Victoria’s gas resources ................................................................................................................ 16
Conventional gas ........................................................................................................................ 16
Unconventional gas ................................................................................................................... 17
Eastern market domestic demand ................................................................................................... 19
Victoria’s demand ........................................................................................................................... 21
New LNG export demand ................................................................................................................. 23
Gas prices will increase..................................................................................................................... 25
The eastern market is already in transition .................................................................................... 27
Potential impacts on domestic consumers ..................................................................................... 28
Potential implications for the Australian and Victorian economies ............................................. 30
Chapter 3: Drivers, challenges and potential solutions for the expanded eastern gas market
.............................................................................................................................................................. 34
About Chapter 3 ................................................................................................................................. 34
Drivers of increasing gas price increases in the eastern market ................................................ 34
Competition between LNG export producers and domestic users ......................................... 34
Logistical and operational issues in the Queensland Gas fields............................................. 35
Increasing production costs .......................................................................................................... 36
Lack of transparency in supply and demand information......................................................... 39
Inefficient upstream competition .................................................................................................. 40
Unconventional gas - challenges and community concerns .................................................. 41
Progress on regulatory reform for unconventional gas ................................................................ 47
Commonwealth-State initiatives (COAG) ................................................................................... 47
South Australia ............................................................................................................................... 48
Queensland ..................................................................................................................................... 49
New South Wales ........................................................................................................................... 50
Victoria ............................................................................................................................................. 51
Potential solutions .............................................................................................................................. 52
Proposals for leading practice regulation and community engagement ................................ 52
Better community engagement through an independent gas commissioner .................... 52
Understand and manage risks to water resources ............................................................... 54
Improve standards for hydraulic fracturing .................................................................. 56
Royalties and industry payments ................................................................................................. 57
Industry incentives ..................................................................................................................... 58
Compensation for landholders and neighbours ..................................................................... 58
Payments for communities........................................................................................................ 59
Initiatives to increase productivity and reduce costs of major projects .................................. 60
Initiatives to improve supply and demand information ............................................................. 61
Upstream competition should be encouraged ........................................................................... 61
Domestic reservation is not a solution ............................................................................................ 62
Chapter 4: Wholesale markets and transmission.......................................................................... 65
About Chapter 4 ................................................................................................................................. 65
Introduction.......................................................................................................................................... 65
History and infrastructure .............................................................................................................. 65
Ownership ....................................................................................................................................... 66
Transmission ....................................................................................................................................... 66
The gas pipelines access regime ................................................................................................ 67
Victorian gas transmission system .............................................................................................. 70
Pipeline capacity trading ............................................................................................................... 71
Capital expenditure and augmentation ....................................................................................... 72
Wholesale markets............................................................................................................................. 73
Upstream markets .......................................................................................................................... 76
New reform initiatives to achieve an integrated and transparent market .......................... 77
Downstream markets ..................................................................................................................... 77
Secondary markets – risk and financial products.......................................................................... 80
Chapter 5: Retail markets and distribution ..................................................................................... 82
About Chapter 5 ................................................................................................................................. 82
Background ......................................................................................................................................... 82
Distribution of gas............................................................................................................................... 84
Retailing of gas ................................................................................................................................... 85
Issues in the retail markets ............................................................................................................... 89
Opportunities to address eastern market challenges ................................................................... 93
Chapter 6: Case studies on overseas market development ........................................................ 95
About Chapter 6 ................................................................................................................................. 95
Early history of gas trading ............................................................................................................... 95
Gas as a traded commodity .............................................................................................................. 96
Case Studies ....................................................................................................................................... 96
United Kingdom .............................................................................................................................. 96
United States and Canada ............................................................................................................ 97
Continental Europe ........................................................................................................................ 99
Summary of approaches to transmission access regulation ................................................. 102
Lessons learnt from overseas markets ......................................................................................... 103
Relevance for Victorian wholesale market ............................................................................... 104
Relevance to the eastern gas market ....................................................................................... 105
Appendix 1: List of stakeholders consulted by the Chair ........................................................... 106
Appendix 2: National reform agenda and other reviews ............................................................ 109
Appendix 3: Gas resources information - further details ............................................................ 113
Appendix 4: Victorian Government media release...................................................................... 121
Appendix 5: Further details on gas regulation in Victoria........................................................... 123
Appendix 6: Royalties background information ........................................................................... 134
Appendix 7: Acronyms..................................................................................................................... 140
Figures
Figure 1: Gas consumption in eastern states in 2011-12 ....................................................................... 3
Figure 2: Turn-in ceremony for Victoria’s first natural gas pipeline ....................................................... 7
Figure 3: Map of Australia gas fields and key pipelines .......................................................................... 8
Figure 4: Projected world natural gas consumption for OECD and non-OECD countries ................... 12
Figure 5: International Energy Agency estimates of natural gas resources by region in 2011 ............ 13
Figure 6: Australia’s produced and remaining gas resources ............................................................... 14
Figure 7: Eastern market total produced and remaining gas resources. .............................................. 16
Figure 8: Victoria’s main gas production basins. Pie charts show past and remaining production. ..... 17
Figure 9: Eastern market primary consumption of gas by sector in 2011–12 ...................................... 19
Figure 10: Total gas consumed by Australian households in 2011-12 ................................................. 22
Figure 11: Non-residential gas consumption in eastern states in 2011-12 ........................................... 22
Figure 12: Intended use of natural gas in 2013 by businesses surveyed ............................................. 22
Figure 13: Projected eastern market demand....................................................................................... 24
Figure 14: Domestic LNG and 2P Reserve Projections ........................................................................ 25
Figure 15: Possible paths for gas price levels in the eastern gas market ............................................ 26
Figure 16: Data on Victorian manufacturing industries that use gas intensively (2011) ....................... 32
Figure 17: Typical production costs for Australian gas resources in 2012 ........................................... 38
Figure 18: The eastern market gas transmission system. ................................................................... 67
Figure 19: Business models for wholesale gas trade through bilateral contracts ................................ 74
Figure 20: Eastern Australian gas market structure - conceptual diagram ........................................... 75
Figure 21: Comparison of residential gas cost components across eastern Australia ......................... 84
Figure 22: Average residential customer numbers per retailer in Victoria in 2011-12 .......................... 88
Figure 23: Gas annual standing offer charges 2007-2012 ($/year 2012) ............................................. 89
Figure 24: Residential retail prices for Victoria ($/GJ, $2013 real) ....................................................... 90
Figure 25: British gas transmission system ......................................................................................... 96
Figure 26: Gas hubs and flows in the US and Canada ......................................................................... 99
Figure 27: Gas transmission in Europe ............................................................................................... 100
Figure 28: Trade volumes at European hubs...................................................................................... 101
Figure 29: Gas Market Development Plan. ......................................................................................... 111
Figure 30:Location map showing details of Gippsland oil and gas fields ........................................... 114
Figure 31:Location map showing details of producing fields in the Otway Basin ............................... 115
Figure 32: Location map showing details of onshore depleted gas fields around Port Campbell ...... 116
Figure 33: Current onshore petroleum licences and mineral licences in Victoria. .............................. 118
Figure 34: Regulatory framework for onshore gas ............................................................................. 125
Tables
Table 1: Key risks for hydraulic fracturing and worst case frequency of occurrence. ........................... 46
Table 2: Leading practices relevant to hydraulic fracturing in the NHRF ............................................. 56
Table 3: Major Victorian gas transmission pipelines ............................................................................ 71
Table 4: Eastern market produced and remaining gas resources (significant basins) ....................... 113
Table 5: Assessment of Victorian legislation against the NHRF......................................................... 130
Table 6: Applicable legislation and existing royalty rates for natural gas production ........................ 134
Table 7: Examples of schemes for sharing benefit from gas production ........................................... 138
Boxes
Box 1: W HAT IS NATURAL GAS? ................................................................................................................. 5
Box 2: KEY AGENCIES IN GAS OVERSIGHT................................................................................................... 9
Box 3: ABOUT GAS – RESOURCE INFORMATION......................................................................................... 11
Box 4: BRIEF HISTORY OF UNCONVENTIONAL GAS EXPLORATION AND HYDRAULIC FRACTURING IN VICTORIA 18
Box 5: QUEENSLAND’S LNG TRAINS ........................................................................................................ 24
Box 6: NETBACK PRICE ........................................................................................................................... 27
Box 7: CASE STUDY – AMCOR ............................................................................................................... 31
Box 8: CASE STUDY – AUSTRALIAN PAPER .............................................................................................. 33
Box 9: POTENTIAL W ATER IMPACTS OF CSG EXTRACTION ........................................................................ 43
BOX 10: MORE ABOUT HYDRAULIC FRACTURING ...................................................................................... 45
Box 11: KEY FINDINGS NEW SOUTH W ALES CHIEF SCIENTIST REVIEW – INITIAL REPORT ............................ 51
Box 12: SOME PRIORITY ACTIONS VICTORIA COULD TAKE TO ACHIEVE LEADING PRACTICE REGULATION OF
ONSHORE GAS ......................................................................................................................................... 53
Box 13: POSSIBLE ROLE FOR A VICTORIAN GAS COMMISSIONER ............................................................... 54
Box 14: PROPOSALS FOR COMPREHENSIVE WATER SCIENCE, MONITORING AND LICENSING ........................ 55
Box 15: HYDRAULIC FRACTURING REFORM PROPOSALS............................................................................ 57
Box 16: CLASSIFICATION OF PIPELINES – COVERED OR UNCOVERED .......................................................... 68
Box 17: REGULATION OF TRANSMISSION PIPELINES .................................................................................. 69
Box 18: KEY RULINGS TO UNCOVER TRANSMISSION PIPELINES .................................................................. 70
Box 19: CASE STUDY: IGNITE EXPLORATION LICENCE FOR BIOGENIC CSG ............................................... 119
Box 20: SUMMARY OF W ATER REGULATION IN VICTORIA ......................................................................... 129
About this report
This report presents details and background information to support the key findings and proposals
that are summarised in the accompanying Gas Market Taskforce: Final Report and
Recommendations.
In this report:

Chapter 1 presents some historical background on Australian gas markets and reforms;

Chapter 2 provides context on the supply and demand of gas in eastern Australia;

Chapter 3 discusses the drivers, challenges and some potential solutions to the key issues
facing the eastern market today and in the coming decades;

Chapter 4 discusses wholesale markets and transmission and particular market reform areas
that might contribute to the development of more competitive and transparent markets;

Chapter 5 presents an overview of the retail and distribution networks; and

Chapter 6 presents an overview of how similar markets have developed overseas and draws
some lessons for the eastern Australian gas market.
This report is not Government policy, but is the independent view of the Gas Market Taskforce. The
Taskforce Secretariat has tried to make the information in this product as accurate as possible.
However, it does not guarantee that the information is totally correct or complete. Therefore, the
reader should not solely rely on the information when making commercial or policy decisions.
Page | 1
Chapter 1: Introduction
About the Gas Market Taskforce
The Gas Market Taskforce was established in December 2012 to provide policy options to
the Victorian Government on improving the operation and efficiency of the east coast
Australian gas market. This included suggesting ways of facilitating market transparency and
transmission capability; and increasing gas supply to meet rising demand at competitive
prices.
The two main issues that the Taskforce was asked to address are:

provide policy options to improve the operation and efficiency of the east coast
Australian gas market, with a particular focus on market transparency and
transmission capability; and

suggest ways of increasing gas supplies in the short to medium term.
The Taskforce is chaired by former Commonwealth Government Minister, the Hon Peter
Reith. The Taskforce members are:

Craig Arnold – Dow Chemicals

David Byers – Australian Petroleum Production and Exploration Association

Frank Calabria – Origin Energy

Cheryl Cartwright – Australian Pipeline Industry Association

Mark Collette – Energy Australia

Angus Taylor – Port Jackson Partners

Innes Willox – Australian Industry Group
The Taskforce has met five times since January 2013. The Chair has also met with more
than 50 industry experts and participants during this period, including relevant state Ministers
and Commonwealth representatives. The list of organisations consulted is available in
Appendix 1.
The Victorian Government was the first to give serious consideration to the long-term issues
faced by the eastern gas market. A number of other state and national bodies have since
launched reviews to consider a range of aspects of this market. The Taskforce has
attempted to consider those and, where appropriate, build on that work and identify gaps.
Page | 2
Gas in Victoria
For many decades, Victoria has had access to low cost gas. This has provided the State
with a major competitive advantage and underpinned its strong and diverse economy.
Natural gas accounts for 19 per cent of all energy used in Victoria.1
In 2011-12, Victoria consumed 270 petajoules (PJ) of natural gas, making it the largest
consumer in the east coast market (Figure 1). This consumption is primarily driven by the
residential sector and manufacturing and commercial services.
300
250
PJ
200
150
100
50
0
Victoria
QLD
NSW
SA
Figure 1: Gas consumption in eastern states in 2011-12
(Source: Bureau of Resources and Energy Economics, 2013 Australian energy statistics data)
Victoria has the largest residential gas demand of any Australian state or territory. Victoria’s
manufacturing and business sector relies on natural gas as an energy source and as a
feedstock, making it a key input for that sector. Natural gas is also an important fuel in the
electricity generation sector.
Gas is likely to continue to be an important primary energy source for Victorian businesses
and households. Increases in the price of gas and changes in its availability could
significantly affect all Victorian gas consumers. The nature and extent of these impacts are
discussed in more detail in this report.
Gas as an energy source
Natural gas, oil and coal are the three fossil fuels that dominate energy production in the
world today. Natural gas is set to increase in importance over the coming decades as it
becomes more easily and economically transported as liquefied natural gas (LNG). Its
abundance and low carbon characteristics make it an increasingly more attractive fuel.
Composed predominantly of methane, natural gas is extracted from naturally occurring
1
Bureau of Resources and Energy Economics, 2012 Australian energy statistics data
Page | 3
geological structures using a number of technologies and processes (see Box 1 for further
details).
Natural gas was initially a by-product of crude oil production and was often flared off by oil
producers seeking to access the oil underneath. It began to be considered as an energy
source in its own right in the mid-20th century as an alternative to the relatively more
polluting and costly coal-derived ‘town gas’. In the 1960s and 1970s, governments and
industry increasingly recognised the benefits of natural gas as a fuel, especially as a
substitute for coal or wood in industry, power generation, and for domestic use. As a result,
demand for natural gas grew substantially.
Today, natural gas is used for heating and cooking in homes and businesses around
Australia. It is a safe, clean and reliable energy source that is relatively easy to transport in
pipelines, or as LNG over longer distances. It is used for electricity generation and as a raw
material in a range of industries such as the production of basic chemicals, plastics,
pharmaceuticals, fertilisers, paints, pesticides, and cosmetics.
Gas is currently the only fossil fuel to exhibit increasing demand, and in the coming decades
it is likely that demand for gas will continue to grow worldwide. 2 Its low carbon emissions
intensity and its relative abundance will make natural gas an important transition fuel as the
world searches for reliable low carbon energy sources.
2
International Energy Agency World Energy Outlook 2012 pp. 125
Page | 4
Box 1: WHAT IS NATURAL GAS?
Natural gas, or simply gas, is the commonly used name given to methane gas that is sourced from
naturally occurring geological formations in the earth. It can also include varying amounts of other
components, such as carbon dioxide, nitrogen, hydrogen sulphide and other higher alkanes. While
the composition of extracted gas varies depending on its source and the particular geological
formation from which it is extracted, the gas sold to consumers is processed to meet uniform quality
standards.
Gas extracted from porous zones in rock formations such as sandstones is often referred to as
conventional gas because this has been the dominant source historically. This can be found
onshore and offshore, and often occurs close to oil deposits, hence production of natural gas is
sometimes accompanied by oil production.
Unconventional gas is sourced from other types of geological formations, for example, of current
interest in Australia are: coal seam gas (extracted from coal seams); shale gas (extracted from rock
formations known as shales); and tight gas (extracted from rock with very low permeability).
Compared to conventional gas, unconventional gas resources are characterised by: the low
permeability of hosting reservoir rocks, laterally extensive accumulations and a requirement for
capital, energy and technology-intensive extraction methods.3
Methane gas can also be produced in other ways, such as from the decomposition of organic matter,
and can be used in the same way as natural gas. However, these tend to be niche sources due to the
small volumes produced.
UNCONVENTIONAL GAS
COAL SEAM GAS
SHALE GAS
TIGHT GAS
(Diagram source: After Gautier, USGS, 2012 cited by Geoscience Australia1)
3
Geoscience Australia Material provided in briefings to the Chair of the Taskforce (May, 2012)
Page | 5
History of gas in Victoria
Victoria has the most mature trading market for natural gas in Australia. It has led the way
through the introduction of full retail contestability in 2002 and deregulation of retail gas
prices in 2009, which has allowed competition to grow in the retail sector.4 Today, Victoria’s
gas market has a diversity of market participants, including six upstream producers, three
major traders, multiple retailers and wholesale buyers and strong interconnectivity with other
states.5
Natural gas was first discovered in the Bass Strait in February 1965. The first offshore gas
drilling in Australia occurred in the Bass Strait in 1965 under a joint venture between Esso
(an ExxonMobil subsidiary) and BHP which discovered gas in the Barracouta field. In 1967,
the Kingfish giant oil field was located in the Bass Strait and remains the largest oil field
discovered in Australia.6 Esso and BHP built the Longford processing plant in Gippsland
shortly thereafter to support the commercialisation of its oil and gas discoveries.
The joint venture between Esso and BHP in the Gippsland Basin first supplied Melbourne
with gas in 1969 through the Longford pipeline. To transport the gas from the Gippsland
region to the Melbourne market, the Bolte-led Victorian Government established the
Victorian Pipelines Commission to construct the Longford to Melbourne Pipeline. 7 The
construction of this pipeline was completed in March 1969, with the first gas entering the
Victorian distribution system on 1 April 1969.8 Shortly after, ownership of the pipeline was
transferred to the Gas and Fuel Corporation of Victoria. The Gas and Fuel Corporation was
a State-owned monopoly with responsibility for the supply of gas in Victoria including
transmission, distribution and retail.
Over the next several decades, many more oil and gas fields were discovered in the Bass
Strait including Cobia (1972), Sunfish (1974), Hapuka (1975), Fortescue (1978), Seahorse
(1978) and West Halibut (1978).
The Gippsland Basin has been the primary gas producer in Victoria and the ExxonMobilBHP joint venture remains in place today. The large quantities of gas located in the Bass
Strait have ensured that Victoria remains a net gas exporter to other states in Australia. In
addition, the large reserves coupled with the lack of export facilities and significant market
reform have led to low and stable prices over the last several decades.
Gas Today Gas Retail Deregulation – Victoria leads the way
<http://gastoday.com.au/news/gas_retail_deregulation_victoria_leads_the_way/000171/> (Accessed
on 15 March 2013)
5 Department of Primary Industries The Victorian Gas Market <http://www.dpi.vic.gov.au/earthresources/oil-gas/the-victorian-gas-market> (Accessed on 15 March 2013)
6 Exxon Mobil Bass Strait <http://www.exxonmobil.com.au/AustraliaEnglish/PA/about_what_gipps_bs.aspx> (Accessed on 15 March 2013)
7 The Australian Pipeliner Building Victoria’s First Natural Gas Pipeline: Duston to Dandenong 1968
<http://pipeliner.com.au/news/building_victorias_first_natural_gas_pipeline_dutson_to_dandenong_19
68/008166/> (Accessed on 15 March 2013)
8 The Australian Pipeliner Building Victoria’s First Natural Gas Pipeline: Duston to Dandenong 1968
<http://pipeliner.com.au/news/building_victorias_first_natural_gas_pipeline_dutson_to_dandenong_19
68/008166/> (Accessed on 15 March 2013)
4
Page | 6
Figure 2: Turn-in ceremony for Victoria’s first natural gas pipeline from Dunston to Dandenong, 31 March
1969
(Source:
http://pipeliner.com.au/news/building_victorias_first_natural_gas_pipeline_dutson_to_dandenong_1968/008166/)
In 1997, the Kennett-led Victorian Government privatised the Gas and Fuel Corporation and
disaggregated it into separate components for transmission (GPU Gasnet), distribution
(Multinet, Westar and Stratus) and retail (Kinetik, Boral and Energy Partnership), as well as
an independent market operator (VENCorp).9 Since disaggregation, these companies have
undergone various mergers, acquisitions and name changes.
In 1998, a serious fire and explosion at the Longford processing plant killed two people and
left Victoria without gas for two weeks, costing gas users an estimated $1.3 billion.10 The
incident highlighted Victoria’s reliance on a single source of gas and motivated the
development of diversified supply base, such as the Otway Basin which connects to
Melbourne. Since then, the Eastern Gas Pipeline from Longford to Sydney, the South-East
Gas Pipeline from western Victoria to Adelaide, the Culcairn Interconnect between northern
Victoria and New South Wales and the Longford-Tasmania pipeline have increased
Victoria’s connectivity with other states and sources.
Australian gas markets
Australia has three separate gas markets: the western market, the northern market in the
Northern Territory, and the eastern market (Figure 3). The eastern market connects Victoria,
New South Wales, Queensland, South Australia and Tasmania. The eastern market is the
focus of this report.
9
Victorian Government Application to the National Competition Council for a Recommendation on
the Effectiveness of the Victorian Third Party Access Regime for Natural Gas Pipelines (1999)
<http://www.ncc.gov.au/images/uploads/CEGaViAp-001.pdf> pp. 5-6
10 The Age Fire shuts Longford gas plants
<http://www.theage.com.au/articles/2004/04/05/1081017067415.html> (Accessed on 15 March 2013)
Page | 7
Figure 3: Map of Australian gas fields and key pipelines
(Source: Geoscience Australia)
The western market is the biggest domestic gas market in Australia due to its strong LNG
export industry and significant consumption by the mining industry and for electricity
generation.11
The northern market is the smallest in Australia and is not currently connected to any other
domestic markets. However, the current Northern Territory Government has suggested that
it will pursue a pipeline linking the northern market to the eastern market via Queensland.12
The eastern market is the most mature of the three markets and connects a number of
production and demand centres in the eastern states.
Historically, the eastern market has been relatively isolated from world gas markets with
supply only meeting domestic demand for manufacturing, electricity generation and domestic
use. However, new export LNG projects in Queensland are expected to commence in 2014,
and while supply is expected to increase to meet this new source of demand, this is
expected to significantly change the structure of the eastern market. This change is
discussed in further detail in subsequent chapters of this report.
Australian Energy Regulator State of the energy market 2012 – upstream gas markets pp. 87
ABC News NT push for gas pipeline link with Queensland 22 February 2013
<http://www.abc.net.au/news/2013-02-22/nt-pushes-for-gas-pipeline-link-with-qld/4533952>
(Accessed on 8 March 2013)
11
12
Page | 8
The eastern market has matured and become more interconnected as investments occurred
to meet increasing and changing demand. Reform work has driven productivity and
efficiency gains through greater harmonisation between the disparate state gas networks.
This includes establishment of the Australian Energy Market Operator (AEMO) in 2009,
which took over the gas market operation and planning functions from the myriad of statebased bodies.
Market oversight and reforms
The main bodies that oversee different aspects of the Australian and Victorian gas market
operations and reform agenda are summarised in Box 2.
Box 2: KEY AGENCIES IN GAS OVERSIGHT
The bodies that oversee the Australian gas market are:

Australian Energy Regulator (AER) - the economic regulator for covered natural
gas transmission and distribution pipelines in all states and territories, except those in
Western Australia. The AER is funded by the Commonwealth, with staff, resources
and facilities, provided from the Australian Competition and Consumer Commission
(ACCC).

Australian Energy Market Operator (AEMO) - operates the Retail and Wholesale
Gas Markets in south-east Australia, and the Victorian Gas Declared Transmission
System.

Australian Energy Market Commission (AEMC) - responsible for rule-making,
market development and policy advice concerning access to natural gas pipelines
services and elements of the broader natural gas markets.
The Standing Council on Energy and Resources (SCER) is a national Ministerial body
that oversees market and regulatory reforms at the national level.
The Essential Services Commission (ESC) regulates the gas retail sector in Victoria,
focusing on performance monitoring and reporting, and complaints.
The eastern market continues to be improved through a national gas market reform
program, managed through SCER. In December 2012, recognising the significant
challenges facing the gas industry, particularly the eastern market, in the face of LNG
developments in Queensland and uncertainty over future price movements, SCER agreed to
a number of further actions to improve the operation of the gas market.
As part of its Gas Market Development Plan, SCER agreed to the principles of:

ensuring that supply responds flexibly to demand; and

promoting market development.
A more detailed summary of the SCER reform agenda including the national Gas Market
Development Plan is detailed in Appendix 2. In addition to the SCER agenda, other recent
Page | 9
reviews and inquiries concerning the eastern gas market are underway, including the AEMC
Scoping Review; New South Wales Parliamentary Inquiry; and Bureau of Resources and
Energy Efficiency (BREE) and Department of Resources Energy and Tourism (DRET)
Domestic Gas Market Study. Details can be found in Appendix 2.
The SCER reforms will help to facilitate a market response to changing needs and demand
profiles. However, the change emerging from commencement of Queensland LNG exports
will be rapid, and reforms may need to be accelerated or bolstered to better facilitate the
market response and promote market development. The Taskforce has been considering
the need for further and faster reforms to manage the transition to an internationally linked
eastern market. Understanding and appropriately responding to the rapidly changing
structure and dynamics of the eastern market are a focus of this report and the Taskforce’s
work.
Commonwealth policy platform 2013
The Abbott-led Coalition Government was elected in September 2013. The Coalition
Government’s 2013 election policy includes a commitment to “set in place a workable gas
supply strategy for the east coast gas market to the year 2020”. The policy also commits
AEMO to provide “up-to-date and accurate information regarding gas consumption in the
east coast gas market” and, through SCER, put in place “mechanisms to provide greater
transparency of gas trades, gas pricing and supply”. Also relevant are commitments to cut
red tape costs in Australian businesses, including in the energy and resources sector, and
deliver a “one-stop-shop” for environmental approvals. Implementation of this policy has
been reported as a high priority for the recently elected Coalition Government.
Chapter 2: Overview of supply and demand
About Chapter 2
Chapter 2 provides a brief overview of global and domestic trends in natural gas supply and
demand, as well as the implications for Victoria and other eastern states of the significantly
expanded gas market.
Globally, the demand for natural gas is growing. Eastern Australia has significant
conventional and unconventional natural gas resources. Developments for LNG export out of
Gladstone, Queensland, are underway. By 2017, the eastern market demand will have
tripled in size from around 700 PJ to more than 2100 PJ per annum. These developments
will transform the eastern Australian gas market from one primarily servicing domestic
demand to one that is dominated by export. This is already placing upward pressure on the
price of gas in the eastern market. The price of gas will increase from the historically low
prices to reach international parity. The transformation in the eastern market is occurring
rapidly and the domestic market is experiencing significant uncertainty during the transition.
Page | 10
Box 3: ABOUT GAS – RESOURCE INFORMATION
Gas Resource classification
The Society of Petroleum Engineers (SPE) is the international professional organisation that
sets international standards for classification of reserves. These standards are widely used
within the industry. In its 2011 publication, SPE sets out a revised classification system
acknowledging the development of unconventional resources.
For projects that satisfy the requirements for commerciality, reserves may be assigned, and
three estimates of the recoverable sales quantities are designated as 1P, 2P and 3P
reserves:

1P (Proved) – there is a 90 per cent probability that the actual reserves will exceed
this value

2P (Proved plus Probable) – there is a 50 per cent probability that the actual reserves
will exceed this value

3P (Proved plus Probable plus Possible) – there is a 10 per cent probability that the
actual reserves will exceed this value
Petroleum Resources Management System classification framework (Reproduced from Guidelines for
Application of the Petroleum Resources Management System November 2011
(Source: http://www.aapg.org/geoDC/PRMS_Guidelines_Nov2011.pdf)
Page | 11
Global supply and demand
International demand for gas is expected to grow faster than any other fossil fuel, at a rate of
1.6 per cent per annum from 2008 to 2035.13 A significant part of this growth in demand
comes from increasing use of gas for power generation. Growth in consumption is expected
to be three times greater in non-OECD countries than in OECD countries.14
Growth in demand for gas in non-OECD countries is expected to be driven by China and
India. China is projected to increase demand from nearly 4 trillion cubic feet (tcf) (over 4,000
PJ) in 2010 to over 19 tcf (over 20,000 PJ) in 2035, and India will increase from 2.26 tcf
(nearly 2,400 PJ) to 6.29 tcf (over 6,600 PJ) over the same time period.15 Figure 4 provides
an outline of projected demand worldwide, broken down between OECD and non-OECD
countries.
180
Trillion cubic feet
160
140
120
100
80
60
40
20
0
OECD
Non-OECD
Figure 4: Projected world natural gas consumption for OECD and non-OECD countries
(Source: US Energy Information Administration (data for reference case) 2011)
There are sufficient resources of natural gas worldwide to meet significant growth in
international demand for many years to come. The International Energy Agency (IEA)
estimates there to be 790 tcf (nearly 850,000 PJ) of remaining natural gas worldwide,
including conventional and unconventional sources, or enough to meet demand for 230
years.16 This will be underpinned by strong growth in the discovery and exploitation of
conventional and unconventional gas resources throughout the world. Figure 4 shows the
IEA’s estimates at the end of 2011 of the world’s recoverable natural gas resources.
The IEA expects that unconventional gas developments in the United States (US), China
and Australia will meet over half of the increase in global demand for natural gas through to
13
US Energy Information Administration International Energy Outlook 2011 (2011) pp. 43
US Energy Information Administration International Energy Outlook 2011 (2011) pp. 43
15 International Energy Agency World Energy Outlook 2012 pp. 128
16 International Energy Agency World Energy Outlook 2012 pp. 125
14
Page | 12
Trillion cubic feet (tcf)
2035. However, it also recognises that significant public concern regarding the
environmental and social impacts of unconventional gas could put this at risk.17
7000
6000
5000
4000
3000
2000
1000
0
Conventional
Unconventional
Figure 5: International Energy Agency estimates of natural gas resources by region in 2011
(Source: International Energy Agency World Energy Outlook 2012 pp. 134)
Unconventional gas production has grown rapidly in the US, where gas production from
shale reached 30 per cent of total gross production in 2011, compared with 8 per cent in
2007. While the percentage contribution of coal seam gas (CSG) to total production has
declined from a peak of 8 per cent in 2007 to 6 per cent in 2011, total CSG production has
not declined and has remained steady at around 2 tcf per year since 2007.18
Developments in the international market and the domestic markets of other countries are of
great relevance to the eastern gas market and Victoria. In particular, new export
developments in Queensland will expose the eastern gas market to international markets
and impact on the price of gas. As the eastern market becomes more connected with
international markets, policies implemented by other countries regarding natural gas use,
import and export will influence domestic market conditions and the eastern market price.
For example, policies which favour gas use in other countries—such as policies to reduce
carbon emissions by shifting power generation away from coal to gas, and moves in Europe
and Japan to reduce reliance on nuclear power following incidents like the Fukushima
Daiichi power station disaster in Japan—are likely to increase demand for gas for electricity
generation and may further increase demand domestically on the eastern gas market.19
Conversely, increased exports from other countries may compete with eastern market
exports and act to reduce demand for gas in the eastern market.
17
International Energy Agency World Energy Outlook 2012 pp. 145
US Energy Information Administration Natural Gas <http://www.eia.gov/naturalgas/annual/>
(Accessed on 10 September 2013)
19 International Energy Agency World Energy Outlook 2012 pp. 76, 130 & 190
18
Page | 13
Australian and eastern market supply
It is difficult to obtain an accurate and consistent estimate of the current supply and demand
situation in Australia, because of rapidly changing dynamics, inconsistent reporting,
extensive recent exploration and new production.20 There are several potential sources of
information, including a number of recent government and industry reports summarising
supply (and demand) data across the eastern market.21 These reports often use different
units, scales and standards, further contributing to uncertainty and a lack of consistency in
information.
This report draws significantly from publicly available information provided to the Taskforce
by Geoscience Australia in May 2013, plus recent published reports (refer to Box 2).
Figure 6: Australia’s produced and remaining gas resources
(Source:Australian Gas Resource Assessment 2012)
20
Department of Resources, Energy and Tourism, Geoscience Australia and Bureau of
Resources and Energy Economics Australian Gas Resource Assessment 2012, pp. 37
21 Australian Energy Regulator State of the Energy Market, 2012 pp. 87
Page | 14
The western market is supplied by conventional gas resources located in the north-west of
the state and is not linked to the eastern market. These extensive conventional gas
resources are mostly destined for LNG export and significant domestic consumption by the
mining industry and for electricity generation.22 In 2010-11, the western market produced
1,393 PJ of gas and domestically consumed 647 PJ.23 The Browse Basin contains around
35,000 PJ of undeveloped gas.24 Woodside and Shell have plans to develop the gas that are
likely to be through offshore floating facilities and would be entirely for LNG export.25
The northern market is located in the Northern Territory, and is the smallest in Australia
with domestic consumption of 22 PJ in 2010-11 sourced mainly from the Bonaparte Basin.26
The Bonaparte Basin supplies an LNG export train in Darwin which exported 12 PJ in
2012.27 The northern market is not connected to any other domestic markets, however the
current Northern Territory Government has suggested that it will pursue a pipeline linking the
northern market to the eastern market via Queensland.28
The eastern market connects Victoria, New South Wales, Queensland, South Australia and
Tasmania. Historically the eastern market has supplied to meet only domestic demand for
manufacturing and other commercial uses, electricity generation, and residential use.
Supply to the eastern market has historically been dominated by conventional gas sources,
with 94 per cent of total historic production being sourced from conventional sources, largely
the Gippsland Basin (52 per cent) and the Cooper Basin (37 per cent).29 In 2012, 773 PJ
was sourced from several basins, including the Gippsland and Otway Basins in Victoria, the
Cooper Basin which spans South Australia and Queensland and the CSG fields in
Queensland.30
Unconventional gas production in the eastern market did not exceed 100 PJ per annum until
2007. In 2012, CSG production was 255 PJ, largely from Queensland basins, and comprised
35 per cent of eastern market domestic gas production. Unconventional gas sources will
contribute increasingly to supplying both export and, if there are adequate reserves, the
domestic market in the future.
Australian Energy Regulator State of the energy market 2012 – upstream gas markets pp. 87
Australian Government Department of Resources, Energy and Tourism Energy White Paper Chapter 9 Energy markets: gas. 2012 pp. 137
24 Australian Government Australian Gas Resource Assessment 2012 Figure 1, pp. 2
25
Woodside Petroleum Ltd ASX Announcement 2 September 2013.
26 Australian Government Department of Resources, Energy and Tourism Energy White Paper Chapter 9 Energy markets: gas. 2012 pp. 137
27 Energy Quest. Energy Quarterly August 2013 Table 7 pp. 30
28 ABC News NT push for gas pipeline link with Queensland 22 February 2013
<http://www.abc.net.au/news/2013-02-22/nt-pushes-for-gas-pipeline-link-with-qld/4533952>
(Accessed on 8 March 2013)
29 Geoscience Australia Australian Gas Resource Assessment 2012 Figure 1 pp. 2
30 EnergyQuest Australia Energy Quarterly February 2013 Report Table 9
22
23
Page | 15
Figure 7 summarises the total produced and remaining resources in the eastern market. It
should be noted that it has been estimated that of almost 50,000 PJ of 2P conventional and
unconventional gas reserves in the eastern market, only about 4,000 PJ is uncommitted.31
Figure 7: Eastern market total produced and remaining gas resources.
(Source: Australian Gas Resource Assessment 2012. See Appendix 3 Table 1 for breakdown by region).
Victoria’s gas resources
Details and maps of Victoria’s gas resources are provided in Appendix 3. Victoria’s domestic
gas is supplied from conventional sources originating from three geological sedimentary
basins (Figure 8).
Conventional gas
All gas production in Victoria is currently sourced from conventional sources in
Commonwealth waters beyond three nautical miles of the Victorian shore. The Gippsland
Basin has produced 8,791 PJ, or 90 per cent of Victorian and about 50 per cent of the
eastern market’s cumulative gas production to date.32 The Otway Basin has produced gas
since 2005 and currently provides about 29 per cent of gas produced annually in Victoria.33
The Bass Basin has minor reserves and production.
The large quantities of conventional gas located in the Gippsland Basin have ensured that
Victoria is a net gas exporter to other states in Australia.
31
Core Energy Group for the Australian Energy Market Operator Eastern &Southern Australia:
Existing Gas Reserves & Resources 2012, Table 6.11
32 Geoscience Australia Australian Gas Resource Assessment 2012
33 Energy Quest Energy Quarterly May 2013 Report
Page | 16
Figure 8: Victoria’s main gas production basins. Pie charts show past and remaining production.
(Data Source: Australian Gas Resource Assessment 2012; Map: Geoscience Victoria.)
Geoscience Australia has estimated that just under half the available resource in the
Gippsland Basin has been extracted over the last 45 years. Based on a number of
assumptions at current production, existing gas reserves of about 11,900 PJ in Victoria could
continue to produce for nearly 30 years (see Appendix 3 for assumptions). If production from
Victorian fields were to increase significantly or estimated resources were not realised, then
reserves could be depleted sooner. For example, the recently announced deal for
BHP Billiton and ExxonMobil to supply Origin Energy with 432 PJ over 9 years from the Bass
Strait34 points to higher production and faster depletion of Victoria’s traditional reserves.
Unconventional gas
Presently, all forms of unconventional natural gas (in shale, tight and coal seam formations)
in Victoria are at an early stage of exploration and there is a lack of key information to
estimate potential resource sizes. There is no production, commercial reserves or identified
reserves of unconventional gas in Victoria.
34
The Australian Origin paid high price for Bass Strait Gas (24 September 2013)
Page | 17
A brief history of exploration in Victoria is provided in Box 4 and further details about
exploration licences, including a map of onshore gas exploration tenements in Victoria
(Appendix 3).
There is a long lead time from discovery to production, therefore any onshore gas resources
discovered today are not likely to be available by 2017, the time the predicted supply
shortfall in the eastern market due to the LNG production peaks. Generally, a minimum of
five to ten years is required to bring discovered gas into commercial production. The
exception to this may be existing operators who may be able to commence production in
under five years where existing infrastructure can be used.
There is currently no exploration activity in Victoria due to the hold on new CSG exploration
licence approvals and the hold on hydraulic fracturing approvals which the Victorian
Government announced on 24 August 2012 (Appendix 4: Victorian Government media
release).
Box 4: BRIEF HISTORY OF UNCONVENTIONAL GAS EXPLORATION AND HYDRAULIC FRACTURING IN
VICTORIA
Most of Victoria has been covered with Exploration Licences in a cycle of grant and
surrender since the early twentieth century. There has been little conversion of Exploration
Licence to Mining Licences reflecting the geological and commercial risks in exploration, but
also the significantly lower cost of conventional gas.
There are nine* petroleum exploration permits in Victoria under which companies can
explore for tight gas and shale gas. Lakes Oil discovered gas in tight reservoirs near
Seaspray in Gippsland, Victoria in 2004 and acquired a Retention Lease in 2007. Other
companies have acquired acreage nearby but have not yet drilled. Beach Energy has stated
that there is shale gas or oil potential in its Otway Basin permits in Western Victoria but it
has not yet drilled.
Prior to the moratorium in 2012, Lakes Oil had trialled hydraulic fracturing 11 times in two
phases of testing for its tight gas exploration program near Seaspray in Gippsland. At the
time of the moratorium, Lakes Oil had a proposal for further testing, but this is on hold.
There are currently 16*mineral Exploration Licences that list CSG in their application. CSG
exploration is relatively new to Victoria. In 1983, CSG was specifically included as a mineral
in the Mining Act 1958. It was most likely regulated under mining legislation prior to this in
the early 1900s as part as State owned underground coal mining operations. Eastern Star
Gas, Purus Energy and Karoon Gas also undertook exploration but there has been little
activity since 2007. CBM Resources (now Ignite Energy) drilled 11 holes and conducted high
rate water fracture treatment operations when exploring for CSG in Gippsland.
*The number of licences changes from time to time with the grant and surrender of titles and was
accurate as at 23 September 2013.
Page | 18
Eastern market domestic demand
Domestic demand for natural gas within the eastern market has traditionally been driven by
three key consumption groups: large industrial (i.e. manufacturing and mining); residential
and commercial; and gas powered electricity generation.35
A breakdown of consumption in the eastern market is at Figure 9. Manufacturing and
electricity generation are the largest consumers of gas in the eastern market representing 33
per cent and 31 per cent respectively of total domestic consumption.
Figure 9: Eastern market primary consumption of gas by sector in 2011–12
(Source: BREE, Gas Market Report, October 2013, p26)
Domestic consumption for gas is expected to grow by approximately 3 per cent a year
through to 2034-35, and will be driven by new investment in gas powered generation and
increased liquefaction of natural gas.36
Each demand sector has different drivers. For example, the demand in the large industrial
sector is relatively constant; however, in recent years it has been strongly influenced by the
high Australian dollar.37 Residential and commercial demand is often driven by weather
conditions, with cold weather resulting in increased demand due to increased use in gas hot
water systems and for space heating. Gas powered electricity generation demand is likely to
increase during hot weather in response to peaks in demand for electricity caused by
increased use of air-conditioning which is met by gas powered electricity generation peaking
plants.
35
Australian Energy Market Operator 2012 Gas Statement of Opportunities for Eastern and South
Eastern Australia. 2012. pp. 3-4
36 Bureau of Resources and Energy Economics Gas Market Report 2012 (2012) pp.27
37 Australian Energy Market Operator 2012 Gas Statement of Opportunities for Eastern and South
Eastern Australia. 2012. pp. 3-5
Page | 19
Residential and commercial demand
Demand from residential and commercial consumers within the various distribution networks
represents 24 per cent of domestic consumption of gas.38 Demand within this segment is
expected to grow in line with economic and population growth.39
Large industrial demand
Manufacturing and mining combined are referred to as the large industrial sector, which is
the largest segment of domestic consumption, at 42 per cent of eastern market
consumption. Manufacturing includes the metal production industry (e.g. smelting), chemical
industry (e.g. fertilisers and plastics) and the cement industry.40 Gas is used in this sector as
an energy source and as a raw material for production processes.
Large industrial demand is expected to grow faster in Queensland due to new mining
projects and the installation of co-generation plants. In New South Wales, Victoria and South
Australia, the slow-down in the manufacturing sector, caused by the exchange rate,
increasing gas prices and global economic uncertainty, is expected to slow growth in
demand.41
Gas powered electricity generation
Gas powered electricity generation is the most unpredictable component of demand for gas
in the eastern market. The considerable variability in renewable energy technology policies
and programs between governments and changes through election cycles contribute to this
uncertainty.
In 2012, gas powered electricity generation constituted 32 per cent of domestic consumption
on the east coast of Australia.42 54 per cent of new generation investment in the National
Energy Market has been gas powered.43 Gas is used in electricity peaking plants which can
be more responsive to spikes in demand, particularly during summer. Gas also has a lower
carbon emissions intensity than coal and could play an important role as a transition fuel for
base load power generation should policies that aim to reduce the carbon intensity of the
electricity generation mix be pursued.
A typical black coal fired electricity generation plant emits in the order of 0.9 tonnes of
carbon dioxide per MWh of electricity generated, while brown coal plants in Victoria emit
around 1.2 to 1.5 tonnes per MWh. This is compared to an open cycle gas turbine (OCGT)
which is the technology most often used for peaking plants and typically emits around 0.6
tonnes per MWh. A combined cycle gas turbine (CCGT) has the lowest emissions level at
0.4 tonnes per MWh and may become the technology of choice for base load gas powered
38
Bureau of Resources and Energy Economics Gas Market Report 2012 (2012) pp.37
Australian Energy Market Operator 2012 Gas Statement of Opportunities for Eastern and South
Eastern Australia
40 Bureau of Resources and Energy Economics Gas Market Report 2012 (2012) pp.26
41 Australian Energy Market Operator 2012 Gas Statement of Opportunities for Eastern and South
Eastern Australia pp. 3-4
42 Bureau of Resources and Energy Economics Gas Market Report 2012 (2012) pp.37
43 Australian Energy Market Operator Generation Information – Victoria – 22 February 2013
39
Page | 20
electricity generation depending on the relative price of carbon permits and the wholesale
price of gas.
Nevertheless, demand for gas powered generation is dampening in the short term due to
reducing growth in demand for large scale electricity generation in general. Electricity
demand forecasts have been revised down by AEMO. The downward revision is driven by
reduced manufacturing consumption, consumer response to increasing prices and energy
efficiency measures.44 This has affected investment decisions in new electricity generation
capacity, for example, Energy Australia recently announced that its proposed 1000 MW
combined-cycle gas-fired power station has been put on hold due to declining wholesale
electricity prices.45 Under the revised electricity demand forecasts, investment in new
generation of any kind is expected to be deferred by four years.46 AEMO has also suggested
that gas powered generation may not rise significantly until 2025.47
The widespread deployment of small-scale generation, such as solar rooftop photovoltaic
systems, has also contributed to reduced demand for new centralised electricity generation
capacity, including gas powered generation.48
Victoria’s demand
Victoria has the largest residential gas demand of any Australian state or territory, at more
than 100 PJ per year, contributing two thirds of all residential gas consumption in Australia
(Figure 10).49 This is supported by an extensive reticulated gas network that supplies gas to
the majority of households which use gas for cooking and heating.50 Victoria’s residential
demand also exhibits a peak during the colder winter months when households use gas for
120
100
PJ
80
60
40
20
0
heating purposes.
Victoria
NSW
SA
WA
QLD
Tas
NT
44
Australian Energy Market Operator Electricity Statement of Opportunities 2012 (2012) iii
The Australian EnergyAustralia puts gas-fired plant on hold (28 December 2012)
<http://www.theaustralian.com.au/business/mining-energy/energyaustralia-puts-gas-fired-plant-onhold/story-e6frg9df-1226544313381> (Accessed on 10 January 2013)
46 Australian Energy Market Operator Electricity Statement of Opportunities 2012 (2012) iii
47 Australian Energy Regulator State of the Energy Market 2012 pp. 94
48 Australian Energy Market Operator Electricity Statement of Opportunities 2012 (2012) 2-12
49 Grattan Institute Getting gas right - Australia’s energy challenge. June 2013 pp. 10
50 Australian Energy Regulator State of the energy market 2012 – upstream gas markets. pp. 88
45
Page | 21
Figure 10: Total gas consumed by Australian households in 2011-12
(Source: Bureau of Resources and Energy Economics, 2013 Australian energy statistics data)
Except in Tasmania, manufacturing dominates non-residential gas demand in the eastern
market, followed by other consumption which includes construction, transport and agriculture
(Figure 11).
160
140
120
PJ
100
80
60
40
20
0
Vic
NSW
Manufacturing
QLD
Mining
SA
Tas
Other non residential
Figure 11: Non-residential gas consumption in eastern states in 2011-12
(Source: Bureau of Resources and Energy Economics, 2013 Australian energy statistics data)
A survey conducted by AIG, in which 36 of 62 respondents were Victorian businesses, found
that heating in industrial processes was the most common intended use of natural gas in
2013, followed by power generation, space heating or cooling and as a feedstock for
industrial purposes (Figure 12).
Percentage of respondents
60
50
40
30
20
10
0
Heating in
industrial
processes
Power
Space heating Feedstock for We do not use
generation
or cooling
industrial
significant
purposes
quantities of
gas
Figure 12: Intended use of natural gas in 2013 by businesses surveyed
(Source: Australian Industry Group, Energy shock: the gas crunch is here, July 2013, pp. 9)
There are a number of individual firms that are significant users of gas as a feedstock for
productions of petrochemical products. However, information on gas usage for individual
Page | 22
businesses or manufacturing firms is often commercial-in-confidence, making it difficult to
identify the largest gas users or subsectors.
Around 17 per cent of total installed electricity generation capacity in Victoria is gas fired,
however actual gas generation in Victoria is variable. In 2011, gas fired electricity generation
contributed only around 1.3 per cent of total electricity generated in Victoria. This variability
is due to the type of gas generation employed in Victoria.
To date natural gas has mainly been used for electricity generation in Victoria during peak
times. Therefore, the total amount of gas fired electricity generation varies significantly from
year to year and often depends on the number of peak electricity demand days and the
availability of other generation sources. This is because gas fired generation can be started
more rapidly based on demand than other generation types. This responsiveness makes it
ideal for use as peaking and intermediate generation.
New LNG export demand
Almost $60 billion is currently being invested to construct three export LNG plants in
Gladstone, Queensland, each comprising two trains (Box 5). 51 The first of these trains is
expected to commence production in 2014 and will mark the first time natural gas is
exported from the eastern market. By 2017, the eastern market will have more than tripled in
size and transformed from an isolated market that primarily services domestic demand to
one dominated by LNG production for export (Figure 13).
Australian Petroleum Production and Exploration Association Cutting Green Tape –
streamlining major oil and gas project environmental approvals processes in Australia (February
2013) pp. 28
51
Page | 23
Box 5: QUEENSLAND’S LNG TRAINS
An LNG train is a facility for the processing and liquefaction (often for export) of natural gas.
An LNG train comprises a series of steps to remove unwanted components from the
extracted natural gas – such as dust, water, hydrogen sulphide, carbon dioxide and other
contaminants – and then compresses and refrigerates the extracted methane to produce
LNG ready for shipping.
LNG projects in Queensland. (Source: Bureau of Resources and Energy Economics, Resources and
Energy Major Projects—April 2013, May 2013.)
Project
Company
Expected start-up
Capacity
Australia Pacific
LNG
Origin Energy,
Conoco Phillips,
Sinopec
2015
495 PJ/a (9.0 mtpa)
Queensland
Curtis LNG
QGC, CNOOC
2014
467 PJ/a (8.5 mtpa)
Gladstone LNG
Santos, Petronas,
Total, Kogas
2015
429 PJ/a (7.8 mtpa)
Note: Arrow LNG has a proposal for LNG initially for 440 PJ/a (or 8.0mtpa) but has not
received the Final Investment Decision and may collaborate with other firm(s) to utilise their
LNG trains.
Figure 13: Projected eastern market demand
(Source: AEMO 2012 Gas Statement of Opportunities for Eastern and South Eastern Australia, Figure 1 p. iv)
Page | 24
The three LNG trains are expected to absorb much of the supply capacity in the short to
medium term, with as much as 95 per cent of the current CSG 2P reserves committed to
LNG export (Figure 14).52 There is potential for a further two trains by 2020-21.53
Figure 14: Domestic LNG and 2P Reserve Projections
(Source: AEMO 2012 Gas Statement of Opportunities for Eastern and South Eastern Australia, Figure 2 p. v)
Gas prices will increase
The lack of LNG export facilities on the east coast gas market has, in the past, insulated
domestic consumers against exposure to world prices. The new LNG developments in
Gladstone are already creating a significant shift in the dynamics and structure of the
eastern gas market.
A direct consequence of the introduction of LNG exports and the eastern gas market
becoming less isolated is that domestic consumers will compete with international
consumers for gas, and inevitably, the price of gas will increase to approach international
prices.
Possible price paths that the eastern market could experience in the short, medium and
longer term are illustrated in Figure 15. The orange line shows a scenario where the price of
gas increases, then returns to a more moderate level. The other lines show possible
scenarios where the gas price simply converges to a new equilibrium level without a peak.
This price remains uncertain, but is likely to be greater than the historical price and will mirror
the netback LNG export price.
52
Core Energy Group for Australian Energy Market Operator Eastern & Southern Australia:
Existing Gas Reserves & Resources 2012, Table 6.11
53 Queensland Department of Energy and Water Supply Gas Market Review: 2012 (2012) pp. 9
Page | 25
Figure 15: Possible paths for gas price levels in the eastern gas market
The historical average for domestic gas prices within the eastern market has been $3-4 per
gigajoule (GJ).54 Many long-term contracts are expiring from 2014 onwards and need to be
renewed.55 Already we have seen a move to lock in gas contracts to secure long term
demand where Origin Energy have entered into a deal with BHP Billiton and ExxonMobil to
purchase 432 PJ of Bass Strait gas for domestic consumers.56 This $3 billion deal appears
to have been priced at 50 per cent or more above usual prices, and the price becomes
linked to the price of oil during the nine year life of the deal, reflecting the influence of the
Gladstone LNG projects.57 Stakeholders have indicated that wholesale prices may reach $812 per GJ in Victoria, although there is considerable uncertainty and divergent views on
price forecasts.
There are some indications that domestic prices have begun to increase. Spot prices in the
gas market during winter in 2012 increased significantly to over $6 per GJ. On some days
this price exceeded $7 per GJ.58
There have also been several recent reports of prices being secured under new contracts:

AGL Energy secured a price of $6 per GJ in its contract with Xstrata’s Mount Isa
mine;59
54
Australian Energy Regulator State of the Energy Market 2012 pp. 21
Australian Energy Regulator State of the Energy Market 2012 pp. 22
56 The Australian Origin paid high price for Bass Strait Gas (24 September 2013)
57 The Australian Origin paid high price for Bass Strait Gas (24 September 2013)
58 Australian Energy Regulator State of the Energy Market 2012 pp. 94
59 The Australian AGL secures east coast’s most expensive gas deal (7 November 2011)
<http://www.theaustralian.com.au/business/mining-energy/agl-secures-east-coasts-most-expensivegas-deal/story-e6frg9df-1226187039505> (Accessed on 10 January 2013)
55
Page | 26

under a 7-year gas supply contract between Origin Energy and MMG, the price for
gas is close to $9 per GJ;60

Santos anticipates that the gas price beyond 2015 will be between $6-9 per GJ and
uses “gas price towards the upper end of that range”;61 and

Brickworks has claimed that it is unable to secure contracts for longer than 2 years
with high prices of $12 per GJ in Brisbane, and $8 per GJ in Sydney.62
There are also a number of modelling reports that speculate on the future price of gas in the
eastern market. For example, modelling by ACIL Tasman has suggested that the wholesale
gas price in southern Queensland in 2020 is expected to be $9.40 per GJ.63 Victoria is
expected to have the lowest price on the east coast gas market at $7.70 per GJ.64
The Bureau of Resource and Energy Economics suggested that in the medium term, the
eastern market gas price is likely to converge to the Asia-Pacific price,65 while in the longer
term, significant US exports may result in a convergence between the Henry Hub, AsiaPacific and eastern market price. For example, a Henry Hub price of $4-5 per GJ could
result in an eastern market LNG netback price of $3.50-4.50 per GJ.66 However, continued
growth in demand from gas-poor countries will increase demand for Australia’s LNG exports.
Box 6: NETBACK PRICE
Gas prices are often quoted as the ‘netback price’. This is the price of the delivered gas, that
is the LNG sale price at the export destination less costs such as shipping, hedging
exchange rate risk, building and operating the LNG liquefaction plant, pipeline costs from the
production field to the shipping facility, and taxes. Netback prices are always quoted with a
place where the gas is sourced from. For example, Queensland CSG is often netbacked to
the Wallumbillah hub.
The eastern market is already in transition
As well as uncertainty about the new longer term price of gas in the eastern market, there is
uncertainty as to how long the transition period may last and the price profile during this
period. The Australian Pipeline Industry Association has suggested that the transition period
60
The Australian Origin Energy secures record gas prices (21 December 2012)
<http://www.theaustralian.com.au/business/mining-energy/origin-energy-secures-record-gasprice/story-e6frg9df-1226541447947> (Accessed on 10 January 2013)
61 The Australian Gas prices soar as Santos signs domestic deals (23 February 2013)
<http://www.theaustralian.com.au/business/mining-energy/gas-price-soars-as-santos-signs-domesticdeals/story-e6frg9df-1226583836782> (Accessed on 13 March 2013)
62 Australian Financial Review Gas crisis looms for industry (21 January 2013) pp. 1 & 4
63 Australian Energy Regulator State of the Energy Market 2012 pp. 94
64 Bureau of Resources and Energy Economics Australian energy technology assessment 2012
pp. 18
65 Bureau of Resources and Energy Economics Gas Market Report 2012 pp. 51
66 Bureau of Resources and Energy Economics Gas Market Report 2012 pp. 51-52
Page | 27
could last for up to seven years.67 It is expected that more supply will come online in the
medium to long term, and that supply and demand, and price, will reach a new equilibrium.
AEMO has reported that the transition period will create difficulties for the companies
seeking long-term contracts.68 Several firms consulted by the Chair confirmed this
observation.
Potential impacts on domestic consumers
Increasing domestic gas prices will have different impacts in the different demand sectors.
Natural gas is an important energy source, as well as a feedstock to many industries. Not all
industries will be affected by gas price rises equally due to their different gas intensities.
As the price of domestic gas increases, affected sectors may respond in a number of ways.
Large industrial companies may change to alternative or cheaper fuel sources. For example,
Brickworks has recently stated that it is switching its fuel source for its kilns from gas to
sawdust power and methane from landfill in response to increasing domestic prices.69
If the price were to rise significantly, it is possible that some large industrial users may
become economically unviable, resulting in closures. During consultation, at least two firms
have predicted that they may be forced to shut down Victorian operations within a year due
to their inability to secure affordable gas contracts. If prices rise to a short-term peak, this
may have the effect of closing some industries which could otherwise be viable in the longterm but are unable to remain economically viable during the transition. Higher prices may
also act to discourage new large industrial users from locating their operations in Australia.
It is difficult to make a definitive assessment of the impact of rising gas prices on the
industrial and manufacturing sectors which are also sensitive to a number of other factors,
including the value of the Australian dollar. It is clear that the manufacturing sector considers
that rising gas prices constitute a significant risk:

the Report of the Non-Government Members of the Prime Minister’s Manufacturing
Taskforce noted the need for the manufacturing industry to access natural gas at fair
and competitive prices and recommended that the Australian Competition and
Consumer Commission investigate competition in the upstream sector;70

the Australian Aluminium Council, the Australian Food and Grocery Council, the AIG
and the Plastics and Chemicals Industries Association (PCIA) have called for an
inquiry into the emerging ‘gas gap’;71
Australian Pipeline Industry Association Energy policy must address looming gas price “bubble”
<http://www.apia.net.au/blog/2012/11/08/energy-policy-must-address-looming-gas-price-bubble/>
(Accessed on 27 February 2013)
68 Australian Energy Market Operator 2012 Gas Statement of Opportunities for Eastern and South
Eastern Australia. 2012 p.iv
69 Australian Financial Review Gas crisis looms for industry (21 January 2013) p. 4
70 Prime Minister’s Manufacturing Taskforce Report of the Non-Government Members (2012) p. 94
71 Australian Food and Grocery Council Inquiry needed to fill gas gap <
http://www.afgc.org.au/media-releases/1310-inquiry-needed-to-fill-gas-gap.html> (Accessed on 28
February 2013)
67
Page | 28

Manufacturing Australia asserts that the “lack of supply certainty and rapidly
increasing gas price represents a significant threat to investment in Australia, existing
industrial users, a large number of Australian jobs, and will inevitably lead to plant
closures if not addressed urgently”;72 and

AIG conducted a survey of business gas users in eastern Australia and reported that
it is not currently possible for every gas user to get a gas supply contract and that a
large number of businesses were either unable to obtain offers for contracts or
unable to obtain offers on realistic terms.73
The AIG and PCIA have commissioned research which asserts that for each petajoule of
gas directed away from large industrial use to LNG export, there is a $24 loss economywide.74
Higher domestic gas prices are likely to result in deferral of new investment in gas powered
electricity generation. However, such investment will be more strongly influenced by falling
electricity demand and the deployment of wind generation in response to the Large Scale
Renewable Energy Target (LRET), rather than the domestic gas price.
Residential gas bills are also likely to increase as a result of increasing wholesale gas prices.
Victorian residential consumers are particularly affected because they represent two thirds of
all residential gas consumers in Australia.75 Modelling commissioned by the Victorian
Government estimates that if all the LNG projects that are currently under construction
commence production and export as planned, the annual average residential gas bill in
Victoria could increase by almost 20 per cent over the period from 2013 to 2020 (a net rise
of $180 by 2020) after peaking in 2015 at 30 per cent above current rates.76 The Grattan
Institute also estimates that Victorian residential gas consumers are likely experience the
largest increases in gas bills, with the average annual bill increasing by around $170.77 This
is partly because the Victorian residential gas price is not regulated and is likely to be more
reflective of changes in wholesale prices.
The effect of increasing prices is unlikely to have a significant impact on demand in the
residential market. This is because gas usage within the residential portion of the market is
relatively inelastic to price changes.78
Manufacturing Australia Policy Solutions for Australia’s East Coast Domestic Gas Crisis (July
2013)
73 Australian Industry Group Energy shock: the gas crunch is here (July 2013) pp. 10
74 National Industry of Economic and Industry Research Large scale export of East Coast
Australian natural gas: Unintended consequences (2012) p. ii
75 Grattan Institute Getting gas right – Australia’s energy challenge (2013) pp. 10
76 SKM MMA Gas and electricity market modelling. Final Report commissioned by Victorian
Department of State Development, Business and Innovation (2 September 2013)
77 Grattan Institute Getting gas right – Australia’s energy challenge (2013) pp. 10
78 Bureau of Resources and Energy Economics Gas Market Report 2012 pp. 47
72
Page | 29
Potential implications for the Australian and Victorian economies
It is difficult to estimate the implications of rising gas prices for the Victorian or Australian
economy. This is because the sensitivity of different sectors will be different, and the
contribution of different sectors to the economy as a whole also varies.
In considering the potential impacts of higher gas prices on business, the scale of the impact
on a business will be influenced by a number of factors, including:

the gas intensity of the business, or the proportion of dollar output to gas consumed;

the extent to which a business can reduce gas consumption through efficiency
improvements and/or fuel or input substitution;

the extent to which a business can pass on higher costs to its customers, including other
businesses. In turn, this will be influenced by the nature of the market in which the
business operates – trade exposed businesses may be ‘price takers’ with little capacity
to increase their sales prices in response to higher input costs. In contrast, businesses
selling to the domestic market and not facing competition from imports may have a
capacity to pass on a substantial proportion of cost increases to their customers; and

the capacity of the business to absorb any cost increases it is unable to pass on to its
customers. In turn, this will be influenced by the profitability of the business and the
nature and extent of other pressures impacting on the costs and revenue of the
business. A business operating with a high profit margin, for example, may be better able
to absorb cost increases than a business operating with tight margins.
The variation between businesses means that the impacts of higher gas prices on
businesses will typically require case by case consideration.
For example, Manufacturing Australia reports that natural gas constitutes 15 to 40 per cent
of the cost base of fertiliser, alumina, cement, float glass, brick and roof tile production, and
that most of these industries are also trade exposed as they compete with imports or exports
from lower cost countries that often have access to lower cost domestic gas.79 Therefore,
Manufacturing Australia reasons that the viability of these domestic manufacturing industries
may be at risk and cites a number of examples where a slowdown in these Australian
industries has commenced:

a fertiliser manufacturer, IPL, has invested $850 million in a US ammonia plant and
delayed investment in New South Wales;

Boral, a cement manufacturer, in December 2012 suspended a $100 million operation in
Geelong at a loss of 100 jobs; and

CSR is closing two glass factories in Sydney at a loss of 150 jobs.
It is unlikely that these decisions were motivated solely by higher gas prices. However it is
likely that rising gas prices contributed to the decision, along with a number of other factors
such as the high Australian dollar and rising cost of other inputs.
79
Manufacturing Australia Impact of gas shortage on Australian manufacturing, May 2013.
Page | 30
In the short term, an increase in gas prices can be expected to result in some businesses
reducing their output, with the scale of such impacts influenced by the extent to which gas
prices rise. If gas prices were to rise significantly, some large industrial users may become
unviable, resulting in closures.
Manufacturing Australia estimates the impact on the Australian economy to be around $29
billion of GDP with losses of around 200,000 jobs from Australian industry.80 Manufacturing
Australia also estimates that gas prices will cost the Australian economy about 83,000 direct
jobs in the manufacturing sector and 111,000 indirect jobs.81 It counts higher electricity
prices and a slowdown in general economic activity due to higher energy costs and lower tax
revenue among the overall costs to the economy arising from increased gas prices.
Box 7: CASE STUDY – AMCOR
AMCOR is a global packaging company that operates 89 plants across 30 countries with
headquarters in Melbourne. Products include packaging for fresh foods such as meat, fish,
bread, produce and dairy; processed foods such as confectionery, snack foods, coffee and
ready meals; as well as high value-added resin and aluminium based medical applications,
hospital supplies, pharmaceuticals, personal and home care products and specialty
packaging.
AMCOR has 40 manufacturing plants across the east coast of Australia—24 in Victoria, five
in New South Wales, seven in Queensland and four in South Australia—directly employing
over 7,000 people.
The annual gas usage at these facilities is over 5.5 PJ. If the gas price increases from
currently contracted levels to an LNG netback price of $9.00 per GJ then Amcor’s gas bill will
increase by $24 million per annum.
Figure 16 shows aggregated data for the main manufacturing industry categories in Victoria,
which are significant consumers of gas, and the number of persons employed in those
industries. The food and beverage industries are significant contributors to both gas
consumption and employment in Victoria. Examples of non-metallic mineral products include
glass products, clay and ceramic products, bricks, cement and other construction products.
Manufacturing Australia Policy Solutions for Australia’s East Coast Domestic Gas Crisis, July
2013
81 Manufacturing Australia Impact of gas shortage on Australian manufacturing, May 2013
80
Page | 31
60000
50000
40000
30000
20000
10000
0
Food,
beverages and
tobacco
Pulp, paper
and printing
Petajoules in 2011-12
Persons employed in Victoria
PJ gas used in Victorian industry
16
14
12
10
8
6
4
2
0
Textile,
Non-metallic
clothing,
mineral
footwear and
products
leather
Employed in Victoria in 2011 Census
Figure 16: Data on Victorian manufacturing industries that use gas intensively (2011)
(Source: Bureau of Resources and Energy Economics, 2013 Australian energy statistics data for consumption
data and 2011 Census for employment data)
The Taskforce has not commissioned specific macro-economic modelling as part of its work.
As suggested by the preceding discussion, such ‘top down’ modelling would be of limited
value given that the impacts on business of higher gas prices requires case by case
consideration. In the absence of a detailed understanding of the response of individual
businesses to higher gas prices in terms of their production and investment decisions, it is
problematic to project the potential impacts on the wider economy.
Page | 32
Box 8: CASE STUDY – AUSTRALIAN PAPER
Australian Paper is Australia’s only manufacturer of fine office and printing papers, with
manufacturing sites in Maryvale and Preston in Victoria, and Shoalhaven in New South
Wales. Australian Paper is part of the Nippon Paper Group. It is Australia’s largest
manufacturer of office papers and one of the largest providers of paper for packaging with
over 34 per cent of its production destined for the export market. As an Australian
manufacturer, Australian Paper is subject to considerable foreign exchange risks and an
ongoing battle to maintain competitiveness in a global market.
The Maryvale mill in the Latrobe Valley is highly energy-intensive consuming some
630,000 MWh of electricity and 8,000,000 GJ of natural gas per annum making the facility
one of Victoria’s largest users. The mill supports some 6,000 direct and indirect jobs.
Australian Paper has undertaken significant upgrades to the Maryvale paper mill, which was
originally built in 1937. Since 1980, it has halved its carbon emissions. The mill uses large
quantities of biofuel and gas, with only 5 per cent of the site’s power being drawn from the
grid. The mill is the largest generator of renewable base-load energy in Victoria, with biofuel
contributing 51 per cent of its energy needs. The remaining 44 per cent of its energy
requirements are sourced from natural gas. Access to affordable energy has been essential
in maintaining market share in a high turnover, low margin environment.
Australian Paper installed the last of its three gas fired boilers in 1997, replacing its coal
burning boiler system with a cleaner and more efficient system that relies on natural gas.
Further upgrades to the mill in 2008 resulted in improved efficiency and increased use of
biofuels thereby reducing reliance on electricity and natural gas. However, gas remains a
critical input into the production process.
Australian Paper has advised the Taskforce that it is unable to obtain a long-term gas supply
contract for 2017 and beyond at a competitive market price. In seeking such a contract from
the three main gas retailers the following responses were obtained:

we will supply you but cannot quote a price for supply;

high price quoted along with very severe terms and conditions; and

declined to quote.
Australian Paper believes this is a result of the expansion of the eastern gas market due to
LNG exports, regulatory barriers to CSG, increasing cost of gas production and inadequate
government policies. Australian Paper believes that Victoria has abundant energy resources
in the form of brown coal and natural gas, and that these resources should be accessed and
harnessed in a manner that both addresses legitimate environmental concerns and
establishes Victoria as the number one state for manufacturing and business.
Page | 33
Chapter 3: Drivers, challenges and potential solutions
for the expanded eastern gas market
About Chapter 3
Chapter 3 takes a deeper look at key drivers and challenges facing the eastern gas market
and discusses potential ways to address the challenges. The rapid growth to supply LNG
exports from Gladstone is impacting on the eastern gas market. The market is already in a
period of transition, in which it is experiencing significant uncertainty, increasing gas prices
and what some observers consider a potential shortfall in supply.
A key feature of the rapid growth in production to supply LNG exports is the expansion of
unconventional gas, which has generated significant community concern about the safety of
operations and potential impacts on the community, competing land uses and the
environment. Some stakeholders consider this is the biggest challenge to meeting gas
production requirements in the eastern market. Others consider that industry has not worked
hard enough to inform and manage the public debate around the risks and mitigation of
potential impacts of unconventional gas exploration and production. A number of challenges
associated with unconventional gas production processes would need to be addressed if an
onshore industry is to be successfully and safely developed in Victoria.
Drivers of increasing gas price increases in the eastern market
Competition between LNG export producers and domestic users
As discussed in Chapter 3, the key driver for increasing gas prices is the introduction of new
LNG export facilities, which is rapidly changing the dynamics and structure of the eastern
gas market. As the commencement of LNG export approaches, it is likely that suppliers will
increasingly look to domestic markets to meet their contractual obligations. There is
evidence that substantial demand is already being created through the anticipated
commencement of LNG exports, which is contributing to direct competition for the first time
between the eastern market between LNG export facilities and domestic consumption
sectors.82 Owners of proposed LNG export facilities are securing contracts for supply in the
domestic market to meet their obligations to international customers.83
There are a number of other factors that are contributing to the upward pressure on prices
and creating uncertainty in the eastern gas market. While some changes are an inevitable
consequence of market expansion and economic progress, there is room for intervention to
address shortcomings in the market environment and to support a smoother, more efficient
transition to a globally connected gas market in the east coast.
82
83
Queensland Department of Energy and Water Supply Gas Market Review: 2012 pp. 23
Australian Energy Regulator State of the Energy Market 2012 pp. 94
Page | 34
Logistical and operational issues in the Queensland Gas fields
“…the initial response from the domestic market is there is going to be gross
oversupply because of the ramp-up.”84 (2008, Richard Cottee Managing Director of
the Queensland Gas Company)
As recently as 2009, there was an expectation that significant volumes of ‘ramp-up’85 gas
would be produced from the Queensland CSG wells in the lead up to commissioning LNG
trains, which would ensure a plentiful supply of gas and maintain low prices in the short
term.86 The expectation was this early ramp-up gas would be collected and sold on the
domestic market until delivery contracts commenced, at which time enough wells should be
drilled to collectively produce the volume required to fulfil the LNG export requirements.
However, the oversupply due to ramp-up has not eventuated as producers employed a
range of management techniques, such as gas swaps between LNG proponents and
storage.87 In addition, LNG developments have experienced delays for a number of reasons.
Several stakeholders consulted by the Chair of the Taskforce identified skill shortages, a
lack of drilling infrastructure, inexperience in production of CSG, and flooding as reasons for
considerable uncertainty and possible delays in delivering gas from CSG fields to meet
export contracts.
While these issues are expected to resolve over time, a shortfall in gas may be experienced
in the interim. There is evidence that delays for LNG export are forcing owners of proposed
LNG export facilities to search for alternative domestic gas sources to meet contractual
obligations in the interim.88The Grattan Institute reported that while there are sufficient gas
resources, demand may not be met in the short term, particularly in New South Wales
between 2015 and 2017, due to insufficient infrastructure availability and insufficient market
signals driving investment in supply infrastructure.89
Community opposition to CSG and complex or uncertain regulation were also commonly
cited as reasons for delays in CSG development (discussed further in the section below on
unconventional gas).
There has also been suggestions that some large users purposely ‘stood out’ of the market
with the expectation that cheap ‘ramp up’ gas from new CSG fields would eventuate.90 This
84
Petroleum News CSM producers plan for LNG ramp-up (17 April 2008)
<http://www.petroleumnews.net/storyview.asp?storyid=195065&sectionsource=s2845> (Accessed on
8 March 2013)
85 ‘Ramp-up’ gas describes the excess gas that was expected to be produced and available for sales
as CSG wells being developed to supply LNG export trains were progressively developed ahead of
commissioning of the LNG trains.
86 EnergyQuest State of the energy market, Part One Essay - Australia’s Natural Gas Markets:
Connecting with the World pp. 36
87 Queensland Department of Energy and Water Supply. Gas Market Review: 2012 pp. 38
88 Australian Energy Regulator State of the Energy Market 2012 pp. 94
89 Grattan Institute Getting gas right – Australia’s energy challenge (2013) pp. 18 & 23
90 The Australian Energy tensions heat up as AGL blames producers for soaring gas prices (28
February 2013) <http://www.theaustralian.com.au/business/companies/energy-tensions-heat-up-asagl-blames-producers-for-soaring-gas-prices/story-fn91v9q3-1226587203717> (Accessed on 13
March 2013)
Page | 35
may have exacerbated the direct competition with exporters as many of these contracts
expire in the same period and a number of large domestic users are seeking renewal of their
contracts.
Increasing production costs
Increased costs associated with the exploration and production of new gas fields are
expected to contribute towards increasing gas prices. New conventional gas production
generally requires drilling wells that are deeper and/or further from the coast. Further, many
of the remaining gas reserves tend to be of a lower quality and require more costly
processing. For example, Esso Resources Australia-BHP Billiton (Bass Strait) announced a
$1 billion upgrade to the Longford facility in December 2012 to, among other things, build a
gas processing facility to remove excess carbon dioxide from natural gas extracted from the
new Kipper Tuna Turrum project.
The high Australian dollar; high labour and construction costs; regulatory cost; and the
increasing contribution of unconventional gas, which is typically more capital intensive are
also contributing to the increasing cost of production of natural gas.91
Construction costs
Australia is considered to have the highest capital costs in the world for capital development
and construction costs, particularly for new LNG export plants.92 Shell claims that
construction costs in Australia are up to 30 per cent higher than in the US and Canada.93
A report prepared by Port Jackson Partners for the Minerals Council of Australia states that
rising costs in the mining sector in general are causing Australia to lose its operating cost
advantage. 94 It claims that over half of Australia’s mines have costs above global averages,
only 28 per cent of thermal coal production operations are in the first two quartiles of global
cost compared with 63 per cent six years ago, and that production costs in half of Australian
copper and nickel mines are in the most expensive 25 per cent of mines globally. The report
claims that although production costs globally are rising due to rising cost of key inputs like
labour, equipment, contracting services and raw materials, capital costs in Australia have
been growing even more rapidly.
McKinsey also reports that the cost of delivering LNG to Japan from Australian projects is 20
to 30 per cent higher than from projects in Canada and Mozambique due to lower
productivity in Australia driven by higher taxation, more burdensome regulation, lower labour
productivity, higher cost of freight, and project design.95
Costs of unconventional gas
91
Bureau of Resources and Energy Economics Gas Market Report 2012 pp. 21
Angela Macdonald-Smith High costs risk to gas boom: Chevron, Australian Financial Review (19
August 2013) pp. 1 & 10
93 Angela Macdonald-Smith High costs risk to gas boom: Chevron, Australian Financial Review (19
August 2013) pp. 10
94 Port Jackson Partners for the Minerals Council of Australia Opportunity at risk – Regaining our
competitive edge in minerals resources (September 2012) pp. 25 – 27
95 McKinsey & Company Extending the LNG boom: Improving Australian LNG productivity and
competitiveness, May 2013, pp. 10 - 14
92
Page | 36
The production of unconventional gas is typically more expensive than conventional gas. 96
This is because production from each well declines much more rapidly than in conventional
gas, necessitating the drilling of more wells, augmentation to increase flow rates and
increasing capital expenditure.97 Exploration and production drilling is less competitive than
the US as an example in part due to the availability of drill rigs. This is likely to place further
pressure on gas prices given future supply is expected to increasingly come from
unconventional gas sources. One stakeholder estimated average break-even costs of
producing gas in the eastern market to increase by a range of $2-6 per GJ.98
Figure 17 shows the average production costs of gas from various Australian reserves. It
shows a trend of increasing cost of production for newly developed reserves, and for CSG
production. As newer fields contribute more to overall production, average production costs
in the eastern market will also increase.
96
Australian Petroleum Production and Exploration Association Unconventional Gas
<http://www.appea.com.au/oil-a-gas-in-australia/unconventional-gas.html> (Accessed on 15 March
2013)
97 Australian Council of Learned Academies Engineering Energy: Unconventional Gas Production
– A study of shale gas in Australia (May 2013) pp. 23
98 Core Energy Group cited in an industry stakeholder’s presentation
Page | 37
16.00
14.00
12.00
$/GJ
10.00
8.00
6.00
4.00
Otway Basin (CSG)
Gippsland Basin (Offshore) - Kipper ex. liquids
Galilee Basin (CSG)
Gippsland Basin (Onshore)
Cooper Basin (Unconventional)
Gippsland Basin (Offshore) - Kipper
Clarence Moreton (CSG)
Sydney Basin (CSG)
Walloons (West)
Hunter Area (CSG)
Walloons (Mid)
Bass Basin (Offshore)**
Moranbah Area (CSG)
Gunnedah Basin (Tier 2)
Otway Basin (Offshore - Otway Gas Project)
Cooper Basin (Conventional)
Walloons (East)
Gloucester Basin (CSG)
Otway Basin (Offshore - Casino et al)
Fairview / Spring Gully Area (CSG)
Gippsland Basin (Offshore) - Longtom ex. liquids
Gippsland Basin (Offshore) - Longtom
Gippsland Basin - GBJV (Offshore) ex. liquids
Cooper Basin (Infill)
Gippsland Basin - GBJV (Offshore)
0.00
Gunnedah Basin (Tier 1)
2.00
Figure 17: Typical production costs for Australian gas resources in 2012
(Source: AEMO99)
Labour costs
Labour costs are a large proportion of overall construction costs and can easily translate into
high construction costs and an uncompetitive industry. Research has identified that
Australia’s construction industry labour costs are higher than those in comparable developed
economies such as the United Kingdom, Canada and Germany. As an example, the average
Australian oil and gas worker earns around $163,600 per year, almost double the global
average.100 Anecdotal evidence from industry executives indicates that pay rates on local
Australian resource projects has shot to 30 to 50 per cent above those in the US.
99
Australian Energy Market Operator 2012 Gas Statement of Opportunities Gas Production Costs
(6 August 2012)
100 The Economist Australia’s gas explorers – The next Qatar? (27 July 2013)
Page | 38
The Australian construction industry is less productive than the US.101 A number of factors
are likely to contribute to this, including monopolistic behaviour by unions proximity of
workers to LNG sites, shift patterns, construction improvements and the availability of skilled
labour.
The resources sector has consistently been identified as an area of skill shortages
(particularly in remote locations), although shortages have eased of late.102
Costs of regulatory uncertainty and duplication
Port Jackson Partners identifies longer delays as a contributing factor to higher project costs
in Australia in general. It reports, for example, that Australian thermal coal projects typically
experience 3.1 years delay compared with 1.8 years for projects elsewhere in the world. 103
Delays increase project costs and impact Australia’s global competitiveness. To address
this, Port Jackson Partners notes that “clear and predictable rules and timeframes for
approvals are essential”.104
The Australian Petroleum Production and Exploration Association (APPEA) also reports that
Australia’s environmental regulatory framework is duplicative, excessive and at times
inconsistent, and that this is causing delays and imposing costs on the industry without
always delivering the desired objectives.105
Lack of transparency in supply and demand information
There are multiple agencies and various sources of information summarising supply and
demand data across the eastern market. However, rapidly changing dynamics and extensive
new onshore gas production make it difficult to accurately and consistently summarise the
supply and demand situation in the eastern market.106 Various reports can be inconsistent
and report figures without providing analysis to enable reconciliation with other data. Further,
reports are not always publicly available.
In an assessment of Australian gas resources the Department of Resources, Energy and
Tourism, Geoscience Australia and the Bureau of Resources and Energy Economics
reported that “there is no current publicly available resource assessment of Australia’s
undiscovered conventional gas resources that adequately reflects the knowledge gained in
101
Australian Treasury International comparison of industry productivity, Adam Young, Joann Wilkie,
Robert Ewing, and Jyoti Rahman, Economic Roundup Issue 3, 2008
<http://archive.treasury.gov.au/documents/1421/HTML/docshell.asp?URL=04%20International%20co
mparison%20of%20industry%20productivity.htm >
102 Commonwealth Department of Education, Employment and Work Place Relations Skill
Shortages – Statistical Summary (2012-2013)
103 Port Jackson Partners for the Minerals Council of Australia Opportunity at risk – Regaining
our competitive edge in minerals resources (September 2012) pp. 25 – 27
104 Port Jackson Partners for the Minerals Council of Australia Opportunity at risk – Regaining
our competitive edge in minerals resources (September 2012) pp. 13
105 Australian Petroleum Production and Exploration Association Cutting Green Tape –
Streamlining Major Oil and Gas Project Environmental Approvals Process in Australia (February
2013) pp. 2
106 Department of Resources, Energy and Tourism, Geoscience Australia, and Bureau of
Resources and Energy Economics Australian Gas Resource Assessment 2012 pp. 37
Page | 39
recent years during the active programs of government pre-competitive data acquisition and
increased company exploration during the resources boom.”107
The eastern gas market has a number of mechanisms to provide information to market
participants, such as AEMO’s annual Gas Statement of Opportunities. However, market
information available is considerably poorer than for gas markets in other countries. The
Commonwealth Government’s Energy White Paper claimed there is a gap in relation to
forecasts of domestic supply and market liquidity.108 Due to the time to develop a gas
reserve to production, it is important that predicted scenarios occur over a longer time
period.
The lack of information has led to information asymmetry between producers, shippers,
consumers and regulators. A recent gas market review in Queensland found that there is a
lack of basic market information, such as forward prices and volumes available, which are
normally required for contracting to occur.109 Many market participants consulted by the
Taskforce have cited inadequate market information as contributing to uncertainty in
wholesale gas prices and the lack of secure contracts.
Australia is also expected to face competition from other jurisdictions (not traditionally
competitors) as unconventional sources increase global reserves for LNG markets. It is
uncertain what effect this competition may have in the long term for gas markets.
Inefficient upstream competition
Several stakeholders have argued the market power of large supply firms is exacerbating
the upward pressure on gas prices, as the market tightens ahead of commissioning the LNG
export plants out of Gladstone.
Concentrated ownership
The need to promote competition in the exploration and production sectors of Australian gas
markets has been identified previously and most recently by the Grattan Institute in June
2013.110
In 1998, an upstream working group identified competition between and within basins as
important sources of competition in the upstream sector, and noted that there is public
benefit from increasing intra-basin competition that could be gained by encouraging new
entrants to bid for acreage.111 The working group recommended that the “tenure of retention
leases should reflect the time period needed before reserves are considered commercially
viable at prevailing market prices, with assessments being re-examined by the relevant
jurisdiction on a regular basis”.112
107
Department of Resources, Energy and Tourism, Geoscience Australia, and Bureau of
Resources and Energy Economics, Australian Gas Resource Assessment 2012 pp. 37
108 Australian Government - Department of Resources, Energy and Tourism. Energy White
Paper - Chapter 9 Energy markets: gas. 2012 p. 142
109 Queensland Department of Energy and Water Supply. Gas Market Review: 2012 (2012) pp. 38
110 Grattan Institute Getting gas right (June 2013)
111 Upstream Issues Working Group Report to ANZMEC and COAG 1998 pp. 1
112 Upstream Issues Working Group Report to ANZMEC and COAG 1998 pp. 2
Page | 40
A COAG Energy Market Review in 2002 also recommended that “exploration licence issuers
to have the promotion of competition as one of their criteria for assessing applications for
acreage”, and proposed that Australia’s competition law be strengthened to require review of
all existing and future joint marketing arrangements.113
While these reports and recommendations are somewhat dated and were not fully
progressed at the time, some Taskforce members consider they are still relevant today.
Experience demonstrates that greater diversity in players can lead to a greater exploration
effort, which may lead to discoveries sooner. A new player is likely to want to develop
immediately, whereas an existing player may decide to put that discovery to one side
depending on existing supply, demand or price signals.
Joint marketing arrangements
The 2002 COAG review identified the lack of upstream gas competition as a barrier to
developing an active gas commodity market that was likely to “lead to much higher prices
once current contracts expire over the next five years”.114 The review identified the need for
more competition in the upstream production sector and, in particular, identified a need to
reconsider joint marketing arrangements.
The Taskforce notes that joint marketing arrangements can help reduce risks and therefore
support the development of the industry. This was an important consideration during the
development of the Australian oil and gas industry in the 1960s and 1970s, when the
Gippsland Basin dominated Australia’s oil production. However, such arrangements also
reduce competition.
Australia’s east coast market is in a transitionary phase and approaching maturity, with a
number of interconnected producers supplying the market from different sources.115 Some
Taskforce members have identified a ten year limit as a sufficient period of time to address
the considerable upfront investment risk faced by project proponents. After such time, the
market would be best served by individual marketing by proponents.
The ACCC monitors market structures and grants authorisation for joint marketing
arrangements where it is satisfied that the arrangement will result in a benefit to the public
that outweighs the detriment of a lessening of competition.
Unconventional gas - challenges and community concerns
A key feature of the transition to a significantly expanded eastern gas market is the
increasing importance of unconventional gas in the supply mix. This is a trend occurring
throughout the world, with the US being the most advanced in the development of its
unconventional gas resources.
The footprint for onshore gas production can be considerable and is more obvious to human
populations than offshore gas production. Projects may need access to private property, drill
at multiple sites, lay extensive pipelines, increase heavy local truck traffic, and introduce
environmental disturbance such as dust, noise and light. Local communities may therefore
113
COAG Energy Market Review Towards a truly national and efficient energy market (2002) pp. 36
COAG Energy Market Review Towards a truly national and efficient energy market (2002) pp. 35
115 Grattan Institute Getting gas right (June 2013) pp. 20-21
114
Page | 41
experience, or perceive, there to be potential for significant negative impacts on their
community with less visible benefits, even if governments and industry establish robust
regulation and environmental safeguards. The problem is particularly acute where
developments are in close proximity to urban centres or productive agricultural land.
The Taskforce and many stakeholders consulted have noted that the CSG industry does not
yet have a ‘social licence to operate’ in some areas, and there has been strong community
opposition in Australia to this industry. Some stakeholders have argued that industry and
governments have failed to address community concerns and fears about the implications
and perceived dangers of unconventional gas production. As a result, scare campaigns
against unconventional gas have flourished, especially in Victoria and New South Wales. In
turn, political leaders have been wary about correcting some ill-informed propaganda, and
further restrictions on exploration have been the result.
More recently, the Queensland experience has been more positive. Queensland
communities are starting to enjoy the benefits of the economic boom from gas production.
The Newman government has helped change the approach by making it clear that the state
government supports the industry and has taken steps to ensure their support is active.
Risks to water resources
The issue most commonly raised with the Taskforce concerning unconventional gas
development is the potential local and cumulative impacts of gas extraction on water quality
and quantity (see Box 9). Many industry stakeholders and experts consider water
management to be the most critical issue that must be addressed to underpin a successful
industry.
A summary of regulatory requirements concerning water for onshore gas producers is in
Appendix 5. In Victoria, the Water Act 1989 provides a robust framework for managing water
quality and quantity. As a general rule, under the Water Act any prospective water user
should be treated equitably. In Victoria, CSG producers (regulated under the Minerals
Resources (Sustainable Development) Act 1990 (MRSDA) are required to meet their water
use by obtaining a water licence, or trading a water licence within the cap of the relevant
water resource. Proponents of shale and tight gas (regulated under the Petroleum Act 1998)
are also required to hold a water licence. Offshore producers in Commonwealth waters are
not subject to state legislation and so are also not currently required to hold a water licence.
Connectivity of aquifers at different depths and between connected offshore and onshore
aquifers must be understood to underpin safe and sustainable management of water
resources. A potentially significant barrier to onshore gas development is the sustainability of
groundwater in the Latrobe Group aquifer in Gippsland. The Taskforce received advice that
the aquifers associated with prospective onshore gas fields in Gippsland are connected with
offshore aquifers, and that significant water extraction and depressurisation has occurred as
a result of oil, gas and water extraction from conventional wells in Bass Strait.116
116
T Hatton, C Otto, J Underschultz Falling Water Levels in the Latrobe Aquifer, Gippsland Basin:
Determination of Cause and Recommendations for Future Work (Joint Report for CSIRO Wealth from
oceans flagship program, CSIRO Land and Water and CSIRO Petroleum Resources) (13 September
2004)
Page | 42
Groundwater levels in the Latrobe Group aquifer have been declining by about one meter
per year over the past 30 years.117
The Taskforce considers it appropriate that the gas industry be subject to similar licensing
requirements as any prospective user and, to ensure integrated management of water
resources, licences should be issued under the Water Act 1989 (Vic).
Box 9: POTENTIAL WATER IMPACTS OF CSG EXTRACTION
CSG is produced by pumping groundwater from coal seams to release gas.
Source: http://www.ehp.qld.gov.au/management/coal-seam-gas/
Potential impacts on water resources from CSG extraction include:

the extraction of water to depressurise the coal measure and allow the gas to
flow;

the use of hydraulic fracturing to fracture the coal measure and allow gas to
flow;

the risk of contamination of groundwater from chemicals used for hydraulic
fracturing;

management of extracted water; and

cumulative impacts of multiple projects occurring in the same area.
117
Victorian Department of Sustainability and Environment Gippsland Region Sustainable Water
Strategy (2011)
Page | 43
Hydraulic Fracturing
Hydraulic fracturing is the fracturing of rock formations by a pressurised liquid (Box 10). It is
used to stimulate the flow of gas, oil, steam or water from fractures in coal or other hard rock
formations for the purpose of petroleum, geothermal or water production.
Hydraulic fracturing has been used in petroleum recovery in Australia for more than forty
years. The first commercially successful use of hydraulic fracturing was in the US in the
1940s. Other industries also use reservoir stimulation, for example, hot dry rock geothermal
energy production, water production and geosequestration.
There have been around 2,500 hydraulic fracturing treatments Australia-wide, compared
with 1.5 million in the US. Most hydraulic fracturing has occurred in Queensland, where
around 8 per cent of existing CSG wells have been fractured since 2000 and between 10–40
per cent may be fractured in the future.118
In Victoria, prior to the hold on hydraulic fracturing, there were a total of 23 hydraulic
fracturing operations in the Seaspray area of Gippsland. Eleven were conducted by Lakes
Oil for tight gas exploration. A further 12 were conducted by CBM Resources for CSG
exploration (high rate water fracture treatment operations).
Commonly raised concerns with hydraulic fracturing include the use of toxic chemicals,
chemical spills, contamination of land and water, the triggering of earthquakes (either directly
by hydraulic fracturing process or from the disposal of reinjected fluids) and subsidence of
land where hydraulic fracturing has occurred. In Australia, there have so far been no
reported cases of induced seismicity from CSG or tight gas operations.119 Recent
investigations of reported incidents in Queensland did not find evidence of risks to the
environment or to public or animal health.120,
Investigations into the effects of hydraulic fracturing by agencies in the US, where most
hydraulic fracturing has occurred, have found that there is no evidence of groundwater
contamination due to hydraulic fracturing per se.121, Instances of reported contamination in
Texas, for example (six in 16,000 wells) were due to surface spills or mishandling of waste,
118
Standing Council on Energy and Resources The National Harmonised Regulatory Framework
for Natural Gas from Coal Seams 2013.
<http://scer.govspace.gov.au/files/2013/06/CACHE_DUVIE=4ffefd0f68a47d228735c71292f60385/Nat
ional-Harmonised-Regulatory-Framework-for-Natural-Gas-from-Coal-Seams.pdf> (Accessed 23 June
2012)
119 Australian Council of Learned Academies (ACOLA) Engineering energy: Unconventional Gas
Production, A study of shale gas in Australia, Final Report (May 2013) pp. 133
120 Minister for Natural Resources and Mines Plan to remediate coal bore on Darling Downs Media
Release (21 August 2012); Queensland Government Condamine River Gas Seep Investigation
(January 2013); Queensland Government Gas Monitoring at Tara Gas Field (7 May 2010)
121 US EPA Evaluation of Impacts to Underground Sources of Drinking Water by Hydraulic Fracturing
of Coalbed Methane Reservoirs (June 2004); Energy Institute University of Texas Separating fact
from fiction in shale gas development (February 2012)
Page | 44
processes common in any drilling activity.122 In a submission to the Taskforce, APPEA
provided references from experts and regulators including the US Department of Energy, the
US Geological Survey, the US EPA and various state investigations, indicating there is “little
to no evidence” of hydraulic fracturing contaminating groundwater.
There have been some cases of induced seismicity reported in the US and overseas, which
were more often correlated with the disposal of large volumes of water, rather than the
hydraulic fracturing process directly.123 There are best practice ways of mitigating risks,
including through improving knowledge of fault structures close to disposal sites.
BOX 10: MORE ABOUT HYDRAULIC FRACTURING
The hydraulic fracturing process involves injecting a fluid into the rock formation at high
pressure. The mix of chemicals used in the hydraulic fracturing fluid and the pressure
required depends on the geological environment. Typically, hydraulic fracturing fluids have
three components: water (greater than 90 per cent), proppant to hold fractures open (sand or
equivalent, approximately 9 per cent) and chemicals (less than 1 per cent).
Shale gas and tight gas normally requires hydraulic fracturing. For CSG, the need for
hydraulic fracturing to stimulate the flow of gas depends on the geological setting of the
resource.
Illustration of hydraulic fracturing (Source: Geoscience Australia 2012 )
122
US Ground Water Protection Council State Oil and Gas Agency Groundwater Investigations and
their Role in Advancing Regulatory Reforms. A Two-State Review: Ohio and Texas (August 2011)
123 ACOLA Engineering energy: Unconventional Gas Production. A study of shale gas in Australia,
Final Report (May 2013)
Page | 45
A recent study conducted by leading Australian scientific organisations reviewed information
concerning the risks and mitigation strategies of hydraulic fracturing for unconventional gas
production.124 The study cites a detailed report of hydraulic fracturing risks in US shale wells,
which describes 20 risks associated with hydraulic fracturing (Table 1). The worst-case
frequency of the risk occurring assumes no mitigation technology is applied. The study
highlighted that:
“technology is a powerful tool in making well selection, materials transport, fluid
storage, well construction, hydraulic fracturing and clean-up operations safer” .
Table 1: Key risks for hydraulic fracturing and worst case frequency of occurrence.
(Source: Figure adapted from King 2012, cited in ACOLA Engineering energy: Unconventional Gas Production. A
study of shale gas in Australia. Final Report. pp. 61 Table 4.2. May 2013)
Key risks for hydraulic fracturing
Worst case
frequency
1
Spill (20,600 litres) of a transport load of water without chemicals
[1 in 50,000]
2
Spill (1,890 litres) of concentrated liquid biocide or inhibitor
[1 in 4.5 million]
3
Spill (227 kg) of dry additive
[1 in 4.5 million]
4
Spill (1,135 litres) of diesel from ruptured saddle tank on truck (road wreck)
[1 in 5100]
5
Spill (13,250 litres) of fuel from standard field location refueler (road wreck)
[1 in 1 million]
6
Spill (80,000 litres) of well-site water (salt/fresh) storage tank – no additives
[1 in 1000]
7
Spill (190 litres) of water treated for bacteria control
[1 in 10,000]
8
Spill (190 litres) of diesel while refuelling pumpers
[1 in 10,000]
9
Spill (80,000 litres) of stored frack water backflow containing chemicals
[1 in 1000]
10
Frack ruptures surface casing at exact depth of fresh water sand
[1 in 100,000]
11
Frack water cooling pulls tubing out of packer, frac fluid in sealed annulus
[1 in 1000]
12
Frack opens mud channel in cement on well less than 2000 feet deep
[1 in 1000]
13
Frack opens mud channel in cement on well greater than 2000 feet deep
[1 in 1000]
14
Frack intersects another frac or wellbore in a producing well
[1 in 10,000]
15
Frack intersects an abandoned wellbore
[1 in 500,000]
16
Frack to surface through the rock strata (well less than 2000 feet deep)
[1 in 200,000]
17
Frack to surface through the rock strata (well greater than 2000 feet deep)
[no cases]
18
‘Felt’ earthquake resulting from hydraulic fracturing
[no cases in US]
19
Frack changes output of a natural seep at surface
[1 in 1 million]
20
Emissions of methane, CO2, NO2 SO2
[high frequency]
In briefing the Chair of the Taskforce, a key message from Geoscience Australia is that:
“Hydraulic fracturing, when conducted correctly, is unlikely to introduce hazardous
concentrations of chemicals into groundwater or to create connections between fresh
and coal containing aquifers”.
This advice is similar to expert findings in a review of hydraulic fracturing in the UK, which
concluded that:
124
ACOLA Engineering energy: Unconventional Gas Production. A study of shale gas in Australia,
Final Report (May 2013)
Page | 46
“The health, safety and environmental risks associated with hydraulic fracturing … as
a means to extract shale gas can be managed effectively in the UK as long as
operational best practices are implemented and enforced through regulation”.125
Progress on regulatory reform for unconventional gas
Australian governments have initiated policies and frameworks to underpin unconventional
gas exploration and development.
Commonwealth-State initiatives (COAG)
In 2012, the Commonwealth Government established a national partnership agreement for
CSG and large coal mining development, which includes an Independent Expert Scientific
Committee (IESC) and funding of $150 million to provide advice on specific CSG or large
coal mining proposals, and to address gaps in scientific knowledge of the actual or potential
impacts on water related impacts of CSG.126 Within the eastern market, New South Wales,
Victoria, Queensland and South Australia generally supported the approach and agreed
under a national partnership agreement to refer CSG and large coal mining projects that are
likely to have an impact on water resource to the IESC for advice.127
The IESC oversees a research program aimed at addressing gaps in knowledge about CSG
impacts. The key priorities for this program are understanding changes in groundwater
hydrology and aquifer integrity, aquatic health including co-produced water, and chemical
risks to human and environmental health, including the potential for impacts on ecosystems.
Through the national partnership agreement with Victoria, Queensland, New South Wales
and South Australia, the Commonwealth has agreed to begin the Gippsland Bioregional
Assessment no later than the end of 2013. Victoria has also commenced collecting baseline
information in other areas of the state that may be prospective for gas as part of a
complementary work program.
The Commonwealth Government subsequently developed legislation extending the
application of the Environment Protection and Biodiversity Conservation Act 1999 (EPBC
Act) to considering water impacts from CSG developments.
National Harmonised Regulatory Framework for natural gas from coal seams
A key government response to the issues and concerns raised by the community regarding
CSG, including for hydraulic fracturing, was the decision in December 2011 by Australian
125
ACOLA Engineering energy: Unconventional Gas Production. A study of shale gas in Australia.
Final Report. (May 2013)
126 Commonwealth Minister for Sustainability, Environment, Water, Population and
Communities Media Release Independent Expert Scientific Committee to advice on Coal Seam Gas
and Large Coal Mining (2012)
<http://www.environment.gov.au/minister/burke/2012/mr20121127.html> (Accessed on 28 February
2013)
127 National Partnership Agreement on Coal Seam Gas and Large Coal Mining Development
<http://www.federalfinancialrelations.gov.au/content/npa/environment/csg_and_lcmd/CACHE_DUVIE
=8f7f20e2c961e5d2ba3dd173f9c74ae4/NP.pdf> (Accessed on 28 February 2013)
Page | 47
governments to develop the National Harmonised Regulatory Framework for natural gas
from coal seams (NHRF).128
State and territory governments have worked cooperatively with the Commonwealth
Government through SCER to develop the NHRF, which is designed to provide guidance to
governments on leading practices for assessing and regulating CSG projects.129 On 31 May
2013, state, territory and federal governments endorsed the NHRF through SCER.
The NHRF establishes leading practices for four key aspects of CSG operations:

well integrity;

water management and monitoring;

hydraulic fracturing; and

chemical use.
The NHRF identifies current leading practice, and also acknowledges that leading practice
regulation is not a static concept. In this way, the NHRF is a foundation for continuous
improvement in leading practice for CSG, built on ever-improving science and data.
The NHRF does not specifically address other unconventional gas, such as tight gas and
shale gas. However, areas of concern for CSG may also apply to other unconventional gas
exploration and development. Given the potential for other types of unconventional gas in
Victoria, the NHRF should be reviewed to identify its applicability for other unconventional
gas resources and address any gaps in regulatory leading practice.
Multiple Land Use Framework
As a complement to its work on the NHRF, the SCER is developing a Multiple Land Use
Framework (MLUF) for the minerals and energy resources sector to address challenges
arising from competing land use, land access and land use change. The objective of the
MLUF is to maximise the net benefits to present and future generations through a
combination of land uses which benefit the wider community.
South Australia
The South Australian Government has developed a ‘Road map’ to consider how
unconventional gas projects could be undertaken sustainably and efficiently, considering the
social, environmental and economic impacts and benefits.130 It is the first of its kind in
Australia. Released in December 2012, the Roadmap makes 125 recommendations ranging
from a one-stop-shop to promote efficient regulation, to renewed efforts to ensure regulators
have relevant and up-to-date capabilities so they can act in the interests of the public.
128
Standing Council on Energy and Resources The National Harmonised Framework for Natural
Coal Seam Gas (2012) <http://www.scer.gov.au/files/2013/09/National-Harmonised-RegulatoryFramework-for-Natural-Gas-from-Coal-Seams.pdf> (Accessed on 4 October 2013)
129 Standing Council on Energy and Resources The National Harmonised Framework for Natural
Coal Seam Gas (2012) <http://www.scer.gov.au/files/2013/09/National-Harmonised-RegulatoryFramework-for-Natural-Gas-from-Coal-Seams.pdf> (Accessed on 4 October 2013)
130 South Australian Department of Manufacturing, Innovation, Trade, Resources and Energy
Roadmap for Unconventional Gas Projects in South Australia (December 2012)
Page | 48
Queensland
Driven by a burgeoning onshore gas industry with the need to fill LNG export contracts
commencing from September 2014, Queensland has worked extensively on policy and
regulatory reform to underpin CSG development, whilst ensuring environmental risks are
managed and community concerns are addressed.
The Queensland Government established a suite of initiatives across the spectrum of safety,
best practice, skills and workforce development, community, environmental management
and land access. Legislation is in place to protect groundwater in the Great Artesian Basin,
control water quality, prohibit harmful chemicals, protect landholders’ water quality and apply
an adaptive environmental management regime.131
A key component of Queensland’s approach is the GasFields Commission, established
under the Gasfields Commission Act 2013 (Qld). The Commission is a statutory body
comprised of seven commissioners representing local government, the community and
industry. The Commission, based in Toowoomba, is designed to manage the interface
between rural landholders, regional communities and the CSG industry. It has been received
favourably, particularly by landholders.
The Queensland Government has also established the Office of Groundwater Impact
Assessment (OGIA) to monitor the potential impacts of the petroleum and gas industry in
relation to water extraction. 132 The OGIA maintains a database to store baseline and
monitoring data that are carried out in accordance with water monitoring strategies in
approved Underground Water Impact Reports.
The Strategic Cropping Land Act 2011 (Qld) is in place to protect land with high agricultural
value. CSG operations in Queensland are also subject to strict laws managing impacts on
natural systems, groundwater and the environment more broadly. A range of approvals must
be sought and licences obtained before and during any related works. These reforms have
been important in providing certainty for both the community and industry, recognising the
difficult balance that governments are required to strike between encouraging growth and
managing environmental risks and concerns.
Queensland is probably the most advanced state in Australia in terms of land access policy.
Queensland developed its contemporary land access regime around 2008, in response to its
burgeoning CSG industry. The Queensland approach is based around a Land Access Policy
Framework developed by the state Land Access Working Group. Key elements include: a
requirement for all resource authority holders to comply with a single Land Access Code;
entry notice requirements for lower impact activities; and a requirement to negotiate a
Conduct and Compensation agreement prior to accessing private land. The policy
framework is given force through legislation, including compliance and enforcement
provisions for breaches of the Land Access Code.
131
Queensland Government Business and Industry Portal <www.business.qld.gov.au/industry/csglng-industry/>
132 Queensland Government Department of Natural Resources and Mines
<http://www.dnrm.qld.gov.au/ogia>
Page | 49
New South Wales
New South Wales has approached CSG development differently to Queensland and South
Australia. The introduction of new regulatory measures in New South Wales, a state with
proven CSG resources, is curbing commercial investment decisions. New South Wales has
some CSG potential (2P resources of 2,904PJ and 6 per cent of the eastern market
remaining gas reserves), but major political and community concerns and regulatory
uncertainty has created barriers for timely production of the resource.
The New South Wales Minister for Resources and Energy, the Hon. Chris Hartcher MP, told
the 2013 APPEA conference that there is no community faith in the state’s regulatory
framework, creating a difficult political environment for legislators to navigate. This
community resistance has led to a cautious approach by the New South Wales Government,
creating uncertainty in the market and a slowdown in production.
New South Wales has a broad range of interventions for CSG, many of which are linked to
its Strategic Regional Land Use Policy, which is designed to protect strategic agricultural
land and water resources. Elements include: a Land and Water Commissioner; an Aquifer
Interference Policy; a Gateway process for projects; a requirement to prepare Agricultural
Impact Statements; and mandatory Codes of Practice for well integrity and CSG fracturing.
The Government has also established an Office of Coal Seam Gas.
On 21 March 2013, the New South Wales Department of Planning released the draft State
Environmental Planning Policy (Mining, Petroleum Production and Extractive Industries)
Amendment (CSG Exclusion Zones) 2013 for public comment. Amongst other things, the
draft prohibits CSG development on or under land within 2 kilometres of residential zones or
future residential growth areas, and within critical industry clusters.
Professor Mary O’Kane, the New South Wales Chief Scientist and Engineer, is conducting a
comprehensive review of CSG-related activities, focusing on the environmental and humanhealth impacts. Following public consultation, she released an interim report in July 2013133
(see Box 11 for key findings).
133
New South Wales Government Chief Scientist and Engineer Initial report on the Independent
Review of Coal Seam Gas Activities in New South Wales (July 2013)
<www.chiefscientist.nsw.gov.au/coal-seam-gas-review/>
Page | 50
Box 11: KEY FINDINGS NEW SOUTH WALES CHIEF SCIENTIST REVIEW – INITIAL REPORT
The initial findings are aimed at assisting the New South Wales Government to build trust in
the wider community that it has the intention and capacity to oversee the safe introduction of
a new industry and its significant economic benefits. The initial report made five
recommendations.
The first recommendation is to establish a world class regime for the extraction of CSG. It
aims to set the bar high, and recommends fair, transparent world’s best practice regulatory
controls undertaken on a full cost recovery basis. Information, understanding of cumulative
impacts, monitoring and training are the focus.
The other four recommendations call for measures in support of the first recommendation: a
comprehensive whole-of-environment data repository, a major whole-of-State baseline
calculation to measure and monitor subsidence, mandatory training and certification for CSG
industry personnel and a key role for Government as a champion of research into the ‘hard
problems’ related to the under-earth, in particular modelling and cumulative impact
assessment.
Victoria
In response to community concerns regarding CSG operations, on 24 August 2012 the
Victorian Government announced a hold on approvals for new CSG exploration licences, a
hold on hydraulic fracturing approvals, and a ban on the use of benzene, toluene,
ethylbenzene, xylene (BTEX chemicals) in hydraulic fracturing (Appendix 4). The
Government also announced that the holds would remain until the Victorian Government
considered the outcomes of the NHRF and policy and legislation are strengthened to ensure
better protection of water resources and consideration of mixed land use issues.
There are over 50 pieces of Victorian legislation, regulations, policies and administrative
arrangements relevant to adopting leading practices for CSG operations. These
arrangements cover the resource, OH&S, dangerous goods, planning, environment
protection and water areas. The complexity in regulatory arrangements creates uncertainty
and adds to the regulatory cost for industry. The diversity of the legislation, as well as the
agencies involved, creates delays and confusion in the regulatory environment. Without
compromising environmental or safety standards, the Victorian Government should take
action to improve certainty, consistency and reduce regulatory costs.
Victoria is the least advanced of the eastern market states in terms of exploration for
unconventional gas sources due to a number of factors, including its proximity to significant
low cost conventional resources in Bass Strait, uncertain geological suitability for
unconventional gas and the current moratoriums on new CSG exploration and hydraulic
fracturing (see Chapter 2 and Appendix 3).
Since placing these moratoriums, the Victorian Government has been working on a number
of initiatives to strengthen and clarify the regulatory framework for the exploration and
development of unconventional gas.
Page | 51
The Victorian Government has reviewed its regulatory arrangements for CSG with respect to
the NHRF leading practices. Overall, Victoria’s existing legislative and regulatory framework
provides a good basis for applying the leading practice approaches set out in the NHRF. The
review found that the Victorian framework fully satisfies eight of the 18 leading practices, and
partially satisfies the remaining 10 leading practices. Specific reforms are therefore needed
for Victoria to meet the leading practices for onshore gas operations (see Appendix 5 for
further details on progress with this work).
Land access is another key consideration for onshore gas development. In Victoria, under
the MRSDA, licensees cannot begin work until they obtain the consent of the land owner or
occupier, have a compensation agreement in place, or compensation has been determined .
The Victorian Government is contributing to the development of the MLUF and is considering
how it may be applied in the Victorian context to improve relationships between the
resources sector and other land users, particularly the agricultural sector.
The Victorian Government also released its response to a parliamentary Inquiry into
greenfields mineral exploration and project development in Victoria, which includes specific
recommendations for community engagement for CSG development.134
Potential solutions
Proposals for leading practice regulation and community
engagement
The leading practices in the NHRF were identified to mitigate the potential impacts of CSG
development and to contribute to a consistent national approach for the regulation of CSG.
Based on its review of the NHRF, consideration of other recent reports and consultation with
relevant agencies135, the Victorian Government has identified a number of specific reforms
that would better align Victoria’s regulatory framework for CSG with the leading practices
agreed in the NHRF (Box 12).
Better community engagement through an independent gas commissioner
The Taskforce recognises that local communities must be properly consulted and engaged,
and industry and governments must address community concerns and build confidence in
the industry.
In Queensland, which is now in a phase of large scale development, the establishment of a
Gas Fields Commission has created significant improvements in the level of engagement
between the Government, industry, landholders and communities.
Noting Victoria is still in a very early exploration phase, the Taskforce considers the
establishment of a similar office in Victoria would greatly assist with engaging local
communities to help build community confidence in the onshore gas industry. Further, if the
134
<http://www.parliament.vic.gov.au/edic/article/1391>
The former Department of Sustainability and Environment (DSE), the former Department of
Planning and Community Development (DPCD), the Environment Protection Authority (EPA) and
WorkSafe Victoria
135
Page | 52
industry moves to production testing and development, the Commission would help facilitate
a smooth transition and coexistence between industry, landholders and communities. The
principal role for the Victorian Natural Gas Commissioner would be to liaise with landholders,
communities and industry, manage communications and information. The Gas
Commissioner could also convene committees, to oversee key aspects of concern for
communities (see Box 13 for possible role of Commissioner).
Box 12: SOME PRIORITY ACTIONS VICTORIA COULD TAKE TO ACHIEVE LEADING PRACTICE
REGULATION OF ONSHORE GAS
Fully implement the 18 NHRF leading practices and consider further opportunities to
improve its regulatory framework for gas operations, including:
i. Amending the MRSDA and the Mineral Resources Development Regulations 2002
to improve their applicability for CSG operations;
ii. Strengthening the existing environment management plan requirements for all
forms of onshore natural gas exploration and development through new regulations
and guidelines;
iii. Requiring well operations management plans for CSG operations to align with
those that apply to the petroleum industry, including requiring formal environment
management plans for all onshore gas exploration (currently only required at the
development stage for CSG);
iv. Developing guidelines specifically for CSG;
v. Requiring industry to undertake baseline and ongoing environmental monitoring
and reporting, including monitoring impacts on the groundwater resources,
environmental values and air quality. The monitoring would be required during the
life of the operation and, if required, post closure;
vi. Developing a comprehensive water science and monitoring program, including
immediately undertaking comprehensive baseline water studies in areas where
onshore gas development is most prospective (see Box 14);
vii. Establishing the highest environmental and safety standards for hydraulic fracturing
operations (see Box 15);
viii. Formalising regulatory responsibilities between earth resources, environmental and
water regulators;
ix. Committing to continuous improvement to address other gaps as they are
identified, by monitoring recent developments for best practice in the industry,
including the findings of the New South Wales Chief scientist; and
x. Contribute to the development of the MLUF and apply in the Victorian context to
improve relationships between the resources sector and other land users,
particularly the agricultural sector.
Page | 53
Box 13: POSSIBLE ROLE FOR A VICTORIAN GAS COMMISSIONER
The functions of the Victorian Natural Gas Commissioner could be similar to those assigned to the
Queensland Gas Commissioner as follows:
a) consult with and facilitate better relationships between landholders, regional communities and
the onshore gas industry;
b) advise Ministers and government entities about the ability of landholders, regional communities
and the onshore gas industry to coexist within an identified area;
c) make recommendations to the relevant Minister that regulatory frameworks and legislation
relating to the onshore gas industry be reviewed or amended;
d) make recommendations to the relevant Minister and onshore gas industry about leading practice
or management relating to the onshore gas industry;
e) advise the Minister and government entities about matters relating to the onshore gas industry;
f) convene fora for landholders, regional communities and the onshore gas industry for the
purpose of resolving issues;
g) oversee the water science and monitoring program;
h) oversee the royalties for the regions program;
i) obtain particular information from government entities and prescribed entities;
j) obtain advice about the onshore gas industry or functions of the commission from government
entities;
k) publish educational materials and other information about the onshore gas industry;
l) partner with other entities for the purpose of conducting research related to the onshore gas
industry; and
m) convene advisory committees to assist the commission to perform its functions, including
convening a Water Science Committee chaired by an eminent independent scientist.
Understand and manage risks to water resources
The Taskforce recognises that water is a vital issue for many stakeholders, especially
farmers and the community. The Taskforce also recognises that the issues concerning water
management are dynamic and complex, extend beyond the CSG industry and typically
involve a range of competing users and environmental concerns. The Taskforce considers
water users should be treated equitably; water use should be licensed, measured and
accounted for as part of integrated water planning and land use strategies. The Taskforce
considers the Victorian Government should take action to ensure alignment of and
coordination between the legislation and the agencies responsible for water management
and the gas industry.
The Taskforce considers that where aquifers are connected (either between onshore and
offshore sources, or aquifers at different depths), all users should be required to hold a water
licence and be subject to coordinated management under the Water Act 1989. This would
mean amendments are required to a number of Acts (including the Petroleum Act 1998,
Offshore Petroleum and Greenhouse Gas Storage Act 2010 (Vic) and Offshore Petroleum
and Greenhouse Gas Storage Act 2006 (Cth)) to require groundwater extraction to be
licensed under the Water Act 1989.
Page | 54
A water science and information program is needed for baseline information and ongoing
monitoring. Reliable baseline information is key to assessing the potential impact of gas
projects on water resources. Regulators also require reliable information and robust
processes to assess cumulative impacts of multiple projects, which may be proposed for the
same area.
The industry can also contribute significantly to the information base and ongoing monitoring
of water resources. In particular, the Taskforce notes there is a significant opportunity to
build baseline knowledge of water resources using data gathered by proponents during the
early exploration phase in Victoria. Collaboration between industry and regulators in the
sharing of information will not only improve the information base, but also the costeffectiveness of information gathering. In order to build community confidence in the
information provided by industry to regulators, peer review and assessment by an
independent science advisory panel should be encouraged. Industry information should also
be made publicly available on the websites of relevant agencies.
Box 14 lists the actions that the Taskforce considers necessary for managing risks to water
resources. The regulatory processes and agencies involved in water management and gas
regulation will need to be coordinated to ensure the processes are robust, streamlined and
provide certainty for industry participants and communities.
Box 14: PROPOSALS FOR COMPREHENSIVE WATER SCIENCE, MONITORING AND LICENSING
Water management, monitoring and baseline assessments
The Taskforce recognises the need for credible independent science and information to
inform decisions concerning operations. The Taskforce proposes:





an independent water science program, to undertake comprehensive baseline assessments of
water resources in areas that may be prospective for unconventional gas and require ongoing
monitoring of those resources;
comprehensive baseline water studies in areas where onshore gas development is most
prospective;
Victoria request the Commonwealth commence the Gippsland bioregional assessment as soon as
possible;
Victoria require independently reviewed data from exploration activity undertaken by proponents
as one source to inform baseline assessments and ongoing monitoring; and
an Independent Water Science Committee to be chaired by an independent eminent scientist to:
o oversee the water science and monitoring program, and
o provide independent advice to Ministers on water and other environmental issues relevant to
gas industry exploration and development operations.
Water licencing to ensure integrated water management for all uses
The Taskforce considers water users should be treated equitably; water use should be licensed,
measured and accounted for as part of integrated water planning and land use strategies. The
Taskforce proposes:
 ensuring there is alignment and coordination between the legislation and agencies responsible for
water management with the gas industry regulation, including the entire gas industry be subject to
similar licencing requirements as any prospective user; and
 to ensure integrated management of water resources, water licences should be issued under the
Water Act 1989 (Vic).
here aquifers are connected (either between onshore and offshore sources, or aquifers at different
depths), all users should be required to hold a water licence and be subject to coordinated
management under the Water Act.
Page | 55
Improve standards for hydraulic fracturing
The Taskforce recognises the significant community concerns surrounding the potential
health and environmental impacts of hydraulic fracturing. Hydraulic fracturing is addressed
specifically as one of the four key aspects of the NHRF. Six of the leading practices in the
NHRF have a primary application to hydraulic fracturing, with a further six also relevant to
hydraulic fracturing activities (Table 2).
Table 2: Leading practices relevant to hydraulic fracturing in the NHRF
NHRF Leading practice
1
2
3
4
5
12
13
14
15
16
17
18
Undertake a comprehensive environmental impact assessment,
including rigorous chemical, health and safety and water risk
assessments
Develop and implement comprehensive environmental management
plans or strategies which demonstrate that environmental impacts
and risks will be as low as reasonably practicable
Apply a hierarchy of risk control measures to all aspects of the CSG
project
Verify key system elements, including well design, water
management and hydraulic fracturing processes, by a suitably
qualified person
Apply strong governance, robust safety practices and high design,
construction, operation, maintenance and decommissioning
standards for well development
Require a geological assessment as part of well development and
hydraulic fracturing planning processes
Require process monitoring and quality control during hydraulic
fracturing activity
Handle, manage, store and transport chemicals in accordance with
Australian legislation, codes and standards
Minimise chemical use and use environmentally benign alternatives
Minimise the time between cessation of hydraulic fracturing and flow
back, and maximise the rate of recovery of fracturing fluids
Increase transparency in chemical assessment processes and
require full disclosure of chemicals used in CSG activities by the
operator
Undertake assessments of the combined effects of chemical
mixtures, in line with Australian legislation and internationally
accepted testing methodologies
Applicatio
n to
hydraulic
fracturing
primary
primary
primary
primary
relevant
primary
primary
relevant
relevant
relevant
relevant
relevant
To manage risks and build community confidence, the Taskforce proposes the Victorian
Government should set and enforce the highest standards for hydraulic fracturing processes,
including supporting a number of new initiatives that are consistent with the requirements of
the NHRF (such as leading practice for well integrity and full public disclosure of chemicals
to be used prior to approval of those chemicals in an operation), or in some cases go beyond
the NHRF requirements (such as, placing a statutory ban on BTEX chemicals). See Box 15
for suggested reforms.
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Box 15: HYDRAULIC FRACTURING REFORM PROPOSALS
The highest environmental and safety standards for hydraulic fracturing operations should be
implemented to build community confidence, using the NHRF as a minimum standard:

Developing new legislation, regulations and supporting guidelines that clearly set out
the requirements for hydraulic fracturing operations;

Imposing a statutory ban on the use of BTEX chemicals as additives to the hydraulic
fracturing process;

Requiring the public disclosure of all chemicals used in hydraulic fracturing
operations;

Requiring demonstration of the effects of proposed chemical mixes, prior to those
chemicals being approved for use in operations;

Encouraging the use of environmentally benign chemicals in hydraulic fracturing
operations; and

Independent monitoring of impacts and seeking independent expert advice on bestpractice hydraulic fracturing to inform legislative and regulatory amendments.
Royalties and industry payments
The possibility for sharing royalty income from gas development with landholders has been
suggested as a way of encouraging community acceptance of the industry. In particular,
comparison has been drawn with the US where landowners receive a share of royalty
income and, it is argued, this has facilitated support for the industry.136 The arrangement in
the US is facilitated by a fundamental difference in ownership principles, as landowners in
the US own the rights to any resources below the property line, whereas in Australia, the
Crown owns the resources (see Appendix 6).
In Australia, the Crown owns mineral and petroleum resources, and applies royalty
payments for their extraction. A royalty is considered to be a purchase price for the resource
and is usually charged at the point where ownership of the resource is transferred to the
licence holder. Appendix 6 summarises the royalty schemes applied by the Commonwealth
and several Australian states and territories.
There is currently no recovery of natural gas in Victoria or Victorian waters, hence there
have been no royalties for gas (although the state collects royalties under the Petroleum Act
1998 from the production of carbon dioxide – see Appendix 6). The rate of royalties that
would be payable on extracted natural gas depends on the location and the nature of the
resource.
CSG and oil shale projects in Victoria are regulated under the MRSDA and are subject to a
royalty rate of 2.75 per cent of the net market value of the gas. Projects for conventional gas,
tight gas and shale gas in Victoria, and projects located within three nautical miles of the
Victorian coastline are regulated under the Petroleum Act 1998 (Vic) and the Offshore
Petroleum and Greenhouse Gas Storage Act 2010 (Vic) respectively. Both of these Acts
impose a royalty rate of 10 per cent of the value of the gas at the well head, less deductions.
136
Australian Financial Review Ben Porter CSG shale oil hunt lags due to low incentives pp. 12 (3
October 2013)
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The Commonwealth Petroleum Resources Rent Tax (PRRT) would also apply to profits from
all projects for the production of gas. However, projects are credited by the amount paid in
royalties such that the overall royalty or tax that the project pays does not exceed the PRRT.
In designing and implementing a royalty scheme the Victorian Government should work with
the Commonwealth Government such that any royalty discounts or holidays reach the
intended business and are not absorbed by the PRRT.
Industry incentives
The Taskforce notes the significant risks and costs faced by the gas industry, particularly at
the beginning of projects. The Taskforce considers there is an interest for governments and
communities to incentivise the production of more gas. A competitive royalty rate should be
applied to onshore gas projects regardless of the technology or type of geological formation
from which gas is extracted. This royalty rate should create incentives for industry to explore
and develop onshore gas in Victoria, and should be attractive and competitive compared to
other states. A “royalty holiday” period, delay in requirement to pay royalties, could be
established with a goal of reducing costs and encouraging production.
Compensation for landholders and neighbours
Existing Victorian legislation provides for compensation under the MRSDA and the
Petroleum Act 1998 (Vic) to landowners and occupiers for any loss or damage that has been
or will be sustained as a direct, natural and reasonable consequence of the approval of
exploration or production activity. Compensation is not payable for the value of the resource
as the Crown owns mineral and petroleum resources, not the landowner. The content of a
compensation agreement is a matter for negotiation between private parties.
Where land is to be occupied for exploration or mining, landowner and occupiers consent or
a compensation agreement must be in place before work can be approved. Alternatively a
company may purchase the actual land affected. Where the amount of compensation cannot
be settled between a landowner and occupier and a licensee, either party may refer the
dispute to VCAT or the Supreme Court for determination in accordance with the Land
Acquisition and Compensation Act 1986 (Vic). Disputes can only be heard after parties have
attempted to settle the claim by conciliation.
A claim for compensation can also be made where land is not occupied for exploration or
mining, but a landowner and occupier still suffers loss or damage due to exploration or
production. For example, the owner of a neighbouring property may claim compensation
from a miner if they believe that the operation has reduced, or will reduce, their property’s
market value or their amenity. Such a claim would not involve a prior compensation
agreement and must be made within three years of the loss, damage or licence expiry,
whichever occurs earlier.
Legislation limits compensation payable where the land is occupied for exploration or mining,
or to affected owners of neighbouring land, for “loss of amenity” to $10,000. This level of
compensation is insufficient, and does not adequately account for the benefit that miners
receive, and the externalities to which communities and land owners are exposed. Further,
there is a power imbalance in arrangements in favour of project proponents as the amount of
compensation can be determined by VCAT or the Supreme Court, should an agreement not
be reached. Landowners and occupiers are likely to be less resourced and less able to
Page | 58
negotiate a mutually beneficial agreement. Local communities, who are exposed to the less
desirable impacts of unconventional gas production, also do not receive any compensation.
The Earth Resources Ministerial Advisory Council has been considering the issue of
increasing the upper limit on compensation to landowners. The Taskforce recommends that
the legislated limit for compensation be raised to $20,000, with the limit indexed at CPI to
retain its value into the future.
The compensation arrangements do not provide local communities any way of receiving
social compensation for environmental and economic impacts. In the view of the Taskforce,
compensation arrangements should more adequately account for the benefit that miners
receive and the externalities to which communities and landowners are exposed.
Payments for communities
The Western Australia and Queensland governments have implemented programs to set
aside funds for initiatives that are directed at supporting local communities impacted by
mining and petroleum production activities. Further information on these, and on the system
in the United Sates which allows land owners to receive a share of royalties from production
activity on their land, is provided in Appendix 6.
There is currently no significant onshore gas industry in Victoria and the State therefore
collects no royalty income from gas. However, it is possible the revenue generated from
onshore gas production could be significant, should the resource be proven in large
commercial quantities. Revenue collected by the Commonwealth Government from the
offshore Gippsland Basin, for example, is estimated to be in the order of $300 million in
2010-11.
Some stakeholders argue that unless more substantial compensation is made available to
land owners, and unless communities also benefit from compensation, there will be no
industry and no revenue for the State at all. This may provide justification for a form of
hypothecation of income from royalties.
Once the revenue threshold has been reached, and royalties are being collected, the
Victorian Government should consider developing a Royalties for the Regions program to
facilitate sharing the benefits with local communities—over and above the benefits that reach
all Victorians in terms of stimulation of the economy and increased supply of natural gas—
and address the negative impacts to which local communities are exposed as a result of
unconventional gas production. Government is already free to allocate resources to
communities and programs of its choice.
The Taskforce considers a mechanism should be established that allows local people to
advise on funding priorities for a Royalties for the Regions program, using existing
arrangements where possible.
In order for industry to undertake investment planning, a clear and certain tax regime should
be developed. The Taskforce considers there is a need for the Victorian Government to
develop and announce the details of any changes to tax and royalty arrangements for the
onshore gas industry as soon as possible.
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Initiatives to increase productivity and reduce costs of major projects
In response to community concerns about the impacts of unconventional gas, the
Commonwealth and state governments have been reviewing and establishing additional
regulatory controls to manage potential impacts from unconventional gas exploration and
production on the environment, particularly impacts on underground water resources. Even
with the release of the NHRF, there remains considerable flux and regulatory differences
across state boundaries in the regulation and management of natural gas in Australia. The
uncertain regulatory environment is leading to delays in the development of new CSG
reserves and some firms have responded to uncertainty in the regulatory environment, for
example, on 13 March 2013, Metgasco announced it would suspend its exploration and
development program.137
The Taskforce recommends that the Victorian Government take proactive action to identify
opportunities to improve productivity in all facets of major projects, including engaging with
the Commonwealth Government to identify opportunities for joint government action. The
Taskforce considers there are immediate opportunities to take action to reduce the
regulatory cost of major projects.
The Taskforce considers reducing regulatory costs can be achieved by streamlining
regulation and better coordinating approvals processes. Regulation of onshore or offshore
natural gas operations requires significant expertise and imposes onerous compliance costs
on both government and industry. The Taskforce accepts the assessment by APPEA and
others that Australia’s environmental regulatory framework is duplicative, excessive and at
times inconsistent, which is causing delays and imposing costs on industry without always
delivering the desired objectives.138
The Victorian Government established Minerals Development Victoria to act as the single
entry point for earth resources project proponents to work with the Government, facilitate
approvals processes to encourage greater certainty and timely decision making, and assist
in the early identification of project infrastructure requirements. The Taskforce also considers
that it would be beneficial if the Government could nominate a senior official within the
Victorian administration who can be the ‘go to’ person to coordinate approvals and other
industry requirements.
In 2012, COAG agreed to address duplicative and cumbersome environmental regulation
and, in particular, to accelerate the development of bilateral arrangements for the
accreditation of the state’s environmental approvals processes. To implement this, a number
of states entered into negotiations with the Commonwealth Government to accredit state
environmental assessments and approvals under the EPBC Act. These bilateral agreements
were developed to remove the duplication and double handling of environmental
assessments while maintaining high environmental outcomes consistent with those sought
under the EPBC Act.
Metgasco ASX Media Release Suspension of Metgasco’s Clarence Moreton program (13 March
2013) <http://www.asx.com.au/asxpdf/20130313/pdf/42dm9cm7hkcd46.pdf> (Accessed on 15 March
2013)
138 Australian Petroleum Production and Exploration Association Cutting Green Tape –
Streamlining Major Oil and Gas Project Environmental Approvals Process in Australia (February
2013) pp. 2
137
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However, in December 2012, the Gillard Government withdrew from these negotiations
citing concerns regarding the scope of the agreements and the processes of how states will
meet the Commonwealth standards for accreditation. The Commonwealth Government also
later amended the EPBC Act to provide a water resources assessment trigger for CSG and
large coal mining developments. The Coalition Government’s 2013 election policy139
included commitments to cut red tape costs in Australian businesses, including in the energy
and resources sector, and deliver a “one-stop-shop” for environmental approvals.
Implementation of this policy has been reported as a high priority for the recently elected
Abbott Coalition Government.140
The Taskforce considers the work to address Commonwealth and Victorian duplication
should be a high priority for governments.
Initiatives to improve supply and demand information
On 27 May 2013, the Commonwealth Minister for Resources and Energy announced that
the Australian Government is undertaking a new, comprehensive analysis of the domestic
gas market outlook. The study is expected to be completed by the end of 2013.
The Taskforce considers that the lack of transparency in the eastern gas market could be
addressed to achieve a holistic view of supply and demand through annual or specific winter
and summer outlooks, particularly as the east coast undergoes significant change to
contracting levels and export demand growth. Due to the time required to develop a gas
reserve for production, it is important that predicted scenarios occur over longer time periods
than are currently available. A national forecast for the gas industry should be developed
and published on a regular basis. It would incorporate reserves, gas supply, industrial and
residential customer demand, and supply and transportation asset capacity. This could be
completed on an annual basis as part of an expanded form of the Australian Energy Market
Operator’s Gas Statement of Opportunities report with market modelling to highlight the state
by state impacts of gas flows between regions given specific scenarios.
To improve certainty and accessibility of gas supply information, the Taskforce also
considers the roles and responsibilities for public reporting of resource information, including
the roles of various Commonwealth and state government agencies with a role in gas market
information or reporting should be clarified (including Geoscience Australia, Bureau of
Resources and Energy Economics, AEMO, the Australian Energy Regulator and the
Australian Energy Market Commission; and agreement reached between governments and
the upstream sector to establish a consistent reporting regime for the public reporting of gas
reserves and production. SCER should facilitate improvements in these areas.
Upstream competition should be encouraged
Given the rapidly changing dynamic of the eastern gas market, the Taskforce considers it
may be timely to review licencing arrangements to ensure that exploration and production
The Coalition’s Policy for Resources and Energy
<http://www.nationals.org.au/Portals/0/00_Election_00/Coalition%202013%20Election%20Policy%20
%E2%80%93%20Energy%20and%20Resources%20%E2%80%93%20Final.pdf> (Accessed on 26
September 2013)
140 Graham Lloyd Environment Editor The Australian (18 May 2013)
139
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are undertaken efficiently and that the potential of individual tenements is fully maximised
and captured.
In issuing licences for gas resources, the Victorian and the Commonwealth Governments
could ensure that the licences are conditioned to encourage field development and increase
competition. This could be done by ensuring that applicants commit to a clear plan that
demonstrates and identifies the path to the commercialisation of any acreage and the
potential for the development of this acreage to promote competition in the upstream sector,
before obtaining a licence. The Taskforce has not recommended taking action in this area
but rather, to ensure a rigorous analysis of the issue, the Taskforce has proposed it be
referred to the Productivity Commission for review.
The Taskforce considers it is also timely that the joint marketing arrangements, particularly in
the eastern market, which have been in place for almost five decades, be reviewed to
consider whether their benefits continue to outweigh the detriment resulting from less
competition.
Domestic reservation is not a solution
A number of stakeholders raised a domestic reservation policy for gas in the east coast
market as a means of providing supply certainty for domestic users, particularly during the
transition period. Domestic gas reservation is the setting aside of a share of locally produced
gas for the domestic market.
In particular proposals by Manufacturing Australia and the Australian Industry Group call for
a national interest test for approving gas export capacity, comparable to that applied in the
US and Canada.
The Australian Industry Group proposes a new national economic assessment process of a
‘national interest test’ to apply to new or significantly expanded LNG export capacity. A key
feature of this process would be to provide an opportunity to assess the national
consequences of significant projects, particularly economic consequences, and give the
public and other gas users visibility and voice.141 The Australian Industry Group recommends
that the test should be national in scope, covering developments in the west and north as
well as the east, including onshore and potential Floating LNG proposals, though it must
take account of differences between these markets, particularly due to their lack of physical
interconnection. The national interest test would be implemented by the Commonwealth to
ensure national consideration. If necessary, the states could proceed with their own
approvals processes – though these should be transitional to a national approach. Three
tests are proposed for the approval process:

it should be clear that approval of a proposed expansion in export capacity would leave
adequate supply for domestic requirements in relevant Australian markets over the life of
the facility;

it should be established that approval of the project would be in the national interest,
taking account of economic, strategic and social consequences; and
141
Australian Industry Group Energy shock: the gas crunch is here, July 2013
Page | 62

it should be established that proponents have adequately considered opportunities to
supply gas for domestic uses in parallel with export development.
Manufacturing Australia has also called for some form of domestic reserve policy and
proposes two potential packages for consideration. The preferred package proposes that a
proportion of production from projects and expansions approved after January 2014 be
allocated to domestic requirements, with no price intervention. Manufacturing Australia
proposes that this arrangement be reviewed or adjusted to respond to the market.
The alternative package proposes that government applies a national interest test, to new
and existing projects, to set limits on gas exports.
While a domestic gas reservation may provide security of supply for domestic consumers, it
also imposes significant costs and risks on the economy.
Imposing retrospective restrictions on existing projects is problematic and raises issues of
sovereign risk that would leave the government at risk of litigation from existing approved
projects. Perhaps more importantly, such a retrospective restriction would set a precedent
that discourages any new investment or expansion to increase the supply of gas, and
investments in other industry, and would therefore impose long term damage to the
Australian economy as a whole without serving to address long term issues in the gas
market. Applying a retrospective reservation or national interest test is therefore
counterproductive and problematic and would not address the immediate challenges faced
by the eastern gas market. The Grattan Institute supports this view and considers that, even
if there were merit to a domestic reserve policy, it is too late to introduce one now, given the
significant progress of projects for LNG export in the east coast.142
Given that a national interest test could only be applied to new projects, the impacts on
potential new projects must be considered before such an intervention is recommended.
The Western Australian Government introduced a 15 per cent domestic gas reserve in 2006.
This has not served to reduce the domestic price of gas in Western Australia, which has
since risen sharply from $2.50 per GJ to as high as $12 per GJ.143
Economic analysis shows that unless a domestic reservation is accompanied by additional
market interventions, such as price controls or subsidies or the amount of gas reserved for
the domestic market is more than the amount of gas that domestic users would otherwise
buy at the export parity price, it often results in an even higher price for gas on domestic
markets.144
APPEA has also expressed concern regarding proposals for domestic reserve and a
national interest test and believes that this would add significant regulatory uncertainty to
gas projects, duplicate existing regulatory processes and not increase gas supply. APPEA
argues that a better approach would be to increase supply by reducing regulatory burden
and not to increase regulation and extend approval processes.
142
Grattan Institute Getting gas right June 2013. p. 17
DOMGAS Alliance Australia’s Domestic Gas Security 2012
144 Stephen King Professor of Economics Monash University <http://theconversation.com/a-gasreservation-scheme-is-protectionism-in-disguise-11810>
143
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Analysis prepared by APPEA identified detrimental effects resulting from the application of
domestic reserve policies including pressure on government budgets where domestic gas
prices are subsidised, wasteful use of energy due to distorted price signals, and deterrence
of investment in new production, including foreign investment. 145
Thus, over the long run, gas reservation polices can lower investment in further gas supply
developments and result in higher domestic gas prices than might otherwise occur if the
market were allowed to respond more freely.146
Although the US and Canada have applied national interest tests, they have been reluctant
to deny approval to projects and favour market driven supply and demand. In the US, export
approvals is a formality for export to the 19 countries with which the US has a free trade
agreement, and exports to other countries have been approved. The US Department of
Energy examined the potential impacts of further LNG exports and concluded that such
exports would be of net benefit to the economy, therefore paving the way for future projects
to be approved.147 In Canada, the impacts of exports on availability of gas to the domestic
market is considered prior to granting approvals to export projects, but to date this has not
been regarded as a concern and two export projects have been approved. 148
Interventionist polices such as a domestic gas reservation distort the market’s ability to
adjust to increasing prices and remove the incentive for investment in increasing supply to
the market. Further, they block price signals that might otherwise drive demand side
responses, such as improvements in energy efficiency, and are likely to result in higher
levels of gas consumption than would otherwise occur.
Overall, the Taskforce believes that a government imposed domestic gas reservation would
not deliver lower priced gas to domestic consumers and may result in a number of
undesirable and unintended consequences in the market and economy as a whole. However
the Taskforce also understands that domestic consumers require more certainty during the
transition and therefore sees merit in industry led reservations. Some gas producers have
voluntarily earmarked particular developments to domestic markets. An example is the
Santos agreement with Drillsearch to accelerate Cooper Basin production with an intention
to supply additional gas into the eastern market in 2014.149
This approach could be encouraged through a voluntary scheme, where producers identify
the volume and sources of production which they assign to the domestic market, thus giving
more certainty to domestic consumers about the availability of gas.
145
EnergyQuest Domestic Gas Market Interventions: International Experience, 2013
Bureau of Resources and Energy Economics Gas Market Report, July 2012, pp. 60
147 EnergyQuest Domestic Gas Market Interventions: International Experience (2013) pp. 16 – 17.
148 EnergyQuest Domestic Gas Market Interventions: International Experience (2013) pp. 19
149 Santos, Media Release – Santos and Drillsearch agree to accelerate Cooper Basin production, 4
July 2013.
146
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Chapter 4: Wholesale markets and transmission
About Chapter 4
Wholesale trade of gas occurs predominantly through confidential long-term bilateral
contracts between producers and retailer or major users. Transportation of gas along a
network of transmission pipelines from production fields to major demand centres also
predominantly occurs under confidential bilateral contracts between shippers and pipeline
owners.
While the eastern market structure has served the east coast well in the past, facilitating
private investments and construction of over 20,000 kilometres of pipelines across the east
coast, compared with a mature market, there is a lack of transparency in gas prices. This is
already contributing to considerable uncertainty in the market. The need for more
transparency and liquidity will become increasingly important as the eastern gas market
experiences a significant transition to accommodate the LNG export market.
Development of liquid trading hubs and secondary markets, flexible and open transmission
access arrangements, and information transparency, would lay the foundations for a wellfunctioning eastern gas market. SCER is currently undertaking a reform program to develop
wholesale markets in these areas, including the establishment of a brokerage hub at
Wallumbilla. However the reform agenda may need to be accelerated or bolstered to
address the rapidly changing market conditions.
This chapter discusses aspects of wholesale markets and transmission that the Taskforce
believes would benefit from increased transparency and liquidity, and identifies potential
areas for reform. The critical question facing the eastern market today is whether the
significant structural changes it is undergoing mean that significant market reforms are
needed to enhance liquidity and transparency in this market.
Introduction
The eastern Australian gas market is a gas market in the broad sense. There is
interconnection and trade between supply and demand centres, but it is not highly integrated
and exhibits strong regional variations. Historically, transmission and distribution
infrastructure emerged to service disparate demand centres across the eastern states.
History and infrastructure
Natural gas is transported along a network of transmission pipelines from production fields to
major demand centres. Australia’s gas transmission pipeline network has almost trebled in
length since the early 1990s, with investment in long haul interstate pipelines to introduce
new supply sources and improve security of supply.
The construction of the QSN Link from Ballera to Moomba in 2009 connected the
Queensland transmission network with major pipelines in South Australia and New South
Wales. Earlier projects included the Eastern Gas Pipeline (Longford to Sydney, completed in
2000), the Tasmanian Gas Pipeline (Longford to Hobart, 2002) and the South East Australia
Gas (SEA Gas) Pipeline (Port Campbell to Adelaide, 2003). The VicHub in eastern Victoria
Page | 65
(located at Longford) was constructed in 2002 to physically connect the Victorian
Transmission System with the Tasmanian Gas Pipeline and the Eastern Gas Pipeline.
In combination, these projects have created an interconnected pipeline network covering
Queensland, New South Wales, Victoria, South Australia, Tasmania and the Australian
Capital Territory. While Western Australia and the Northern Territory have also had
significant pipeline investment, they have no transmission interconnection with other
jurisdictions. In total, Australia’s gas transmission networks cover over 20,000 kilometres.
Ownership
The gas transmission infrastructure in the eastern market is privately owned. However, the
history of ownership has differed between states. In Victoria and Western Australia,
significant periods of state ownership and development occurred in the 1960s to 1990s
associated with development of the Bass Strait and North West Shelf gas fields. In South
Australia150, New South Wales151 and Queensland, ownership and development of pipelines
was undertaken by private ventures (in partnership with governments in some cases).
Government reforms to the gas sector in the 1990s led to structural reform and significant
ownership changes. In particular, vertically integrated gas utilities were disaggregated and
most government owned transmission pipelines were privatised. Currently, APA Group and
Singapore Power International (through its subsidiary Jemena) are the principal owners in
the gas transmission sector.
APA Group is the most significant owner of pipeline transmission infrastructure. It owns three
pipelines in New South Wales, the Victorian Transmission System, five major Queensland
pipelines, pipelines in Western Australia and a major Northern Territory pipeline. It also has
a 50 per cent interest in the SEA Gas Pipeline.
During 2012, APA Group acquired Hastings Diversified Utilities Fund; with a portfolio
including the Moomba to Adelaide Pipeline, the South West Queensland Pipeline, QSN Link
and the Pilbara Energy Pipeline in Western Australia. Singapore Power International
acquired a portfolio of gas transmission assets from Alinta in 2007. Presently, it owns and
operates the Eastern Gas Pipeline, VicHub and the Queensland Gas Pipeline.152
Transmission
All eastern market transmission infrastructure is privately owned and subject to markedly
different regulatory frameworks and price signals in each state. Figure 18 shows the eastern
gas transmission network and parts of the northern network. Wholesale trade of gas occurs
predominantly through confidential long-term bilateral contracts, which have been a key
feature underpinning investor security to finance infrastructure development in the market.
150
Barry Wood, The Australian Pipeliner Pipelining in South Australia - where it all started: the
Moomba-Adelaide pipeline, October 2005.
151 The Australian Pipeliner The Moomba to Sydney pipeline: 1971 to 1976. The Australian
Pipeliner, July 2007.
152 Australian Energy Regulator State of the Energy Market 2012
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Figure 18: The eastern market gas transmission system. (Source: AER State of the Energy Market, 2012)
The gas pipelines access regime
Access to gas transmission pipelines is regulated through the National Gas Law and
National Gas Rules, which aim to facilitate third party access to spare pipeline capacity,
promote efficient gas pipeline investment, establish wholesale gas exchanges and support
retail contestability. However, not all pipelines are subject to access regulation. A test is
applied to a given pipeline, to determine if it is regulated (“covered”) or unregulated
(“uncovered”)(see Box 16). Only covered pipelines are subject to the National Gas Law and
National Gas Rules.
Page | 67
Box 16: CLASSIFICATION OF PIPELINES – COVERED OR UNCOVERED
The relevant minister determines whether a pipeline is covered or not, based on a formal
advisory process run by the National Competition Council. A pipeline is covered if it meets
the following criteria:153

that access (or increased access) to Services provided by means of the Pipeline would
promote competition in at least one market (whether or not in Australia), other than the
market for the Services provided by means of the Pipeline;

that it would be uneconomic for anyone to develop another Pipeline to provide the
Services provided by means of the Pipeline;

that access (or increased access) to the Services provided by means of the Pipeline can
be provided without undue risk to human health or safety; and

that access (or increased access) to the Services provided by means of the Pipeline
would not be contrary to the public interest.
The National Gas Law and National Gas Rules require the submission of access
arrangements by pipeline owners to the AER for determination. Access arrangements
provide a mechanism for third parties to obtain access to covered pipelines within an
independent regulatory framework outlined in the National Gas Rules, including referral to
arbitration to resolve access disputes.
The National Gas Rules aim to provide a degree of certainty regarding terms and conditions
for access to the services of covered pipelines in the event of a dispute, while preserving the
ability for parties to negotiate access on commercial terms. Different forms of economic
regulation apply, based on coverage criteria set out in section 15 of the National Gas Law
and form of regulation factors set out in section 16. These are full regulation, light regulation
and no regulation (see Box 17 for a summary of each level of regulation).
The existence of a test for coverage and the three tiered system of regulation creates a
regime in which there is a mixture of different regulatory and contractual arrangements
across the eastern market. Even parts of the same pipeline may be subject to full access
regulation with regulated prices and specific terms and conditions of carriage, while others
are entirely unregulated, with the terms of access entirely at the discretion of the pipeline
owner.
153
National Third Party Access Code for Natural Gas Pipeline Systems
<www.austlii.edu.au/au/legis/wa/consol_reg/ntp84acfngps586/>
Page | 68
Box 17: REGULATION OF TRANSMISSION PIPELINES
Full regulation – Covered pipelines that have market power
Full regulation is applied when a pipeline is deemed to have a degree of market power which warrants
regulatory intervention to promote overall efficiency.
Full regulation requires a pipeline provider to periodically submit an Access Arrangement to the
regulator for approval. A full Access Arrangement must set out:

the terms and conditions of access to covered pipelines to which the Access Arrangement relates;

proposed pipeline services that are likely to be sought by a significant part of the market
(“Reference Services”);

tariffs for those Reference Services (“Reference Tariffs”);

capacity trading requirements;

queuing requirements (if applicable) to determine user priorities for spare capacity;

how the pipeline is to be expanded or extended; and

how access requests are to be dealt with.
The regulator assesses the revenues needed to cover efficient costs and provide a commercial return
on capital, then derives Reference Tariffs for the pipeline. The AER regulates five transmission
pipelines including those supplying Brisbane, Melbourne and Darwin, under full regulation.
The AER is currently developing a “Rate of Return Guideline”. This guideline will set out how the AER
intends to apply the rules framework to set rates of return for network business that meet the long
term interests of consumers. The final guideline is to be published in November 2013.
Light regulation – Covered pipelines where there is potential for
contestability
Light regulation is applied where the market power exercised by the pipeline is less substantial and
there is the potential for contestability for the services to emerge.
Under light regulation, the pipeline provider determines its own tariffs. The AER is responsible for
three transmission pipelines subject to light regulation: the Carpentaria Gas Pipeline in Queensland,
the covered portions of the Moomba to Sydney Pipeline and the Central West Pipeline in New South
Wales.
When light regulation applies, the pipeline provider must publish access prices and other terms and
conditions on its website. In the event of a dispute, a party seeking access to the pipeline may ask the
AER to arbitrate.
No regulation – Uncovered pipelines
No regulation is applied when a pipeline does not satisfy the coverage criteria.
A large proportion of transmission pipelines are ‘uncovered’, meaning that they are not subject to
economic regulation. The National Gas Law also enables the Federal Minister for Resources and
Energy to grant a 15 year ‘no coverage’ determination for new pipelines in certain circumstances.
There has been controversy over the intended scope of coverage of gas transmission
infrastructure. While some governments, including Victoria’s, anticipated a fairly wide extent
of coverage, the industry and other governments preferred a light-handed approach. The
evolution of the regime has tended strongly to light handedness and non-coverage, in
Page | 69
practice. This debate was crystallised in the Productivity Commission’s 2004 review of the
Gas Access Code.154
The regulatory framework anticipates the potential for market conditions to evolve, and
includes a mechanism for reviewing whether a particular pipeline needs economic
regulation, and the extent of that regulation. The coverage of several major transmission
pipelines has been revoked over the past decade. Additionally, only one transmission
pipeline constructed in the past decade is covered. Box 18 gives a brief overview of key
rulings to uncover pipelines.
Box 18: KEY RULINGS TO UNCOVER TRANSMISSION PIPELINES
Some key decisions on pipeline regulation since 2000 are summarised below.
Eastern Gas Pipeline
The Eastern Gas Pipeline was covered by a Ministerial decision on 16 October 2000. This
was made on the basis of a recommendation by the National Competition Council. The
Australian Competition Tribunal reversed this decision on 4 May 2001. The Tribunal
concluded on the basis of Duke Energy’s application for review:
The Tribunal concludes that EGP will not have sufficient market power to hinder
competition based on the commercial imperatives it faces, the countervailing power
of other market participants, the existence of spare pipeline capacity and the
competition it faces from the MSP and the Interconnect. As EGP does not have
market power, the Tribunal cannot be satisfied that coverage would promote
competition in either the upstream or downstream markets.
(Source:
http://www.judgments.fedcourt.gov.au/judgments/Judgments/tribunals/acompt/2001/2001acompt02)
This decision arguably set the parameters for future decisions in respect of coverage.
Moomba to Adelaide Pipeline System
Coverage of the Moomba to Adelaide pipeline system was revoked in 2007. It was argued
that due to the changed market conditions caused by the entry of SEA Gas into the Adelaide
market, together with the emergence of an increasingly competitive south eastern Australian
gas market, the pipeline no longer satisfies the coverage criteria.
South East Pipeline System
Coverage of the South East Pipeline System was revoked in 2000 as it was found that, in
the short to medium term, access to the pipeline was unlikely to promote competition and the
costs of regulation were likely to outweigh the benefits.
Victorian gas transmission system
Victoria’s major gas transmission pipelines are listed in Table 3. The major component of
this system is the 1,993 km Victorian Transmission System, which transports almost all of
the natural gas consumed in Victoria. The Victorian Transmission System primarily functions
to transport gas from Esso's Longford gas treatment plant in south east Victoria (which
processes gas from offshore Bass Strait gas fields), the Otway Basin gas fields and
154
Australian Government Productivity Commission Review of the Gas Access Regime
<http://www.pc.gov.au/projects/inquiry/gas/docs/finalreport>
Page | 70
underground storage in southwest Victoria. This transmission line is interconnected with the
Moomba Sydney Pipeline.
Table 3: Major Victorian gas transmission pipelines (Source: AER State of the Energy Market, 2012)
PIPELINE
Lengt
h (km)
Cap.(TJ/d
)
Constructe
d
Covere
d
Valuatio
n
($M)
Current
access
arrangeme
nt
Owne
r
Operator
Victorian
Transmissio
n System
2035
1030
1969 –2008
Yes
524
(2007)
2008–12
APA
Group
APA
Group/AEM
O
South
Gippsland
Natural Gas
Pipeline
VicHub
250
2006 –10
No
50 (2007)
Not required
DUET
Group
150
(into
Vic)
2003
No
Not required
Jemen
a
Jemena
Asset
Managemen
t
Jemena
Asset
Managemen
t
The first commercial underground gas storage facility in Australia, the Iona Gas Plant, was
developed in Victoria near Port Campbell making use of depleted gas reservoirs in the
Otway Basin. Iona’s storage reservoirs can provide up to 500 Terajoules (TJ) of gas per
day.155
Pipeline capacity trading
In a study of several institutional arrangements around the world, Makholm found that the
most important factor in stimulating liquid commodity markets in gas is the creation of robust
and uniform contractual entitlements to pipeline capacity.156 Makholm concluded that the
success of the US in building its gas market has been the uniform creation of a system of
transportation entitlements that may be traded by participants.
The universality of gas transportation arrangements in the US has allowed utilities and other
parties to trade in gas without fear of contractual congestion or hoarding of capacity by
regional incumbents, or discrimination by pipeline owners. In the US, the contractual
entitlements are also supported by transparency over the accounting practices of pipelines,
which facilitates efficient pricing and investment in those pipelines.
“In that market, gas pipelines own and operate the price-regulated facilities that
support those entitlements to transport gas, but they do not own or control the
entitlements themselves, nor do they possess any operational or financial information
that is not an open book to those who would buy or sell those entitlements.”157
The Australian access regulation framework, by contrast, is predicated on the assumption
that if pipelines are working in a ‘competitive’ environment (under pressure from rival
155
EnergyAustralia <http://www.energyaustralia.com.au/about-us/what-we-do/powergeneration/gas-plants/iona-gas-plant>
156 Jeff D Makholm The Political Economy of Pipelines: A Century of Comparative Institutional
Development. University of Chicago Press, April 2012.
157Jeff D Makholm The Political Economy of Pipelines: A Century of Comparative Institutional
Development. University of Chicago Press, April 2012. pp. 140
Page | 71
pipelines serving the same market) then they will be forced to price efficiently by the market
and further regulation is unnecessary.
However, this regime is tested by the current circumstances of the rapidly expanding eastern
gas market. The Grattan Institute points out that there is such little transparency in the
market now that potential buyers and sellers are unable to find each other and, as a result,
pipeline owners have little incentive to offer competitive prices for pipeline capacity and
existing pipeline infrastructure is not used to its full potential.158 It argues that facilitating
short term capacity trading would increase competition and lower gas prices.
SCER recognises this issue and has most recently canvassed options for facilitating trade in
pipeline capacity in a Regulatory Impact Statement Consultation Paper159 (see Appendix 2
for further details). AEMO has also recognised that pipeline capacity trading will be a key
enabling requirement for the establishment of gas trading hubs, such as the one being
developed in Wallumbilla (see section on wholesale trade). Both AEMO and SCER have
recognised the benefits of standard terms and conditions to facilitate short term capacity
trading and increase transparency. However, incumbent pipeline owners argue that bespoke
contracts are better for long term trading as they allow more opportunity for innovation in
pipeline services and can more flexibly meet the needs of both capacity sellers and buyers.
It is therefore an appropriate time for a suitably expert body to re-examine whether the
access regime actually delivers an efficient market in transportation, and particularly,
whether the market in capacity entitlements could be better facilitated.
Capital expenditure and augmentation
For pipelines subject to full regulation, the AER sets Reference Tariffs for third party access
to the transmission capacity. To inform this analysis the AER estimates the efficient cost of
providing pipeline services. It does this by the ‘building blocks’ methodology, whereby
various cost components—cost of capital, depreciation, capital expenditure, operational
expenditure and taxes—are analysed and added together. The AER then sets tariffs in five
year blocks to give pipeline owners an incentive to maximise profits by reducing costs below
the level deemed efficient.
Some market participants argue that the current method of assessing the Rate of Return is
flawed. In determining the Reference Tariffs, the AER predicts capital expenditure needs
over a five year period. This means that it also predicts the need to augment and expand
capacity on covered pipelines, and makes decisions about capital expenditure and whether
there is a demonstrated need for investment. The AER therefore performs a de facto system
planning role and significantly influences whether investment is made to expand or upgrade
pipeline assets.
The National Gas Rules provide for alternative means of investing in capacity such as
speculative investments and capital contributions by interested parties. However, these have
been seldom used in practice. In respect of ‘speculative investments’, covered pipeline
owners have not shown an appetite for this level of risk. In respect of capital contributions,
Grattan Institute Getting gas right: Australia’s energy challenge, June 2013, pp. 22.
Standing Council on Energy and Resources Officials, Regulatory Impact Statement - Gas
Transmission Pipeline Capacity Trading – Consultation paper, May 2013
158
159
Page | 72
capacity-seeking parties have not shown such an appetite either, particularly as there is a
risk of subsequent access-seekers using capacity paid for by the contributor.
Alternatives to this situation include firm capacity rights that can be sold to underpin pipeline
development, or central planning to an economic viability test similar to arrangements that
apply in the Victorian electricity transmission sector. In the former case, the arrangements
may be difficult and complex to work out in an integrated system. In the latter case,
investments are still ultimately funded by end users and there are limits to the ability of
central planners to foresee the capacity needs looking forward.
Wholesale markets
Gas in the east coast wholesale market is traded through:
 bilateral and confidential commercial contracts;
 facilitated exchanges or hubs; or
 integrated market arrangements.
There are various points in the gas system at which gas may be bought and sold for
delivery. Most frequently, these are the production facilities (like Longford), the ‘town gate’
where gas leaves a transmission pipeline, or the supply point at the end of a distribution
pipeline. The various steps between production facility and consumer mean that a number of
different parties may buy and sell gas before it is delivered.
The predominant business model for small and commercial gas customers is buying gas
from a retailer at the supply point for their premises. The retailer will buy gas wholesale from
a production facility (or may even own that facility) and arrange for carriage across the full
pipeline system to the user. The price risk of gas and pipeline capacity from the production
facility to the user is internalised by the retailer. However, large commercial/industrial
customers do not always use retailers, as they may feel better able to manage their own gas
supply and realise cost savings from doing so. In such circumstances, they may buy gas
from a producer or shipper, which will deliver gas wholesale to the town gate (but not
beyond), or may buy from a producer at the production facility, and arrange their own
carriage across the transmission pipeline. The three business models for trade in bilateral
contracts are illustrated in Figure 19.
Page | 73
Figure 19: Business models for wholesale gas trade through bilateral contracts in the eastern market
While the eastern market has become increasingly connected, the variety of facilitated
exchange markets that have been, or are being, established added to the various
arrangements for regulation and sale of pipeline services, make for an heterogeneous
market structure (Figure 20). In a market with comparably few pipelines in a large
geographic area, the multiplicity of different commercial environments increases transaction
costs and reduces the efficiency of the market as a whole.
Page | 74
Figure 20: Eastern Australian gas market structure - conceptual diagram
In general, trade near the supply side is referred to as the upstream market and trade nearer
to the demand side is referred to as downstream market. At each of the points on this chain
– production facility, town gate, and supply point – facilitated market arrangements may be
put in place to assist trade. At upstream points, trading ‘hubs’ such as the proposed
Wallumbilla hub may be instituted. At town gates, downstream trading markets like the Short
Term Trading Markets (STTMs) have been established. Retail markets provide for the
switching of supply points between suppliers. While upstream and downstream wholesale
markets provide for the trading of gas – as a commodity – retail markets provide for the
exchange of customers, and are of a different type.
Page | 75
Upstream markets
No central hub for trade of gas exists in the upstream market. In the upstream sector, gas is
bought from suppliers, and pipeline capacity from pipeline owners under direct bilateral
contracts. These contracts have historically been long term and fairly inflexible, with take-orpay provisions providing the investment underpinning development of gas production and
pipeline facilities.
The current SCER reform program seeks to develop a voluntary Gas Supply Hub market for
wholesale gas in Australia, to improve transparency and facilitate flexible and efficient trade
in upstream markets. The first hub that will be established as part of this reform is a
brokerage hub at Wallumbilla that will facilitate wholesale trade of gas in south central
Queensland, which will be the dominant gas producing region in the eastern gas market in
the next decade.
The Taskforce believes that the Wallumbilla hub will facilitate trading of gas, to the extent
that broad price trends will start to become discernible. However, the Wallumbilla hub may
be strongly constrained, at least initially, by the lack of physical transmission infrastructure
and availability of pipeline capacity rights to facilitate wider trade of gas across the eastern
market. Further, it will not address barriers to effective third party access rights to
transmission pipeline capacity, which particularly affect new market entrants.
There are various potential issues that may affect the development of a successful gas
supply hub in eastern Australia:




Hub services – A critical factor in the development of successful overseas hub markets
has been intra-hub transportation services which allow for gas traded at the hub to be
physically delivered to exit or storage facilities according to customer needs. In its initial
‘brokerage’ form, Wallumbilla will not be supported by such services. Instead, only trades
between participants at the same facility or those that can be facilitated by ‘swaps’
between participants at different facilities will be possible.
Pipeline and storage capacity - the development of Henry Hub in the US (the world’s
foremost financial market for gas) was predicated on fortunate historical circumstances,
namely the pre-existence of a very well connected physical facility, in a convenient
location, with plenty of spare capacity to ensure the deliverability of gas to traders. (See
Chapter 6 for more information on the Henry Hub and the US transmission trading
system). In contrast, an Australian gas hub may be challenged by a lack of spare
capacity, especially in Wallumbilla where transmission pipelines have significant firm
contractual commitments to LNG export facilities and limited interconnectivity.
Contractual obligations – Large bilateral contracts will continue to be a major part of
the gas market for unavoidable reasons. These contracts will necessarily remove
potential liquidity from commodity trading markets. The extent to which this is the case
will affect the success of commodity markets, noting that overseas experience shows
that there is a trend away from overly rigid contractual arrangements where alternatives
exist.
Action by government – In some markets, industry participants have worked together
to establish hub services and other supporting infrastructure for gas trading. However,
government may have a necessary role in ensuring that appropriate incentives exist to
facilitate transport of gas by market participants.
Page | 76
The Wallumbilla trading hub, in combination with the downstream STTMs and major contract
carriage markets will hopefully stimulate trade to the extent that broad price trends will start
to become discernible.
New reform initiatives to achieve an integrated and transparent market
There was general support from the Taskforce to pursue the SCER’s vision of forming a
“single trading zone” with interconnected hub services to facilitate liquidity in the eastern gas
market. However, the Taskforce is not in a position to prescribe immediate remedies to the
complex technical and economic issues involved in determining the next wave of reforms. It
may be that the gas industry itself is best placed to cooperate to bring about hub services,
greater information transparency, standardised transportation entitlements and many of the
things required for a better functioning eastern gas market. If not, government intervention
may be required. The Taskforce therefore concludes that a thorough review of the regulatory
environment is needed. Given its history in advising the Commonwealth Government on
broad economic policy questions, including those of infrastructure access, the Productivity
Commission is the most appropriate body to conduct a thorough review of the eastern gas
market with a view to informing future government policy in this area.
Downstream markets
Downstream markets provide for the exchange of gas between trading participants close to
demand centers, such as major cities or industrial regions. This allows market participants,
who may be shipping gas to the demand region under contract through transmission
pipelines, to balance their portfolios, and to manage price and volume risk in the demand
region on a more fine grained basis than may be allowed by their upstream positions and
pipeline contracts. In Sydney, Adelaide and Brisbane, this trading is achieved through
STTMs, a wholesale market system designed to facilitate short term gas trading using
market driven daily prices. The STTMs are operated by AEMO. Victoria has the most
sophisticated market arrangements where gas is traded on the Declared Wholesale Gas
Market (DWGM).
Victorian downstream market
In Victoria, the DWGM is a facilitated market that integrates the transmission system and
allows injection and withdrawal of gas at different points. It allows market based scheduling
of gas, and short term trading and provides market participants with transparent and
appropriate economic signals for investment. The market price (up to $800 per GJ) is
calculated by assuming that there are no physical limitations on the pipeline and is
determined five times each gas day at standard reschedule times. Participants offer gas into
the DWGM through a competitive bidding process. These bids are stacked in order of price
and cleared against the total forecast demand.
The DWGM facilitates effective trading and balancing arrangements to market participants;
stimulating a competitive market for gas retailing, and safeguarding the security of market
operations and supplies by integrating new sources of gas supply.
Nevertheless the open access arrangements adopted by the DWGM place limitations on the
extent to which parties can hedge against the risk of being constrained off the system during
periods of pipeline congestion. In this respect, the DWGM is analogous to the National
Page | 77
Electricity Market, where absence of commercial signals for transmission investment have
been highlighted by the AEMC and solutions proposed in its Transmission Frameworks
Review.160
A review of the DWGM conducted by AEMO161 in 2011 concluded that, particularly in respect
of the allocation of rights to capacity on the transmission system (and flowing through to
incentives to augment capacity where needed), there were significant areas needing
attention. These included:

Existing capacity instruments not meeting market needs
The DWGM uses two capacity instruments – authorised maximum daily quantity
(AMDQ) and AMDQ Credit Certificates (AMDQ CC) as a way for Market Participants
to manage risk. AEMO concluded that there were a number of shortcomings with
these instruments, including the inability to use AMDQ for exports at Culcairn,
insufficient liquidity, complexity, a perception that there are insufficient benefits from
these instruments to justify their costs and the focus of these instruments on
intrastate demand at the expense of exports. There are also issues of potential
inconsistency of these instruments with how capacity is treated under access
regulation.

Maintaining adequate capacity
There are issues with maintaining capacity in the face of potential growth in demand
at various locations on the system. Under the open access arrangements, investors
in pipeline augmentations are unable to secure any rights to the system. This creates
potential free rider effects, which can dis-incentivise parties from offering to fund
augmentations. There is further uncertainty associated with regulatory approval of
regulated investments, inconsistency between prices of regulated and potential
unregulated capacity, lack of appropriate incentives on service providers to invest to
a standard of reliability or capacity, and challenges arising from potential future
growth of gas fired power generation. It is acknowledged that there is little growth in
demand in Victoria at present, but circumstances may change in future particularly in
response to carbon pricing signals.

Inadequate investment signals
A market based investment decision for pipeline augmentation requires clear and
timely investment signals. The DWGM relies only on market signals (revealed in gas
prices and ancillary payments), because there is limited public planning information
available. This issue is closely linked to the issues discussed above. Issues have
been identified with the lack of differentiated pricing in different parts of the DWGM,
limited linkage between market signals and capacity shortfalls, and uncertainty over
the role of AEMO’s planning and forecasting role. That is to say, there are no
mechanisms through which the value of pipeline capacity can be signalled and
purchased.
160
Australian Energy Market Commission Transmission frameworks review - final report (April
2013) <http://www.aemc.gov.au/Media/docs/Transmission-Frameworks-Review---Final-Reportd183e454-f5b8-4e3d-895f-4e9e2f126ea0-0.PDF>
161 Australian Energy Market Operator Transmission capacity issues in the DWGM (August 2011)
<http://www.aemo.com.au/~/media/Files/Other/vicwholesalegas/1000-0112%20pdf.ashx>
Page | 78
Other potential issues in the Victorian wholesale market include:

Commodity trading of gas
The spot market has not been successful in stimulating commodity trading of gas. By
and large, gas is sold to retailers under bilateral contracts and only bid into the
market by those retailers. Hence, the spot market is used as a balancing market only.
This arguably underutilises the potential of the DWGM to achieve greater
transparency and efficiency.

Connection of gas fired generation
In Victoria, there are six generators (Loy Yang B, Jeeralang, Newport, Laverton
North, Somerton and Valley Power) connected to the gas Declared Transmission
System (DTS). Generators in Mortlake and Bairnsdale are not connected to the DTS.
The taskforce has heard complaints that the attractiveness of connection to the DTS,
where it would otherwise be most efficient to do so, may be reduced by the difficulty
in obtaining firm capacity and the need to manage “unhedgeable” price risks in the
DWGM.
Section 295(3) of the National Gas Law provides that applications for rules regulating the
DWGM can only be made by AEMO or the Minister of an adoptive jurisdiction. Pursuant to
this provision, AEMO has continued to take stewardship of DWGM development through its
industry consultative committees.
Under this arrangement AEMO can initiate rule changes by first drafting the proposed rules
for consultation before submitting to AEMC, which undertakes a second round of
consultation. The Victorian Minister also has the power to initiate rule changes, but has not
exercised this power, and is unlikely to do so unless there was a matter of considerable
urgency to warrant it.
The Taskforce has heard that effectively engaging with the AEMO rule change processes is
a time and resource consuming exercise that only major gas market participants can sustain
over time. Thus, the process itself represents a barrier for smaller market participants and
potential new entrants to influence market development. As a result, market development
tends to be skewed in favour of existing major market participants.
There have been only five changes to the DWGM so far, one of which is a minor change.
This pace of change is too slow given the substantial issues identified by AEMO in its 2011
report and the urgency of the challenges for Australia’s gas markets.
In the electricity sector, an ‘open standing’ rule change regime has been adopted, which
allows any interested party to submit to the AEMC a proposal to change the rules in a way
that better achieves the National Electricity Objective. This open standing procedure has
been used to great effect162 by stakeholders to progress the framework as demands have
arisen in the relatively fast changing electricity sector. The open standing rule change
process is overseen by an independent rule maker. It was devised by COAG in the early
162
There have been 56 revisions of the National Electricity Rules at the time of writing.
Page | 79
2000s in response to the findings of the COAG Energy Market Review,163 which criticised the
former electricity code change process as being overly cumbersome and slow; requiring the
assent of two different bodies and two separate open consultation processes – the National
Electricity Code Authority and the ACCC.
The Taskforce has not come to a position on these issues, but recommends that the
Victorian government consider the merits of revisiting the National Gas Law section 295(3)
and the appropriateness of adopting an open standing rule change process for the DWGM.
Secondary markets – risk and financial products
The ability to trade in financial products derived from trade in commodity natural gas can be
used by market participants to hedge market exposure and manage financing. A Victorian
Wholesale Gas Futures on the Australian Stock Exchange (ASX) was introduced in 2009,
however over the past 4 years there has been little trade in gas futures. No other secondary
market in derivative financial products for gas has emerged in Australia.
The lack of a future wholesale price for gas has contributed to the lack of transparency and
uncertainty in the wholesale gas market. This in turn has made it difficult for industry players
to enter into contracts.
The Natural Gas Services Bulletin Board164 tracks capacity flows on all major gas production
fields, major demand centers and natural gas transmission pipeline systems (including the
interconnected systems of South Australia, Victoria, Tasmania, New South Wales, the
Australian Capital Territory and Queensland).
The purpose of the bulletin board is to facilitate the trade in gas. However, the information
available is modest in its scope compared to some overseas examples. While Australia’s
bulletin board provides actual flow data on a current and past basis, the information portal
operated by National Grid in the UK165 provides a much finer grained level of detail and
integrates with forecast information that assists participants in taking their positions. The
Taskforce considers that opportunities to improve information in the Australian gas market
should be explored.
Most market participants and parties consulted by the Chair raised the issue of the need for
greater transparency of market information.
SCER is pursuing development of the Wallumbilla trading hub to stimulate trade in derivative
products. However, the ability for the Wallumbilla hub to do so will depend on the limitations
around delivery of gas where it is needed. Further action by the SCER will be needed to
address these limitations.
163
Council of Australian Governments COAG energy market review (December 2002)
<http://www.ret.gov.au/Documents/mce/_documents/FinalReport20December200220050602124631.
pdf>
164 <www.gasbb.com.au>
165 <http://marketinformation.natgrid.co.uk/gas/frmPrevalingView.aspx>
Page | 80
SCER should therefore investigate options for developing uniform transmission capacity
rights and pursue ways of facilitating more transparent and liquid trade in transmission
capacity. This should include options for:

the creation of uniform tradeable products for transmission of gas across east coast
gas markets;

promoting transparency of information on availability of transmission rights;

creating platforms to allow a more liquid secondary market in the trading of
transmission rights;

introducing mechanisms that address the potential hoarding of pipeline capacity; and

ensuring that pipeline owners have adequate incentives to ensure that spare pipeline
capacity is made available to the market in a timely and transparent manner.
Establishing arrangements that facilitate trading in pipeline capacity should facilitate more
liquidity in the market and enable market participants to transport their gas in response to
demand.
An industry led process is currently underway to develop a gas price futures index, with the
Australian Financial Markets Association convening a Gas Market Working Group. For this
index to work, a minimum of four producers and four users are required, to allow for
sufficient price spread as well as anonymity. To date, this process has been hampered by
polarisation between producers and gas users on a variety of issues.
The Taskforce believes that a survey-based gas price index is worthwhile to pursue, as it
would go some way in providing price transparency in absence of (and may assist the
eventual development of) a liquid futures market.
As a minimum first step, industry participants should commit to publishing available
transmission capacity on a central bulletin board to allow third parties access to that
information and reduce transaction costs of trade in transmission capacity. In this way, a
more liquid market in transmission capacity could develop and more efficient use can be
made of existing transport infrastructure.
Finally, any effective reform program needs to incorporate mechanisms for monitoring and
measuring success. SCER should therefore also include measurable performance
measures, including specific timelines and responsibilities, and regular progress reviews to
assess the effectiveness of its program. The progress reviews should be used to determine
whether the program is delivering on its objectives of achieving more transparency and
liquidity in the east coast Australian market, and to reprioritise its reforms accordingly.
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Chapter 5: Retail markets and distribution
About Chapter 5
Chapter 5 focuses on the gas distribution system and gas retail market in Victoria, and
discusses issues around the current system, the health of retail competition in Victoria and
the proposed national reform agenda.
Distribution systems in south eastern Australia are privately owned and seen as natural
monopolies, which are covered by full regulation. The retail market in Victoria has full retail
contestability and customers are able to choose a retailer from any of the competing gas
retail businesses. Victorian residential consumers pay the lowest rates for their gas
consumption of the eastern states. This is due to lower pipeline charges and retail costs in
Victoria.
Retail consumers will, in due course, be affected by the increasing wholesale price of gas.
The extent and timing of any flow-through of wholesale prices will depend on existing
contractual arrangements. Modelling commissioned by the Victorian Government estimates
that, if all the LNG projects that are currently under construction commence production and
export as planned, the annual average residential gas bill in Victoria could increase by
almost 20 per cent over the period from 2013 to 2020; rising by $180 by 2020, after peaking
in 2015 at 30 per cent above current rates.166 The Grattan Institute estimates that the
average annual Victorian residential gas bill will increase by around $170 by 2020.
Background
A network of distribution pipelines delivers gas from demand hubs to industrial and
residential customers. Gas is reticulated to most Australian capital cities, major regional
areas and towns. The total length of gas distribution networks in eastern Australia is around
74,000 kilometres. The networks have a combined asset value of almost $8 billion.167
In the early 1990s, the Kennett Government commenced a process of restructuring,
corporatising and privatising the government-owned energy assets and businesses in
Victoria. As part of the restructuring process, the Government established a number of retail
businesses. In the gas sector the retail businesses were established as separate corporate
entities but “stapled” (or joined) to corresponding distribution business. Unlike electricity, the
geographic areas serviced by each gas retailer overlapped, but did not mirror the geographic
distribution areas. Rather, a single distribution area was divided between two retailers. The
stapled gas retail and distribution businesses were sold in the first quarter of 1999.
Subsequently, the gas distribution businesses were separated from retail businesses and
sold for commercial reasons by the new owners.168
166
SKM MMA Gas and electricity market modelling Final Report, commissioned by Victorian
Department of State Development, Business and Innovation (2 September 2013)
167 Australian Energy Regulator State of the Energy Market 2012
168 Australian Energy Market Commission Review of the Effectiveness of Competition in the
Electricity and Gas Retail Markets – Victoria - First Final Report (2008)
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Ownership
The major gas distribution networks in eastern Australia are privately owned, with four
principal players:




Envestra, a public company in which APA Group (33.4 per cent) and Cheung Kong
Infrastructure (18.9 per cent) have shareholdings, owns networks in Victoria, South
Australia, Queensland and the Northern Territory;
Singapore Power International, through its subsidiary Jemena, owns the principal
New South Wales gas distribution network (Jemena Gas Networks) and has a 50 per
cent share of the Australian Capital Territory network (ActewAGL). Singapore Power
International also has 51 per cent direct equity in a Victorian network (SP AusNet);
APA Group has minority interests in Envestra and the Allgas Energy network in
Queensland (rebranded from APT Allgas in March 2012), and owns the Central
Ranges system in New South Wales; and
DUET Group owns Multinet in Victoria.
The ownership links between gas and electricity networks are significant. Jemena, APA
Group, Cheung Kong Infrastructure and DUET Group all have ownership interests—in some
cases, substantial interests—in both sectors.169
Investment
Investment to augment and expand distribution networks in eastern Australia is forecast at
around $2.6 billion in the current access arrangement periods (typically five years). The
underlying drivers include rising connection numbers, the replacement of ageing networks
and the maintenance of capacity to meet customer demand. For example, a significant driver
of capital expenditure for Envestra’s South Australian distribution network is the replacement
of cast iron and unprotected steel mains, to address leaks from older sections of the
pipeline. 170
Cost of gas distribution
In eastern Australia, gas distribution charges typically make up 40−60 per cent of a typical
gas bill for a residential customer. Figure 21 compares the structure of retail gas prices for
residential customers in Victoria, Queensland, New South Wales and South Australia. The
component of retail gas prices shown as “pipeline charges” includes both transmission
charges and distribution charges, with the bulk of cost associated with distribution. As
shown, Victorian pipeline charges are significantly lower than those in other states, due to
the proximity of Melbourne and Victorian consumers to the major supply sources compared
with other states which need to invest in longer transmission pipelines, and because a higher
proportion of Victorian consumers are connected to the reticulated network, allowing for a
higher throughput and the ability to smear distribution infrastructure costs across a larger
number of consumers.
169
170
Australian Energy Regulator State of the Energy Market 2012
Australian Energy Regulator State of the Energy Market 2012
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40
Residential gas cost ($/GJ)
35
30
25
Retail costs
20
Pipeline charges
Wholesale gas
15
10
5
0
Queensland
New South Wales
Victoria
South Australia
Figure 21: Comparison of residential gas cost components across eastern Australia
(Source: ACIL Tasman, 2012 - Data is indicative only, given that costs to any particular customer will vary
depending on customer location and annual consumption.)
Distribution of gas
Unlike the transmission sector, most distribution networks are covered by full regulation
under the National Gas Law, as the monopoly characteristics of distribution systems are
stronger than transmission pipelines. The AER regulates ten distribution networks under full
regulation, including all major distribution networks in New South Wales, Victoria,
Queensland, South Australia and the Australian Capital Territory. The Tasmanian and
Northern Territory distribution networks and a number of small regional networks are
unregulated. No Australian distribution network is currently subject to light regulation.171
Access regulation
The National Gas Code requires gas distributors to provide access to their networks. For gas
distributors access is provided to retailers who are the users of the network. The terms and
conditions of access are proposed by the distributors as part of the access arrangements
and are approved by the regulator.
Retailers procure gas through long term contracts and arrange for conveyance or haulage of
that gas on networks in order to provide gas to their customers. The relationship is a straight
line relationship, where the distributor provides services or access to the retailer and the
retailer manages the relationship with the customer.
Gas regulations
Energy Safe Victoria regulates the safety and technical compliance of gas supply,
installations, appliances and pipelines, and raises industry and community awareness of gas
171
Australian Energy Regulator State of the Energy Market 2012
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and pipeline safety. All gas pipelines are covered by the Gas Safety Act 1997, with respect
to operational safety.
The Essential Services Commission regulates the gas retail sector in Victoria—regulation
focuses on performance monitoring and reporting, and complaints.
Gas Industry Licenses
Licenses are currently issued under State law (Section 25 of the Gas Industry Act 2001
(Vic)) by the ESC for one or more of the following activities:


to provide services by means of a distribution pipeline; and
to sell gas by retail.
Retailing of gas
The gas market in Victoria has full retail contestability, which allows customers (large and
small) to choose a retailer from any of the gas retail businesses competing.
Full retail contestability for Victorian gas domestic and small business customers began in
2002, and was accompanied by a price oversight mechanism and consumer protection
arrangements to safeguard the interests of customers during the transition to effective
competition.
The objective of energy retail competition is 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. Rivalry between retailers and the exercise of choice by
customers maintains competitive pressure on retailers to manage their input costs
effectively, to offer more cost-reflective prices, and to improve and diversify the retail
services they offer in order to better meet the preferences of customers. Together with
competitive wholesale energy markets and efficient incentive regulation of energy network
services, effective retail energy competition contributes to the efficient, reliable and secure
energy supply needed by households and businesses.172
The role of AEMO in retail markets
AEMO facilitates gas retail markets in New South Wales, Australian Capital Territory,
Queensland, South Australia and Victoria, and provides a similar service to Western
Australia under contract. The retail markets provide for the switching of customer metering
points between suppliers, to allow customers to switch retailers in a competitive market.
There are four primary gas retail market services that AEMO administers. They are:

Delivery Point Management – managing the information technology and data system
that assigns gas delivery points (meters) to customers, retailers and distribution
businesses, and facilitates customer switching in a competitive market;
172
Australian Energy Market Commission Review of the Effectiveness of Competition in the
Electricity and Gas Retail Markets – Victoria - First Final Report (2008)
Page | 85



Balancing, Allocation and Reconciliation Management – managing the daily
allocation of gas usage to retailers; to enable settlement of gas supply contracts,
transmission and distribution use of system contracts;
Procedure Change Management – managing further development and improvement
of the procedures governing the operation of the retail gas markets under the
National Gas Law and the National Gas Rules; and
Operating the central IT systems that facilitate retail market services.
Profile of retail demand in Victoria
Gas consumption in Victoria is cyclical and related to the seasons, with peak demand for
heating in winter and low demand in summer. High levels of winter demand for gas and the
creation of a ‘spot market’ (which provided a price signal related to peak demand) led to the
construction of an underground gas storage facility onshore at Port Campbell in Western
Victoria in 1999. This facility was the first commercial operation of its type in Australia and
uses depleted gas reservoirs.
Interaction with the wholesale market
Gas retailers who wish to sell gas to customers in distribution networks that are connected to
the Declared Transmission System (DTS) in Victoria (the majority of customers) must ensure
that they convey gas to those distribution systems through the DWGM.
The DWGM provides for gas to be bought and sold according to a central ‘bid stack’ which
sets a system-wide price for gas in Victoria. This price then determines the value of gas
injected and withdrawn at various places around the DTS. However, if capacity constraints
arise within the DTS, then retailers may not be able to access all the gas they need at the
system clearing price. These constraints are managed by AEMO, which operates both the
market and the gas system. Additional costs may be incurred and paid for by market
customers to ensure that adequate gas is delivered to consumers.
Retailers in theory may buy their gas from the DWGM, but this practice is understood to be
rare, or not used for the bulk of a retailer’s gas needs. Instead, the prevailing practice is for
retailers to contract with suppliers such as BHP or ExxonMobil for bulk gas and trade that
gas into the DWGM themselves; using the DWGM to balance any difference between their
bulk contracts and their retail load. This is a crucial difference between the prevailing
practice in the National Electricity Market (NEM) and the DWGM.
For retailers to offer a competitive product, they must be able to execute commercial
strategies to procure gas in bulk at competitive prices. The DWGM provides a means for
retailers to access several competing sources of gas and potentially interstate imports. In
this respect the DWGM is a crucial underpinning mechanism for retail competition.
Issues with the DWGM have been outlined in Chapter 4. In short, the DWGM is strong on
providing for free exchange and balancing of gas within the constraints of the system, but
weak on providing for certainty of access to capacity and incentives to invest in it.
In parts of Victoria not serviced by the DTS, retail market arrangements still apply, but the
conveyance of gas to those markets must be arranged through other channels as the
Page | 86
DWGM does not facilitate this. Contract carriage on the relevant transmission pipeline is the
norm.
Retail competition
Retailers contract with domestic and small business customers in Victoria, under either a
standing offer or market contract, to sell delivered gas at specified prices. Retailers purchase
wholesale gas to meet the needs of these customers at prices that can fluctuate over the
short-term. The central function performed by an energy retailer in any Australian jurisdiction
is therefore to act as an intermediary between the entity which produces the energy (i.e. the
gas producer) and the end use customer. In performing this role, the retailer manages the
price and volume risk faced by the customer in exchange for a risk premium, which is
incorporated into the retail price of gas. The efficient management of this risk is a key area in
which retailers can compete. 173
A gas retailer does not control or otherwise direct the flow of gas from the place of
production to the end user through the transmission and distribution networks. Rather, a gas
retailer assumes the liabilities and risks of purchasing gas directly from producers and, in
selling gas to the customer, charges a price for the energy and an appropriate return for the
assumption of risk. Accordingly, the retail price for each unit of gas comprises the wholesale
price of the gas, the charges for transporting the gas from the place of production to the
consumer’s location, the variable costs incurred by the retailer in supplying the gas, a
contribution towards its fixed costs, taxes and other levies, and a margin for risk and profit.
The quantum of these price components will be affected by any regulatory intervention, but
also by the effectiveness of competition between rivalrous suppliers of the component goods
or services.174
Is retail competition working in Victoria?
In general, the competition in gas retailing in Victoria is the most effective in Australia. Seven
gas retailers175 compete for residential customers actively across Victoria (Figure 22) and no
single retailer is dominant; in contrast to other states and territories where a single retailer
tends to dominate.
The approach taken to privatisation of the Gas and Fuel Corporation with retail franchises
not precisely mapping distribution system boundaries was highly conducive to competition.
The establishment of a sophisticated wholesale market and the integration of new sources of
gas supply from the Otway and Bass production regions has allowed retailers to pursue
competitive advantages that are not necessarily evident in other states.
A review of competition in the Victorian gas market by the AEMC in 2008 found that the
majority of gas customers are participating actively in the competitive market by exercising
173
Australian Energy Market Commission Review of the Effectiveness of Competition in the
Electricity and Gas Retail Markets – Victoria - First Final Report (2008)
174 Australian Energy Market Commission Review of the Effectiveness of Competition in the
Electricity and Gas Retail Markets – Victoria - First Final Report (2008)
175 AGL Sales, Australian Power & Gas, Lumo, Origin Energy, Red Energy, Simply Energy,
TRUenergy
Page | 87
choice among available retailers, as well as price and service offerings. There is strong
rivalry between energy retailers, facilitated by market structures and entry conditions.176
Competition has been facilitated by electricity retailers acquiring or merging with gas
retailers, and pursuing ‘dual fuel’ sales strategies whereby economies can be obtained and
discounts offered if consumers choose the same retailer for both electricity and gas supply.
However, some stakeholders have argued that there is insufficient competition among the
Victorian retailers. Figure 22 shows the number of residential gas customers each retailer
serviced in 2011-12. TRUenergy,177 AGL and Origin Energy each service more customers
than the remaining three retailers combined. The Essential Services Commission reports
that this is because these three retailers have a long history of incumbency, while the others
entered the market after it was opened to competition in the early 2000s.178
The Essential Services Commission runs the YourChoice179 price disclosure and comparison
service, which allows consumers to access a representative selection of electricity and gas
product options. Private sector comparator and brokerage sites have also arisen to leverage
the market for easy price discovery. Nevertheless, standing offers for residential and small
business customers have risen by an average 28 per cent from 2007 to 2012, as shown in
Figure 23.180
600000
500000
400000
300000
200000
100000
0
Figure 22: Average residential customer numbers per retailer in Victoria in 2011-12
(Source: Essential Services Commission, Energy Retailers Comparative Performance Report –Pricing, 2011-12,
pp.14)
176
Australian Energy Market Commission Review of the Effectiveness of Competition in the
Electricity and Gas Retail Markets – Victoria - First Final Report (2008)
177 In October 2012 TRUenergy changed its name to EnergyAustralia.
178 Essential Services Commission Energy Retailers Comparative Performance Report –Pricing,
2011-12, pp.10
179 <http://www.yourchoice.vic.gov.au>
180 Essential Services Commission Energy Retailers Comparative Performance Report –Pricing,
2011-12, pp.10
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Figure 23: Gas annual standing offer charges 2007-2012 ($/year 2012)
(Source: Essential Services Commission, provided to the Victorian Government on 22 March 2013)
Ultimately the benefits of retail competition will be best realised if it is backed by robust
competition in the wholesale market, if reticulated gas is available wherever practicable, and
existing barriers to entry for retailers are reduced. The sections ahead examine some of the
impediments to these conditions.
Issues in the retail markets
Retail Prices
Gas prices are expected to rise for retail customers on the eastern market. The Grattan
Institute estimates that Victorian customers are likely to experience the largest price rises,
with the average annual bill increasing by around $170 by 2020.181 Recent modelling
commissioned by the Victorian Government estimates that, if all the LNG projects that are
currently under construction commence production and export as planned (base case), the
annual average residential gas bill in Victoria could increase by almost 20 per cent over the
period from 2013 to 2020; rising by $180 by 2020, after peaking in 2015 at 30 per cent
higher than current rates (Figure 24).182 The modelling also projected similar increases in
two other scenarios where it was assumed that LNG production in the eastern market
continues to expand (High LNG) or no more Queensland LNG projects, other than the 6 that
have currently reached committed status are commissioned (Low LNG).
181
Grattan Institute Getting gas right (June 2013) pp. 10
SKM MMA Gas and electricity market modelling. Final Report. Commissioned by Victorian
Department of State Development, Business and Innovation (2 September 2013)
182
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High LNG
Base Case
Low LNG
$28.00
$26.00
$24.00
$22.00
$20.00
$18.00
$16.00
Figure 24: Projected residential retail gas prices for Victoria ($/GJ, $2013 real)
(Source: SKM MMA Gas and electricity market modelling Final Report. Commissioned by Victorian Department
of State Development, Business and Innovation (2 September 2013))
National reform agenda
In the retail and distribution space, the national reform agenda has been focussed on
development and implementation of the National Energy Customer Framework (NECF). The
NECF provides for a robust regulatory framework for the electricity and gas retail sectors
and uniformity of approach across the various participating states and territories (only
Western Australia and the Northern Territory are not participating in the NECF).
The NECF largely replicates and elevates to a national level the regulatory matters currently
embodied in Victoria’s regulatory laws and codes. However, there are a number of procompetitive reforms bundled with the NECF, including:


a new, more robust, “retailer of last resort” framework to secure the market if a
retailer fails financially; and
reforms to requirements for the financial insurance that retailers are obliged to
provide to distribution pipeline businesses to achieve more equitable treatment of
large and small retailers that is more reflective of a retailer’s risk of default.
Victoria is committed to implementation of the NECF. However, issues in dispute between
the Commonwealth and Victoria in relation to the electricity sector have held up
implementation so far. The industry will be notified when the NECF is due to be implemented
in Victoria.
Rolling out more gas reticulation in regional Victoria
Customers cannot access any benefits from natural gas supply if they are not connected to
reticulated natural gas. While the Melbourne metropolitan area has been thoroughly
reticulated for some time, this is not the case for many regional towns and cities.
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The Victorian Government’s Energy for the Regions Program183 is investing $100 million to
expand natural gas to communities across regional and rural Victoria. Funded by the
Victorian Government’s $1 billion Regional Growth Fund, the Program will drive new
investment in regional communities through new industry and business opportunities.
The Program has three broad initiatives:



to fast-track the delivery of natural gas to an initial twelve towns including Avoca,
Lakes Entrance, Invermay, Winchelsea, Heathcote, Orbost, Warburton, Marong,
Bannockburn, Terang, Maldon and Huntly;
to invest in a major upgrade of Mildura’s natural gas supply capacity; and
to invest up to $1 million to fund a feasibility study into the provision of natural gas to
Victorian communities along the Murray River.
In addition to the initial twelve towns, the Government has made subsequent commitments
to deliver gas to Wandong-Heathcote Junction and Koo Wee Rup.
Regional Development Victoria (RDV) has adopted a staged approach. The first stage,
which involved direct negotiation with gas distribution businesses regarding the capture of
early opportunities, is now complete with agreement reached on two regional projects in
Mildura and Huntly. These projects are subject to regulatory approval and the execution of
development agreements.
Revised delivery strategy
Following a review of the direct negotiation process, which did not elicit a strong response
from the gas distribution businesses, the Minister for Regional and Rural Development
announced a broadened strategy to engage natural gas suppliers in both the conventional
pipeline and alternative delivery markets.
The new strategy involves three overlapping work streams:



offering a fixed subsidy or ‘bounty’ to gas distribution businesses for connecting all
remaining priority towns using conventional pipeline technology;
the design of a tender for development of a gas supply for regional Victoria using
compressed natural gas (CNG) or LNG facilities; and
the facilitation and establishment of local reticulation networks in priority and additional
towns, where gas distributors are not willing to deliver gas to these communities via
a traditional trunk pipeline.
The first component of the broadened strategy involves offering gas distributors a fixed
subsidy ‘bounty’ amount to supply the remaining priority towns. The ‘bounty’ offer was made
to distributors on 29 August 2012 and closed on 14 December 2012.
Consistent with the second and third components of the revised strategy, on 7 November
2012, RDV released an invitation for Expressions of Interest for the development and
operation of a delivered natural gas capacity for regional Victoria using CNG/LNG, or other
alternative delivery solutions. The proposal to decant and transport CNG/LNG to the
183
Regional Development Victoria <http://www.rdv.vic.gov.au/infrastructure-programs/energy-forthe-regions> (Accessed September 2013)
Page | 91
outskirts of regional towns provides an opportunity to work with the energy industry to
achieve broader energy security for regional Victoria, while also providing consumers a
product with a comparable price and convenience to conventional pipeline gas.
In September 2013 the Government also announced an additional $30 million to supply
natural gas to Murray river communities. This funding is comprised of $15 million from
Commonwealth’s Murray-Darling Basin Regional Economic Diversification Program and an
additional $15 million from the Regional Growth Fund.
Practical barriers to gas extensions
Barriers faced by the Energy for the Regions program are reflective of practical issues
associated with extending natural gas reticulation. It is believed that this issue is not relevant
to new growth areas. Rather, it relates only to the ‘retrofitting’ of reticulated natural gas
networks to settled areas, where households currently rely on other fuels for space and/or
hot water heating purposes – most likely (bottled) LPG, diesel fuel or electricity.
The Victorian Government believes the key influences are:







Gas distribution businesses regard the revenue risks from gas extension projects as
extremely high. That is, they believe that after pipelines have been laid throughout a
given area, the rate and timeframe for customers seeking to convert their premises and
appliances (at significant cost and inconvenience) to natural gas is highly uncertain.
Where extension areas are distant from the existing network, customer density is
typically lower; leading to higher unit costs for distributors.
Whilst there is an obligation on gas distributors to offer to connect new customers who
reside less than one kilometre from the existing network, there is no regulatory
requirement for gas distributors to respond in a similar manner to more substantial
network extension proposals. Distributors are therefore inclined to prioritise their capital
expenditure budgets toward programs designed to meet statutory reliability, safety and
connection performance targets for their existing networks (rather than invest in broader
extension projects).
The gas industry regulator is unable to allow cost recovery for projects that are not
economically efficient; thereby reducing the prospect of gas extension proposals
involving gas costs that exceed those of an alternative fuel. Nor is the regulator able to
approve cost recovery regimes that involve clear cross-subsidies by other users.
Substantial capital injections are therefore typically necessary from
Governments/consumers to enable most gas extension proposals to progress.
Given the Government’s policy and legislative framework for retail competition in the
energy sector, it is unlikely that any given gas retailer will underwrite a distributor’s
investment in any given gas extension project.
Increasing gas prices could erode the potential cost benefit of using gas compared with
other fuels.
The energy efficiency of electrical appliances, together with the affordability of solar
panels, is improving significantly. The continuing cost attractiveness of gas heating
appliances cannot therefore be assumed.
Pioneer customer problems
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In addition to the barriers to regional gas roll-outs, there are some extant difficulties with
extensions of gas reticulation in areas near to existing networks. A particular issue is that of
‘pioneer customers’ who wish to have gas in an area or street without existing reticulation.
These customers face a large bill to have gas extended to them, although there may be
other customers in their area who could share the bill. The problem is a first-mover
disadvantage, as other customers may join on the network after the ‘pioneer’ has paid for its
extension, effectively free riding.
In the electricity sector, there are some provisions for pioneer customers to be rebated part
of the cost of the extension if other customers subsequently connect. Though this does not
reduce the up-front bill, it does moderate the first-mover disadvantage. There are understood
to be regulatory impediments to implementing such a scheme in the gas sector, such as the
inability of distributors to charge in such a way as to fund reimbursements from future
customers.
Access to reticulated gas networks for business consumers
The Taskforce has also heard from some gas customers who have apparently had difficulty
in negotiating with the Victorian gas transmission and distribution owners for access to
related services, such as connection or upgrading of pipeline assets. Chapter 6 of the
National Gas Law provides for a comprehensive access dispute resolution and
determination framework, overseen by the AER, which is intended to ensure that where
customers experience difficulty in getting access to regulated monopoly services (as the
Victorian transmission and distribution systems are), the independent regulator may resolve
them. It is understood that this is an onerous process, however, and few disputes get as far
as the commencement of a formal access dispute proceeding. The AER needs to be well
resourced to ensure that, where connecting customers are required to negotiate with
monopoly businesses for services, that the imbalance in bargaining power inherent in this
situation can be remedied where necessary.
The Victorian Government has had ongoing concerns with the resourcing of the AER, and
made a point of this when discussing electricity market reforms at the Council of Australian
Governments in December 2012. COAG agreed to provide the AER with more funding from
2013, and to a further review of the governance and performance of the AER in 2014. The
Victorian Government should ensure that the effective operation of the access dispute
framework is considered in this review.
Opportunities to address eastern market challenges
Overall, the retail and distribution part of the gas system in Victoria works well and is
efficient. Although retail gas prices have increased over the past five years, competition in
gas retailing in Victoria remains the most effective in Australia. In terms of the national
reform agenda, the implementation of the NECF reforms would continue a robust regulatory
framework and provide uniformity across jurisdictions.
In the context of the Taskforce’s work, the retail and distribution issues outlined above are
unlikely to have a significant impact on operation of the market as a whole, or on addressing
the sorts of access issues the Taskforce is considering.
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There are customers at the margins who are effected by the inability to gain access to
natural gas reticulation or offers of gas at competitive prices. While governments may wish
to readdress this issue, this will not address the overarching challenges faced by the eastern
market, in the form of rising gas prices and a potential shortfall during the transition period.
Retail consumers will in due course be affected by the increasing wholesale price of gas.
Page | 94
Chapter 6: Case studies on overseas market
development
About Chapter 6
Natural gas has traditionally only been transported through pipelines and pressurised
storage. This has placed a limitation on the distance over which gas can be transported, and
led to gas being traded only within contained production and distribution systems, often
nationally bound. Each system, or market, developed in relative isolation and evolved under
different geographic, economic and regulatory conditions. Each market developed to supply
particular cities or industrial areas. Chapter 6 looks at some prominent examples of how gas
markets around the world have developed, and considers the circumstances that allowed
this to occur.
The Taskforce undertook a desktop review of markets in North America, the United Kingdom
and parts of continental Europe. The eastern gas market has significantly less liquidity than
these markets. Experience in these regions has shown that although commercial
imperatives and market forces have played an important part in driving the development of
liquid markets, none of the markets examined have developed without some action by
government.
In both North America and Europe, governments have passed strong measures to open up
transmission pipelines to third party access. In the United Kingdom, the government has
gone further to implement wide ranging market development policies; including the
development of auction-based pipeline capacity allocation mechanisms that enable gas
shippers to secure capacity on a short and long term basis, accompanied by anti-hoarding
mechanisms and strong incentive arrangements on pipeline operators to maximise the
release of available capacity. The Taskforce considers Victoria and eastern market
governments should draw on experience from gas markets in other countries.
Early history of gas trading
Natural gas was initially a by-product of crude oil production and was often flared off by oil
producers. By the mid-20th century, it was recognised as a cheap and less polluting energy
source, and began to be harnessed for domestic and industrial use by establishing new
pipelines from oil and gas fields to cities, but no significant trade occurred. As gas remained
a by-product of oil production, long-term gas contract prices were often linked to the oil price.
In the 1960s and 1970s, the manifest benefits of natural gas as a fuel led to substantially
increasing demand for natural gas as an industrial commodity. Gas transmission systems
grew larger and interconnections were made between them, facilitating more trade.
However, this was still limited by the prohibitive cost of long distance transport.
The first journey of the Methane Princess carrying LNG to the UK from Algeria in 1964
pointed to a way that natural gas could in future be traded over longer distances. However,
this remained rare and no significant trade occurred between isolated markets. Towards the
end of the 20th century, demand and the price of gas increased such that developing natural
gas fields, where there was little or no oil, became economically viable.
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Gas as a traded commodity
In the industrialised world, gas markets consisted of a number of pressurised systems that
operated as isolated markets but were becoming increasingly interconnected. These
systems were underpinned by investment from founding customers under long term
contracts. However, other customers were increasingly seeking gas, under more diverse
conditions.
The larger, more interconnected markets also tended to have a greater number of producers
and, by the 1980s, there was more trade between markets of gas in the form of LNG. These
developments created the potential for a competitive trade in natural gas within and between
separate gas systems.
No single market for natural gas emerged. Instead, markets developed, which served
particular cities, or clusters of cities, but were not physically connected to each other by
pipeline. As a result, there is no single global price for gas and many large LNG contracts
are price indexed against the price of oil.
Within the gas transmission systems in the major demand regions of the world, such as
major cities or industrial regions, gas markets developed during the 1990s and 2000s, and
many regions have reached or are evolving toward a liquid market in gas where long term
contracts are priced competitively and are supplemented by short term trading options that
allow more efficient outcomes.
Case Studies
United Kingdom
In United Kingdom in the 1950s, preexisting town gas networks with
diverse ownership were combined by
the national government to form a
national gas agency in order to
rationalise the sector and achieve
economies of scale. The discovery of
gas in the North Sea and increasing
concerns about air pollution in the
cities in the 1960s, led to a national
policy of natural gas substitution for
town gas. This substitution was
completed by the end of the decade.
To facilitate this, a large country-wide
system of trunk transmission lines was
constructed to link the North Sea with
London and other centres of demand
(Figure 25).
The system was then privatised under
the Thatcher Government in the
Figure 25: British gas transmission system
(Source: National Grid, About the Gas Industry)
<http://www.nationalgrid.com/uk/Gas/About/How+Gas+is+Delivered/>
Page | 96
(Accessed on 11 October 2013)
1980s, as British Gas. In the 1990s, contestability for large customers was introduced,
allowing customers to choose their supplier. This necessitated the facilitation of third party
access to the system on reasonable terms. Full retail contestability was introduced in the late
1990s and, to support this, a sophisticated balancing market was established to allow trading
of gas across the system while enabling the system operator - National Grid - to keep it
balanced despite variable demand.
The United Kingdom system adopts a National Balancing Point - a virtual point in the system
whose price is set so as to balance the system as a whole. This balancing point provides a
whole of system spot price, relative to which other locational prices are set. As all gas is
traded through the integrated transmission system, this price reflects a physical market
encompassing all gas trade and is thus highly liquid. The transparency over the price of gas
in the system at any given time has thus facilitated a high degree of financial trading of
derivatives to allow participants to manage price risk in the system.
Further arrangements were put in place to facilitate effective trade, not just at the National
Balancing Point but also at entry and exit points in the system. Standardised contracts for
gas and gas carriage are in place and equitably available. Capacity auctions are held to
ensure pipeline capacity is allocated to those most willing to pay. An end-user retail market
facilitates the switching of meters between suppliers in off take distribution systems. A highly
developed information portal gives market participants detailed real time information on
system capacity and flows, to aid informed trading.184
United States and Canada
The North American market for gas draws on the continent’s past as a major oil producer,
which provided the basis for harnessing natural gas. There has not been prevalent public
ownership of natural gas infrastructure, but there is a strong history of monopoly regulation
arising from antitrust actions in the oil industry and the New Deal185 reforms in the earlier
20th century.
Gas pipeline systems developed largely as integrated sale and supply utilities. However, the
Federal Energy Regulatory Commission (FERC) passed a series of orders from the 1970s
aimed at opening up the sector, which had become highly interconnected, to competition
and trade. Order 436 in 1985 established open access to transmission pipelines as a
regulatory requirement. This was followed by Order 636 in 1992, which required natural gas
pipeline owners to become transportation companies only.
Pipeline regulation in the US in particular facilitated transparency and competition by moving
the market away from vertical integration and away from long term contracts.186
The gas utility sector in North America remains highly diverse. Distribution and sale of
energy is regulated at the state or provincial level in the federations of the USA and Canada
184
<https://www.gov.uk/oil-and-gas-uk-oil-portal> (Member log-in required for access)
The New Deal was a series of domestic economic programs implemented in the US between 1933
and 1936 in response to the Great Depression to provide relief for the poor and unemployed, support
economic recovery and reform the financial system to prevent a repeat depression.
186 Energy Australia Global Gas Market Reform: Implications for Gas Market Development in
Australia, June 2013, pp. 12
185
Page | 97
respectively, and there are over 1200 gas distribution utilities. Furthermore, the ownership of
gas transmission infrastructure is massively diverse, with 160 different pipeline owning
companies in the US.187
Gas trading in North America is facilitated by a well-developed financial overlay, centred on
the Henry Hub in Louisiana. The Henry Hub was chosen by the New York Mercantile
Exchange (NYMEX) in 1990 as the delivery point for natural gas futures contracts. Since that
time it has cemented itself as the most liquid market for gas trading in the world, with about
400,000 natural gas futures contracts traded there every day.188 The price of gas at Henry
Hub effectively sets the continental price of gas and strongly affects the price at other
markets, which will tend to trade at a difference to the Henry Hub price reflecting the cost of
transport.
The Henry Hub itself is a physical facility in Louisiana, which was once a natural gas
processing plant. Due to its convenient location, a number of pipelines had connected to it to
draw gas for their customers, but its volumes were declining in the 1980s, creating spare
capacity in its system. The centrality of the facility to existing pipelines and its spare capacity
marked it out as a suitable pricing point, as there was relative certainty that gas traded at
that point would be deliverable.
The Henry Hub’s selection by NYMEX made it the default pricing point for natural gas traded
throughout the interconnected pipelines of North America. Its role is supplemented by
dozens of other trading hubs, which provide opportunities for traders and shippers to
optimise their trading closer to their points of supply or delivery. These are shown in Figure
26 below. Like the Henry Hub, these are largely the product of the initiatives of facility
owners who perceive value can be created by facilitating trade through their hubs.
187
Natural Gas Industry and market structure <http://www.naturalgas.org/business/industry.asp>
(Accessed on 18 March 2013)
188 RBN Energy Understanding Henry Hub <http://www.rbnenergy.com/henry-the-hub-i-am-i-amunderstanding-henry-hub> (Accessed on 18 March 2013)
Page | 98
Figure 26: Gas hubs and flows in the US and Canada
(Source: US Energy Information Administration About US Natural Gas Pipelines)189
Trading in Henry Hub natural gas futures is simple and NYMEX standardised contracts apply
through the electronic trading platform. Actual delivery of gas from point to point throughout
the continent, however, is not necessarily standardised. Arrangements for trading gas may
differ at each hub and arranging for carriage separately may be necessary. While futures
trading is usually ‘netted off’ and actual delivery at Henry Hub is almost never taken, physical
delivery may require agreements with several different parties.
The highly liquid commodity market provides for a transparent continent-wide price for
natural gas, which has helped provide appropriate price signals for the development of new
gas sources during the price hikes of the mid-2000s, such as the development of shale gas
resources.
Continental Europe
The natural gas market in Europe, whose transmission network is shown in Figure 27, is
highly diversified and strongly interconnected.
189<http://www.eia.gov/pub/oil_gas/natural_gas/analysis_publications/ngpipeline/ngpipeline_maps.htm
l> (Accessed on 18 March 2013)
Page | 99
Figure 27: Gas transmission in Europe
(Source: Eurogas The European Natural Gas Grid in 2010) 190
The history of the gas utility sector in Europe differs from country to country, but there is a
history of state ownership or large integrated monopolies. There are fewer supplies than in
North America, with the main suppliers currently being the North Sea suppliers, including
190<http://blog.eurogas.org/en/2010/09/the-european-natural-gas-grid-in-2010/>
(Accessed on 18
March 2013)
Page | 100
Norwegian StatOil, Algeria and Russian supplies through Gazprom. Increasingly, these are
supplemented by LNG shipments from the Middle East, especially Qatar.
Major gas utilities, such as those in Germany, import gas (from Russia especially) under
long term contracts, over 85 per cent of which have take-or-pay conditions. These contracts
are generally linked to oil prices. This link makes it more difficult to make decisions based on
supply and demand conditions of gas by introducing changes associated with oil markets.
The presence of these oil linked imports therefore exerts a confounding effect on the pricing
of gas as a commodity in its own right in central and western Europe.
The European Union (EU) has attempted to stimulate development of a single European
market for natural gas in much the same way as the FERC in the US. Successive EU
directives in 1998, 2003 and 2009 have imposed increasing requirements for third party
access and the contestability of customers.191
As in North America, a number of trading hubs or markets were established through the
2000s taking advantage of the newfound ability for third parties to trade gas through the gas
transmission systems. Unlike North America, however, no single trading hub has become
dominant so as to provide a continental commodity price for gas. This is despite of the EU’s
success in developing liquidity in trades (Figure 28).
In part, this is due to the continuation of different industry structures, processes and
practices in the various member states. However, the continuing existence of large oil pricelinked import contracts is likely to be just as significant.192
Figure 28: Trade volumes at European hubs
191
Stephen Thomas The European Union Gas and Electricity Directives
<http://gala.gre.ac.uk/3629/1/PSIRU_9600_-_2005-10-E-EUDirective.pdf> (Accessed on 18 March
2013)
192 J Stern and H Rogers The Transition to Hub-based Gas Pricing in Continental Europe
<http://www.oxfordenergy.org/wpcms/wp-content/uploads/2011/03/NG49.pdf> (Accessed on 18
March 2013)
Page | 101
The first major trading hub to be established was the Belgian Zeebrugge hub in 2000. This
was formed by a commercial initiative between service providers at the port of Zeebrugge (to
which two major continental pipelines run, as well as the UK interconnector) and an LNG
import terminal. Other hubs have been established in France, the Netherlands and
Germany. These exhibit different designs and principles with a mixture of physical and virtual
trading hubs.
Summary of approaches to transmission access regulation
The US has created uniform creation transportation entitlements that may be traded by
participants, through FERC orders.
The universality of these transportation arrangements allow utilities and other parties to trade
in gas without fear of contractual congestion or hoarding of capacity by regional incumbents,
or discrimination by pipeline owners. The contractual entitlements are supported by
transparency over the accounting practices of pipelines, which facilitates efficient pricing and
investment in those pipelines. Makholm notes:
“In that market, gas pipelines own and operate the price-regulated facilities that
support those entitlements to transport gas, but they do not own or control the
entitlements themselves, nor do they possess any operational or financial information
that is not an open book to those who would buy or sell those entitlements.”193
The critical Orders which support this highly successful regime for access are:

Order 436 (1985) which requires pipelines offering transportation services to offer
those services on a non-discriminatory basis; and

Order 636 (1992) which requires pipelines to fully unbundle gas sales from
transportation services, allows the offering of unbundled services at market based
rates under sales certificates issued by the FERC, establishes a suite of firm and
interruptible services, and establishes mechanisms to free up available capacity to
the market.194
Similarly, the European Union, in which multiple contract carriage pipeline operators are
present, has adopted key principles associated with the regulation of access to transmission
capacity. An example of this is Regulation 715/2009195 of the European Parliament on gas
transmission access.
This regulation has potential relevance to Australia, given the existence of fragmented
European pipeline ownership and access arrangements, and difficulties experienced by gas
193
Jeff D Makholm The Political Economy of Pipelines: A Century of Comparative Institutional
Development. University of Chicago Press pp. 140 (April 2012)
194 Federal Energy Regulatory Commission Order 636 <http://www.ferc.gov/legal/maj-ord-reg.asp>
(Accessed 11 October 2013)
195 Official Journal of the European Union Regulation (EC) No 715/2009 of the European
Parliament and of the Council of 13 July 2009 on conditions for access to the natural gas transmission
networks and repealing Regulation (EC) No 1775/2005
<http://eur-lex.europa.eu/LexUriServ/LexUriServ.do?uri=OJ:L:2009:211:0036:0054:en:PDF>
(Accessed 11 October 2013)
Page | 102
shippers in transporting gas from region to region. The regulation aims to establish nondiscriminatory rules for pipeline access to cross border transmission systems within Europe
in order to facilitate the development of a well-functioning and transparent wholesale market.
Some of the key elements of this regulation include:

the establishment of network code arrangements that provide for effective and
transparent transmission access arrangements;

network codes supported by robust governance and code change arrangements;

pipeline operators to ensure that services are offered on a non-discriminatory basis to all
network users – where the same service is provided to different customers it shall be
provided under equivalent contractual terms and conditions;

pipeline operators to provide both firm and interruptible services, and to offer users both
long and short-term services;

tariffs should be cost reflective and applied in a non-discriminatory manner;

pipeline operators shall implement and publish non-discriminatory and transparent
pipeline capacity allocation and congestion management mechanisms;

capacity allocation mechanisms shall provide economic signals for efficient and
maximum use of technical pipeline capacity and which facilitate investment in new
pipeline infrastructure;

network users should be free to re-sell unused contractual capacity on the market;

in the event of contractual congestion, the pipeline operator shall offer unused capacity
at least on a day ahead and interruptible basis;

pipeline operators shall make public detailed information regarding the services they
offer and the relevant conditions applied;

pipeline operators shall publish information on technical, contracted and available
pipeline capacities for all relevant points including entry and exit points on a regular and
rolling basis and in a user friendly manner;

pipeline operators shall publish ex-ante and ex-post supply and demand information
based on nominations, forecasts and realised flows in and out of the pipeline system;
and

pipeline operators should publish sufficiently detailed information on their tariff derivation,
methodology and structure.
Lessons learnt from overseas markets
Case studies from other countries demonstrate several common characteristics in the
development of natural gas commodity markets. It is clear that the eastern gas market has
significantly less liquidity than markets in other countries such as the US, the UK and parts
of continental Europe.
Page | 103
Experience in these regions has shown that although commercial imperatives and market
forces have played an important part in driving the development of liquid markets, none of
the markets examined has developed without some action by government. In both North
America and Europe, governments have passed strong measures to open up transmission
pipelines to third party access. In the UK, the government has gone further, to implement
wide-ranging market development policies; including the development of auction-based
pipeline capacity allocation mechanisms that enable gas shippers to secure capacity on a
short and long term basis, accompanied by anti-hoarding mechanisms and strong incentive
arrangements on pipeline operators to maximise the release of available capacity.
It has been observed that financial liquidity is also affected by physical capacity. The
development of Henry Hub as the world’s foremost financial market for gas was predicated
on the existence of a very well connected physical facility in a convenient location, with
enough spare capacity to ensure the deliverability of gas to traders. This has implications for
the prospects of an eastern market gas hub, as spare capacity is understood to be relatively
rare in Queensland’s growth regions.
The development of markets with fully integrated transportation and trading systems (such
as the UK market and the Victorian DWGM) appears to have happened most easily where
there is a history of state ownership and subsequent privatisation. While it is possible for
such an outcome to eventuate in a system with multiple private owners, imposing such
arrangements may require interference with private property.
Finally, the development of transparent gas commodity pricing can be distorted by other
price signals arising from historical oil-linked contract prices.196 As large LNG contracts are
often negotiated on this basis, this has implications for the prospects of gas commodity
pricing in the eastern market as it now exposed to price signals from an immensely larger
LNG export industry. Pricing and trading of gas in its own right may be beneficial. However,
so long as the oil-linkage remains, a transparent commodity market in gas may never
develop. Conversely, there may be other benefits to trading for the purposes of balancing or
optimising portfolios, as the growth in traded volumes in Europe shows.
Relevance for Victorian wholesale market
The current Victorian gas market is most analogous to that of the UK. For example, in both
regions, post-war nationalisation led to the integration of the gas transmission system under
a single owner, which optimised the system for balancing of gas supply and demand
throughout, rather than for point-to-point flows. Nationalisation was followed by privatisation,
and regulatory arrangements were put in place that allowed the government to require the
development of an integrated wholesale spot market with market carriage over the
transmission system.
Victoria differs from the UK, in that the UK spot market was successful in stimulating
commodity trading of gas, and the development of effective pipeline capacity auction and
trading mechanisms. This has generally not occurred in Victoria. Gas is predominantly sold
to retailers under bilateral contracts and only bid into the market by those retailers. Hence,
the Victorian market is used as a balancing market only. In recognition of the potential for the
196
Jonathan Stern and Howard Rogers The transition to hub-based gas pricing in continental
Europe Technical Report NG 49, Oxford Institute for Energy Studies (March 2011)
Page | 104
Victorian market to emulate the UK National Balancing Point, the Australian Stock Exchange
listed Victorian gas futures in 2009. However, to date there has been little trade in these
futures. This is likely to be because all participants are effectively managing wholesale price
risk by buying wholesale gas straight from upstream producers, and then selling it to
themselves through the DWGM. Further, the Taskforce heard from some stakeholders that
the DWGM spot price cannot be adequately hedged by futures products because of charges
for other ancillary services.
Relevance to the eastern gas market
Overseas experience points to two possible scenarios for the future development of the
eastern gas market, depending on government and industry decisions and exogenous
factors.
In the first, a liquid market for gas as a commodity might develop in the eastern market,
spurred by increases in both the scale and diversity of production, and the increasing
interconnectedness of the gas network. Entrepreneurial traders would then be able to
establish financial products to manage risk in this market and provide further liquidity. This
would be similar to the North American scenario.
Alternatively, heterogeneity of the various state markets could continue while the effect of oillinked LNG prices, accounting for a large proportion of gas production, continues to make a
national gas price moot. This would be akin to the European scenario. Nevertheless
development of effective balancing markets and initiatives to allow gas to move as freely as
possible between the different markets would still be beneficial.
Page | 105
Appendix 1: List of stakeholders consulted by the Chair
Over the period January to October 2013, the Chair of the Taskforce met with
representatives of more than 50 organisations and participated in a number of public
meetings and workshops. These are listed below:
Upstream and downstream firms
AGL
Amcor
APA Group
Australian Paper
Bechtel (Gladstone)
Brickworks
Coogee Chemicals
Dow Chemicals
Energy Australia
Energy Power Systems Australia
Epic Energy
Exxon Mobil
GDF SUEZ
Ignite Energy
Incitec Pivot Limited
Jemena
Lakes Oil
Orica
Origin Energy
Qenos
Santos GLNG (Gladstone)
Page | 106
Government agencies and industry regulators
Australian Energy Market Commission (AEMC)
Australian Energy Market Operator (AEMO)
Australian Energy Regulator (AER)
Bureau of Resources and Energy Economics (BREE)
Victorian Earth Resources Advisory Council
Energy Safe Victoria
Geoscience Australia
Queensland Department of State Development, Infrastructure and Planning
(Gladstone)
Department of Resources, Energy, and Tourism (Commonwealth)
Victorian Departments:

Premier and Cabinet

Treasury and Finance

State Development, Business and Innovation

Environment and Primary Industries
Regional Development Victoria
Productivity Commission
Independent experts and consultants
Grattan Institute
Independent Expert Scientific Committee on CSG
ACIL Tasman
Gas Fields Commission (Queensland)
Port Jackson Partners
Industry Associations
Australian Industry Group (AIG)
Page | 107
Energy Supply Association
Manufacturing Australia
Mineral Resources Council (Victoria)
Victorian Farmers Federation
Ministers and Shadow Ministers
New South Wales Minister for Energy and Resources
Victorian Minister for Energy and Resources
Victorian Deputy Premier and Minister for State Development
Victorian Premier
Victorian Treasurer
Queensland Deputy Premier
Queensland Minister for Energy and Resources
New South Wales Shadow Minister Energy and Resources
Shadow Minister for Climate Action, Environment and Heritage (Commonwealth)
Shadow Minister for Energy and Resources (Commonwealth)
Workshops, roundtables and public meetings
CSG forum Mirboo North
KPMG/Grattan Institute - Roundtable discussion of the Grattan Institute report on
Australia’s domestic gas market
APPEA conference, including panel member of plenary session “Developing
Onshore Gas Resources”
Forum on CSG, Centre for Regional and Rural Futures (CeRRF), Deakin
University, Melbourne, Tuesday 8 October 2013
Gladstone visit (see meetings listed above)
Page | 108
Appendix 2: National reform agenda and other reviews
The Standing Council on Energy and Resources (SCER) is responsible for progressing a
national reform agenda for the eastern gas market. This section provides an overview of this
agenda, which has been endorsed by the Council of Australian Governments (COAG).
Brief history of reforms
The reforms of the gas industry have proceeded in a number of stages since the 1990s:







1996 – National competition policy and the Gas Access Code establish third party
access;
1998 – Victoria’s gas industry privatisation and the establishment of the DWGM;
2002 – COAG Energy Market Review197 analyses the state of the gas market and
observes inefficiencies in gas transmission and trading arrangements;
2004 – Signing of the AEMA and beginning of reform of the regulatory arrangements
to integrate with the national energy market institutions;
2005 – Gas Market Leaders Group is established by the Ministerial Council on
Energy and works to develop actions to address market issues, leading to the
establishment of the STTMs and the gas market bulletin board;
2008 – Establishment of the National Gas Law, replacing the Gas Access Code
based arrangements; and
2012 – SCER agrees to new round of gas market development reforms, including the
establishment of the Wallumbilla hub.
2012 SCER reform agenda
In December 2102, SCER, recognising the significant challenges facing the gas industry in
the face of LNG developments in Queensland and uncertainty over future price movements,
agreed to further actions to improve the operation of the gas market. As part of its Gas
Market Development Plan, SCER agreed to the principles of:


ensuring that supply responds flexibly to demand; and
promoting market development.
The actions agreed by SCER include:







undertaking pre-competitive geoscience work;
offshore petroleum exploration acreage release;
development of a Multiple Land Use Framework;
development of a National Harmonised Regulatory Framework for CSG;
improving availability of data on gas exploration and development activity;
development of Gas Supply Hubs;
work on facilitating Pipeline Capacity Trading;
197
Council of Australian Governments COAG energy market review, December 2002
<http://www.ret.gov.au/Documents/mce/_documents/FinalReport20December200220050602124631.
pdf>
Page | 109






further development of the Short Term Trading Market;
enhancements to the AEMO Gas Statement of Opportunities;
medium term capacity outlook and possible refinements to the Gas Bulletin Board;
analysis of links between LNG and domestic gas markets;
development of a forward price for gas; and
closer industry and community engagement.
A more detailed summary of the Gas Market Development Plan is shown in Figure 29 below.
Regulatory impact statement – pipeline capacity
Whilst the development of the Wallumbilla hub is well underway, there is a recognition by
SCER that its effective operation may be hampered if pipeline capacity to and from the hub
is not readily accessible by trading participants. To this end, a consultation regulatory impact
statement (RIS) has been released by the Commonwealth Department of Resources,
Energy and Tourism. This RIS examines several options for improving the accessibility of
pipeline capacity, including:




the status quo / counterfactual;
improvements to information provision about pipeline capacity;
establishment of a trading platform for pipeline capacity with voluntary participation
by pipeliners and traders; and
establishment of a trading platform for pipeline capacity with compulsory participation
by pipeliners and traders.
The pipeline capacity RIS is expected to report to SCER in December 2013.
Other reviews and inquiries
AEMC scoping review
The Australian Energy Market Commission (AEMC) is the body charged with providing
strategic market development advice to SCER on both gas and electricity matters. As part of
this function, the AEMC has undertaken a scoping review of gas markets to see how the
regulatory arrangements for markets under the National Gas Law could be improved to the
long term benefit of consumers. The report was released on 27 September 2013, and
provides an overview of the changes in the east coast gas market and identifies areas of
potential improvement in the market and regulatory arrangements.198 The study found that a
strategic plan is needed to assist the industry in developing a mature and well-functioning
market.
198
Australian Energy Market Commission Gas market scoping study
<http://www.aemc.gov.au/market-reviews/completed/gas-market-scoping-study.html> (27 September
2013)
Page | 110
Figure 29: Gas Market Development Plan. (Source: http://www.scer.gov.au/workstreams/energy-market-reform/gas-market-development/)
Page | 111
New South Wales parliamentary inquiry
The New South Wales Legislative Assembly Committee on State and Regional Development
has been undertaking a review into the downstream gas supply industry, with a view to
ascertaining whether it is adequate, and likely to receive adequate investment in the years
ahead, to meet New South Wales demand. As in Victoria, the New South Wales
Government has a focus on expanding access to natural gas as widely as possible. The
Committee’s terms of reference199 reflect this.
New South Wales Chief Scientist review
Professor Mary O’Kane, the New South Wales Chief Scientist and Engineer, is conducting a
comprehensive review of CSG-related activities, focusing on the environmental and humanhealth impacts. Following public consultation, she released an interim report in July 2013200.
BREE/DRET domestic gas market study
On 27 May 2013, the Commonwealth Minister for Resources and Energy announced that
the Australian Government would undertake a new, comprehensive analysis of the domestic
gas market outlook. The Domestic Gas Market Study is a joint DRET-BREE study that will
inform the policy-makers of the gas demand-supply situation and help identify potential
supply constraints. It will also inform the gas market development work being undertaken
with states and territories through the SCER. The study was expected to be completed by
the end of 2013.
Commonwealth policy platform 2013
The Coalition Government’s 2013 election policy includes commitments to “set in place a
workable gas supply strategy for the East Coast gas market to the year 2020” 201. The policy
also committed to AEMO provide “up-to-date and accurate information regarding gas
consumption in the east coast gas market” and, through SCER, put in place “mechanisms to
provide greater transparency of gas trades, gas pricing and supply”. Also relevant are
commitments to cut red tape costs in Australian businesses, including in the energy and
resources sector, and deliver a “one-stop-shop” for environmental approvals. Implementation
of this policy has been reported as a high priority for the Abbott Coalition Government202,
recently elected in September 2013.
199
Downstream gas supply and availability in New South Wales (Inquiry Terms of Reference)
<https://www.parliament.nsw.gov.au/prod/parlment/committee.nsf/0/FCDC7EAF8B2C87F6CA257B43
00755E93> (Accessed on 11 October 2013)
200 New South Wales Government Chief Scientist and Engineer Initial report on the Independent
Review of Coal Seam Gas Activities in New South Wales. July 2013
<www.chiefscientist.nsw.gov.au/coal-seam-gas-review/>
201 The Coalition’s Policy for Resources and Energy
<http://www.nationals.org.au/Portals/0/00_Election_00/Coalition%202013%20Election%20Policy%20
%E2%80%93%20Energy%20and%20Resources%20%E2%80%93%20Final.pdf.> (Accessed on 26
September 2013)
202 Graham Lloyd, The Australian, Environment Editor (18 May 2013)
Page | 112
Appendix 3: Gas resources information - further details
Eastern market gas resources
Table 4: Eastern market produced and remaining gas resources (significant basins)
Produced
PJ
% of
eastern
market
produced
Remaining
resources
PJ
% of
eastern
market
remaining
resources
8,791
48
9,300
19
Otway
726
4
1,600
3
Bass
79
0
800
2
9,596
52
11,700
24
Sydney (CSG)
30
0
287
1
Gunnedah (CSG)
0
0
1,520
3
Gloucester (CSG)
0
0
669
1
Clarence-Morton (CSG)
0
0
428
1
New South Wales total (CSG)
30
0
2,904
6
6,791
37
1,200
2
Surat/Bowen
1,001
5
550
1
Surat/Bowen (CSG)
1,002
6
33,001
67
QLD total
2,003
11
33,551
68
Eastern market conventional
total
17,399
Eastern market CSG total
1,032
Basin
Victoria
Gippsland
VIC total
New South Wales
South Australia
Cooper/Eromanga
Queensland
94
6
13,650
35,905
27
73
(Source: Australian Gas Resource Assessment 2012)
Notes: Conventional gas unless indicated as CSG
Remaining resources are GA reserves and contingent resources for conventional gas and 2P estimates
for CSG
Percentages are rounded
Bass Basin and parts of Otway Basin are in Tasmania but gas is produced through Victorian facilities
For comparison, AEMO (2012) has total 2P reserves of 48,497PJ of which 15% (7,275PJ) is
conventional and 85% (41,222PJ) is CSG
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Victorian gas resources
Conventional gas resources
The Gippsland Basin is a large basin on the southeast margin of Australia's continental
shelf (offshore Victoria) largely lying in Commonwealth waters. The Gippsland Basin is one
of Australia's most prolific and mature petroleum provinces. The detail of the oil and gas
fields in Gippsland Basin is illustrated in Figure 30.
The largest resource base and production capacity within the Gippsland Basin is operated
under a joint venture, with 50/50 interests held by BHP Billiton and Exxon Mobil. A smaller
producing resource is the Longtom field which is owned by Nexus Energy. There are
currently various exploration projects in the region.
Figure 30:Location map showing details of Gippsland oil and gas fields
(Source: Department of State Development, Business and Innovation)
The Otway Basin is a large, northwest trending basin on the southern Australian continental
margin (Figure 31). Three primary offshore production fields account for all existing
resources and production capacity:

Otway Gas Project (also known as Thylacine Geographe) - operated by Origin;

Casino (including Henry and Netherby) - operated by Santos; and
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
Minerva - operated by BHP.
There are various exploration projects in the region, both onshore and offshore.
Figure 31:Location map showing details of producing fields in the Otway Basin
(Source: Department of State Development, Business and Innovation)
The Bass Basin is a northwest-trending basin located mainly on the continental shelf in
Bass Strait, between the Australian mainland and Tasmania. The only producing reserves in
the Basin are in the Yolla field, which is also known as the BassGas project and is operated
by Origin. Various exploration projects are being conducted in the region.
Onshore gas storage
Gas is also stored underground within the now depleted onshore Otway Basin’s Iona field,
near Port Campbell (Figure 32). Gas from this storage facility is redistributed into the gas
network when market conditions are suitable and contributes to the State’s overall gas
supply capacity during periods of high demand.
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Figure 32: Location map showing details of onshore depleted gas fields around Port Campbell
(Source: Department of State Development, Business and Innovation)
Assumptions: How long will Victoria’s existing conventional gas
resources last?
Companies regard the detailed information required to calculate depletion of gas resources
as commercial-in-confidence. Nevertheless, how long gas supply will last is sometimes
estimated as a ratio of known reserves to demand, noting that this approach provides only a
notional indication, because gas does not fully deplete in a given year. Rather, supply will
gradually decline as individual fields become unprofitable.
Table 5 summarises the results of two demand scenarios and two reserves scenarios and
illustrates a gas supply longevity for Victoria ranging between 10-27 years.
A high demand scenario is that:

Victoria supplies a shortfall equivalent to New South Wales demand (175PJ) when gas
contracts end there in 2017 (Source: AGL presentation at APPEA CSG Conference
October 2012); and

gas-fired power increases in Victoria rising 60PJ for every five years commencing 2015
(Source: modified from estimate of Victorian Department of Primary Industries, based on
four proposed power stations (one constructed to date), McLeish, October 2010).
The high reserves scenario is estimated by GeoScience Australia and includes contingent
resources (discovered but not developed). A low reserves scenario is used by a number of
agencies including AER and AEMO and by Energy Quest. Current Victorian production
forms a low demand scenario.
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Table 5:Longevity of Victorian gas supplies in high and low demand reserve scenarios
(Source: GeoScience Australia, AER, AEMO and EnergyQuest)
Low reserves (4,400 PJ)
High reserves (9,300 PJ)
Low demand
14 years
27 years
High demand
10 years
17 years
Exploration licence tenure - unconventional gas resources
There are currently no production, commercial reserves or identified reserves of onshore
unconventional gas in Victoria. Exploration licence details and a map of onshore petroleum
and gas exploration tenements in Victoria as at 23 September 2013 are shown below
(Figure 33). The number and location of tenements change from time to time with the grant
and surrender of titles. Under the Petroleum Act 1998 a proponent does not have to
distinguish between unconventional or conventional targets for a permit or retention lease,
hence all onshore tenements are illustrated.
Compared to the scale of exploration and development in Queensland, the scale of activity
in Victoria is small very and yet to be demonstrated as commercially viable. The case study
in Box 19 illustrates the scale and scope of operations for one firm.
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Figure 33: Current onshore petroleum licences and mineral licences in Victoria. (Source: Department of State Development, Business and Innovation accurate as at 23/9/2013)
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Box 19: CASE STUDY: IGNITE EXPLORATION LICENCE FOR BIOGENIC CSG
The deeper lignite (brown coal) seams within EL 4416, Ignite Energy Resource's whollyowned exploration licence in Gippsland, are prospective for biogenic natural gas.
An 11-well drilling program during 2007 and 2008 demonstrated the presence of permeable,
gas-bearing lignite seams. During an initial short-term testing program, gas was produced to
the surface (and flared) in sub-economic quantities.
The natural gas within the deep lignite seams of EL 4416 differs from other CSG operations
in Australia, because the lignite is much shallower than the black coals - so the gas has
been predominantly created by biologically decomposed organic matter (biogenic gas) rather
than heat and pressure effects during the coalification process (thermogenic gas).
In general, biogenic gas is associated with large volumes of fresh water (contained in the
lignite seams) that could probably be used for livestock and irrigation with little to no
treatment. This differs from the CSG in Queensland, for example, which produces significant
quantities of salty water that needs to be significantly treated.
The water extracted during the 2007 and 2008 drilling program was able to be used on the
farm property for normal agricultural purposes without further treatment.
Victorian Natural Gas (VNG), the joint venture between Ignite Energy and ExxonMobil to
investigate CSG potential in EL4416, is currently undertaking a limited exploration program.
This program will study what natural gas resources exist within the licence, and assess
whether they can be safely and commercially produced.
The initial exploration phase will take around 2 years. During this exploration phase VNG will
be working to drill up to 7 exploration wells to gather core samples and other important
information about the characteristics of the coal and surrounding geology.
There will be no hydraulic fracturing or use of hydraulic fracturing fluid during the initial
exploration phase.
Part of the evaluation activities during the initial exploration phase will be to determine the
best way to produce the gas and whether hydraulic fracturing will be needed, should VNG
proceed to the production phase.
(Source: Information provided by Ignite, based on public information extracted from the
Ignite Energy Resources website and the Victoria Natural Gas joint venture public facts
sheets regarding the natural gas exploration program on Exploration License EL4416 in
south east Gippsland)
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Key sources of information concerning gas resources
International

International Energy Agency; US Energy Information Administration; US Geological
Survey – provide a high level assessment of global gas resources and the gas
market;
National

Geoscience Australia (GA) is the primary source of Australian gas supply
information, including for a number of other Australian Government institutions and
agencies (e.g. BREE, ABARE);

The Department of Resources Energy and Tourism (DRET) sets policy and leads
marketing for investment attraction in Commonwealth waters;
Victoria

Geological Survey of Victoria (GSV) assesses Victorian onshore and offshore gas
resources, both developed and undiscovered. GSV and GA cooperate in geological
assessment. GSV also leads investment attraction in Victorian resources;

The Department of State Development Business and Innovation (DSDBI) receives
reports on production from companies and makes assessments of developed gas
reserves;
Some recent reports:

Australian Energy Market Operator (AEMO) - Annual Gas Statement of Opportunities
and supporting documents prepared by Core Energy Group;

Bureau of Resources and Energy Economics (BREE), - Gas Market Report July
2012;

Department of Resources, Energy and Tourism (DRET), Geoscience Australia (GA)
and BREE - Australian Gas Resource Assessment 2012;

Queensland Department of Energy and Water Supply - 2012 Gas Market Review;

Australian Government, Energy White Paper; and

Various industry reports, for example: EnergyQuest – Energy Quarterly;
EnergyQuest – Australian CSG 2013: All Aboard the LNG Train, May 2013; and Core
Energy Group – Gas Production Costs, August 2012.
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Appendix 4: Victorian Government media release
Page | 121
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Appendix 5: Further details on gas regulation in Victoria
Gas exploration and development regulation in Victoria
Current arrangements
Gas exploration and development activities in Victoria and its state waters are regulated
under the Offshore Petroleum and Greenhouse Gas Storage Act 2010, the Petroleum Act
1998, or the Mineral Resources (Sustainable Development) Act 1990 (MRSDA).
Conventional gas, tight gas and shale gas come under the petroleum legislation; CSG and
gas from oil shale are under the MRSDA. The intent of regulating CSG (and gas extracted
from oil shale) under the MRSDA is to avoid conflicts with proponents targeting coal. Each
Act has associated regulations as well as guidelines and other administrative material to
assist with regulation.
Conventional gas exploration and development has been taking place in Victoria for over
100 years. The first petroleum discovery in Victoria was an oil discovery near Lakes
Entrance in 1924.
Legislation has developed through that time with significant changes occurring when
exploration expanded offshore in the 1950’s and 1960’s, again with the assertion of
Commonwealth rights over the offshore in the 1970’s, the introduction of objective-based
regulation starting in the 1990’s and most recently, the Commonwealth’s taking on
administrative responsibility for Commonwealth waters in 2012. Practices for conventional
petroleum are well established. Recent trends have been towards more objective based
regulation and to greater expectations for community engagement.
Offshore legislation
The Victorian Act, the Offshore Petroleum and Greenhouse Gas Storage Act (2010)
(OPGGS (Vic)) applies in State waters out to three nautical miles from the coast. The
OPGGS (Vic) largely mirrors the Commonwealth Act which applies beyond three nautical
miles from the coast). Victoria administers the OPGGS (Vic). Two Commonwealth
authorities, the National Offshore Petroleum Titles Administrator (NOPTA) and the National
Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA),
administer the OPGGS (Cth) in Commonwealth waters.
Onshore legislation
The Petroleum Act (1998) operates in a similar manner to the OPGGS (Vic), but adds
provisions around access to land, both private and Crown. The Petroleum Act 1998 applies
to tight gas and shale gas. While the Act provides limited exemptions from other legislation
where equivalent processes are in place, further laws and regulations apply.
For historic reasons, the Mineral Resources (Sustainable Development Act) 1990 applies to
CSG and oil shale extracted by chemical or industrial processes. For both minerals and
petroleum legislation, there are two main licensing processes: exploration and
mining/production. Both regimes also allow for a retention licence, where a resource is not
commercially viable but is likely to become commercial in the future (specific timeframes are
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included in the relevant acts). A summary of the processes is presented in Figure 34 below.
Projects may also be referred to the Minister for Planning to determine the need for an
Environment Effects Statement (EES).
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Figure 34: Regulatory framework for onshore gas
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Mineral Resources (Sustainable Development) Act 1990
Exploration
Minerals exploration requires an exploration licence. An exploration licence allows a
proponent to undertake low impact exploration activities only; any other work requires a work
plan approved by the Department of State Development, Business and Innovation (DSDBI).
Prior to being approved, the work plan is referred to other agencies on an as needs basis.
Native vegetation clearing is referred to the Department of Environment and Primary
Industries (DEPI); groundwater extraction or water bore construction to the relevant Rural
Water Corporation; and off-site discharges, disposal or chemical use to the Environment
Protection Authority (EPA).
A cultural heritage management plan may be also required for ground disturbing works in
areas of cultural heritage sensitivity and must be prepared to the satisfaction of the
Registered Aboriginal Party (or Aboriginal Affairs Victoria) prior to the approval of the work
plan by DSDBI.
Other requirements of an exploration licence include a duty to consult throughout the period
of the licence, surveying and marking out of licence boundaries, consent or a compensation
agreement in place with landowners or occupiers, and insurance and rehabilitation
arrangements. A planning permit is not required for exploration.
Production
The MRSDA defines mining as “extracting minerals from land for the purpose of producing
them commercially and included processing and treating ore”. Mining requires a mining
licence, however, the licence in itself does not permit mining to occur. A mining work plan
needs to be prepared in accordance with regulations. Once a draft work plan has been
prepared to the satisfaction of DSDBI, it is referred to statutory referral authorities, DEPI and
the Rural Water Corporation and any other agency (such as the EPA for discharge / disposal
/ chemical use) as required.
Cultural heritage requirements are similar to those for minerals exploration. In the event of
no objections from the referral process, the work plan is statutorily endorsed as having
sufficient technical merit to support a planning permit application and is sent to the
proponent to attach to the planning permit application. The work plan is only approved by
DSDBI once the planning permit has been granted. The key guidance documents are
MRSDA, the Mineral Resources Sustainable Development Regulations and Work Plan
Guidelines for Mining Licence - Exceeding 5 hectares. Other requirements of a licence
include a duty to consult throughout the period of the licence, surveying and marking out of
licence boundaries, consent or a compensation agreement in place with landowners or
occupiers, and insurance and rehabilitation arrangements.
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Petroleum Act 1998
Exploration
Petroleum exploration requires a petroleum exploration permit (PEP). Petroleum tenements
are released by the Minister under acreage releases and companies are invited to tender.
The tender process includes commitments by the company to undertake specific work and
spend certain dollars. These become conditions on the PEP against which the Minister
assesses performance.
Once the PEP is granted, the permit holder must prepare and have approved an operations
plan prior to commencing any on the ground work. For drilling, the operations plan
comprises a description of the operation, a well operation management plan that details
technical aspects of the well construction and the environment management plan that
describes environmental effects, risks, objectives and standards.
Like that for minerals, the petroleum operations plan is referred to other agencies on an as
needs basis on matters regarding native vegetation clearing (DEPI), groundwater extraction
(Rural Water Corporation), and discharge / disposal / chemical use (EPA).
A cultural heritage management plan may also be required for ground disturbing works in
areas of cultural heritage sensitivity and must be prepared to the satisfaction of the
registered aboriginal parties (or Aboriginal Affairs Victoria) prior to the approval of the
operations plan by DSDBI (the decision maker).
A planning permit is not required for exploration. Unlike minerals exploration, approval must
be sought to suspend or abandon wells and conduct down hole stem tests. Licensees must
also have consent or a compensation agreement in place with landowners or occupiers
before an operation starts, hold insurance and provide a rehabilitation bond. Before any
operations are undertaken on a licence, the licensee must also provide 21 days written
notice to the landowner or occupier.
Production
Petroleum production requires a petroleum production licence, which will only be granted on
the discovery of a commercial petroleum resource. Prior to commencing production, the
licensee must prepare and have approved an operations plan as per exploration (see above)
and production development plan (including a reservoir management plan). The plans must
address all the issues relating to the operation and will be referred to the relevant agencies
for comment and input as required. Planning approval is required for petroleum production
and development unless the project is assessed under the Environmental Effects Act 1978.
Licensees must also have consent or a compensation agreement in place with landowners
or occupiers before an operation starts, hold insurance and obtain a rehabilitation bond.
Before any operations are undertaken a licence, the licensee must also provide 21 days
written notice to the landowner or occupier.
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Environmental Effects Statement process
It is considered likely that any proposal to mine / produce unconventional gas would require
an assessment under the Environment Effects Act 1978 (EEA) rather than proceed through
a planning permit process. Development projects are assessed under one process or the
other; not both. The Minister for Planning decides, according to specific criteria, whether an
Environmental Effects Statement (EES) is required for projects referred to him. The process
is administered by the Department of Transport, Planning and Local Infrastructure (DTPLI).
The process involves the preparation of a scoping document by DTPLI which guides the
study program of the EES, the preparation of specialist reports and consultation with the
relevant agencies typically through a Technical Review Group. Once the EES is prepared,
the document is placed on public exhibition, submissions are received and the Minister may
choose to appoint a panel to explore the submissions. The Minister then assesses the
environmental effects of the proposal and submits the assessment to the relevant decision
makers for project-level approvals.
Under the National Partnership Agreement on CSG and Large Coal Mining Development
(NPA), Victoria agreed to refer all CSG development proposals to the Independent Expert
Scientific Committee (IESC) for assessment. The IESC was established under the
Environment Protection and Biodiversity Conservation Act 1999 (EPBC Act) to provide state
governments with expert scientific advice relating to CSG and large coal mining proposals
that may have a significant impact on water resources.
Projects may also be required to be assessed under the EPBC Act (Cth). Negotiations to
address some of the Commonwealth duplication of the state environment assessment
process are ongoing, with a clear solution yet to be reached. The introduction of bilateral
assessments would remove the requirement for both State and Commonwealth approval,
thus reducing duplication and the regulatory burden on investors. To date bilateral
assessment has been case by case typically with a common exhibition and panel process,
but with the Commonwealth Minister retaining the right to make an approval decision in
addition to the Victorian decision.
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Regulation of water resources in Victoria
Box 20: SUMMARY OF WATER REGULATION IN VICTORIA
i.
The lead agency responsible for water management in Victoria is the Department of
Environment and Primary Industries (DEPI).
ii.
Mining exploration or development approvals are not granted unless it can be demonstrated that
the risks affecting water resources can be removed or controlled to an acceptable level on par
with best practice environmental regulation.
iii.
Each development proposal is subject to approvals by the Department of State Development
and Business Innovation, the relevant Water Corporation, the Minister for Planning or local
council, and possibly the Environment Protection Authority.
iv.
The Water Act 1989 provides formal protection for the environmental qualities of waterways,
catchments and groundwater. This ensures Victoria’s water resources are conserved and properly
managed for sustainable use by present and future Victorians. It also includes consideration of the
potential impacts on other water users or water dependent environmental values.
v.
The disposal of poor quality water, to either the surface or groundwater, is subject to strict
environmental conditions under the MRSDA, the Environment Protection Act 1970 and the Water
Act 1989. If water resource impacts cannot be adequately mitigated or offset, a project would not
receive approval to proceed.
Recent developments - Licensing of deep activities such as tight gas and shale gas
vi.
As part of the revision of the groundwater management framework, DEPI is introducing a depth
boundary to current managed groundwater resources. The boundary is defined as 200m from the
land surface or 50 metres below the base of the Tertiary age geological sequence, whichever is
the deeper. Below this boundary, the requirement to licence groundwater extraction under the
Water Act 1989 still applies, but the decision is made on a case by case basis in accordance with
the Water Act. If it is demonstrated that taking groundwater, gas or other fluids from the deep zone
would not adversely impact the shallower groundwater resources, then the management
constraints applied to the shallow resource would not apply.
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Progress on a regulatory framework for unconventional gas in Victoria
Since placing holds on new exploration and hydraulic fracturing the Victorian Government
has been working on a number of initiatives to strengthen and clarify the regulatory
framework for the exploration and development of unconventional gas, including a review of
regulatory arrangements against the leading practices in the NHRF.
The assessment is summarised in Table 6.
Table 6: Assessment of Victorian legislation against the NHRF
NHRF Leading Practice (LP)
Fully Covered by Existing Legislation, Regulations,
administrative practices?
LP 1 – Undertake
comprehensive
environmental impact
assessment, including
rigorous chemical, health
and safety and water risk
assessments
Yes - via EES process
LP 2 - Develop and
implement comprehensive
environmental management
plans which demonstrate
that environmental impacts
and risks will be as low as
reasonably practicable
No
LP 3 - Apply a hierarchy of
risk control measures to all
aspects of the CSG project
Assessment of work plans currently provides for the general
matters articulated in LP 2, but does not specifically
consider the risks particular to CSG or hydraulic fracturing
operations.

CSG exploration: there is no specific requirement for an
EMP at this stage and requirements don’t cover
hydraulic fracturing.

CSG development: Mineral Regulations require an
EMP as part of the work plan but don’t specifically
cover ‘risks’ and hydraulic fracturing.

Shale/tight gas (Petroleum Act): requires operation
plans and identification of risks to the environment and
management of these. Petroleum Regulations
specifically require an EMP be included in the operation
plan, whether for exploration or development. EMP
requirements do not specifically refer to hydraulic
fracturing.
Yes
A partial gap exists under the MRSDA in that there is no
EMP required for CSG exploration and no WOMP required
for any CSG operations (as is the case for Petroleum
Regulations).
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NHRF Leading Practice (LP)
Fully Covered by Existing Legislation, Regulations,
administrative practices?
LP 4 - Verify key system
elements, including well
design, water management
and hydraulic fracturing
processes, by a suitably
qualified and authorised
person
No
MRSDA and Mineral Regulations do not explicitly require
the proponent to outline the skills, experiences,
accreditation and qualifications of their personnel or
contractors.
Petroleum Act / Regulations do not specifically provide for
verification, though there are requirements for applicant to
provide information about technical qualifications etc. EMP
requires implementation plan, including a clear chain of
command, roles and responsibilities etc.
Guidelines (Work Plan Guidelines for a Mining Licence)
don’t outline what is an acceptable level of competency for
an operator or contractor to perform well drilling and
hydraulic fracturing processes based upon a risk
assessment.
LP 12 - Require a geological
assessment as part of well
development and hydraulic
fracturing planning
processes
No.
LP 5 - Apply strong
governance, robust safety
practices and high design,
construction, operation,
maintenance and
decommissioning standards
for well development
No
LP 6 - Require independent
supervision of well
construction
No
LP 7 - Ensure the provision
and installation of blowout
preventers informed by a
risk assessment
No
There is no requirement for geological assessments as part
of work plan (or well operation management plan) that
would ensure all risks around dewatering or hydraulic
fracturing processes take into account the unique geology
for a given operation.
There are currently no requirements for a WOMP for CSG
operations under the MRSDA or Mineral Regulations. The
requirement does exist under the Petroleum Act.
There is no explicit requirement for independent supervision
of well construction under the MRSDA or Petroleum Act,
however this is likely to be standard industry practice.
This requirement is not specifically contemplated by the
MRSDA, which was developed to legislate for traditional
minerals exploration. However, there is a standard licence
condition (20.4) applied to require blowout preventers for
CSG exploration.
The Petroleum Act and Regulations does not explicitly
require blowout preventers.
Gap relates to ‘informed by a risk assessment’.
LP 8 - Use baseline and
ongoing monitoring for all
vulnerable water resources
Yes
The current water licensing framework enables
requirements to be imposed for baseline and ongoing
monitoring.
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NHRF Leading Practice (LP)
Fully Covered by Existing Legislation, Regulations,
administrative practices?
LP 9 - Manage cumulative
impacts on water through
regional-scale assessments
Yes
LP 10 - Ensure co-produced
water volumes are
accounted for and managed
Yes
LP 11 - Maximise the
recycling of co-produced
water for beneficial use,
including managed aquifer
recharge and virtual
reinjection
Yes
LP 13 - Require process
monitoring and quality
control during hydraulic
fracturing activity
No
LP 16 - Minimise the time
between cessation of
hydraulic fracturing and
flow back, and maximise the
rate of recovery of
fracturing fluids
No
LP 14 - Handle, manage,
store and transport
chemicals in accordance
with Australian legislation,
codes and standards
Yes
LP 15 - Minimise chemical
use and use
environmentally benign
alternatives
Yes
LP 17 - Increase
transparency in chemical
assessment processes and
require full disclosure of
chemicals used in CSG
activities by the operator
No
LP 18 - Undertake
assessments of the
combined effects of
chemical mixtures, in line
with Australian legislation
and internationally accepted
testing methodologies
No
There are currently no specific requirements or guidance
related to hydraulic fracturing.
There are currently no specific requirements or guidance
related to hydraulic fracturing.
There is currently no requirement for the full/public
disclosure of chemicals under the MRSDA or Petroleum
Act.
Full disclosure is required for an EPA Works Approval or
Research, Development and Demonstration (RD&D)
approval.
There is currently no robust linked together process for
assessing cumulative impacts of chemicals.
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The review also found opportunities to improve Victoria’s framework for regulating onshore
gas operations by establishing other specific provisions and clarifications:

amending the Mineral Resources Development Regulations 2002 to improve their
applicability for CSG operations;

creating guidelines to assist industry to meet its obligations for CSG and hydraulic
fracturing; and

extending and enhancing formal administrative arrangements and coordination between
regulators.
The NHRF has been developed specifically for CSG, but many of the leading practices may
also apply to other forms of unconventional gas, such as shale and tight gas, particularly as
they relate to hydraulic fracturing. Guidelines specific to hydraulic fracturing could cover
activities under both the MRSDA and the Petroleum Act.
Parliamentary inquiry and Government response
In May 2013, the Victorian Government released its response to the Economic Development
and Infrastructure Committee inquiry into greenfields mineral exploration and project
development in Victoria. Some of the initiatives in the response contribute to streamlining
regulatory requirements for all mining requirements and improving community engagement.
A number of initiatives coming out of the Inquiry relate to CSG including:

a broad program of community engagement activities, in particular for CSG, and new
policies to articulate government’s expectations of industry to better engage with
communities during their activities;

specific roles for the Earth Resources Ministerial Advisory Council , include:
o
advice on how to improve the information provided to communities so that it is simple
and transparent; and
o
review of appropriate aspects of the landowner compensation agreement process
under the MRSDA;

a major work program under the National Partnership Agreement for CSG and Large
Coal Mining Development to better understand and monitor potential impacts on water
resources, supported by regulatory reform to protect water resources;

increased reporting on the health of the mining sector in Victoria, including a new
working group with industry to identify further indicators to improve monitoring of the
health and activity of the sector; and

additional information on the Departmental website to better inform communities about
licence application processes.
The Victorian Government is now in the process of implementing the response to the report
of the Inquiry.
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Appendix 6: Royalties background information
Table 7: Applicable legislation and existing royalty rates for natural gas production in several
jurisdictions
Project location
and type
Applicable
legislation
Royalty rate
Current value
Offshore
Petroleum and
Greenhouse
Gas Storage
Act 2010 (Vic)
10 per cent of the value of
the gas at the wellhead
No projects
currently in
offshore Victorian
waters
Onshore Victoria–
conventional,
tight gas and
shale gas
resources
Petroleum Act
1998 (Vic)
10 per cent of the value of
the gas at the wellhead
Onshore Victoria
– CSG and oil
shale
Minerals
Resources
(Sustainable
Development)
Act 1990 (Vic)
Victorian administered royalties
Offshore –
Victorian waters
Projects located
within three
nautical miles of
the territorial sea
baseline
Value at the wellhead is agreed
between the owner of the
production permit and the
Victorian Minister
Value at the wellhead is the
reasonably expected sale
price, less any processing or
refinement expenses and
delivery expenses
2.75 per cent of the net
market value of the gas, and
$1.43 per m3 for tailings
Net Market Value means the
market value of the mineral at
the time it is first sold,
transferred or disposed of, less
any costs reasonably,
necessarily and directly
incurred by the licensee in
connection with the sale,
transfer or disposal, including
insurance, freight and
marketing expenses
Total royalties
collected in 201112: $142,785
(One licence for
well producing
principally carbon
dioxide)
Total royalties
collected in 201112 for mining
activities
(predominantly
brown coal, and
mineral sands):
$55.9 million
Royalties from
other products
such as stone for
buildings:
$5.6 million
Tailings are waste mineral,
stone or other material that was
produced during the course of
mining
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Project location
and type
Applicable
legislation
Royalty rate
Current value
Royalties revenue
generated from
gas production in
the Gippsland
Basin is estimated
to be in the order
of $300 million in
2010-11
Commonwealth administered royalties
Overlayed on all
gas production
projects,
including
conventional and
unconventional
gas
Petroleum
Resource Rent
Tax Act 1987
(Cth)
40 per cent of a project’s
taxable profit
Overlayed on all
mining and
minerals projects
– including CSG
extracted as a
necessary
incident of mining
coal
Minerals
Resources
Rent Tax Act
2012 (Cth)
40 per cent of a project’s
taxable profit
Petroleum
(Onshore) Act
1991
A royalty holiday for the first
5 years, then increasing to 10
per cent wellhead value by
the end of year 10
Taxable profit is the project’s
income after all eligible
expenditures have been
deducted from all assessable
receipts. State royalties is an
eligible expenditure for the
calculation of taxable profit.
Taxable profit is the project’s
income after all eligible
expenditures have been
deducted from all assessable
receipts. State royalties is an
eligible expenditure for the
calculation of taxable profit.
No projects
currently in
Victoria
(Existing mining
projects in Victoria
are below the
$75 million
threshold)
Other jurisdictions
New South Wales
Wellhead value is the revenue
and/or savings from the
generation of electricity after
deducting costs incurred
downstream of the well head.
Northern Territory
Petroleum Act
10 per cent wellhead value
Wellhead value is taken from
the point that a market value
can be independently
established for the product
(usually the point of sale) back
to the wellhead, with allowable
costs deducted.
Total royalties
collected under
State legislation in
all areas 2011-12:
$1.464 billion
(largely from coal)
Total royalties,
rent and dividends
collected under
Territory
legislation in all
areas 2012-13:
$158.12 million
Page | 135
Project location
and type
Applicable
legislation
Royalty rate
Current value
Queensland
Petroleum and
Gas
(Production
and Safety)
Regulation
2004
10 per cent wellhead value
Total royalties
collected under
State legislation in
all areas 2012-13:
$2.311 billion
Petroleum and
Geothermal
Energy Act
2000
10 per cent wellhead value
Mineral
Resources
Development
Act 1995
12 per cent wellhead value
South Australia
Tasmania
Wellhead value is the amount
that the petroleum could
reasonably be expected to
realise if sold on a commercial
basis, less deductable costs.
Well head value is the price
that could reasonably be
realised on sale to a genuine
purchaser at arm’s length from
the producer less all expenses
reasonably incurred by the
producer in treating processing
or refining the substance and in
transporting the substance
from the well head to the point
of delivery.
Total royalties
collected under
State legislation in
all areas 2012-13:
$186.5 million
Total royalties
collected under
State legislation in
all areas budget
estimate 2012-13:
$55.4 million
Page | 136
Project location
and type
Applicable
legislation
Royalty rate
Current value
Western Australia
Petroleum and
Geothermal
Energy
Resources Act
1967
10 – 12 per cent wellhead
value
Total royalties
collected under
State legislation in
all areas 2011-12:
$4.493 billion

Primary production
licences, 10 per cent
wellhead value;

Secondary production
licences, 12.5 per cent
wellhead value.
(Excludes tight gas, 5 per
cent)
Wellhead value is such amount
as is agreed between the
permittee, holder of the drilling
reservation, lessee or licensee
and the Minister, or in default of
agreement within such period
as the Minister allows is such
amount as is determined by the
Minister as being that value.
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Table 8: Examples of schemes for sharing benefit from gas production with local communities and land
owners in other jurisdictions
Jurisdiction
Scheme
USA
Gas rights and royalties
Onshore gas rights in the US extend vertically downward from the property
line, and unless explicitly separated by deed, they are owned by the surface
landowner who may be a private individual, corporation, indigenous tribe, or
the government at local, state or federal level. Once severed from surface
ownership, the rights may be bought sold or transferred like other real
estate.
This is significantly different to Australia, where the Crown, in right of the
State, owns all onshore petroleum rights.
Most gas interests in the US are leased to companies for development. A
gas lease is different from the general definition of a lease. A gas lease in
the US gives the investor (the lessee) ownership of the gas and an
easement to access the surface estate as reasonably necessary to develop
the gas resource. The land-owner (the lessor) receives a royalty interest in
the gas and maintains title to the surface estate.
Royalties are the primary source of the owner’s compensation under a gas
lease. This is defined as “a share of production, free of the expenses of
production”. The owner’s usual share is one-eighth of the production and is
payable either in kind or in money.
As per the definition, the owner’s interest is free of production costs,
however different states legislate differently on the treatment of production
costs.
Page | 138
Jurisdiction
Scheme
Western
Australia
Royalties for Regions
This program sets aside 25 per cent of the State’s mining and onshore
petroleum royalty revenue to be invested in regional WA.
Under the Royalties for Regions Act 2009, each financial year the Treasurer
credits a Special Purpose Account with an amount equal to 25 per cent of
the forecast minerals and onshore petroleum royalty income for the financial
year, capped at $1 billion per annum.
This is distributed to specific projects and programs through three subsidiary
funds: the Country Local Government Fund; the Regional Community
Services Fund; and the Regional Infrastructure and Headworks Fund.
Funding is allocated to particular projects or programs in accordance with
processes established under each subsidiary fund. For example, the
Regional Grants Scheme, which is administered by the Regional Community
Services Fund, provides funding through a publicly advertised grants
scheme.
Royalties for Regions is administered by the Western Australia Department
of Regional Development. Advice on the allocation of money from the Fund
and on the allocation of money between the Fund’s subsidiary accounts is
provided by the WA Regional Development Trust, which is required to report
to Parliament each year.
Queensland Royalties for the Regions
The Royalties for the Regions scheme was launched in Queensland in 2012,
with $495 million of “State royalties” to be invested across Queensland over
a four year period commencing in 2012 and with $60 million of this is to be
available in 2013-14. In future years there will be an ongoing commitment of
$200 million each year. Funding is allocated to three separate funds: the
Resource Community Building Fund; Road to Resources; and the Floodplain
Security Scheme.
Separate application guidelines exist for the different funds and applications
for funding are assessed on strategic merit. All funding is allocated to eligible
local councils based on a competitive process, with a two-stage assessment
process comprising an expression of interest and a business case for
shortlisted projects.
Councils eligible for the funding are those with communities experiencing
negative impacts from large scale developments or that have a role as
service centres and hosts of major infrastructure projects linked to resource
developments.
The scheme is administered by the Queensland Government’s Department
of State Development, Infrastructure and Planning.
Page | 139
Appendix 7: Acronyms
ACCC
Australian Competition and Consumer Commission
AEMC
Australian Energy Market Commission
AEMO
Australian Energy Market Operator
AER
Australian Energy Regulator
AFMA
Australian Financial Markets Association
AIG
Australian Industry Group
APPEA
Australian Petroleum Production and Exploration Association
BREE
Bureau of Resources and Energy Economics
BTEX
chemicals
benzene, toluene, ethylbenzene and xylene
CNG
Compressed Natural Gas
COAG
Council of Australian Governments
CSG
Coal seam gas
DEPI
Department of Environment and Primary Industries (Victoria)
DSDBI
Department of State Development, Business and Innovation (Victoria)
DTPLI
Department of Transport, Planning and Local Infrastructure
DTS
Declared Transmission System
DWGM
Declared Wholesale Gas Market
EEA
Environment Effects Act 1978
EES
Environment Effects Statement
EPA
Environment Protection Authority
EPBC Act
Environmental Protection and Biodiversity Conservation Act 1999
Page | 140
ESC
Essential Services Commission (Victoria)
ESV
Energy Safe Victoria
FRC
Full Retail Contestability
GJ
Giga joules
IESC
Independent Expert Scientific Committee
LIBOR
London Inter-bank Offer Rate
LNG
Liquefied Natural Gas
MA
Manufacturing Australia
MRSDA
Mineral Resources (Sustainable Development) Act 1990
mtpa
Million tonnes per annum
NECF
National Energy Customer Framework
NEM
National Electricity Market
NGL
National Gas Law
NGR
National Gas Rules
NHRF
National Harmonised Regulatory Framework for Natural Gas from Coal
Seams
NOPSEMA
National Offshore Petroleum Safety and Environmental Management
Authority
NOPTA
National Offshore Petroleum Titles Administrator
OPGGS (Vic)
Offshore Petroleum and Greenhouse Gas Storage Act 2010
PC
Productivity Commission
PJ
Petajoules
RDV
Regional Development Victoria
SCER
Standing Council on Energy and Resources
STTM
Short Term Trading Market
Page | 141
tcf
Trillion cubic feet - 1 tcf of pure methane has an energy content of 1,055
PJ
tcm
Trillion cubic meters - 1 tcm is equal to 35.315 tcf and has an energy
content of 37,260 PJ
UK
United Kingdom
US
United States
VCAT
Victorian Civil and Administrative Tribunal
VTS
Victorian Transmission System
Page | 142