7.1
This chapter commences with a discussion about the myriad of cross ownership and links to multinational entities before examining possible avenues for increasing economic returns for Australians.
Bled dry…foreign ownership and profits
7.2
As discussed by a number of submitters, and illustrated in Figure 7.1, Australia's oil and gas industry is over 80 per cent foreign owned, with the vast majority of profits flowing overseas.
7.3
Mr Boyd Milligan and Professor Peter Newman observed that:
… with the large multinationals operating in the Australian LNG industry, degree of benefit to the Australian society and offshore distance to corporate headquarters appear to be to be inversely related.
7.4
Furthermore, with the exception of Western Australia (WA), figures for local content are not generally available so it is difficult to gauge the extent of local benefit. Chevron noted that it had $67 billion in local content including local wages and contractors, local fabrication and local service contracts. In contrast, Lock the Gate Alliance and the Conservation Council of WA submitted that unconventional gas operators typically source design and engineering expertise, materials and equipment from overseas, sending profits overseas and with limited benefit to the local economy.
7.5
Research conducted by the Australian Industrial Transformation Institute (AITI) supports this view and discusses the indelible effects on Australian capability and resilience:
Upstream of the mines' operations, local content in mine construction and technologies was seen to have fallen from well over 50 per cent at the start of the last decade's mining boom in 2003, to well below 50 per cent by around 2011. This decline had several causes, amongst which was the shift in the balance of resources expansion toward large offshore LNG projects with very low local content. Key systems technologies, together with plant and equipment, are increasingly imported as modules. Australian content is concentrated on more basic construction, operations and labour … The structure favours early-stage extraction for overseas markets over domestic value-adding.
7.6
The Institute submitted that ultimately Australia's policy settings are favourable to foreign-owned businesses and work against the national interest:
In the resources sector, large multinational businesses are dominant. This together with policy arrangements favourable to these businesses, but unfavourable to the national interest, has allowed the Australian resources industry to regress towards a predominantly export oriented, low value-add, extractive industry, alongside strong overseas repatriation of its revenues.
Improving Australia's economic return
7.7
Per Capita submitted that reform to Australia's oil and gas tax regime is required:
On any objective assessment of Australia's current taxation system … remains the one in which successive governments have proved unwilling or incapable of implementing adequate taxation measures.
… It's well past time for our political leaders to grasp the mettle of structural reform to deliver a sustainable tax base to support the wellbeing and future prosperity of the Australian people.
… a critical part of such reform is the implementation of efficient and effective taxation on our natural resources, including our oil and gas reserves.
7.8
While the oil and gas industry argued for policy and fiscal certainty to ensure ongoing investment in Australian oil and gas, other submitters suggested changes to improve Australia's economic return, as discussed below.
Suggested amendments to the petroleum resource rent tax
7.9
The Australian Manufacturing Workers' Union (AMWU) thought oil and gas market transparency could be improved by shifting the transfer pricing point from point of processing to the point of LNG sale. Taking account of evidence provided by the Australian Petroleum Production and Exploration Association (APPEA), this might have the effect of making liquefaction and shipping processes deductible for petroleum resource rent tax (PRRT) purposes.
7.10
Lock the Gate Alliance recommended the application of a modified netback only approach to calculating the gas transfer price.
7.11
Similarly, the Australia Institute and the Centre for International Corporate Tax Accountability and Research (CICTAR) recommended a retrospective regulatory change in the gas transfer pricing mechanism, restricting the gas transfer price to the net-back only approach, with CICTAR calculating that this would increase revenue by $90 billion, as well as simplifying regulations and improving transparency.
7.12
The AMWU and Dr Cameron Murray argued that excessive carry-over and escalation of costs in the tax base for the existing PRRT should be removed to ensure greater flow of PRRT to public revenue. Mr Kevin Morrison suggested that the transfer of carried forward expenditure from one project to another and that decommissioning costs should no longer be deductable. This is in accordance with the Henry Review which found that 'uplift rates over-compensate successful investors for the deferral of PRRT deductions'.
7.13
Prosper Australia suggested that, in conjunction with a fixed royalty, the PRRT should be phased out over five years, allowing industry to write off the $342 billion in carry forward losses. It also recommended that depreciated optimised replacement costs be better regulated to ensure that the value of assets is not over estimated, enabling excessive depreciations.
7.14
Per Capita also argued similarly to the Henry Review, that the PRRT ought to be replaced by a uniform national resource rent tax, applied at a rate significantly higher than the current effective tax rate.
The sovereign risk snipe
7.15
The Fraser Institute's annual Global Petroleum Survey 2018 noted that Australia is an attractive oil and gas investment destination, with around 38 per cent of those surveyed responding that the taxation regime is only a 'mild deterrent to investment, but that uncertainty, compliance costs, labour and employment frameworks and environmental regulation were contributing to a reluctance to invest'.
7.16
Dr Diane Kraal, Professor Machiel Mulder and Mr Peter Perey wrote in their 2020 paper that risks to investment by oil and gas as a result of tax changes are vastly overstated:
… it is anticipated that industry will again raise the issue of 'sovereign risk' in response to calls for tax reform, however as discussed, such risk concerns are overstated. Sovereign risk is characterised by overt changes, such as nationalisation of resources, certainly not by tax regulatory changes.
7.17
They noted that changes to the petroleum regulatory framework in the 1970s and again in 2018 did not stem investment or cause the industry to claim 'sovereign risk'.
7.18
CICTAR agreed that PRRT changes would be unlikely threaten future investments, given that projects were approved on the basis of revenue and supply that has not been delivered, that the annual financial impact is small given oil and gas income, and that the PRRT has already changed a number of times to benefit industry. Dr Murray also thought that future investment was unlikely to be threatened, with tax and regulation changes a recognised part of doing business.
7.19
Similarly, Ms Emma Dawson from Per Capita thought that arguments about Australia's operating environment and costs were 'irrelevant':
The argument is about the value of our natural resources and how much return we're getting from them. Those cost benefit considerations are for companies to make, and it's a similar argument to that which says, 'If we tax them too highly, they'll take their business elsewhere.' We have the resources; the resources are in our land mass. It's a pretty spurious argument. The fact that other countries do this successfully, such as Norway, which is a highly developed country with very high living standards and high rates of income, I think really puts the light on that argument.
7.20
In 2015, the Boston Consulting Group's analysis of the percentage government share of oil and gas revenues placed Australia's rate at around a global low 59 per cent, well below Algeria's 88 per cent and Norway's 76 per cent, as shown in Figure 7.2. Australia's government share is moderate at best—if not corporate welfare—implying that there is significant opportunity to increase public benefit without reducing an adequate return on investment.
Apply a royalty on offshore projects
7.21
A number of submitters argued for a flat-rate royalty for all offshore gas projects in order to maximise economic return.
7.22
States and territories levy royalties on onshore oil and gas and mineral resources, generally applying a specific rate calculated as a flat rate per tonne or an ad valorem which is calculated as a proportion of the royalty value or value of the product sold.
7.23
Given commodity price fluctuations royalties have the benefit of generating a quicker, more stable stream of taxation revenue but may have a dampening effect on investment in exploration and technology because they are levied before net profit is determined, and they do not take account of differences in project profitability.
7.24
The Henry Review argued that royalty-based taxes offer a lower rate of return over time for finite resource opting for an across the resource sector profits-based tax that built in the value gained by a commodity over time effectively meaning the taxpayer gets a higher rate of return.
7.25
By contrast, industry revenues and profits are more stable under a resource rent tax regime and in theory such taxes would be more efficient and adjust to profitability with no effect on production decisions, by implication encouraging investment. The Tax and Transfer Policy Institute noted that:
Because the resource rent tax base is much smaller than the royalty base, as noted in the table above, in order to collect about the same revenue the resource rent tax rate has to be severalfold times the royalty rate.
7.26
The South Australian (SA) Government told the committee of the success of its royalty regime in generating public revenue. Similarly, the Conservation Council of WA noted the success of WA's North West Shelf (NWS) project in bolstering public revenue through a royalty:
… the North West Shelf, is an exception to the current rule that LNG projects get free gas. It paid $1.9 billion for its gas over just 18 months in 2014 and 2015. Why is the NWS different? Because it is subject to a royalty, not the PRRT.
7.27
The Institute for Energy Economics and Financial Analysis (IEEFA), suggested a levy of 12.5 per cent on the wellhead value, and CICTAR argued for a retrospective royalty, levied at 10 per cent. CICTAR suggested that the royalty be applied along with a reformed PRRT and the associated credits to provide potential future revenue. Per Capita advised the committee that:
… the benefit of having a royalties based system is that it's a lot harder to do that tricky accounting. The system that we have in place should be designed in order to minimise the opportunities for that tax avoidance as much as possible … the fact remains on principle that, as long as we are still exporting fossil fuels, the return to the Australian people—and I think it's a more imperative argument now—should be sufficient to invest not only in all of the social and economic programs that we need but in carbon mitigation and decarbonising our economy.
7.28
Similarly, the Australian Manufacturing Workers' Union (AMWU) told the committee that a royalty on top of the PRRT would simplify matters:
… the PRRT was a well-designed tax in the late eighties but is no longer. So I think the view is that royalties are easy to calculate because you count them as they come out the ground and you take your cut as you go through.
…
We can either go through a costly and detailed reanalysis of the PRRT and how it should work or we can simply add a bit more—clip the tickets on the way through and make it a simpler way of raising a fair share of revenue for the taxpayer out of their resources when they're sold.
7.29
The committee was told that a royalty would provide guaranteed revenue up front, with the Conservation Council of WA pointing to the success of the NWS royalty, ensuring that Australia's finite resources are not given away free of charge. Under such a scheme it was estimated that a royalty would raise $2.8 billion in revenue per annum and still provide a highly competitive investment environment, as per Norway's example.
7.30
The IEEFA also recommended a thorough review of how royalty is calculated for onshore gas, as well as an Australian Taxation Office (ATO) determined wellhead value on which the royalty rate is applied.
7.31
Dr Kraal argued for an earlier revenue scheme, anticipating a shorter than expected lifespan for fossil fuels due to lower commodity prices, climate change and moves to a net zero emissions economy:
… payment for Australia's gas upon extraction should arguably be earlier—on production—as with a royalty regime, rather than delayed payments—as with a profits-based tax. In the case of integrated gas projects in Commonwealth waters, the retention of the PRRT and the addition of a Commonwealth royalty on production (which is fully creditable against the PRRT) would provide uniformity of federal legislation and is strongly suggested as the best option to meet the PRRT Review aim of providing an equitable return to the Australian community.
Oil and gas government assistance
7.32
Like many industries, the oil and gas industry benefits from a range of direct and indirect government assistance at federal and state levels. These range from direct funding to subsidies, grants, tax offsets, rebates and credits, to indirect assistance through infrastructure development and upgrades (such as ports, rail and roads), and exploration assistance (for example, through provision of exploration data).
7.33
It is challenging to ascertain the value of assistance granted to the oil and gas industry over time due to the difficulties of identifying and collating subsidy information. Nevertheless, the Australia Institute reported that government assistance to the oil and gas industry has been significant historically, reporting that between 2008 and 2014 state government subsidies amounted to over $2.2 billion in direct assistance. Combined federal and state government assistance to the oil and gas industry was reported as $10.3 billion in 2020–21, with $8.3 billion committed to longer-term projects. Per Capita told the committee that 'the amount of compensation we gave just to oil and gas last year [i.e. 2020] outspent the value of our defence spending.'
7.34
The International Monetary Fund (IMF) estimated that Australia subsidised oil and gas to the value of $9.7 billion in 2021—inclusive of both implicit and explicit subsidies. Bearing in mind that the oil and gas revenue paid to Australians was estimated at around $3.52 billion per annum in 2019 it may be that that Australia is giving more than it receives.
7.35
Mr Milligan and Professor Newman advised the committee that further assistance to industry is provided through sale opportunity. They estimated that the provision of gas for the generation of thermal or electrical energy, at no apparent cost to industry at $1.6 billion (as domestic gas) in 2019 and $3.6 billion (as LNG) per annum, rising to the then present-day value of $19.2 billion and $60.6 billion respectively, not including any PRRT payable on this gas.
7.36
Mr Andrew McConville, Chief Executive of APPEA, argued for reforms to maximise benefit to the Australian people through further subsidisation, including encouraging employment through deductible salary and wage costs, the introduction of investment allowances to encourage investment, and the enabling business project restructuring through the transactional swapping of permits and infrastructure interests.
7.37
Disturbingly the Australia Institute found that 'many Australians are unaware of the existence and extent of fossil fuel subsidies in Australia' but that they increasingly oppose industry support, preferring to see public funds spent on renewable energy projects. Moreover 'the proposal of a "gas-fired recovery" remains deeply unpopular', with only 12 per cent of Australians preferring investment in gas.
Reduce or stop oil and gas subsidies
7.38
Professor Clinton Fernandes told the committee that the government could have structured these assistance measures as income-contingent subsidies, with companies required to pay back some or all of the subsidy once their income exceeded a specified amount.
7.39
The Australia Institute and Per Capita argued for the reduction or removal of subsidies to the oil and gas industry, along with increased taxation, in order to improve public revenue.
7.40
Mr Kevin Morrison suggested that fossil fuel subsidies could be partly reduced by applying a carbon price or tax on greenhouse gas (GHG) emissions, with the revenue raised used to fund projects to transition Australia to a lower emission economy. Australian Parents for Climate Action similarly advocated for incentives and support for renewable energy projects and the transition away from gas.
7.41
Mr Milligan and Professor Newman also advocated for the review of other forms of industry assistance, such as the National Energy Guarantee which exempts and protects emissions-intensive trade-exposed industries competing with cleaner, global competitors, to determine alternative policy settings.
Nationalise oil and gas
7.42
Some witnesses suggested the nationalisation of Australia's oil and gas as a way of maximising economic returns, either through direct government ownership or equity in private operators.
… the Australian government has been completely missing in action to secure Australia's energy security or even to ensure government revenue is generated from the extraction and export of Australia's natural resources.
7.44
Associate Professor David Lee, Professor Fernandes and Dr Murray argued for the issue of equity to state and/or territory governments, or the Australian Government (depending on whether the project is onshore or offshore), as a proportion of total revenues in that year.
7.45
Dr Murray suggested this be at a rate of, for example, five per cent per annum, continuing until the total proportion of government ownership is 30 per cent. He argued that, for future projects, governments could force companies to take them as an equity partner, with share ownership favouring the government's contribution—for example on a two to one basis where the government contributes 15 per cent of costs but is given a 30 per cent equity stake. As discussed above, this model offers public advantages through the state's ability to exert influence, prioritise the maximisation of public benefit and through shareholder profits.
7.46
Professor John Chandler argued that the time for a national oil and gas company had passed, after 60 years of private exploration and development. He told the committee that:
… generally speaking, government in Australia doesn't have a great appetite for the risk that's involved, unless you have a free carried interest. There are ways of structuring these things so you have a free carried interest and you don't have to put your hand in your pocket for the exploration and development costs. But the beauty of the licence model, as it is currently without a national oil company, is the government doesn't have to put its hand in its pocket, except in relation to tax refunds and things like that
…
Certainly, a national oil company is one way of doing it. But if you have a stronger regulator and you've got good tools and a very competent regulator, you can do quite a bit.
7.47
Mr Morrison shared this view:
It may have been a good idea back in the seventies, when Rex Connor was proposing the PMA [Petroleum and Minerals Authority], but probably not now, given the issue with emissions and decommissioning. The liabilities any national oil company would then have to take on with decommissioning would add to taxpayer expense. So I can't see some of the merits in that—but, as I said, had it been 30, 40 or 50 years ago, perhaps.
Risk of stranded assets
7.48
Nationalisation of oil and gas is not without risks; in 2011 the World Bank warned that
As of today, the volatility in oil prices, the global recession, and the uncertain economic outlook make it difficult to accurately define the outlook for energy demand, petroleum supply additions, international trade policy, or even the geopolitical land-scape, all of which are critical to the future economic and political role of NOCs [national oil companies]. Several factors—including the significantly reduced availability of debt financing, and the ongoing volatility in the equity markets—may limit the ability of some NOCs to invest in new upstream capacities as originally planned.
7.49
Furthermore, it warned that 'the performance and commercial efficiency of these state enterprises has in most cases not lived up to expectations and quite often has been disappointing.'
7.50
The IMF also advised that some of the benefits of state equity (such as having a 'seat at the table' to influence decision making, rectifying information asymmetry) are also achievable by regulation. They observed that 62 per cent of nationalised oil and gas companies have poor public transparency, many spend most of the money they earn rather than transferring it to public revenue, and they can take on large amounts of debt which the state may become liable for. The global drive to transition away from fossil fuels makes this a risky proposition, with the assets that they hold potentially becoming unviable and stranded. More recently, a number of countries have considered or enacted partial privatisation or listing of their national oil companies.
7.51
Mr Warren Tegg from the AMWU highlighted the potential risks associated with nationalisation of oil and gas, particularly in relation to stranded assets:
I think there is a real risk of stranded assets whenever we talk about gas. As mentioned, the IPCC [Intergovernmental Panel on Climate Change] was pretty firm on its view on the future for natural gas. As we move into the next round of climate negotiations, given how much of this stuff we export and the sort of the demands we're going to have on our emissions reduction to avoid things like carbon tariffs in the future, we might see gas turn south in a real hurry. Given the power of the gas industry, we are talking about potentially billions of dollars in a stranded asset, so there is a risk of the government getting involved.
7.52
A recent report by the Bank of International Settlements and Banque de France pointed to research that identified the costs of extraction of fossil fuels as a predictive factor for which assets will be stranded, with resources in locations with higher extraction costs, like Australia, likely to be stranded first. Citi reported that
…the risk of stranded assets is higher in Australia just by dint of the higher likelihood that people will take a bet on oil and gas compared to the EU [European Union], where they won't.
7.53
In 2020, BP reduced the value of its assets by US$17.5 billion, with Royal Dutch Shell also announcing an asset write-down of US$22 billion. Locally, significant write-downs were observed by the Australian Competition and Consumer Commission (ACCC), the majority of which were coal seam gas (CSG) fields in Queensland.
7.54
In 2020 Santos wrote down the value of its gas investments (including Gladstone LNG) by $1 billion to $1.1 billion as a result the collapse of oil and gas prices; with similar write-downs by Origin Energy of $1.2 billion and Woodside by $6.3 billion. In total, it was anticipated that write-downs would be more than $18 billion during the first half of 2020 alone.
7.55
Locally, Australia is the fourth country most at risk of stranded fossil fuel assets, valued at $103 billion. Global Energy Monitor placed Australia as the fifth most exposed country to the risk of stranded pipelines, with $56.2 billion of gas pipelines under construction or planned, at risk of becoming stranded assets.
7.56
Wood Mackenzie estimated that the fall in value industry-wide is US$1.6 trillion, with further falls anticipated. While COVID-19 has impacted on business, they warned that a more fundamental change to the industry is in progress. The Australasian Centre for Corporate Responsibility have also warned that these write-downs are evidence that fossil fuel assets are being stranded.
Establish a sovereign wealth fund
7.57
Mr Milligan, Professor Newman and Mr Morrison each drew the committee's attention to the lack of long-term benefit that had been accrued from Australia's oil reserves—for example through a sovereign wealth fund:
What legacy does it [Australia's oil and gas industry] want to leave with Australia, what legacy do the Australian people want it to leave, to supplant the Australian natural assets it consumes?
The consumption of these assets should serve to develop an equivalence conceptual: replacement of a natural asset with some sort of human constructed asset, such as national wealth.
At Australia's peak oil production in 2000-01 when oil output averaged almost 563 000 barrels a day (b/d) in the 2000-01 year and when the global average oil price was less than US$29/barrel for the same period. Given Australia has been an oil producer for almost 60 years, it has not created any long-term legacy to future generations for the extraction of its non-replenishable finite resources such as a sovereign wealth fund.
7.58
Per Capita argued for the establishment of an Education Future Fund as a form of sovereign wealth fund, using proceeds from a uniform national resource rent tax. It envisaged that the fund would be dedicated to school and vocational education and training to enable Australia to adapt and progress in an increasingly technological and automated environment. Crucially, Per Capita noted that 'its proceeds could…sustainably fund Australia's school education sector in perpetuity, even beyond the natural end of demand for non-renewable energy resources'.
7.59
The Australia Institute and Associate Professor Lee also argued for a sovereign wealth fund, as did IEEFA, suggesting that 30 per cent of royalties or PRRT be put aside, with income available to current governments for spending, and capital available to future generations.
7.60
Prosper Australia also argued for the introduction of environmental bonds to enable 100 per cent environmental remediation of oil and gas fields and revegetation (for onshore sites).
Improve industry efficiency and competitiveness
7.61
Professor Chandler explained the importance of effective and oil and gas industry operations, explaining to the committee that excessive operating or capital costs reduce the tax return to Australians:
Being energy efficient in production is an example of another aspect of a country getting the best out of petroleum—which you could call avoiding waste or more broadly ensuring operations are sustainable and fair to future generations.
7.62
He explained further that the intensity of production from a field and the lack of shared facilities can result in these excessive costs and that, importantly, production may not maximise oil and gas extraction from the field as a whole, with each operator focussed on profit and their own operations. He also observed that different operators perform at different levels of effectiveness and that efficiency and ability to manage delays and cost overruns, as well as fugitive emissions, affects public returns:
These companies are supposed to have expertise, but if they engage in a project and have a massive cost overrun or a massive time delay, that's going to impact on the government's revenue. There needs to be some accountability to them on those kinds of issues. They'll have a different view, for example, about the rate at which they want to produce and how fast, and they're going to do things at particular times depending on what the price is like. You have things like the flaring of gas and waste and all those kinds of issues, where they will do things to maximise their profit, but it will reduce what the government's going to get.
7.63
National Energy Resources Australia's (NERA) 2016 Australian Oil and Gas Competitiveness Assessment found that Australia had an overall ranking of 6.4 out of 10, placing it seventh globally and slightly above the world median of 5.5, as shown in Figure 7.3. It found that Australia ranks first in the area of exploration, but lags in development and execution and production and abandonment phases. NERA noted that:
Importantly for Australia, the industry is shifting from the Development to the Production phase; as a result, the focus should primarily be on improving operations performance, with a view to building capability in the Abandonment phase.
7.64
Professor Chandler expressed his surprise at the lack of local discussion about how sharing infrastructure can increase company profits, as well as tax income, and reduce decommissioning costs—a win for industry, government and Australians. He argued for a model of 'sustainable profitability' and pointed to the experiences in Norway and the United Kingdom (UK) and how these issues have been addressed in these jurisdictions through strengthened regulation. Likewise, NERA pointed to collaboration and sharing of resources and infrastructure, in addition to regional hubs, as one area for potential improvement.
7.65
In the UK, the government recognised the importance of collaboration between commercial entities and the need for exploration and production companies to become more efficient. The revised Maximising economic recovery of UK petroleum strategy (MER UK)—now the Oil and Gas Authority (OGA) Strategy—required emissions minimisation, collaboration and access to upstream infrastructure, as well as the publication of efficiency data to drive change in the industry and improve maximisation of its oil and gas reserves. The obligations on stakeholders are supported by metering, measuring and reporting requirements. Failure to act in accordance with the revised strategy may result in revocation of a licence or operatorship.
7.66
The Department of Industry, Innovation and Science's (DIIS) 2015 offshore petroleum resource management review identified some of these issues, in particular those relating to inefficient field and infrastructure utilisation.
7.67
The review's response to these issues reflected the underlying fundamentals of Australia's resource management approach. The report stated that:
the potential regional and sub-regional interactions between fields need to be understood and considered, through time, by regulators and industry to ensure, where practical, optimal long-term economic recovery is achieved from all fields present within an area, through the entire development lifecycle of a basin; and development lifecycle of a basin; and
while the issue of optimising infrastructure appropriately remains an economic consideration between commercial parties, consistent with the government's stewardship mandate, it should ensure its policy and operational frameworks encourage industry to consider all viable options for optimal design and operation.
7.68
The government undertook to strengthen its offshore resource management capacity, stating the regulatory framework itself was sufficient to address these issues. However, it warned management and oversight of basin-wide issues:
… could cause tension between the interests of government and individual developers. For this reason, progression to a more systems-based approach must be supported by a transparent indication of emerging issues. This will enable issues to be identified and addressed at an early stage, and in partnership with industry, rather than after the fact when it is too late or expensive to adjust the action already undertaken to bring the resource to development.
7.69
The review also found that a systems-based approach is essential to the success of the oil and gas industry given the increasing focus of development around foundation or hub projects and collaborations in key producing regions. This approach requires resources and infrastructure to be managed in an integrated manner to secure the necessary long-term supply of feed gas, ensure project viability, and value for investors and the government. Naturally, the benefits of a systems-based approach apply equally to onshore oil and gas development and this method of operation is crucial given Australia's relatively high costs of exploration and production.
7.70
The ability to take a systems-based approach depends on better understanding of the resource base, and the associated physical and economic connectivities and this grows with maturity and technology. The value of this approach has also been recognised in the OGA Strategy which requires a whole of basin approach, collaboration, information sharing, and access to infrastructure between operators.
7.71
Despite recognising the value of collaboration, NOPTA observed in its 2020–21 Annual Report of Activities that it occurs in only limited respects.
7.72
In 2017, the Commonwealth Scientific and Industrial Research Organisation's (CSIRO) Oil and Gas Roadmap also observed that collaboration needs to occur more widely:
Companies, as well as local, federal and state agencies should coordinate more effectively in the planning stages to ensure that environmental, social and economic benefits are fully realised in the long-term.
7.73
Mr Steve Walker, author of the Walker review into the circumstances surrounding the Northern Endeavour floating production storage and offloading (FPSO) vessel, pointed to the UK's experiences, including the stimulation of ageing and life extension policies and practices by both regulators and industry, as well as a more general overhaul of the regulator and its responsibilities and powers, as pathways for improving maximisation of benefit.
7.74
Mr Steve Walker, explained alternative ways of maximising benefit, including through the management of late-life assets through the different approaches which may be taken by minor oil and gas operators. He told the committee that:
… [in the case of the Northern Endeavour] there was a disparity between the approaches of a major oil company which was seeking to divest from a late-life field and the business model of a smaller company which was eager to economically life extend … They had different views about improving efficiency, different views about bolstering production and different views about using the FPSO as a regional hub. They had quite a lot of ideas and vision … That shows the differences between the approaches of the major and the smaller companies.
7.75
Professor Chandler also advocated for improved access to information. He suggested that more information could enable best practice, new techniques and benchmarking to drive performance improvement, while information about capacity could enable access to upstream infrastructure. Professor Chandler also argued that additional information could improve economic viability and outcomes in field development plans (FDP) and project execution quality. This could be used to hold operators to account and maximise economic returns. This is discussed further in Chapter 4.
Tertiary recovery
7.76
Mr Robert Cook of OFM Consulting recommended that benefit from Australia's oil and gas reserves be maximised by improving recovery through tertiary recovery, including through injecting CO₂ into existing reservoirs. Enhanced oil recovery (EOR) could also have the benefit of turning gasses which are currently vented into assets for exploitation and sequestration rather than contributions to Australia's GHG emissions, although enhanced oil recovery is not included in the CCS method currently being developed.
7.77
He provided evidence of EOR technologies being used in other jurisdictions, primarily the United States (US), but of its limited use in Australia.
7.78
Mr Cook told the committee that oil and gas operators appear to have no interest or intention of implementing EOR in fields which they operate (for example: the Gippsland Basin by ExxonMobil and other abandoned oil fields such as Laminaria-Corallina, Saladin, Cowle, Crest and Skate), noting that the National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) does not require companies to evaluate residual oil or EOR potential before field abandonment. Mr Cook puts this lack of interest down to companies focussing on short-term, high returns as well as lack of knowledge and industry experience within government.
7.79
Mr Cook noted that Australian governments also do not appear to be interested in EOR:
I went to the four governments—the Australian government, the Western Australian government, the South Australian government and the Queensland government—and basically got the same response each time: they rely on industry. Except South Australia, South Australia is a probably [more] aware of EOR than any other government, but again it still bows to the operator.
7.80
However, Mr Cook stated that these fields 'appear to have very significant CO₂-EOR potential' (subject to due diligence) and recommended that the fields or equity in the fields be purchased by the Australian Government in order to maximise extraction, and therefore public benefit. He estimated that there are close to two billion barrels of oil that could be recovered using EOR:
So there's a big target out there for us to chase for that enhanced oil recovery or that tertiary phase of oil production, which is not happening here in Australia at the present time. It could, but it doesn't.
7.81
The committee also heard evidence from CO2CRC, a not-for-profit research organisation with oil and gas industry membership, that there is the potential for the recovery of an additional three billion barrels of oil across Australia's basins as a result of the injection and storage of one to three gigatonnes of CO₂. Dr Mohammad Bagheri, Senior Manager Subsurface at CO2CRC, told the committee that while there is greater potential for EOR from offshore basins, onshore basins are 'more economic, more cost-effective and more accessible'.
7.82
When asked about the potential for EOR in Australia Mr David Wawn from Chevron Australia responded:
Theoretically, the CO₂ captured out of the LNG plant at Gorgon could be used for EOR. Just as a quick LNG101, we have to separate the CO₂ from our gas whatever we do, because CO₂ is naturally occurring in the gas you pull out of the ground. Every LNG plant in the country, in the world, strips the CO₂ from that. In most cases, it's vented into the atmosphere. In Gorgon, that reservoir gas is the gas that's to be injected. You could take that CO₂ and use it for other purposes.
7.83
However, Mr Wawn provided evidence that EOR is just not economic:
… we have every reason to want to sequester carbon. We have every reason to maximise oil production from our WA oilfields on Barrow Island. So, if it were economic to use it, we would. As the witness said, Chevron has a long history with this technology. I think the reason we're not doing it is that it's just not an economic solution on Barrow Island.
7.84
Dr Bagheri told the committee that most operators move from primary production, through to secondary production through water injections, then CO2 EOR, which is more complex and less cost-effective, particularly when oil prices are low. He indicated that 'most oil production is reaching that primary production life period now' and that companies would start to look at secondary production and EOR, particularly if oil exceeded US$60 per barrel and incentives were offered—making it more economic.
Improving domestic gas prices
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Submitters proposed a number of options to reduce high domestic gas prices, although not all submitters thought there is a solution to high domestic prices, with the Ai Group concluding:
The expansion of production, largely for export, has depleted the cheapest resources and driven development of new resources with higher production and/or transport costs. The countervailing forces of innovation and resource depletion will shape future production costs, but geology and geography make a return to past costs for coal and gas very unlikely (and irrelevant unless Australian resources become isolated from global markets).
Gas reservation policy
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A gas reservation policy is currently under consideration by government, and a number of submitters discussed the effects of a gas reservation policy, such as those already in place in WA and Queensland, and overseas.
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Several submitters recommended a gas reservation policy for the east coast in order to guarantee supply, address high prices, and promote fuel security. For example, Dr Murray recommended a reservation of 50 percent of all gas production while the AMWU recommended a reservation of 15 per cent.
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The IEEFA argued for a price control of $5/GJ on a domestic gas reservation to halve wholesale gas prices and lower the wholesale price of electricity, with flow-on effects for energy intensive manufacturing in Australia.
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The BCA, Ai Group and the AMWU suggested that existing export contracts should be grandfathered, and replaced by a national interest test, similar to that used in the US, to ensure a minimum domestic gas reserve, as well as harmonisation of gas reservation policy across state jurisdictions.
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However, other witnesses did not support such a policy. The PC acknowledged that gas may be cheaper initially but that it may not prevent rising wholesale gas prices over time due to the disincentivising effect of on investment, particularly for projects which supply the eastern market. It also argued that a gas reservation policy would prevent producers from taking advantage of higher international returns, and instead require them to supply gas below export rates, effectively representing a net loss to the community.
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In 2020, the ACCC warned against such mechanisms because:
they may not increase the overall supply to the domestic market if an equivalent quantity of gas is exported instead;
they may increase tenement concentration, squeezing out smaller producers who provide competition in the market; and
they may not provide pricing benefits to all market participants as conditions increase the bargaining power of buyers by limiting the alternatives available to producers selling gas.
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Lock the Gate Alliance were of the view that a gas reservation policy would entrench high gas prices because of the need for cheaper gas now, rather than when projects come online, and because new and future gas projects 'typically include the more expensive, harder to access gas'.
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Mr Fischer also told the committee that implementing a gas reservation policy could force producers to breach their contracts with overseas customers, causing them to seek restitution from the Australian Government, as well as having negative impacts on junior explorers seeking to enter the field.
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Ai Group's submission dealt extensively with the operation of a prospective national gas reservation scheme (PNGRS). It considered a number of reservation design models but concluded that:
Given the lack of clarity on any of the above design features, it is not possible for Ai Group to give a definitive recommendation in favour of or against the adoption of a PNGRS. It would be possible to design a PNGRS that was unmitigatedly destructive to economic development. It would also be possible (indeed very easy) to design a PNGRS that had no meaningful impact at all. We believe it is possible, though complex, to design one that has modest but meaningful overall benefits—though it is unclear if this would be better than other options.
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APPEA warned that mechanisms to regulate exports or prices must be carefully considered to avoid unintended consequences such as reducing incentives for exploration and commercialisation—echoed by AGL Energy.
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Ai Group acknowledged the potential for negative investment impacts, but also observed that a gas reservation policy may have a positive impact on investment by promoting confidence in local economic benefits and strengthening the social license to operate.
Gas market reform, including the ADGSM
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Chemistry Australia argued for a national domestic gas strategy and associated market reforms to ensure globally competitive long-term contracts, noting that for some industries there are no appropriate substitutions.
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It envisaged that the strategy would manage domestic gas pricing, prioritise domestic gas availability and supply, competition, and the concentration of market power, address imminent supply gaps, investment in infrastructure such as pipelines to bring new gas to the market, gas storage facilities and improved market transparency.
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Chemistry Australia and the AMWU also recommended a national interest test for new gas export licences to ensure guaranteed supply at sustainable prices.
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Despite DISER confirming that the Australian Domestic Gas Security Mechanism (ADGSM) is a fuel security mechanism, rather than a price control mechanism, Manufacturing Australia argued for policy changes to enable the ADGSM to be activated at any time, a price trigger, and a stronger 'sufficient supply test' to ensure LNG exporters maintain commitments to the domestic market. The AMWU also criticised the mechanism because it only targets a shortfall in supply, not rising prices.
Gas importation
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Gas importation is being explored as a mechanism for safeguarding supply and lowering domestic prices. It has the potential to come on board quickly, with relatively short build and commissioning timeframes for import terminals, when compared with exploration and production.
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The committee was told by AGL Energy that gas import was important to ensuring the availability of gas to the market. The RBA observed that the key drivers for LNG import terminals appear to be improved security and flexibility of supply rather than price, with the final prices for imported gas expected to be greater than $8/GJ over the medium term.
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Some witnesses doubted that lower prices would result from gas importation because east coast prices are already linked to the international market and subject to international currency and oil price risks, and because gas imports embed the cost of liquefaction and shipping into the domestic price.
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Five import terminal projects are under consideration nationally:
Australian Industrial Energy's (AIE) proposed terminal at Port Kembla, currently forecast to operate from early 2023;
Venice Energy's proposed terminal at Port Adelaide, scheduled to launch in early 2023;
Newcastle GasDock, proposed by Energy Projects and Infrastructure Korea, scheduled to commence operations in mid-2023;
Viva Energy's Gas Terminal project in Geelong, which is expected to deliver gas as early as 2024; and
Vopak is considering a potential import terminal in Port Phillip Bay.
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In May 2021, AGL ceased development on its proposed floating terminal at Crib Point (Victoria); and another project backed by ExxonMobil was abandoned in December 2019. Australia's Chief Economist anticipates only one or two of the projects will proceed.
Nationalised gas company
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The AMWU suggested that a publicly owned national gas company could be set up to coordinate industry as a whole and to be wholesale buyer of gas. It cited increased competition, the ability of a national gas company to set the price of gas to a netback price and its ability to establish long term contracts for domestic gas users as mechanisms to improve domestic gas pricing.
Energy efficiency and moving to cheaper energy sources
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Several submitters argued for improvements to energy efficiency and conservation, and a rapid transition to electricity or other forms of energy to reduce demand and improve costs.
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Ai Group thought that over time this would reduce the impact of gas prices on energy users, with the speed of reduction dependent on public policy, the speed of fuel switching and the displacement of gas by renewables.
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Additionally, some submitters told the committee that renewable energy offers wider benefits, including 'great promise for economic, social and environmental sustainability', including through jobs and new export industries.