Gas Market Taskforce Supplementary Report

October 2013

Contents

1About this report

2Chapter 1: Introduction

2About the Gas Market Taskforce

3Gas in Victoria

3Gas as an energy source

6History of gas in Victoria

7Australian gas markets

9Market oversight and reforms

10Commonwealth policy platform 2013

10Chapter 2: Overview of supply and demand

10About Chapter 2

12Global supply and demand

14Australian and eastern market supply

16Victorias gas resources

16Conventional gas

17Unconventional gas

19Eastern market domestic demand

21Victorias demand

23New LNG export demand

25Gas prices will increase

27The eastern market is already in transition

28Potential impacts on domestic consumers

30Potential implications for the Australian and Victorian economies

34Chapter 3: Drivers, challenges and potential solutions for the expanded eastern gas market

34About Chapter 3

34Drivers of increasing gas price increases in the eastern market

34Competition between LNG export producers and domestic users

35Logistical and operational issues in the Queensland Gas fields

36Increasing production costs

39Lack of transparency in supply and demand information

40Inefficient upstream competition

41Unconventional gas - challenges and community concerns

47Progress on regulatory reform for unconventional gas

47Commonwealth-State initiatives (COAG)

48South Australia

49Queensland

50New South Wales

51Victoria

52Potential solutions

52Proposals for leading practice regulation and community engagement

52Better community engagement through an independent gas commissioner

54Understand and manage risks to water resources

56Improve standards for hydraulic fracturing

57Royalties and industry payments

58Industry incentives

58Compensation for landholders and neighbours

59Payments for communities

60Initiatives to increase productivity and reduce costs of major projects

61Initiatives to improve supply and demand information

61Upstream competition should be encouraged

62Domestic reservation is not a solution

65Chapter 4: Wholesale markets and transmission

65About Chapter 4

65Introduction

65History and infrastructure

66Ownership

66Transmission

67The gas pipelines access regime

70Victorian gas transmission system

71Pipeline capacity trading

72Capital expenditure and augmentation

73Wholesale markets

76Upstream markets

77New reform initiatives to achieve an integrated and transparent market

77Downstream markets

80Secondary markets risk and financial products

82Chapter 5: Retail markets and distribution

82About Chapter 5

82Background

84Distribution of gas

85Retailing of gas

89Issues in the retail markets

93Opportunities to address eastern market challenges

95Chapter 6: Case studies on overseas market development

95About Chapter 6

95Early history of gas trading

96Gas as a traded commodity

96Case Studies

96United Kingdom

97United States and Canada

99Continental Europe

102Summary of approaches to transmission access regulation

103Lessons learnt from overseas markets

104Relevance for Victorian wholesale market

105Relevance to the eastern gas market

106Appendix 1: List of stakeholders consulted by the Chair

109Appendix 2: National reform agenda and other reviews

113Appendix 3: Gas resources information - further details

121Appendix 4: Victorian Government media release

123Appendix 5: Further details on gas regulation in Victoria

134Appendix 6: Royalties background information

140Appendix 7: Acronyms

Figures

3Figure 1: Gas consumption in eastern states in 2011-12

7Figure 2: Turn-in ceremony for Victorias first natural gas pipeline

8Figure 3: Map of Australia gas fields and key pipelines

13Figure 4: Projected world natural gas consumption for OECD and non-OECD countries

14Figure 5: International Energy Agency estimates of natural gas resources by region in 2011

15Figure 6: Australias produced and remaining gas resources

17Figure 7: Eastern market total produced and remaining gas resources.

18Figure 8: Victorias main gas production basins. Pie charts show past and remaining production.

20Figure 9: Eastern market primary consumption of gas by sector in 201112

22Figure 10: Total gas consumed by Australian households in 2011-12

23Figure 11: Non-residential gas consumption in eastern states in 2011-12

23Figure 12: Intended use of natural gas in 2013 by businesses surveyed

25Figure 13: Projected eastern market demand

26Figure 14: Domestic LNG and 2P Reserve Projections

27Figure 15: Possible paths for gas price levels in the eastern gas market

33Figure 16: Data on Victorian manufacturing industries that use gas intensively (2011)

39Figure 17: Typical production costs for Australian gas resources in 2012

68Figure 18: The eastern market gas transmission system.

75Figure 19: Business models for wholesale gas trade through bilateral contracts .

76Figure 20: Eastern Australian gas market structure - conceptual diagram

85Figure 21: Comparison of residential gas cost components across eastern Australia

90Figure 22: Average residential customer numbers per retailer in Victoria in 2011-12

90Figure 23: Gas annual standing offer charges 2007-2012 ($/year 2012)

91Figure 24: Residential retail prices for Victoria ($/GJ, $2013 real)

98Figure 25: British gas transmission system

100Figure 26: Gas hubs and flows in the US and Canada

101Figure 27: Gas transmission in Europe

103Figure 28: Trade volumes at European hubs.

113Figure 29: Gas Market Development Plan.

116Figure 30:Location map showing details of Gippsland oil and gas fields

117Figure 31:Location map showing details of producing fields in the Otway Basin

118Figure 32: Location map showing details of onshore depleted gas fields around Port Campbell

120Figure 33: Current onshore petroleum licences and mineral licences in Victoria.

126Figure 34: Regulatory framework for onshore gas

Tables

47Table 1: Key risks for hydraulic fracturing and worst case frequency of occurrence.

57Table 2: Leading practices relevant to hydraulic fracturing in the NHRF

72Table 3: Major Victorian gas transmission pipelines

115Table 4: Eastern market produced and remaining gas resources (significant basins)

131Table 5: Assessment of Victorian legislation against the NHRF

135Table 6: Applicable legislation and existing royalty rates for natural gas production

139Table 7: Examples of schemes for sharing benefit from gas production

Boxes

5Box 1: What is natural gas?

9Box 2: Key agencies in gas oversight

12Box 3: About gas resource information

19Box 4: Brief history of unconventional gas exploration and hydraulic fracturing in Victoria

25Box 5: Queenslands LNG trains

28Box 6: Netback price

32Box 7: Case study AMCOR

34Box 8: Case Study Australian Paper

44Box 9: Potential Water impacts of CSG extraction

46Box 10: More About Hydraulic Fracturing

52Box 11: Key findings New South Wales Chief scientist review initial report

54Box 12: Some priority actions Victoria could take to achieve leading practice regulation of onshore gas

55Box 13: Possible role for a Victorian Gas Commissioner

56Box 14: Proposals for Comprehensive water science, monitoring and licensing

58Box 15: Hydraulic Fracturing reform proposals

69Box 16: Classification of pipelines covered or uncovered

70Box 17: Regulation of transmission pipelines

71Box 18: Key rulings to uncover transmission pipelines

121Box 19: Case study: Ignite exploration licence for biogenic CSG

130Box 20: Summary of Water regulation in Victoria

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.

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.

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.

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.

050100150200250300VictoriaQLDNSWSAPJ

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. Victorias 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 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. 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.

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.

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.

(Diagram source: After Gautier, USGS, 2012 cited by Geoscience Australia1)

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. Today, Victorias 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.

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. 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. The construction of this pipeline was completed in March 1969, with the first gas entering the Victorian distribution system on 1April1969. 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 ExxonMobil-BHP 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.

Figure 2: Turn-in ceremony for Victorias 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). 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. The incident highlighted Victorias 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 Victorias 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.

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.

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.

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.

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 state-based 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 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 Taskforces work.

Commonwealth policy platform 2013

The Abbott-led Coalition Government was elected in September 2013. The Coalition Governments 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.

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)

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. 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.

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. Figure 4 provides an outline of projected demand worldwide, broken down between OECD and non-OECD countries.

020406080100120140160180Trillion cubic feet

OECDNon-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. 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 IEAs estimates at the end of 2011 of the worlds 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 2035. However, it also recognises that significant public concern regarding the environmental and social impacts of unconventional gas could put this at risk.

01000200030004000500060007000Trillion cubic feet (tcf)

ConventionalUnconventional

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 8percent 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.

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 countriessuch 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 Japanare likely to increase demand for gas for electricity generation and may further increase demand domestically on the eastern gas market. Conversely, increased exports from other countries may compete with eastern market exports and act to reduce demand for gas in the eastern market.

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. 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. 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).

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. In 2010-11, the western market produced 1,393 PJ of gas and domestically consumed 647 PJ. The Browse Basin contains around 35,000 PJ of undeveloped gas. 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.

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. The Bonaparte Basin supplies an LNG export train in Darwin which exported 12 PJ in 2012. The northern market is not connected to any other domestic markets, however the current NorthernTerritory Government has suggested that it will pursue a pipeline linking the northern market to the eastern market via Queensland.

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 GippslandBasin (52 per cent) and the Cooper Basin (37 per cent). 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.

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.

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.

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).

Victorias gas resources

Details and maps of Victorias gas resources are provided in Appendix 3. Victorias 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 8,791PJ, or 90 per cent of Victorian and about 50 per cent of the eastern markets cumulative gas production to date. The Otway Basin has produced gas since 2005 and currently provides about 29per cent of gas produced annually in Victoria. 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.

Figure 8: Victorias main gas production basins. Pie charts show past and remaining production.

(DataSource: 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 BHPBilliton and ExxonMobil to supply Origin Energy with 432 PJ over 9years from the Bass Strait points to higher production and faster depletion of Victorias 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.

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.

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.

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 201112

(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.

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. 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.

Residential and commercial demand

Demand from residential and commercial consumers within the various distribution networks represents 24 per cent of domestic consumption of gas. Demand within this segment is expected to grow in line with economic and population growth.

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. 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.

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. 54 per cent of new generation investment in the National Energy Market has been gas powered. 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 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. 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. Under the revised electricity demand forecasts, investment in new generation of any kind is expected to be deferred by four years. AEMO has also suggested that gas powered generation may not rise significantly until 2025.

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.

Victorias demand

Victoria has the largest residential gas demand of any Australian state or territory, at more than 100PJ per year, contributing two thirds of all residential gas consumption in Australia (Figure 10). This is supported by an extensive reticulated gas network that supplies gas to the majority of households which use gas for cooking and heating. Victorias residential demand also exhibits a peak during the colder winter months when households use gas for heating purposes.

020406080100120VictoriaNSWSAWAQLDTasNTPJ

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).

020406080100120140160VicNSWQLDSATasPJManufacturingMiningOther 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).

0102030405060Heating in

industrial

processes

Power

generation

Space heating

or cooling

Feedstock for

industrial

purposes

We do not use

significant

quantities of

gas

Percentage of respondents

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 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). 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).

Box 5: Queenslands 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 ProjectsApril 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)

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). There is potential for a further two trains by 2020-21.

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.

The historical average for domestic gas prices within the eastern market has been $3-4 per gigajoule(GJ). Many long-term contracts are expiring from 2014 onwards and need to be renewed. 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. 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. Stakeholders have indicated that wholesale prices may reach $8-12 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.

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 Xstratas Mount Isa mine;

under a 7-year gas supply contract between Origin Energy and MMG, the price for gas is close to $9 per GJ;

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; 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.

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. Victoria is expected to have the lowest price on the east coast gas market at $7.70 per GJ.

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, while in the longer term, significant US exports may result in a convergence between the Henry Hub, Asia-Pacific 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. However, continued growth in demand from gas-poor countries will increase demand for Australias 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 could last for up to seven years. 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. 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.

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 long-term 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 Ministers 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;

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;

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; 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.

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 economy-wide.

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. 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. 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. 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.

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. 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.

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. 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. 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 Australia24 in Victoria, five in New South Wales, seven in Queensland and four in South Australiadirectly 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 Amcors 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.

01000020000300004000050000600000246810121416Food,

beverages and

tobacco

Pulp, paper

and printing

Textile,

clothing,

footwear and

leather

Non-metallic

mineral

products

Persons employed in VictoriaPJ gas used in Victorian industryPetajoules in 2011-12Employed 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.

Box 8: Case Study Australian Paper

Australian Paper is Australias 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 Australias 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 630,000MWh of electricity and 8,000,000 GJ of natural gas per annum making the facility one of Victorias 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 sites 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.

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. Owners of proposed LNG export facilities are securing contracts for supply in the domestic market to meet their obligations to international customers.

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.

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. (2008, Richard Cottee Managing Director of the Queensland Gas Company)

As recently as 2009, there was an expectation that significant volumes of ramp-up 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. 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. 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.The 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.

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. This 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.

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. Shell claims that construction costs in Australia are up to 30 per cent higher than in the US and Canada.

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. It claims that over half of Australias 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.

Costs of unconventional gas

The production of unconventional gas is typically more expensive than conventional gas. 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. 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.

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.

0.002.004.006.008.0010.0012.0014.0016.00

Gippsland Basin - GBJV (Offshore)Cooper Basin (Infill)Gippsland Basin - GBJV (Offshore) ex. liquidsGippsland Basin (Offshore) - LongtomGunnedah Basin (Tier 1)Gippsland Basin (Offshore) - Longtom ex. liquidsFairview / Spring Gully Area (CSG)Otway Basin (Offshore - Casino et al)Gloucester Basin (CSG)Walloons (East)Cooper Basin (Conventional)Gunnedah Basin (Tier 2)Otway Basin (Offshore - Otway Gas Project)Moranbah Area (CSG)Bass Basin (Offshore)**Walloons (Mid)Walloons (West)Hunter Area (CSG)Sydney Basin (CSG)Clarence Moreton (CSG)Gippsland Basin (Offshore) - KipperCooper Basin (Unconventional)Galilee Basin (CSG)Gippsland Basin (Onshore)Gippsland Basin (Offshore) - Kipper ex. liquidsOtway Basin (CSG)

$/GJ

Figure 17: Typical production costs for Australian gas resources in 2012

(Source: AEMO)

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 Australias 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. 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.

The Australian construction industry is less productive than the US. 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.

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. Delays increase project costs and impact Australias global competitiveness. To address this, Port Jackson Partners notes that clear and predictable rules and timeframes for approvals are essential.

The Australian Petroleum Production and Exploration Association (APPEA) also reports that Australias 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.

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. 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 Australias undiscovered conventional gas resources that adequately reflects the knowledge gained in recent years during the active programs of government pre-competitive data acquisition and increased company exploration during the resources boom.

The eastern gas market has a number of mechanisms to provide information to market participants, such as AEMOs annual Gas Statement of Opportunities. However, market information available is considerably poorer than for gas markets in other countries. The Commonwealth Governments Energy White Paper claimed there is a gap in relation to forecasts of domestic supply and market liquidity. 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. 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.

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. 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.

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 Australias competition law be strengthened to require review of all existing and future joint marketing arrangements.

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. 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 Australias oil production. However, such arrangements also reduce competition.

Australias east coast market is in a transitionary phase and approaching maturity, with a number of interconnected producers supplying the market from different sources. 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 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