THE NATIONAL CHOICE THE NATURAL CHOICE

THE

NATIONAL

CHOICE

NATGAS Generating economic and social wealth for the nation now and in the future

T H E

N AT U R A L

C H O I C E

THE

NATIONAL

CHOICE

Contents Chapter 1: Introduction

1

The Policy Context

1

Gas – A Valuable Resource to the Nation Now and in the Future

1

Australia’s Gas Resources

2

A Gas Development Strategy

5

Chapter 2: The National Market

7

Natural Gas Demand in Australia Overview Potential for increased demand — strategic drivers Potential for increased demand — sectoral analysis Other demand side policy issues

7 7

11 15

National Gas Supply Overview Investment in new supply sources Investment in transmission infrastructure

15 15 16 21

Chapter 3: International Markets

23

Demand for Export Gas

23

International supply Overview Investment in new supply capacity The changing market context Export potential — gas processing

24 24 26 28 29

Attachments

32

T H E

N A T U R A L

9

C H O I C E

T H E

N A T I O N A L

C H O I C E

CHAPTER 1

Introduction The Policy Context Over recent years, through the LNG Action Agenda, decisions by the Council of Australian Governments, the Ministerial Council on Energy, the Ministerial Council on Mineral and Petroleum Resources and outcomes of international meetings, governments have called for: ■

development of Australia’s energy resources

■

delivery to Australians of a reliable, competitively priced, sustainably produced energy supply, and

■

the greater use of natural gas in Australia.

A summary of relevant decisions is at Attachment 1 While delivery of these outcomes requires consideration of petroleum exploration industry issues related to pre-competitive work, exploration and project development this strategy focuses on project development (pre competitive and exploration issues are dealt with in other APPEA policy documents).

Gas — A Valuable Resource to the Nation Now and in the Future The gas supply industry makes a fundamental contribution to the Australian economy. The national benefits include: ■

reliable, clean, efficient energy supplies for families and industry

■

an impetus for regional development

■

significant flow on benefits to the economy via a substantial ancillary services sector (involving some 900 firms and up to 17 000 jobs)

■

significant company taxation revenue

■

significant resource taxation revenues (for petroleum they totaled $1.4 billion in 2001–2002), and

■

more than $2.6 billion in export income from LNG in 2001–02.

T H E

N A T U R A L

C H O I C E

1

T H E

N A T I O N A L

C H O I C E

About 19 per cent of Australia’s national primary energy consumption comes from natural gas. In 2000–01, the national market consumed 966 PJ of natural gas. Australia is the fifth largest exporter of LNG and has an enviable reputation as a reliable supplier. This export market (currently entirely from Western Australia) was supplied with 413 PJ of natural gas in 2000–01. In addition, much of the natural gas consumed in the national energy market was used for the processing of mineral commodities and the production of manufactured goods which were exported from Australia. With plentiful reserves there is a huge opportunity for Australia to generate additional national benefits including via: ■

creation of a less carbon intensive national energy market (particularly in eastern Australia)

■

an expansion of the use of gas in resource processing, with consequent reduction in the carbon intensity of the resource processing sector

■

additional LNG sales to Asia

■

LNG sales to the USA

■

development of alternative transport fuels to enhance supply reliability and lower carbon intensity, and

■

development of new chemical industries.

Australia’s Gas Resources Abundant resources of natural gas exist in the south east, the centre and in the north west of the continent. In recent years these resources have been supplemented by new discoveries in all these areas. In addition, coal seam gas (CSG) has emerged as an important new source of gas production from the Bowen and Surat Basins in Queensland and in a number of areas in New South Wales including the Sydney Basin. Significant new gas discoveries have also been made in the Otway Basin of western Victoria. At Attachment 2 is a map showing the location and size of Australia’s gas resources. Geoscience Australia classifies Australian gas resources as: ■

Known, which are then sub divided into: those considered to be commercially developable, that is, those reserves that have been proven and can be supplied to markets on a profitable basis, based on current costs of production and the price of gas, and those considered non commercial, that is those that are recoverable, but are not yet profitable to produce.

■

2

Potentially discoverable.

The industry is concerned that the split between ‘commercially developable’ and ‘non commercial’ is somewhat artificial. It involves government agencies making judgements about market prospects, the impact of fiscal regimes, technology developments and development plans, about which government is not necessarily well informed. For example, although gas development is underway in the Bass Basin it is shown at Attachment 3 as non commercial. Equally in the Bonaparte Basin, commercial discussions are in train but reserves are shown as non commercial. On the basis of this government classification, Australia’s total commercial and non-commercial reserves are estimated to be 129 080 PJ. In Australia’s three most prolific gas basins (Bonaparte, Browse and Carnarvon), only 22 per cent of the reserves are currently considered by government to be ‘commercial’. Geoscience Australia also considers that Australia has substantial potential undiscovered or unidentified resources. They estimate these resources to be upwards of 37 158 PJ (principally in the Carnarvon Basin). Reserves data is shown at Attachment 3.

Data Requirements Essential to the development of any policy is the need for reliable, consistent data. Appropriate government agencies and industry need to jointly develop a more appropriate reserves classification regime. Splitting known gas resources into commercial and non commercial is a highly subjective business and requires speculation about market prospects, the impact of fiscal regimes, technology developments and development time frames as well as about company investment profiles. On the demand side, industry forecasters as a group have been overly optimistic in relation to demand growth, particularly in south east Australia and particularly in relation to power generation. ■

Forecasts must be treated with caution. As an example, quite apart from power generation, actual gas consumption in Victoria was flat over the ten year period 1992–2001 whereas the 1992 forecast was for 1.5 per cent pa compound growth.

■

In 2000–2001, ABARE estimated the actual national production of natural gas at 1379 PJ. In 1996 ABARE forecast that production in 2001 would be 1629 PJ and the AGA forecast that it would be 1518 PJ.

T H E

N A T U R A L

C H O I C E

3

T H E

N A T I O N A L

C H O I C E

In recent years new gas discoveries have been made in a number of basins (e.g. Otway, Carnarvon, Browse and Bonaparte Basins). The discoveries in the south east have been close to existing markets. A number of companies have brought gas projects on stream in WA. In south east Australia, Origin/AWE/CalEnergy/Mitsui is developing Yolla and BHP Billiton is developing Minerva. OMV/Santos/Mitsubishi has built Patricia/Baleen. ExxonMobil and BHP Billiton recently brought on stream the fourth major gas producing field in Bass Strait, and ExxonMobil, BHPB, Woodside, Santos and a number of other companies are planning further exploration for gas in various parts of the Bass Strait and offshore Tasmania. The industry is at an advanced stage of planning further developments in the Otway (e.g. Thylacine/Geographe and Casino) and Gippsland Basins. Gas is also vying for the supply to the next tranche of electricity generation in Western Australia and looking to supply various new energy-intensive manufacturing projects. One of the most significant changes in Australia’s gas supply in the last five years has been the emergence of CSG as a viable major new source of supply located close to eastern Australian markets. While almost unknown in Australia in the mid-late 1990s, CSG now supplies over 25 per cent of the Queensland gas market, with contracts written for the supply of over 50 PJ of gas per annum by 2007. CSG is also being supplied to the Sydney market and a new CSG-fired power station has recently been announced for northern New South Wales. The resource potential in Queensland and New South Wales alone has recently been quoted by ABARE1 as around 250 000 PJ, many times the existing conventional gas resources in eastern Australia. How much of this resource will prove to be economic is still to be determined, but recent reports confirm over 1 600 PJ of proved and probable reserves in four fields in Queensland2. Current CSG resources are shown at Attachment 4. Coal seam gas has started flowing into Queensland and New South Wales and developments are under consideration in a number of other states. 1

2

4

Abareconomics ‘Australian Gas Supply and Demand Balance to 2019–20’ August 2002 Oil Company of Australia ‘Target’s Statement’ as amended September 2003

While Australia is 100 per cent self sufficient (with abundant domestic gas resources), there are additional potential sources of competitively priced gas, namely from the Timor Sea and Papua New Guinea. The Timor Sea fields contain over 20 000 PJ of gas with Papua New Guinea adding upwards of 10 000 PJ.

A Gas Development Strategy The key objective of any supply strategy is to facilitate the development of Australia’s gas resources, in such a way that they provide a reliable and competitive energy supply that allows possible market opportunities to be realised in a commercially practicable manner. In generating wealth for Australia gas potentially has a number of competitive advantages: ■

it has an abundance of gas resources. Australia is currently self sufficient in natural gas and will continue to be for the foreseeable future (see next section)

■

gas is a clean fuel with the lowest greenhouse gas emissions of all the fossil fuels. In many other respects it also has a small environmental footprint (see discussion at Attachment 5)

■

there is a wide range of potential development options, and

■

Australia has a very good reputation as a reliable supplier in export markets.

However, developing Australia’s gas resources faces a number of hurdles: ■

because gas supply to a customer requires dedicated pipeline or LNG shipping infrastructure, new gas can only be developed once a commercial contract is signed with a customer, thereby underpinning the substantial development costs

■

the national and export markets Australia is seeking to supply are currently illiquid. Within the next 20 years the liquidity of the national gas market is not expected to change much

■

Australia’s gas resources are located largely (but not exclusively) offshore and in high cost areas. In order to service potential export markets, the Australian industry is now moving into exploration and development locations that are very remote, further offshore and in deep water. By moving further offshore, the industry is faced with higher costs of development. Where ‘dry’ gas is concerned, there is no liquids-generated cash flow stream to augment the viability of any gas development

■

over 60 per cent of Australia’s sources of residential demand for gas are located in the south east and at a considerable distance from much of the undeveloped known resources in the north and north west (on the other hand, much of the energy intensive minerals processing and all export gas activities are in the west and north) (see Attachment 6)

■

gas faces strong market competition: in national energy markets from other fuel sources (abundant, low cost, high quality supplies of coal, relatively cheap coal-based electricity and renewable energy) all of which are advantaged by preferential fiscal treatment relative to gas, and

T H E

N A T U R A L

C H O I C E

5

T H E

N A T I O N A L

C H O I C E

in export and import competing markets, from an abundance of resources (see Attachment 7) often with low development costs and access to projectspecific government support. A successful gas development strategy must be focussed on servicing: ■

the national (predominantly east coast and resource development associated) market, and

■

an export gas market based in the north and north west of Australia. This market will involve gas as a commodity as well as processed gas.

Each of these markets will be considered in depth in the following chapters.

Data Policy Measures Government agencies and industry need to jointly develop:

6

■

a more objective way of classifying gas reserves in Australia to avoid the subjective judgments (dependent on market, technology and fiscal factors) about the capacity to commercialise gas that are inherent in the current system, and

■

better demand and supply scenarios that more realistically take account of sector-specific growth patterns and inter fuel competition.

CHAPTER 2

The key policy

The National Market

Natural Gas Demand in Australia

outcome sought to enhance national use of natural gas is the removal of both demand and supply side barriers to access to markets.

Overview Natural gas is a major energy source in Australia. ABARE estimates that consumption of gas has grown by an average of 6.9 per cent a year over the past 25 years, almost tripling its share of total energy consumption. ABARE forecasts this pattern to continue with a projected average growth rate of 3.4 per cent a year to 2012. Other sources (e.g. ACIL/Tasman) have a slightly lower growth rate forecast. As a proportion of total energy fuels used, natural gas increased from 16.6 per cent in 1991 to 19.7per cent in 2001. Natural gas consumption has increased by nearly 50 per cent since 1990. The most rapidly growing sectors have been mining/minerals processing (growth of over 50 per cent) and manufacturing (growth of over 30 per cent). Much of the resource development use is in Western Australia and the Carpentaria province of Queensland. The aluminum industry consumes 10 per cent of Australia’s domestic gas. Other major natural gas using industries include brick making, glass manufacture, pulp and paper manufacturing and the cement industry. More households now have access to natural gas. In Australia as a whole, 46.7 per cent of houses are connected to natural gas. Household connectivity is above 50 per cent in the Australian Capital Territory (62.4 per cent), Western Australia (58.5 per cent), Victoria (85.4 per cent) and South Australia (53.8 per cent). In Victoria 90 per cent of households have access to natural gas supplies and in Western Australia the figure is 76 per cent, while in South Australia it is 80 per cent. There are 3.36 million residential gas consumers and about 105 000 industrial and commercial gas consumers in Australia. In Australia, gas can be best characterised as competing in three regional domestic energy markets: ■

the Western Australia market

■

the Northern Territory market, and

■

the integrated Queensland, New South Wales, Victoria, Tasmania and South Australia market).

Development of natural gas resources has historically been State based along with transmission infrastructure which was not interconnected on the east coast.

T H E

N A T U R A L

C H O I C E

7

T H E

N A T I O N A L

C H O I C E

As such, historically customers have had a high level of dependence on a single supply source. Transmission and retail/distribution networks were highly protected by way of being serviced by government retail companies or private, regulated franchises. Governments also regulated retail gas prices. The rapid uptake and growth in gas demand was supported by these low, regulated retail prices, with upstream development and downstream market development and growth underwritten by long-term gas supply contracts. The low producer prices and supply franchises led to a gradual stagnation of the eastern gas market. This situation is rapidly changing in all of the regional markets primarily as a result of the reforms of the 1990s, although this has not solved all the problems associated with getting more gas to markets. Gas has been able to make gains in its market share of primary and final energy (Primary and Final energy consumption in Australia, by fuel is at Attachment 8) in large part due to significant construction of pipelines. There has been substantial growth in transmission pipelines in Australia since 1990. According to the Australian Gas Association, there was an 113.9 per cent increase in the length of transmission pipelines in use between 1989 and 2002 — in 1989, the length of gas transmission pipelines in use was 9 399 km, and by 2002 this had increased by 10 710 km to 20 109 km. This has resulted in the interstate trade of gas and changes to transmission, distribution and retail companies. The number of retailers hasn't effectively increased, but they differ in that they operate across states. For example, AGL formerly operated only in New South Wales, Gascor in Victoria, SAGASCO in South Australia, and Energex in Queensland. AGL now operates in New South Wales and Victoria, Origin operates in South Australia and Victoria, TXU operates in Victoria and South Australia, and Energex operates in Queensland, Victoria and New South Wales. Retailers have also adopted differing business strategies, such as: ■

companies becoming energy retailers, selling both gas and electricity (AGL, TXU, Origin)

■

vertically integrating with gas production (Origin with Yolla and Coal Seam Gas)

■

diversification of a company’s gas supply portfolio (AGL/TXU), and

■

acquisition of significant gas-fired power generating assets (Origin in South Australia, TXU in Victoria/South Australia and Alinta in Western Australia).

Effectively, the gas market in the eastern states is becoming a single pool. That is, retailers have a portfolio of gas supply that can be moved around into any market.

8

Once the Tasmanian market is fully developed, there will still be limited large growth opportunities for gas in the southern states in the near term, with no new industrial projects on the horizon. The role gas will play as a fuel source for new electricity generation, particularly in New South Wales and Victoria is unclear due to inter-fuel economics, although consideration of potential public benefits and addressing the unfavourable tax treatment for offshore gas would change this position. There are some potential growth opportunities in Queensland in both minerals processing and electricity generation. Even after the significant advances arising out of the 1990s reforms, the Australian gas market is still relatively small, lacking liquidity and depth. A recent ABARE study has confirmed that this situation is likely to remain for some time. More supplies and customers connected by more pipelines and more facilities such as Duke Energy’s Victoria hub at Longford, will encourage more trade in gas. Then the Australian market will eventually be able to develop liquidity and depth. For production of natural gas in eastern Australia to keep pace with growing demand in the decade 2010 to 2020, the right development framework and market signals (including potential public benefits) will be needed to ensure sufficient gas reserves can be commercialised. Key drivers for the demand for gas are: ■

population growth

■

economic growth

■

inter-fuel economics, and

■

consumer attitudes.

Potential for increased demand — strategic drivers A number of key public policy issues have the potential to lead to a significant increase in demand for natural gas in national energy markets. Depending on how these issues are resolved in the public domain, there is potential for demand to increase substantially over and above the growth potential identified in the next section. The abundance of natural gas resources in Australia means that there is a capacity in both the medium and longer term for natural gas to play a major role in meeting Australia’s transport fuel needs.

T H E

N A T U R A L

C H O I C E

9

T H E

N A T I O N A L

C H O I C E

A key public policy issue relates to risk perceptions associated with an increasing level of reliance on imports as a source of transport fuels. What are the national economic, defence and foreign policy public benefits to be derived from having a higher level of self-sufficiency in supply of transport fuels for Australia? Currently Australia’s level of petroleum liquids self-sufficiency exceeds the 80 per cent level. Production of petroleum liquids in Australia is projected to decline significantly in the period to 2012 and self-sufficiency levels are projected to drop to or below the 50 per cent level. While an enhanced exploration effort and demand management measures will have an impact on this decline it is likely that Australia will have to become increasingly reliant on imported fuels or develop a substantial gas-based alternative fuel strategy. Which option is chosen depends on community perceptions of supply risk as: ■

more oil supplies become concentrated in the Middle East

■

the refining infrastructure in Australia and the region becomes fully utilised

■

the demand for cleaner fuels increases, and

■

risks of supply disruptions arise along supply routes.

The public benefit to be generated by maintaining supply security and reliability levels is a matter for governmental judgement. A second public policy issue relates to judgements about how quickly and on what scale the nation wishes to change the carbon-intensity of the national economy. There are three sub questions. What are the public benefits, nationally and internationally, of changing the carbonintensity of energy intensive manufacturing and resource processing in Australia? What are the public benefits, nationally and internationally, of changing the carbon-intensity of the likely tranche of growth in electricity demand over the next two decades? What are the public benefits, nationally and internationally, of changing the carbon-intensity of the current base load electricity generation system? When will such a change be required and how big a change will be needed? While a suite of public measures will be required to address all three of these questions, given ■

the magnitude of the changes involved

■

the current state of development of alternative technologies and their cost, and

■

the scale of supply that may be met from alternative technologies,

it is highly likely that natural gas will be a key source of less carbon-intensive energy for Australia for the foreseeable future.

10

The economic costs of making such changes to lower carbon-intensity fuels is also a key element of the public policy debate given the energy intensity of Australia’s lifestyle and the need to maintain the competitive position of Australian trade exposed, energy-intensive industries. The lack of international certainty about: ■

the entry into force and effectiveness of current carbon intensity reduction approaches, and

■

the additional uncertainty about potential carbon-intensity reduction approaches in the longer term

complicates the public debate about the need for, and benefits flowing from, strategies to switch to lower carbon-intensity fuel. The third public policy issue is the extent to which governments wish to take a leadership role in creating gas processing industries to add value to Australia’s abundant gas resources. In the view of industry, these are issues which should be at the core of public discussion about the strategic development of energy supply in Australia. To the extent that governments decide there is a significant national and/or international public benefit to be gained, there are grounds for positive fiscal assistance to develop gas and deliver these public goods.

Potential for increased demand — sectoral analysis Over and above demand growth driven by changes in strategic policy directions nationally, there is substantial potential for demand growth within the existing national market. In this context, five segments of demand with different price influences can be distinguished: ■

power generation

■

residential

■

industrial use of gas for process heat

■

transport (including gas-to-liquids and hydrogen production), and

■

gas as a feedstock.

Power generation Currently natural gas has significant penetration in the electricity generation market in South Australia, Western Australia and the Northern Territory. In Tasmania, once gas replaces fuel oil at Bell Bay, competition for new generating capacity in that state will be between gas, renewable energy and co-generation.

T H E

N A T U R A L

C H O I C E

11

T H E

N A T I O N A L

C H O I C E

Should the PNG Pipeline, or pipelines from the north west proceed, or CSG expand substantially, gas-fired generation will penetrate further in eastern states markets. Fuel inputs for thermal electricity generation, by state are shown at Attachment 9. The challenge areas for growth of gas in electricity generation are Victoria, New South Wales and south east Queensland. In all of these areas, the relatively low cost of coal (partly due to its favourable tax treatment) and the manner in which electricity transmission prices are set on a basis that may not reflect the transmission distance, are problems for gas-fired generation participating in base-load electricity generation. Gas has potential in peak and some intermediate-load electricity but some of this opportunity may be missed if the tax differential with coal, subsidies for renewable energy and the lack of cost signals for electricity transmission are allowed to continue. There are a number of factors working against the penetration of gas into the east coast electricity market. Gas fired power stations are cheaper to build than coal fired stations in terms of capital but they are more expensive to run (the delivered fuel carries a higher secondary tax burden and the fuel sources are generally remote from power stations). Therefore, the marginal cost of electricity produced by gas-fired power stations is more expensive, meaning that they compete primarily as peaking stations, or at best, intermediate stations. The following table highlights some of the differentials in current resource taxation for competing fuels used in power generation. Fuel

Current resource taxation per GJ

Brown Coal VIC royalty

approx $0.03

Black Coal NSW royalty

approx $0.07

Onshore Natural Gas SA/QLD royalty Coal Seam Gas NSW/QLD royalty Offshore Natural Gas Commonwealth PRRT

less than $0.25 approx $0.25 more than $1.00

In the case of offshore gas the tax differential with brown coal largely represents the difference in competitiveness of the two fuels in power generation. Given the relatively high total operating costs (largely delivered fuel cost) of gas-fired power stations and the fact that they operate generally as peakers, it is possible that retail electricity price caps could also deter the establishment of such stations. Electricity price caps can distort the pricing signals that users receive and also therefore potentially distort the price signals that retailers receive from users. Among the great advantages of gas-fired power stations is their ability to be built relatively quickly and to be locate close to load centres. A serious market flaw is

12

that the current electricity tariffing regime provides limited ability to reflect the benefits associated with the proximity of a generator to a large load. For example, a generator located in the LaTrobe Valley pays essentially the same transmission tariff as one located in Altona and near to large load. This effectively nullifies the locational advantage a gas-fired power station may have over a coal-fired station unless the gas-fired power station has no intention of exporting its electricity from its host site (which is unlikely in most situations). State governments, particularly on the east coast (greenhouse issues aside) have an incentive to prefer coal-fired power generation because coal use usually attracts a state excise or royalty. Until the recent commercialisation of CSG, gas use usually resulted in a tax payment to the Commonwealth. Coal-fired power stations are also usually more labour intensive (especially the coal mining) which can also make them more attractive candidates to States in terms of employment (particularly regional) and the political issues that go with that. Potentially, governments could stimulate the further use of gas in electricity generation by applying a tax regime on gas that allows it compete with coal on a similar tax basis (i.e. PRRT is more expensive than a royalty) as far as the fuel cost for electricity generation is concerned. Potentially this could be done by giving users of gas for new power generation a rebate of the differential taxation revenue.

Residential Natural gas is now widely available to households across Australia, particularly in Victoria, South Australia and Western Australia where access is available to 75 per cent of all households (see Attachment 10) and the Sydney region. It is important to note that 100 per cent access to households in Australia is effectively impossible as some customers are simply too isolated to make connection economically viable. However, the Victorian Government is providing grants for the construction of distribution pipelines to some of the larger isolated communities in that state. Another factor impacting on the usage of natural gas in households is the availability of subsidies for renewable energy (e.g. for solar hot water heaters).

Industry — gas as process heat The process energy/direct heat market is in minerals processing, iron and steel and non-ferrous metals production, petrochemicals, manufacturing, service industries such as tourism and health care, and the residential sector. Several of these (energy intensive export and import-competing industries such as minerals processing, food processing, pulp and paper, and tourism) are price takers in their own markets and so are sensitive to energy prices. They are also very important industry

T H E

N A T U R A L

C H O I C E

13

T H E

N A T I O N A L

C H O I C E

customers due to their substantial energy requirements e.g. the aluminium industry accounts for 10 per cent of Australian domestic gas demand. The energy sources which compete with gas in these markets are coal, electricity, fuel oil, solar hot water, biomass (in pulp and paper and sugar), and hydroelectricity in Tasmania and in the Snowy Scheme. In the process-heat market, gas generally competes strongly with these alternatives, although this does depend on geographical location. There is already substantial market penetration by gas in Victoria, South Australia and Western Australia and in parts of regional New South Wales and Queensland. New markets will open up in Tasmania following the completion of the new Tasmanian transmission and distribution pipelines. Penetration in Queensland markets will be enhanced as CSG is developed. Should the PNG Pipeline or pipelines from the north west proceed it is expected that there will be additional penetration of natural gas into eastern state markets. There is potential for growth in Western Australia, particularly in minerals processing, and an opportunity in the Northern Territory depending on local economic growth and on a decision as to whether the Gove project converts to gas. An important remaining target area for growth is on the east coast stretching from Gladstone in Queensland to Wollongong in New South Wales.

Transport In relative terms, gas for transport use is a very small national market sector. The potential for gas in the transport market is almost exclusively in road transport as CNG or small scale LNG (and LPG which is not being considered here). In the immediate future there is scope for limited additional penetration of CNG as a transport fuel. In the longer term, options may arise for conversion of gas to liquids (both for domestic and export markets) and for the use of gas to produce hydrogen as a transport fuel. This latter option appears on current indications to be a longer term possibility.

Gas — raw material for production Natural gas is already used as a raw material for the production of chemicals and fertilizer in Australia. Ethane is used to produce plastics. A new fertilizer production plant is under construction on the Burrup Peninsula. The capacity to further commercialise gas for these purposes depends on the extent to which Australia can offer an internationally competitive investment regime for new projects. This issue is discussed further in Chapter 3.

14

Other national demand side policy issues There are also a number of market regulation issues (mainly in State jurisdictions) to be considered including: ■

retail price capping which does not allow market-driven price signals to generate a supply side response

■

Victorian ‘market carriage’ arrangements for gas transportation which inhibit firm delivered gas sales within or out of the State and are preventing the benefits of deregulation being fully realised

■

the additional costs imposed by the Victorian gas market, and

■

the Victorian Significant Producer Legislation which lessens competition and impacts on market development, inconsistent with the Trade Practices Act. (The Victorian Essential Services Commission has recommended the repeal of the legislation and the recommendation is currently being considered by the Victorian Government).

The industry considers that urgent action is needed to address these issues.

National Gas Supply Overview Australia has abundant supplies of natural gas and coal seam gas. Currently 966 PJ are consumed domestically per year. There are substantial resources available to meet demand growth, but there is a potential for a demand supply imbalance to occur due to the geographical location of know gas reserves relative to potential growth in residential demand and demand for electricity generation. It is generally assumed that reserves in the Cooper-Eromanga, Bass, Bowen/Surat and Adavale Basins will be all but depleted before 2020. This would mean that only the Gippsland Basin will remain as a significant reserves base close to the eastern market (see ABARE). As such, south eastern Australian supplies (see Attachment 11) may need to be supplemented by a northern or north western supply (any or all of gas from PNG, the Timor Sea, the Browse Basin and the Carnarvon Basin through a transcontinental pipeline) and CSG to meet the growing demand. However there are differing views between industry and government on the undiscovered potential of the Cooper Basin. Also the resource potential of the Otway Basin and some other south eastern basins has yet to be fully appraised.

T H E

N A T U R A L

C H O I C E

15

T H E

N A T I O N A L

C H O I C E

For production of natural gas in eastern Australia to keep pace with growing demand in the decade 2010 to 2020, the right development framework and market signals will be needed to ensure sufficient gas reserves can be commercialised. This will be particularly the case if additional reserves need to be discovered and assessed in frontier and deepwater regions.

Investment in new supply sources The key issue that needs to be recognised in identifying and developing Australia’s gas resources, so that they continue to provide a competitively priced domestic supply of energy, is that Australian projects are competing for investment capital against other nationally and globally. Of paramount importance in the policy framework for gas development is that decisions on project development and technologies are based on their economic merits and that gas is allowed to find its highest value market. Without that certainty, investors will have less confidence and gas reserves will be stranded for longer than necessary, hampering market development. The key strategic themes that need to be addressed (particularly if major gas developments are to occur in remote locations and/or in deep water) are: ■

remaining an internationally attractive investment destination, and

■

the regulatory regime.

These aspects are discussed in the following sections.

Maintaining international fiscal attractiveness The petroleum industry is a global industry. Australian projects are competing for investment capital against other projects in Australia and against projects in other countries (particularly in the developing world). Also in that context, most countries with gas projects that are competing with Australian projects have no obligations under the Kyoto Protocol (the USA or non-Annex A countries), and hence no greenhouse-related cost impost. The impact of taxation on the return from gas extraction and production activities is a key determinant of the flow of investment capital to Australian developments. Positive policy decisions will provide near-term stimulus to gas development. However, given the long lead times involved in gas exploration and subsequent development decisions, it is unlikely that any of the PRRT issues raised below will impact negatively on Commonwealth revenues in the next five years. Equally, the flow-through share proposal will have very minimal immediate revenue implications for the 2004–2005 Commonwealth Budget.

16

Indeed, over the long term, increased activity would most likely lead to an increase in the overall level of industry investment and ultimately therefore to the growth of the tax revenue base. There are a number of taxation issues that need addressing: ■

Company tax provisions need to remain internationally competitive. While the decision to cap the depreciation effective lives of a range of oil and gas production assets in 2002 was a positive step, Australia still remains relatively less attractive than competing jurisdictions using a range of fiscal criteria (see Attachment 12).

■

Changes to the PRRT. The base parameters of this system have remained unchanged for a decade while market expectations in relation to reasonable rates of return and risk profiles have changed significantly. Currently, it is likely that for new gas projects the PRRT payments will need to be made before an economic rent has been earned. In short, tax will be paid before a reasonable rate of return has been generated by the project. Accommodating the very different cost and risk profiles between oil and gas projects remain priorities. Options canvassed by APPEA include: a change to a lower rate of tax for PRRT for designated frontier/deepwater projects the uplift rate for un-deducted general project costs under PRRT should be increased to at least the long term bond rate plus ten percentage points, and the PRRT GDP factor rule which can act to limit the rate at which exploration costs are compounded forward should be modified to recognise the significant time lags between exploration and subsequent development decisions for gas fields.

■

In addition to the above, the company taxation treatment of exploration expenditures incurred by junior explorers needs to be revised for companies where there is insufficient income against which such costs can be deducted. APPEA considers that this can best be achieved via a flow through share scheme, and

■

As suggested in the section on power generation, equalisation of resource taxation for fuel supplies to that sector (e.g. by the use of rebates to gas users) could be considered.

The House of Representatives inquiry into impediments that impact on exploration decisions in Australia’s resources sector specifically addressed a number of fiscal issues. The inquiry report recommended that certain aspects of the PRRT regime be reviewed to examine whether it is acting to impede investment decisions in the industry. Specific reference was made to the carry-forward rate for un-deducted general project costs and the rate applicable for exploration costs incurred more than five years prior to the granting of a production licence. In addition, the Committee identified a range of issues that were limiting the ability of junior explorers to raise capital for exploration activities. It recommended that

T H E

N A T U R A L

C H O I C E

17

T H E

N A T I O N A L

C H O I C E

consideration be given to the introduction of a flow-though share mechanism, the adoption of simplified capital raising processes associated with equity funding and the examination of a scheme to encourage juniors to explore on the margins of onshore production basins for small accumulations.

The regulatory regime Full competition in gas markets is essential to encourage the wider penetration of gas. One of the principle drivers for competition policy in the gas market has been the desire to ensure competitive, cheap supplies of gas to customers. Australia already has the second lowest gas prices in the OECD and continuing pressure for low or even lower gas prices will not be conducive to development of the required supply. The emphasis should be on a reliable and sustainable, competitively priced supply, and not simply regulated cheap gas. The price needs to be competitive for customers and needs to provide adequate returns to producers such that production at the level of reliability required by customers is maintained over the long term. End consumers cannot be shielded from the competitive cost of energy supply. Freely negotiated market prices must be allowed to provide the supply/demand signals between consumers and producers. Prices of competing energy sources should also reflect the true costs of supply and delivery to markets. As examples, there should not be subsidies for renewable energy which in effect discriminate against gas in a market where it might play a greater role, such as in peak-demand electricity generation. Similarly, electricity tariffs which do not fully reflect transmission costs can discriminate against gas in new, distributed energy systems. Governments are well advanced in implement the Parer Report’s recommendations on governance arrangements for the electricity and gas industries. In relation to natural gas the time frame for implementing these decisions now stretches to 2005. Further delay in this timetable would not be acceptable. While the move to a single national regulator announced in December 2003 is welcomed, it is vital to recognise the differences between the electricity and gas markets and to maintain separate gas and electricity expertise. It is also important that any body established to advise on changes to the Gas Pipeline Access Code have direct industry representation and not be merely made up of government-appointed experts. Without direct representation, there will not be the benefit of industry experience and views of the many practical issues affecting the workability of the Code. Aspects of regulation of downstream gas markets by some State jurisdictions are having a detrimental impact on gas market development, especially:

18

■

retail price caps in New South Wales and Victoria

■

‘market carriage’ arrangements in Victoria, and

■

significant producer provisions in Victorian legislation.

In relation to upstream competition, four factors have been thoroughly canvassed over the past ten years, namely: ■

inter-basin competition

■

joint marketing

■

pipeline access, and

■

third party access to upstream processing facilities.

Competition policy — inter-basin competition: Ensuring competition on the supply side of the gas market by bringing about more basin-on-basin competition goes beyond just enhancing price competition. Different petroleum exploration and production companies have different expertise in finding and developing and marketing gas. Competition between those players and their different development proposals will allow the optimum market development to ensure long-term reliable and sustainable supplies and competitive prices for producers and consumers alike. Conversely, interference in gas development to favour one project over another or one market over another — be it domestic markets over export markets or one regional market over another — will over time see a diminution of supply investment. This will ultimately lead to market failure, resulting in inadequate supplies and higher than necessary prices. Competition policy — joint marketing: The best way of introducing competition into the supply side of the gas market is to allow a greater range of supply options to be developed so that there can be more basin-on-basin and gas on gas competition. Australia has some of the cheapest ex-plant gas prices in the OECD, so there is no evidence of any price ‘gouging’ by producers and, as such, the current levels of competition appear to be acting effectively. Western Australia, where gas-on-gas competition has been in place for over a decade, is a prime example.

T H E

N A T U R A L

C H O I C E

19

T H E

N A T I O N A L

C H O I C E

Separate marketing is pursued by the industry where it is feasible to do so. However, to require separate marketing in all situations, in the context of Australia’s still relatively immature illiquid gas market, might simply reduce the position of joint venturers with smaller production shares to the point where it is uneconomic to sell. In turn this may place entire developments in doubt, given that upstream joint venture arrangements usually require most, if not all, joint venturers to agree to commit to a development. It would be far better to have a policy environment in place to encourage the finding and development of more sources of supply and to ensure the viability of joint developments. Joint marketing arrangements can assist to achieve this outcome. They are also equally important in supporting the development of new reserves in an existing field. It must be noted that for project developments, new contracts need to be signed prior to project investment being sanctioned and at the same time by all participants, and that joint marketing arrangements facilitate this process. Without joint marketing, the likelihood of each participant signing volumes at the same time would be very low, particularly in an illiquid market. New developments in existing areas (brownfield developments) are similar to greenfield developments and have similar issues, also requiring contract timing and financing. Because of these issues, without joint marketing, some new projects may not proceed. The Parer Report’s recommendations on joint marketing failed to take account of the significant increase in the diversity of upstream gas supplies on offer, reflected in contracts signed during the latter part of the inquiry. The current state of development of the Australian market and its lack of liquidity and depth generally requires that joint venturers can market jointly. Indeed, given the lack of depth in the market, forcing separate marketing may not in fact lead to additional price competition. The upstream industry will continue to draw this to the attention of governments as they reach decisions on Parer’s recommendations in developing a national energy policy. Competition policy — pipeline access: It is vital for the industry that producers can gain access to pipelines on fair and reasonable terms and that pipeline owners can secure a fair return to encourage investment in economic new pipelines. The gas access regime is currently being reviewed by the Productivity Commission. The upstream industry believes that there is no evidence that the regime has hindered investment in economic pipelines and there should be no wholesale changes. However, some enhancement of the Code is warranted to encourage investment in greenfields pipelines, for example to give greater regulatory certainty. The upstream industry supports the implementation of the recommendations of the Parer Report in this regard. Competition policy — third party access to upstream processing facilities: The present coverage of facilities under Part III A of the Trade Practices Act is appropriate and should not be extended to any part of the gas production process, such as feeder pipelines, gathering systems or gas processing plants. There is no

20

theoretical case for access regimes to be extended to production and processing facilities and, in practice, there is cooperation between upstream facilities’ owners where that cooperation is commercially advantageous in getting gas to markets. Coal Seam Gas: Coal seam gas faces a number of land owner perception issues which can act to inhibit its development. There is a need for industry to ensure that land owners are fully informed about the impact of CSG developments on their land. In Queensland, updating of the Petroleum Act to clarify the management regime applying to CSG needs to be finalised. The main objective is to clarify that CSG will normally be produced from petroleum leases under the Petroleum Act, to facilitate consultation and negotiation between alternative commodity tenure holders, and to empower the Minister to determine the best resource management outcome where there are potentially conflicting developments of alternative commodities.

Investment in transmission infrastructure Identification and exploitation of gas resources is a prerequisite for greater use of gas, but it is not a sufficient condition. Gas transportation infrastructure also needs to be developed, usually in the form of gas transmission pipelines or LNG shipping infrastructure. Transmission pipeline infrastructure to support gas development often needs to be constructed somewhat in advance of ultimate market demand. A mix of regulatory, commercial and construction factors need to be resolved well in advance of anticipated demand if transmission facilities are to be constructed in a timely manner. Against this background, regulatory and taxation arrangements need to recognise the fact that: ■

there are lengthy lead times

■

the company tax system must be internationally competitive

■

clarification of the gas transfer pricing mechanism for PRRT is essential

■

there is a need for efficient and effective approvals processes for the construction of pipelines (including for native title onshore and offshore and the capacity for pipelines to transit marine and terrestrial conservation areas), and

■

there must be an investment framework for pipeline infrastructure which encourages investment in, and facilitates, access to pipelines.

Governments also need to recognise that certain key facilities are common to a number of projects and that the development of hubs in industry activity can be very helpful to the development of both export markets and national energy policy.

T H E

N A T U R A L

C H O I C E

21

T H E

N A T I O N A L

C H O I C E

National Market Policy Measures The key policy outcome sought to enhance national use of natural gas is the removal of both demand and supply side barriers to access to markets. The key regulatory principle should be that decisions on project development and technologies are based on their economic merits and that gas is allowed to find its highest value market. Industry development policies for renewable energy should be developed in such a way that they minimise distortions of fuel choice decisions. Remove electricity price caps that distort price signals retailers receive and address other state-based regulatory issues. Remove distortions in the electricity tariff setting process that fail to recognise the ability of gas fired generation to locate close to load centres. Equalise resource taxation across fuels competing for power generation. Review the key parameters of the PRRT system to ensure that they have kept pace with changing market expectations and changing risk perceptions. The PRRT should not be payable until gas projects have earned a reasonable rate of return on investment (based on market expectations). Clarify the gas transfer pricing mechanism in the PRRT legislation. Adopt a flow through share scheme to facilitate the availability of equity funds for small independent gas explorers. Develop a pipeline investment framework that facilitates investment in pipeline infrastructure and access to pipelines. Enhance the effectiveness and efficiency of the upstream gas market by: ■

facilitating basin-on-basin competition in the upstream gas market

■

facilitating separate marketing while maintaining the capacity for industry to utilise joint marketing arrangements

■

retaining the pipeline access code with modifications to encourage increased investment in new pipelines, and

■

retaining the present arrangements governing access to upstream processing facilities via the industry code of conduct rather than any extension of coverage under Part IIIA of the Trade Practices Act.

Finalise legislation in Queensland to give effect to the management regime for the development of coal seam gas.

22

CHAPTER 3

International Markets

The key policy

Demand for Export Gas

outcome

Key factors impacting on international demand for gas are:

sought in

■

sustained demand growth for competitively priced energy (driven by population growth and changing lifestyle expectations as economic development occurs)

■

a desire for fuel supply security

■

a desire for lower levels of atmospheric related externalities flowing from energy use (including particulates, acid rain and greenhouse gas emissions), and

■

the availability of transportation infrastructure.

regard to international markets relates to ensuring Australia

These factors will drive a demand for gas to be traded both as a primary commodity (by pipeline and as LNG) and as a processed product (e.g. in petrochemicals and

remains an

alternative transport fuels).

internationally

International trade in gas is developing rapidly and new global gas flows are coming into operation (see Attachment 13).

competitive

This increased trade is being fuelled not only by demand growth in Asia but

destination for

also be demand growth elsewhere. For example in 2003 European natural gas consumption was projected to be 19 trillion cubic feet (tcf) and USA natural gas

investment

consumption was projected to be 28 tcf.

capital so that

In the case of Europe, economic growth, a push for a less carbon intensive energy

commercial opportunities can be

sector and the ageing of existing nuclear facilities are likely to lead to increased demand for natural gas (consumption is projected to grow to 24 tcf by 2012). Russia, the Caspian Sea region, the Middle East and North Africa are likely to be the main supply sources for this demand increase. Europe’s reserves-to-production ratio is 23 years.

exploited as

USA gas consumption is projected to grow substantially by 2010. The North

they arise

American gas reserves-to-production ratio is four years. This has led to increased

in global

(more than 20 times today’s rate) in 2025.

markets.

Given the expected growth in global LNG demand, LNG receiving-terminal

interest in LNG imports. USA imports of LNG could reach 4.7 tcf per annum

infrastructure needs to be developed. For example, over 20 proposals for new terminals along the North American East Coast and Gulf of Mexico have appeared over the past few years, plus at least another 10 on the West Coast. Not all will be

T H E

N A T U R A L

C H O I C E

23

T H E

N A T I O N A L

C H O I C E

built, but a mix of regulatory, commercial and construction factors means that work will need to begin now simply to meet that demand. Australia is well placed to gain market share in the emerging LNG market on the west coast of the USA. It is reasonable to expect that winning market share in this region would generate national economic and regional and industrial benefits gains for Australia equivalent to those being generated by the existing export sector. Developing economies on the Asia Pacific Rim are demanding more gas to meet the needs of rapidly growing economies and improving living standards (including improved environmental standards). The Asian reserves-to-production ratio is 118 years. While some of this growth in energy demand will be met from piped gas (eg in China) LNG demand is also expected to grow substantially. Current LNG demand in the region is 80 million tonnes per year and this is expected to double by 2015. At Attachment 14 are ABARE demand projections for LNG in Asia for the period to 2015. Japan dominates this market at present and is likely to continue to do so over the period to 2015. ABARE expects Australian exports to increase to 20 million tonnes by 2010–11, and then to 26 million tonnes by 2019/20.

International Supply Overview The world has abundant natural gas resources. The greater part of global gas reserves are concentrated in Russia, the republics around the Caspian Sea and in the Middle East (see Attachment 7). While pipelines will play a major role in meeting growth in gas demand in Europe and to some extent in Asia, an expanded trade in LNG is also expected to be a major supply source. LNG Exports: Australia is currently the world’s fifth largest LNG exporter behind Indonesia, Malaysia, Algeria, and Qatar, exporting 413 PJ or approximately 8 million tonnes per annum. Exports are expected to grow substantially over the next few years as new production facilities come on stream in Darwin (using Bayu-Undan gas) and in Western Australia (on the Burrup Peninsula). Growth is likely to be sustained with developments on Barrow Island and the Burrup Peninsula in an advanced planning stage. In the longer term, further facilities are being considered for Barrow Island, Darwin and near Broome.

24

One of the major advantages Australia has developed in the Asian LNG export market is its reputation as a reliable supplier of gas. Maintaining Australia’s reputation as a reliable supplier will be a key national policy issue for the future. Loss of this reputation could seriously disadvantage Australia as it seeks to expand its share in global gas markets. Export Benefits: LNG exports are important national income earners in their own right and, in addition, they create substantial regional and national economic benefits. These benefits (including a substantial increase in taxation revenue) would come on stream as the ageing of the Australian population begins to impact on a number of fiscal areas. The LNG Action Agenda (using data prepared by the University of Western Australia) notes that the existing production capacity: ■

increased national GDP by 1.24 per cent

■

increased Western Australian Gross State Product by 14 per cent

■

created an additional 80,000 jobs

■

increased annual Commonwealth revenue by $850 million and annual state revenue by $206 million

■

increased Australian exports by 3.5 per cent, and

■

created major opportunities for Australian industries.

Access Economics has estimated that the $2.4 billion expansion of the North West Shelf Development Project, now nearing completion, would deliver the following benefits during its construction and 20 year operational life.

North West Shelf Expansion — Economic Benefits to Australia Construction

Operations (per annum)

2002–2004

2010

2020

(1999 $ million) Private Consumption

500

600

1,300

GDP

1,700

1,400

1,800

Exports

200

1,100

1,100

Tax Revenue

300

200

Employment (number)

9,000 (av)

6,000

400 9,000

Source: Access Economics

T H E

N A T U R A L

C H O I C E

25

T H E

N A T I O N A L

C H O I C E

The Bayu-Undan/Darwin project (currently under construction) will also generate additional taxation revenue and export benefits in the short to medium term. A little further into the future, it is estimated that the proposed Gorgon project will: ■ ■ ■

■

entail $11 billion of investment expenditure to 2020

increase exports by $2 billion per year

add 6000 jobs nationally, 1700 of which will be in Western Australia, and

generate some $17 billion of PRRT payments over the project life.

Exports can also play a role in improving project economics so that additional gas can be developed and supplied to national markets (production for export vs. domestic is shown at Attachment 15). Processed Gas Exports: The gas export market in Australia is presently LNG dominated (a market which is expected to grow significantly) but there is a view that substantial additional future potential lies in the export of gas transformed into GTL and chemicals. For some time there has been an expectation that Australia’s existing (import competing) chemical industry would be supplemented by new gas processing projects in a number of locations. The first of these projects (an export fertilizer plant) is currently under construction on the Burrup Peninsula. If issues relating to both gas supply costs and project capital costs can be addressed, there are other substantial opportunities (chemicals and alternative transport fuels) to further exploit Australia’s natural advantage in relation to gas resources. In turn these opportunities would add to Australia’s national wealth and enhance supply reliability for transport fuels. Australia has an abundance of gas available, if commercial circumstances can be established, to serve both commodity export and processed gas export industries.

Investment in new supply capacity Investing in new supply capacity directed at export markets will deliver major economic benefits to Australia and significant environmental benefits globally. The key supply objectives for Australia must be to:

26

■

maintain its ‘international reputation’ so as to expand LNG sales in Asian markets

■

win market share in emerging LNG markets including the USA, and

■

maximise long-term economic and social benefits from the development of Australia natural gas resources by establishing and expanding gas processing industries (including chemicals and alternative fuels).

In meeting these objectives Australia has a number of advantages including: ■

abundant gas resources

■

a reputation as a reliable international supplier

■

a skilled workforce

■

a stable political and administrative system, and

■

a location in close proximity to markets.

It also faces a number of hurdles including: ■

Australian gas is relatively high cost due to its remote, offshore location

■

the high capital and labour costs associated with construction

■

competition from alternative supply sources (often onshore and with access to substantial development finance assistance and lower secondary tax burdens).

The key policy issues that need to be considered to ensure that gas development investment occurs, for gas as a commodity export, were set out in the LNG Action Agenda. They related to: ■

taxation

■

local content

■

greenhouse

■

approvals processes, and

■

market access facilitation.

A full list of these policy commitments is set out at Attachment 16. Both the industry and governments have set in train a number of measures to address local content and approval process issues. Tax: The key parameter impacting on project viability is taxation. Taxation can absorb up to 58 per cent of the net revenue of a new greenfields gas project. Decisions on the effective life of assets for company tax depreciation purposes were a positive step to maintaining international competitiveness. However, further changes are necessary. The fiscal situation in competitor countries changes regularly, as do market conditions. Australia must keep pace with these developments. As discussed in the domestic supply section in Chapter 2, ensuring that the parameters of the PRRT system are updated to meet changing market expectations and changing risk profiles is an essential next step. Greenhouse: The production and liquefaction of gas generates greenhouse gas emissions in Australia, but provides greenhouse and air quality benefits to our LNG customers overseas. A carbon cost introduced in Australia could not be passed on

T H E

N A T U R A L

C H O I C E

27

T H E

N A T I O N A L

C H O I C E

to customers and under current international treaty arrangements, would not be incurred by any of Australia’s LNG market competitors. Therefore, any domestic impost on emissions will significantly reduce the international competitiveness of Australia’s LNG industry and hence its ability to expand unless (by internationally acceptable mechanisms) emissions generated in Australia are exempt from the carbon cost, or are able to be offset by emissions reductions resulting from the use of Australian LNG in customer countries. In order to minimise this potential cost, the industry is committed to continuous improvement and the development of new technology e.g. CO2 re-injection and sequestration, to reduce emissions. In this regard, the government’s commitments in the LNG Action Agenda are extremely important. The success of the petroleum industry’s Geodisc research project and the establishment of the CO2CRC with the petroleum industry as a key financier (along with government and the coal and power sectors) mean that technology solutions related to geological storage of CO2 have a higher profile in industry response options, particularly for LNG projects. Storage of CO2 which is naturally produced as a result of gas extraction may be close to commercial viability. This could significantly improve the greenhouse gas emissions profile of LNG projects. However, there are a number of fiscal, legal and regulatory issues to be addressed before demonstration can commence. There are also significant technical and economic issues to be resolved (particularly with CO2 separation in flue gas streams) and achieving economic practicability may take some time. Facilitating Market Entry: The potential market for Australian gas exports extends from the Indian Sub-Continent around the south east and east Asian coast to Korea and the west coast of the USA. In certain of these markets, commercial access is facilitated by a demonstration of government support. It is essential that: ■

all Australian governments continue existing support facilities for international market access, and

■

Australian diplomats and trade officials are attuned to promoting the benefits of Australian gas, and that facilitation of gas exports is recognised by Commonwealth officers as a national diplomatic and trade priority.

The changing market context Until recently, LNG exports had been on the basis of long-term supply contracts with prices set by some formula usually related to changing global oil prices. In recent times a small spot market has been developing.

28

If substantial LNG exports to the USA and the European Union develop, it is possible that, while long-term contracts will still be the basis of most market sales, price arrangements in contracts may change. It is possible that increasingly, prices for LNG will be set on the basis of a net back from either the USA or EU markets. In the longer term, the upper limit of this net back price may depend on the cost and availability of clean coal technologies. The lower limit will be set by the supply cost for Russian gas delivered by pipelines or LNG delivered from low cost, large volume, land-based Middle East suppliers. Where the net back price will settle in this range will depend on a range of associated factors including: ■

supply availability

■

the customers’ need for supply source diversity

■

political factors, and

■

supply reliability.

Australia has a capacity to create a competitive advantage on the basis of at least three of these points.

Gas processing — export potential In the longer term, it is possible that there is scope for increased gas use as a raw material for the production of chemicals, petrochemicals, GTL products, and in the more distant long term, hydrogen. Chemicals already produced in Australia from gas as a feedstock include ammonia, methanol and sodium cyanide for local consumption and export. Methanol can also be regarded as a GTL product because of its fuel properties and, depending on cost, it can be attractive for power generation where LNG cannot be easily accessed. Methanol can also be used as a feedstock for olefin manufacture as an alternative to ethane in the emerging Methanol to Olefin (MTO) technology. Australia’s early participation in MTO development could see revitalisation of the petrochemical industry in Australia. Proponents of this view recognise that (given the current state of commerciality of these options) government would need to provide a substantially more attractive investment policy framework if development is to occur. Experience gained to date with these types of energy-intensive projects shows that the cost of gas supply must be very low if the conversion project is to be economically viable. It has been estimated that gas for large domestic processing projects could be available in Australia at around $US 1 per GJ and that to make chemical production viable gas supply costs may need to drop to about half this

T H E

N A T U R A L

C H O I C E

29

T H E

N A T I O N A L

C H O I C E

level. Achieving this reduction presents a challenge for remote, deep-water gas resources in Australia’s north and north west. It is argued that if Australia can gain an early mover advantage in MTO, GTL, methanol and hydrogen, it will be able to attract additional investment in these industries since (in the longer term) additional investment is likely to favour brownfield over greenfield development. If not, those developments may be lost to competitor countries given the expected advantage of brownfield developments. Whether MTO, GTL, methanol and hydrogen can fulfil this longer term promise depends on a number of commercial and strategic policy issues: ■

the cost competitiveness of the products in the petroleum products market (they will be seeking to penetrate markets where oil-based petroleum products are well established and relatively cheap) the International Energy Agency (Kaastad and Kowad) estimates the following pre-tax costs per GJ of producing energy from: Gasoline $3.00 Hydrogen produced from Natural Gas $5.60 Hydrogen produced from Coal $10.30 Hydrogen produced from Water Electrolysis $20.10

■

final government energy policy decisions about the risk of supply interruption in liquid fuels supply and the economic costs of increasingly relying on imports for transport fuels

■

whether Australia is willing to create an investment framework that will facilitate a market leader position, and

■

resolution of the potentially significant greenhouse emission issues associated with the production process and the costs that certain solutions will impose.

In pursuing these options, it should be remembered that today the highest value for Australia's gas resources can be achieved at the burner tip and there is an opportunity cost in pursuing non-commercial developments that divert resources away from higher value developments such as LNG and domestic use. In addressing the investment framework for MTO, GTL, methanol and other gas processing industries, governments need to recognise that their development must, in the end, be determined on their economics. This can be bolstered by support for common-use infrastructure and appropriate tax parameters such as internationally competitive depreciation provisions but governments should not be trying to choose between projects.

30

Export Market Policy Measures The key policy outcome sought in regard to international markets relates to ensuring Australia remains an internationally competitive destination for investment capital so that commercial opportunities can be exploited as they arise in global markets. Fully address the policy issues raised in the LNG Action Agenda in relation to: ■

taxation (particularly PRRT)

■

Australian industry participation

■

streamlining approvals processes

■

greenhouse (and in particular ensure that greenhouse policies do not undermine the international competitiveness of the gas export industry or the development of gas dependent export and import competing industries), and

■

facilitation of access to overseas markets.

Develop a cost effective and efficient regulatory regime (including in relation to property rights, monitoring and legal liability) applicable to geosequestration of CO2. Development by governments of a substantially more attractive investment framework in relation to gas processing developments (including via completion of an Australian Chemicals and Plastics Industry Action Agenda).

T H E

N A T U R A L

C H O I C E

31

T H E

N A T I O N A L

C H O I C E

Attachments

ATTACHMENT 1

The Policy Context In August 2000, the Commonwealth, Western Australian and Northern Territory Governments agreed that over the next 20 years the aim is for the Australian LNG industry to: ‘Be the preferred supplier of new LNG demand, realise its potential to be one of Australia’s largest export earners and expand its share of the Asian market from the current level of 10 per cent to 30 per cent by 2030.’ On 8 June 2001 the Council of Australian Governments agreed that one of the objectives of national energy policy was to: ‘Encourage responsible development of Australia’s energy resources… and their efficient use by industries and households and their exploitation in export markets.’ The Council of Australian Governments also agreed that their energy policies will: ‘Encourage the efficient economic development and increased application of less carbon intensive…energy sources and technologies, including exploring opportunities for appropriate fuel substitution.’ In September 2003, the Ministerial Council on Mineral and Petroleum Resources agreed the following vision statement: ‘In 2025 Australia is recognised as a world class location for…petroleum exploration and development, with a competitive resources industry valued for its contribution to the sustainable development of the nation and the world.’ On 11 December 2003 the Ministerial Council on Energy noted: ‘The importance of gas supply in the national energy framework, and of policies which encourage efficient investment in Australian oil and gas exploration and development and which facilitate the creation of domestic gas markets.’ and ‘The medium to long term supply of gas to eastern Australia will be considered in the context of security of supply, greenhouse response and cost to consumers.’

32

ATTACHMENT 2

Location of Australian Natural Gas Resources

July 2003 Existing natural gas pipelines Natural gas pipelines under construction Proposed natural gas pipelines Reserves are shown as a percentage of total reserves. Estimated Australian Gas Reserves at 1 January 2001 = 157343 PJ (Geoscience Australia 2002)

Source: Australian Gas Association

ATTACHMENT 3

Australian Natural Gas Reserves and Resources Reserves Commercial NonCommercial

Eastern Australia

Northern & Central Australia Western Australia

Adavale Bass Bowen/Surat Cooper/Eromanga Gippsland Otway Subtotal Amadeus Bonaparte Browse Subtotal Carnarvon Perth Subtotal

Total Source: Geoscience Australia

PJ 15 123 3437 5164 46 8785 460 3 463 24332 114 24446 33694

PJ 376 95 1461 3204 1654 6790 28 24892 20719 45639 42957 42957 95386

Unidentified Resources PJ 1358 1358 6440 5370 11810 23990 23990 37158

Total Resources PJ 15 376 218 4898 9726 1700 16933 488 31335 26089 57912 91279 114 91393 166238

T H E

Production

PJ 0.8 0 27 232 202 8 470 19 0 0 19 718 10 729 1218

Sub-Total 0.17% 0.00% 5.74% 49.36% 42.98% 1.70% 100.00% 100.00% 0.00% 0.00% 100.00% 98.49% 1.37% 100.00% -

N A T U R A L

Total 0.07% 0.00% 2.22% 19.05% 16.58% 0.66% 38.59% 1.56% 0.00% 0.00% 1.56% 58.95% 0.82% 59.85% 100.00%

C H O I C E

33

T H E

N A T I O N A L

ATTACHMENT 4

C H O I C E

Coal Seam Gas Resources PJ New South Wales

97,242 Sydney

28,576

Gunnedah

27,816

Clarrence-Moreton

40,580

Gloucester

na

Queensland Bowen Surat

Source: ABARE

ATTACHMENT 5

152,000 na

The Real Economic and Social Value of Energy Resources The discussion in this section is relevant to the strategic national and international public benefit issues identified above in relation to lowering the carbon intensity of national electricity generation, resource processing and transport fuels. Notionally all energy resources should be valued in a way that reflects both their economic and social costs and benefits: ■

All known energy sources have some associated environmental/social costs e.g. greenhouse emissions from fossil fuels, waste disposal issues associated with nuclear, biodiversity costs associated with hydro and land use costs associated with wind and biomass.

■

All known energy sources have some level of greenhouse gas emissions associated with their extraction and/or production, as shown in a recent ACARP study (see figure below). CSIRO data shows similar findings.

Determining the social value of a fuel is a very subjective process at present. Key difficulties include:

34

■

determining appropriate parameters for ‘whole of life cycle’ calculations

■

determining at which stage of the energy cycle external costs and benefits are to be bought to account (e.g. at extraction, transformation, transmission or final energy use), and

■

determining an economic value for costs that will be incurred some time in the future by another generation and in other parts of the world.

Greenhouse Gas Emissions for Power Generation Technologies Nuclear

NUCLEAR

Hydro

RANGE

Wave* Wind*

RENEWABLES

Solar* Photovoltaic Future Coal

Key

CLEAN COAL

IGCC

■ Non renewable

LNG C-C

■ Potential ash credit * These numbers exclude backup systems and storage technologies needed with renewables

RANGE

Natural Gas C-C

GAS

RANGE

Natural Gas O-C Conventional Coal 0.0

Source: ACARP

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

GCE (t CO2-e/MWh)

An additional complication in relation to greenhouse emissions is that the accuracy of databases for measuring emissions is still evolving and relatively uncertain. In relation to non-greenhouse related social costs, natural gas is attractive relative to other fuels since: ■

the land/marine impact of developments is small compared to coal mines and wind and solar farms

■

offshore gas developments and decommissioned platforms can create a beneficial environment for marine biodiversity

■

there is no risk of spillage (in comparison with fuel oil)

■

gas transmission and distribution pipelines are generally less intrusive environmentally than overhead electricity transmission and distribution cables, and

■

gas is a relatively environmentally attractive transport fuel.

In relation to greenhouse gas emissions it needs to be noted that an effective national strategy will involve a suite of measures that include the development of new technologies and the use of: ■

end use efficiency measures

■

sequestration (including geosequestration) approaches, and

■

the effective use of all fuel sources, including fossil fuels.

The Council of Australian Governments has recognised that: ■

for the foreseeable future, Australia will be fundamentally reliant on the use of fossil fuels as an energy source, and

■

natural gas usage should be encouraged (since it is the least greenhouse emission intensive member of the fossil fuel group in most circumstances).

T H E

N A T U R A L

C H O I C E

35

T H E

N A T I O N A L

C H O I C E

Given the relative importance in the national inventory of greenhouse gas emissions related to stationary energy sources, the relative greenhouse emission attractiveness of gas as a fuel for electricity generation is particularly important. Using Australian Gas Association data (AGA Assessment of Greenhouse Gas Emissions from Natural Gas – February 2000): ■

‘Australian best practice gas generation is estimated to emit between 514 and 658 kgCO2e /MWh. By comparison. Australian best practice coal generation is estimated to emit between 907 and 1246 kgCO2e /MWh for black and brown coal respectively’

■

‘greenhouse gas emissions from Australian best practice gas-fired electricity generation using closed cycle gas turbine (including full fuel cycle emissions) vary from 41%-46% of brown coal emissions and 57% to 64% of black coal emissions’, and

■

‘greenhouse gas emissions from direct gas supply water heating range from between 1470 and 2042 kg per annum. This compares with emissions of 1922 to 2499 kg per annum for electric heating from gas fired generation and 3975 to 5393 for coal fired electricity generation.’

Other data produced by the Australian Coal Association in its Coal in a Sustainable Society Report clearly shows gas with lower greenhouse gas emission levels compared to coal based technologies, although the relativities are different from those contained in AGA data. A key issue for the natural gas industry is that current international greenhouse treaty arrangements would potentially impose a cost impost on greenhouse emissions in Australia that would: ■

damage the international competitiveness of the gas export, and

■

undermine the development/continued economic viability of key gas dependent customer industries that are export and/or import competing industries.

The use of gas as a source of distributed energy is a possible avenue for development. Here, a key issue is developing engineering solutions to enable the electricity grid to be balanced as more distributed and (potentially variable) energy sources come into production. Research and development to address this issue should be a national priority. Geosequestration may be an attractive technology to address emissions co-produced during extraction and (if separation technologies can be commercialised) emissions associated with LNG production, gas fired electricity generation, the production of GTL and the conversion of gas to hydrogen. Given some energy uses are "essential services" and energy supply involves significant sunk capital costs, it is not clear that changing pricing structures necessarily produces reduction in consumption or appropriate fuel switching. One approach to enhancing the role of gas in power generation is to reduce the taxation burden imposed on offshore gas used for power generation (as discussed above). The initial focus should be on gas supply for new power

36

stations to meet growth in demand rather than replacement of existing (sunk cost) generation facilities. The upstream gas industry is committed to taking all commercially practicable steps to abate greenhouse gas emissions and to ensure its facilities take appropriate adaptation measures.

ATTACHMENT 6

Location of Gas Reserves and Demand Centres

Source: Woodside Energy Limited

ATTACHMENT 7

Proved Natural Gas Reserves at end 2002

Trillion cubic metres

61.04 56.06

Source: BP statistical review of world energy 2003

7.08

7.15

South and Central America

North America

11.84

12.61

Africa

Asia Pacific

T H E

Middle East

N A T U R A L

Europe and Eurasia

C H O I C E

37

T H E

N A T I O N A L

ATTACHMENT 8

C H O I C E

Primary and Final Energy Consumption in Australia by Fuel

Primary Energy Consumption

Final Energy Use

Petroleum Share = 52.7%

Petroleum Share = 71%

Brown Coal 13.3%

Natural Gas 17%

Renewables 5.8% Crude Oil 34.6%

Electricity from Gas 2% Electricity from Black Coal 11% Electricity from Brown Coal 5% Electricity from Other Sources 2%

Petroleum Products: Non-Transport 12%

Black Coal 28.1%

Other Energy (Coal Biomass & Solar) 11%

Petroleum Products: Transport 40%

Natural Gas 18.1%

Source: ABARE

ATTACHMENT 9

Fuel Inputs for Thermal Electricity Generation PJ 600

500

400

Key ■ Petroleum

300

■ Natural Gas ■ Brown Coal

200

■ Black Coal 100

0

Source: ABARE

38

New South Wales

Victoria

Queensland

Western Australia

South Australia

Tasmania

Northern Territory

ATTACHMENT 10

Household Access and Connection to Natural Gas 1993

1994

1995

1996

1997

1998

1999

2000

%

%

%

%

%

%

%

%

Households connected to gas

27.2

26.3

27.3

28.4

29.3

31.6

31.4

32.9

Households with access to gas mains

54.0

67.5

60.3

34.9

na

na

na

na

Households connected to gas

74.7

76.1

76.8

77.4

78.4

80.2

82.2

85.4

Households with access to gas mains

88.7

89.3

87.9

90.4

na

88.0

88.0

90.0

46.9

49.8

51.3

52.8

55.6

57.7

57.3

58.5

na

na

62.0

na

65.0

na

76.0

76.0

Households connected to gas

49.9

50.5

51.8

52.6

53.1

54.0

53.4

53.8

Households with access to gas mains

80.0

80.0

80.0

80.0

80.0

80.0

80.0

80.0

Households connected to gas

9.4

9.4

9.5

9.4

9.7

10.0

9.7

9.7

Households with access to gas mains

na

na

na

na

na

na

35.0

40.0

39.1

43.7

46.2

48.5

50.8

53.9

63.6

62.4

na

50.0

na

na

na

na

na

na

40.5

40.9

41.3

41.9

43.3

44.9

45.3

46.7

New South Wales

Victoria

Western Australia Households connected to gas Households with access to gas mains South Australia

Queensland

ACT Households connected to gas Households with access to gas mains Australia: Households connected to gas

Note: These data are based on responses from an annual AGA survey of distributors, pipeline-owners and producers. Statistics only available up to 2000. The recent edition of Gas Statistics Australia 2002 does not provide household connection information. Source: BHP Billiton

T H E

N A T U R A L

C H O I C E

39

T H E

N A T I O N A L

ATTACHMENT 11

C H O I C E

Composition of State Gas Supplies in 2001 State

Basin

%

New South Wales

Cooper

85

Gippsland

15

Surat/Bowen

40

Cooper/Eromanga

40

Coal Seam Methane

20

Gippsland

90

Queensland

Victoria

* Since early 2004 South Australia has also been receiving gas from the Otway Basin.

Source: ABARE

ATTACHMENT 12

Otway

7

Cooper

3

South Australia*

Cooper

100

Western Australia

Carnarvon Perth

Northern Territory

Amadeus

100

1

53 Relative fiscal regime ranking of 103 countries

4

United Kingdom

15

Pakistan

18

New Zealand Nigeria

38

China

39 42

Brazil

49

Philippines Australia

53

Russia

55

Iran

59

Libya

64 84

Norway

86

Malaysia

92

Indonesia

99

Vietnam

40

3

Global Risk Profile— Fiscal Ranking Ireland

Source: Wood Mackenzie

97

Favourable

Harsh

ATTACHMENT 13

Major Trade Movements for Natural Gas

Trade flows worldwide (billion cubic metres)

75.34 50.97 5.97

■

USA

■

Canada

■

Mexico

■

South & Central America Natural Gas

■

Europe & Eurasia

■

Middle East

■

Africa

■

Asia Pacific

22.05

108.80

11.60 39.33 20.20

14.16 8.45

7.45 4.28

6.95

8.40

4.90

20.56

6.78

5.93

4.08

5.48

14.50 3.1 2.85 6.20

6.34

9.72

7.95 4.15 23.40

5.34

LNG

Source: ABARE

ATTACHMENT 14

Asia LNG Projections 80 70 60 50

Key ■ 2001

40 30

■ 2010 ■ 2015

20

■ 2015 High

10 0

Source: ABARE

ATTACHMENT 15

Source: ABARE Australian Energy National and State Projections 2019–2020. Table A1

Japan

Korea

Taiwan

China

India

Production for Export vs. Domestic Consumption 2000–01 PJ

%

Domestic

966

70.05

Export

413

29.95

1379

100.00

Total Production

T H E

N A T U R A L

C H O I C E

41

T H E

N A T I O N A L

ATTACHMENT 16

C H O I C E

LNG Action Agenda 2000

The following is a summary of the Actions proposed to address impediments identified in the Action agenda.

Greenhouse Gas Emissions: Government Actions ■

■

■

Given that greenhouse is a global problem requiring global solutions, the Commonwealth Government and industry, in their international and domestic pronouncements and strategies, will promote LNG as a greenhouse beneficial fuel.

will resolve methodological issues relating to sinks as soon as possible, and will avoid greenhouse gas abatement policies and measures that would distort investment decisions between particular LNG projects and locations. In particular, the Government will:

Given that the national interest lies in maintaining the competitiveness of Australian industry and the particular national circumstances of the Australian LNG industry in that the industry is exposed to high levels of low cost competition from projects located in countries with no emission reduction obligations under the Kyoto Protocol, the Commonwealth Government pledges that future greenhouse gas abatement policies and measures will promote cost-effective actions that minimise the burden for business and the community, so that Australian industry, including the LNG industry, can remain competitive. Given the objectives of achieving compliance with the Kyoto Protocol in a way that is at least cost to the national economy and, recognising the need for equity by ensuring that any undue burden of adjustment potentially borne by a particular sector or region is taken into account, the Government: will involve industry from the inception through to the implementation phase of greenhouse gas abatement policies and strategies that impact on the industry will negotiate the implementation of the Kyoto Protocol flexibility ‘mechanisms’ (international emissions trading, the Clean Development Mechanism and Joint Implementation) so that they can operate in an efficient and transparent manner

42

will implement a mandatory domestic emissions trading scheme only if the Kyoto Protocol is ratified by Australia and enters into force, and there is an established international emissions trading regime

pursue the development of a consistent approach across Commonwealth, state and territory governments and their agencies. avoid greenhouse gas abatement policies that unduly limit access to the most cost effective greenhouse mitigation options, and avoid greenhouse gas abatement policies and measures that discriminate against new entrants to LNG industry or disadvantage ‘early movers’ in the LNG industry who have previously implemented greenhouse gas abatement measures. ■

The Western Australian and Northern Territory Governments have endorsed the position taken by the Commonwealth on greenhouse issues.

Greenhouse Gas Emissions: Industry Actions Industry will work towards maximising the commercial development of Australian’s gas resources and agrees to: ■

continue to have Greenhouse Challenge Agreements for all current and future LNG projects

■

regularly review these Agreements and report on emissions and abatement activities

■

apply to greenhouse gas management the best economically available technology

■

manage greenhouse gas emissions in line with Greenhouse Challenge Agreements, government approvals and corporate policies

■

maintain an inventory of greenhouse gas emissions, and measures taken to abate greenhouse gas emissions

■

provide advice to Government on competitiveness issues associated with the introduction of any greenhouse gas management proposals, and how best to account for verified emission reductions that have occurred prior to that time

■

fund at an appropriate level, research applicable to the industry on greenhouse abatement opportunities, and

■

investigate sink enhancement opportunities.

Approval Processes for Projects ■

Governments will take measure to ensure that approvals processes are responsive to the needs of the industry and other stakeholders.

LNG Marketing and Promotion ■

Effective, coordinated and non-project specific promotion of the LNG industry into new and existing markets.

■

Use of every opportunity to ensure that overseas buyers are fully aware of the benefits of sourcing LNG from Australia.

■

Assistance to overseas posts in target markets to monitor LNG markets and take full advantage of market opportunities.

Taxation ■

Continue implementation of the Government’s decision announced in December 1998 to correct anomalies and uncertainties associated with the provisions of the Petroleum Resource Rent Tax Assessment Act 1987.

■

The impact of broader taxation reform will be taken into account when larger capital intensive projects are considered through the expanded Strategic Investment Coordination process.

■

Continue to consult with industry on the Tax Commissioner’s review of the effective lives of assets.

Australian Industry Participation ■

Support full and fair opportunity for Australian business to participate in major projects.

■

Endorse and promote the APPEA/ACE Best Practice Guide for Maximising Australian Industry Participation in Petroleum Exploration and Production.

T H E

N A T U R A L

C H O I C E

43

APPEA HEAD OFFICE GPO BOX 2201 CANBERRA ACT 2601 LEVEL 3 24 MARCUS CLARKE ST CANBERRA ACT 2600 PHONE 61 2 6247 0960 FAX 61 2 6247 0548 APPEA PERTH OFFICE PO BOX 7039 CLOISTERS SQUARE PERTH WA 6850 190 ST GEORGE'S TERRACE PERTH WA 6000 PHONE 61 8 9321 9775 FAX 61 8 9231 9778 INTERNET www.appea.com.au EMAIL [email protected]