2.1
This chapter discusses the nature of public benefit, ranging from firstly, outlining definitions, pitfalls, and expectations of benefit, followed by evidence suggesting a lack of adequate benefit. It then considers different types of benefits that can be derived to ensure an adequate proportion of the wealth derived from the sale of finite resources is received. The chapter also examines what other countries have done to ensure their taxpayers gain a benefit.
Defining benefit to the public
2.2
The terms of reference for this inquiry go to assessing the 'benefit to the public of Australia's national oil and gas resources'. Benefit has been described in a variety of ways by submitters, primarily from an economic standpoint. Some submitters drew attention to the additional benefits flowing from oil and gas exploitation, including downstream economic benefits, as well as environmental and social benefits. Dr Murray drew attention to the importance of maximisation of benefit:
Oil and gas resources of Australia can only be extracted once, and it doesn't actually really matter how much or what proportion is extracted now or in 10 years' time. The optimal thing for the country as a whole to do, whenever they're extracted, is to share the value gained as broadly as possible.
2.3
Australia, as discussed in chapter 1, is a country blessed with an abundance of natural resources as our top three exports—iron ore, coal, and natural gas—show. Deriving a collective benefit for all Australians from the extraction of a finite resources is a paramount public resource policy issue.
2.4
The story of Australia's oil and gas exploitation has been well documented, as has the level of federal assistance for identifying and developing with certainty the oil and gas resources—before industry participants have even begun exploration—in order to considerably reduce the exploration risk.
2.5
The 2020 Productivity Commission's (PC) review of the resources sector regulation discussed the benefit realised from resources projects such as oil and gas, with an emphasis on regional direct and indirect impacts. The review confined its analysis to the 'material impact on business investment in the resources sector'—primarily regional micro impact and avoiding any discussion related to the wider macro impact and need for broader distribution of benefit and wealth:
While communities often benefit from the normal economic activities of resources companies (for example, through new jobs and higher wages), the contributions to communities by many companies go beyond these impacts. Additional 'benefit sharing' activities include financial payments to local governments and community groups, investment in infrastructure, programs to increase local employment and business capability, and approaches to mitigate the negative social effects of resources projects.
Double, double toil and trouble…
2.6
A recurring issue that can affect a resource-rich nation like Australia is the pitfall of the 'resource curse' (RC) often referred to as the 'paradox of plenty' or the 'Dutch disease', driven by an appreciation of the exporter's currency along with poor technological growth. This is often characterised as the failure of many resource-rich countries to benefit fully from their natural resource wealth, and the failure of governments in these countries to respond effectively to ever-increasing public spending needs.
2.7
Judith Brett highlights the risk to Australia as a resource-rich of an economy so devoted to one sector as a potential textbook case of RC:
Australia is a trading nation. We have a small population, so exporting enables our companies to grow by reaching larger markets. We need the foreign income earned by our exports to pay for goods and services we import, and to service debts to foreign lenders. Our exporters also contribute to the national economy by paying taxes, distributing dividends to shareholders and employing people. All this is true of fossil-fuel exporters, but there are costs to having an export profile so skewed to one sector.
2.8
Many examples of the 'curse' are featured in developing countries with abundant non-renewable natural resources. Those countries can experience slower rates of economic growth when exports are concentrated in natural resources. Demand for natural resource exports can cause disturbing exchange rate appreciation, leading to the decline of lagging non-natural resource tradable sectors. In Australia's case, the difference of performance was stark between the mining states and the non-mining sector and regions, predominately on the east coast verse the resource intense west coast during the mid-2000s mining boom. This difference was characterised by the Department of the Treasury (The Treasury) as a 'two-speed economy'. Mr Phil Garton describes the effects of those boom years and the impact on the domestic economy:
The stimulus from the resources boom means that mining states will tend to grow faster than the non-mining states while the mining industry is expanding. Further, faster expansion of mining-related sectors and regions will attract labour and capital away from the rest of the economy.
…
In the presence of capacity constraints, the stimulus to demand from rises in the terms of trade adds to inflationary pressures, requiring some offsetting mechanism to moderate demand growth. Under the macroeconomic policy framework in operation in Australia this largely occurs through higher interest rates and a higher exchange rate.
2.9
A 2010 Treasury paper noted the detrimental impact the confluence of these factors can cause, particularly in developing economies in our region:
When governments can rely on one sector or a limited number of projects to supply a large portion of its revenue, the incentive to promote broad wealth creation, which can then be taxed, is reduced. Moreover, when citizens are lightly taxed their incentive to hold governments accountable is diminished … Empirically, there is a strong correlation between poor governance and natural resource wealth in developing countries.
The 2009 Henry Tax Review
2.10
The Treasury-led, 2009 Dr Ken Henry Tax review noted that 'well-structured taxes on land and natural resources are highly effective means of raising revenue'. The review examined the charging for non-renewable resources noting that the current arrangements needed to be replaced with a uniform resource rent tax administered by the Australian government. In particular, the review noted that:
Australia has abundant non-renewable resources, which are expected to continue to command high prices driven by demand, particularly from China and India. Non-renewable resources such as petroleum and minerals are a significant asset of the Australian community.
…
The current charging arrangements distort investment and production decisions, thereby lowering the community's return from its resources. Further, they fail to collect a sufficient return for the community because they are unresponsive to changes in profits, particularly output-based royalties. For example, existing resource taxes and royalties have collected a declining share of the return to resources over the recent period of increasing profitability in the resource sector [see Figure 2.1].
2.11
Professor Chandler told the committee that Australia's present oil and gas policy approach does not incorporate social values or specific economic objectives or require the maximisation of benefit to Australians. Rather, he states, the current regime relies on the economic activity generally contributing to government revenue and jobs.
2.12
One method detailed in discussions of how to avoid the resources curse and to deliver a more equitable returns has been the establishment of sovereign wealth funds (SWFs). In Australia's immediate region, a number of Pacific Island countries have utilised SWFs to manage government revenue from exhaustible natural resources with the aim of improving development outcomes. Experience in the region has been mixed — some SWFs have aided intergenerational equity and macroeconomic stability while others have struggled to bring about improvements in wellbeing.
2.13
Conversely, the Henry Review recommended the establishment of a uniform resource rent be introduced at a set rate:
A uniform resource rent tax should be set at a rate of 40 per cent. It would use an allowance for corporate capital system, with taxable profit associated with a resource project equal to net income less an allowance for undeducted expenses or unused losses. The allowance rate would be set by the long-term government bond rate, as the government would share in the risks of projects by providing a loss refund if the tax value of expenditure is otherwise unable to be used.
Subject to transitional arrangements, the new rent-based tax should apply to existing projects, replacing existing charging arrangements. The allocation of revenue and risks from the new tax should be negotiated between the Australian and State governments. A cash bidding system could also be adopted to supplement the resource rent tax and promote the efficient allocation of exploration rights.
2.14
Dr Henry had argued that the royalty-based taxes lower the return available from resources:
A tax on high-value resource rents would on average over time likely raise higher revenues than existing output-based royalties.
2.15
Despite moves by Prime Ministers Rudd and Gillard to implement a mining tax in line with Dr Henry's recommendations, the idea succumbed to democratic opposition through two Federal elections. As a result, it is unlikely to be revived by any government in the foreseeable future.
Not all taxes are equal
2.16
Industry, as outlined, was not so impressed by the moves to spread the wealth. Under the sub-heading of 'How much does it cost to bring down a prime minister?' the Sydney Morning Herald informed readers that the Australian Electoral Commission had published the political spending disclosures for 2009-10, revealing just how much the resources industry had spent campaigning against the RSPT—$22.2 million. The Minerals Council of Australia alone spent $17.2 million.
2.17
The missed opportunity to better place Australia's economic security more broadly was again highlighted by Dr Henry recently, stating that:
Australia's "stupidity" and economically "illiterate" failure to tax the mining boom properly has cost the country dearly and prevented a badly needed cut to the 30 per cent company rate to boost investment and worker wages … Australia was missing out on attracting foreign equity capital in other industries because of its uncompetitive corporate tax system.
… Until we fix the taxation of natural resources we will not have a cut in Australia's company tax rate, at least for large businesses.
2.18
Dr Henry notes further that the 'failure to cut the company tax rate had "stuffed" other trade-exposed industries hurt by the high Australian dollar over the past decade and non-mining investment had "stalled"', once again raising the spectre of the curse.
2.19
Against this background, the committee was informed that some liquified natural gas (LNG) projects will never pay petroleum resource rent tax (PRRT), despite extracting large volumes of gas (noting that they may pay ordinary corporate tax). For example, in 2017 INPEX reported that its Ichthys liquefied natural gas (LNG) project would export more than $195 billion of LNG, liquified petroleum gas (LPG) and condensate over the next 30 years but that it would pay zero dollars in PRRT.
2.20
Professor Murray in his evidence, told the committee that in 2004–05 the 'total average annual revenues from the Commonwealth resource tax system on oil and gas were just $2.7 billion per year during this historic boom period, while oil and gas producers reported $33.5 billion in annual revenues on average and $8.2 billion in annual profits'.
Maximising economic benefit
2.21
With the value of Australia's remaining oil and gas reserves estimated at $1.5 trillion in 2018 Australia's oil and gas peak industry body, Australian Petroleum Production and Exploration Association (APPEA), contends that there is potential for further value to be realised.
2.22
The key public benefit that the majority of submitters asserted as being necessary was the need for a fair contribution to public revenue from the sale of oil and gas. This can be achieved in a variety of direct and indirect ways including the payment of taxes, royalties, excise duties and other government payments at federal, state, and local levels. Economic activity through investment and jobs can provide a significant contribution, though generally at a localised level rather than a national one, with export earnings also contributing.
2.23
The committee heard that economic benefits can also potentially also be accrued by domestic industries providing those downstream sectors are sufficiently innovative. However, relying on a notion of 'cheap energy' for another industry's convenience is a mistake; with each sector is a player in its own right and it will first and foremost seek a return for its own shareholders. Nevertheless, those truly innovative firms can create an advantage.
2.24
Professor John Chandler from the Centre for Mining, Energy and Natural Resources Law at the University of Western Australia described the common focus of countries and private enterprise in regard to petroleum production:
The research reinforced the perhaps obvious point that companies produce petroleum to generate profits. But it also brought out that the prime motivation of countries is generating economic activity and tax revenue. So there is a common interest in turning petroleum into money.
Corporate income tax
2.25
Generally, corporate income tax is levied on Australian companies' world-wide income and on non-resident companies' Australian income at a full company tax rate of 30 per cent, with taxable income comprising assessable income minus deductable expenditure, such as payments of PRRT, state royalties or Commonwealth excise. Profits and losses can also be aggregated across projects of business functions within a single tax entity.
2.26
APPEA estimated that the oil and gas industry has contributed around $70.7 billion in corporate income tax between 1987 and 2019, with an additional $4 million paid in other taxes and fees, although it noted that typically corporate income tax payments are minimal in the early stages of a project because of initial high investment costs and the recoup of these before tax is payable.
2.27
Some commentators have identified oil and gas companies as paying little or no corporate income tax over a number of years due to favourable loan arrangements and transfer pricing arrangements and, in the case of those companies operating under the PRRT, overly generous uplift depreciation rates.
2.28
The committee also heard evidence that aggressive profit-shifting and tax avoidance policies, transfer pricing, and excessive deductions have meant that Australia has failed to maximise the economic value of its oil and gas reserves. Mr Bruce Robertson from the Institute for Energy Economics and Financial Analysis (IEEFA) observed:
Essentially, most countries in the world have better functioning tax systems than Australia, and they look to tax their corporates. In the oil and gas sector in Australia this does not occur. The entire industry, according to the Australian Taxation Office, accounts for just $81 m[illion] in tax.
2.29
The Australian Taxation Office (ATO) noted that oil and gas companies are now largely compliant with their tax obligations. For the period 2017–18 the ATO estimated the PRRT gap to be 1.7 per cent or $21 million, indicating that over 98 per cent of the theoretical PRRT payable was paid.
2.30
As part of its Justified Trust Program under the Tax Avoidance Taskforce the ATO, in its Findings Report for the top 1 000 performance program found that, of the 88 top one thousand taxpayers in the mining, energy and water sector 21 (24 per cent) achieved high assurance, 50 (57 per cent) medium assurance and 17 (19 per cent) low assurance—consistent with the broader results.
2.31
Nevertheless, the ATO noted that disputes do happen from time to time. For example, a recent Federal Court finding against Chevron's transfer pricing schemes resulted in an assessment of $340 million in taxes and penalties owed by Chevron. Building on the Chevron precedent Practical Compliance Guidance (PCG) 2017/4 on cross-border related party financing arrangements was published.
2.32
As of June 2021, the ATO had reached agreements with a number of companies on the application of transfer pricing laws; the ATO estimated that this would result in additional revenue for the federal government.
PRRT
2.33
The PRRT, established in 1988, is a tax on profits made from the sale of gas and oil before corporate income tax is calculated. It is applied to the cost of the gas or oil prior to its liquefaction (see Box 2.1) and is designed to encourage investment and development of reserves. The ATO explains that the PRRT:
… is calculated on the taxable profit the entity makes from an interest in a petroleum project in a year of tax.
Taxable profit is calculated by subtracting certain deductible expenditure and transferred exploration expenditure from the assessable receipts derived from the project interest.
An entity's PRRT liability is levied at 40% of the taxable profit made from its interest in the project.
If an entity holds an interest in an exploration permit or retention lease, it will not have a liability to pay PRRT until a production licence is derived from that interest and commercial production starts.
2.34
The PRRT has been updated and modified on a number of occasions most notably in 2012 following the Rudd Government's response to the 2009 Henry Tax Review where it was extended from specified offshore areas to the NWS, coastal and onshore oil and gas projects, and coal seam gas projects.
Box 2.1: Rent and resource rent taxes
An economic rent is the return in excess of that necessary to attract commercial investment into an activity. Governments may promote policies to maximise economic rents because economic rents are the basis for calculating the value governments can extract through taxes and other measures.
A resource rent tax targets the returns made on an investment that exceed the minimum reward necessary for the capital to be invested. Under a resource rent tax, an investor enjoys relief from taxation (through various deductions and uplift rates) until a satisfactory rate of return has been earned (costs plus minimum return). Beyond this point, profits are shared with the host government on an ex-post basis.
Rents arise across the economy in cases where there is a factor of production that is in fixed supply. If there was no factor in fixed supply, new firms could enter at lower prices and eliminate the rent. In the case of petroleum resources, excess returns are in part a function of the scarcity of the resources and the diverse quality of resources, which are owned by the Australian community.
2.35
The profit (subject to taxation) depends on the price at which the gas is 'sold' from one part of the entity that extracts it to another prior to it being processed and liquefied for export—the 'transfer point'. The transfer point calculation is required to establish the price of feedstock gas used in vertically integrated operations.
2.36
Oil prices, foreign exchange rate movements and project costs are key factors affecting the amount of PRRT payable by oil and gas operators.
Callaghan Review of the PRRT
2.37
In Aril 2017 Mr Michael Callaghan AM PSM handed down the final report of the review into the operation of the PRRT, crude oil excise and associated Commonwealth royalties. The review was aimed at shoring up Australia's revenue base and ensuring oil and gas projects were 'paying the right amount of tax on their activities in Australia'.
2.38
Mr Callaghan identified four reasons for dwindling reported profits at a time of record production: declining oil and gas prices, as well as production, large expenses involved in setting up new mega-projects, and the transfers of spending between projects for accounting purposes.
2.39
The review found the PRRT was a sound basis for taxing petroleum resources, but it needed updating in light of the contemporary petroleum industry and to improve certainty and transparency. Mr Callaghan took the opportunity to exercise the industry's perennial sovereign risk scare tactic, that any major changes that significantly increase the PRRT paid on existing projects 'could have adverse implications for Australia's reputation as a stable investment destination'.
2.40
The Tax Justice Network (TJN) in its opening statement to committee's 2017 Corporate Tax Inquiry public hearing commended the Callaghan review's level of analysis, though it took exception to the sovereign risk defence:
TJN was impressed with quality of analysis in the Callaghan Review, but seriously disappointed in its recommendations to not make any substantive and necessary reforms to existing projects. The Review backed up the analysis put forward by TJN, but completely capitulated to the trumped-up claims of sovereign risk put forward by the industry. The PRRT has been changed at least 9 times already, each time to the benefit of the industry, and no concerns of sovereign risk were raised before. There is plenty of hypocrisy in play here to preserve an incredibly beneficial fiscal regime for the oil and gas industry and one that very clearly deprives Australians of a fair share of revenue.
2.41
The review made 12 recommendations, one of which was an examination of gas transfer pricing arrangements to provide greater simplicity and transparency, ease of compliance, and fair treatment of the economic rent from each stage of an integrated petroleum operation. Mr Callaghan urged the Government to consider a comparable uncontrolled price (CUP) method as the primary method of setting the gas transfer price in line with international best practice. He was of the view current regulations likely undervalued gas used in vertically integrated LNG or electricity generation projects compared to what an arm's length market price for sales gas would be.
2.42
In June 2017 the Government issued a consultation paper and conducted consultation to inform its response to the review, releasing its final response in November 2018. The government agreed to make some changes to the PRRT to better reflect the current petroleum industry and LNG domination, including:
lowering of uplift rates;
removal of onshore projects from the PRRT regime;
a review of gas transfer pricing regulations; and
other technical changes to improve the efficiency and administration of the PRRT in support of recommendations two to 12.
2.43
The Centre for International Corporate Tax Accountability and Research (CICTAR) told the committee that it estimated that these changes to the PRRT may increase revenue by $6 billion per annum, though this has not been independently verified.
Calculating the transfer price
2.44
One key concern with the PRRT is the method of calculating the transfer price. The gas transfer price determines the value of gas feedstock for LNG plants at the PRRT taxing point—it determines the gross receipts subject to the PRRT. The current method for calculating the transfer price was recommended by accounting firm Arthur Anderson in 1998.
2.45
Monash University academic, Dr Diane Kraal wrote that Australia has adopted the complex residual pricing method (RPM) used no-where else in the world—it averages two prices, the 'net-back' price (used elsewhere) and the 'cost-plus' price (not used elsewhere). She and her co-authors observed that 'the current RPM is seen to advantage industry to the detriment of the community that owns the gas resources'.
2.46
Under the RPM method, the community is returned at a rate of 20 per cent of the total project rents.
2.47
Dr Kraal modelled PRRT revenue if the transfer price was calculated on the 'net-back' price rather than the RMP and found that revenue would be $15.5 billion instead of the presently anticipated $5.5 billion. Dr Kraal observed:
There is no obvious reason for the Australian government to value the gas itself at zero. The idea that its only value comes from the equipment, labour and technical know-how used to extract it wouldn't be accepted in the United States or in any other place that charges for resources extracted and demands payment promptly upon extraction … If Treasury's review of gas transfer pricing results in only fine-tuning the existing regulations it will miss the chance to get us a proper return on our resources. We own them and they are worth something.
The Treasury: gas transfer pricing
2.48
As part of the government's response to the Callaghan Review, in 2019 the Treasury initiated a separate review of PRRT gas transfer pricing arrangements.
2.49
Treasury's consultation paper asked for views on a range of matters including the pricing of feedstock gas in vertically integrated operations, CUP rules, and factors that impact the calculation of the RPM.
2.50
However, it warned that:
The purpose of determining the arm's length price in the legislation is to be able to determine the assessable receipts of the upstream project. In the PRRT, the assessable receipts provisions and the deductible expenditure provisions are finely balanced to ensure that it is the rents that are calculated.
The PRRT will not effectively tax resource rents, to the extent that the arm's length methodology chosen changes the balance between the assessable receipts provisions and the deductible expenditure provisions.
2.51
A range of views were represented in submissions, including calls for greater returns to the Australian community to fix environmental impacts and ensure energy justice, and the importance of largely retaining the current rules to ensure unnecessary uncertainty and administrative, practical and tax issues impacting on oil and gas investment.
2.52
The Treasury has conducted further targeted consultations with industry, however COVID–19 caused the review to be put on hold. The committee understands that work on the review has since recommenced, but with no indication from government on progress or finalisation of the review.
Taxpayers received how much?
2.53
APPEA advised that oil and gas projects have contributed around $155.71 billion to public revenue from 1987-2019—approximately $4.8 billion per year. The bulk of this has comprised corporate income tax of $70.7 billion, PRRT of $37 billion and $43.8 billion of production excise, royalties and fees. While these public revenue amounts sound large, petroleum export earnings are massively higher—estimated at $617 billion since 2010. The differential between export earnings and PRRT revenue is well illustrated in Figure 2.2.
2.54
In 2019, the total oil and gas revenue paid to Australians was estimated at around $3.52 billion per annum. This was balanced against future and foreseeable externalised costs which are borne by Australian taxpayers, which are estimated at between $2.23 and $25.4 billion per annum, comprising fuel subsidies and greenhouse gas (GHG) offsets.
2.55
The Australia Institute's recent Climate of the Nation 2021 report found that Australians overestimate the economic contribution of the oil and gas industry:
Australians … overestimate the economic value of the gas industry, believing it accounts for 11.3% of GDP, while the actual figure is around 3.2%.
…
On average, Australians believe that the PRRT … contributed 11.0% to the federal budget for the 2020–21 year … In reality, the PRRT contributed 0.2% to the federal budget, $800 million of the total $500 billion. In other words, respondents perceive the oil and gas industry as contributing around 55 times more to Australian Government revenue than it actually does.
2.56
The extent to which the PRRT, in particular, has been successful in maximising economic returns to Australians is hotly contested. The government's review of the PRRT in 2017 concluded that the tax was working as designed, and that declining PRRT revenue did not mean that Australians were not receiving and equitable return for their resources:
The overall assessment is that while the PRRT remains the preferred way to achieve a fair return to the community for the extraction of petroleum resources without discouraging investment, changes should be made to PRRT arrangements to make them more compatible with the developments that have taken place in the Australian oil and gas industry.
2.57
In 2018, the Senate References Committee, in its inquiry into corporate tax avoidance reported that:
Dr Craig Emerson, one of the architects of the original tax said:
"I think the story has been a pretty good one. I calculate that over its lifetime PRRT has collected around $33 billion for the people of Australia."
2.58
The Treasury noted that the corporate tax and the PRRT both work on the basis of profits and APPEA explained Australia's high-cost and complex regulatory environment, the risks associated with uncertain investment, and the high up-front costs associated with an oil and gas projects mean that PRRT payments until projects are in production and costs are deducted, as shown by Figure 2.3.
2.59
The ATO advised that in 2019–20 the 28 large market groups in oil and gas reported $17.5 billion of profit and has $71.8 billion of carry forward losses. In relation to PRRT for the same period the ATO advised that the PRRT payable was $881 million, with carry forward expenditure of $282 billion, shielding projects from a PRRT liability in the near future.
2.60
The ATO advised the committee that, at the time of the submission, 'LNG projects currently do not pay any PRRT', with payments expected once assessable receipts exceed deductible expenditure—estimated to occur between 2027 and 2050, with PRRT revenue expected to drop in the mid-2040s as some major projects end and have decommissioning expenditure refunded.
2.61
From other witnesses the committee heard damning evidence that Australia has failed to make the most of its resources through the PRRT—with both sides of politics complicit in creating a regime favourable to industry. They argued that the PRRT design has not sufficiently recouped economic benefit for Australia. Per Capita submitted that:
On any objective assessment of Australia's current taxation system, the third of these four categories remains the one in which successive governments have proved unwilling or incapable of implementing adequate taxation measures.
2.62
Similarly, Prosper Australia, observed that:
Whilst the Commonwealth is the legal owner of these resources, they have been largely gifted to the extraction industry with little recompense. In a modern economy this must be addressed.
…
Australia is akin to a petrostate without the petrodollars. We're basically giving away our resources as if they're an exclusive money tree for multinationals and their shareholders, and the problem we face is that our PRRT regime is banking on future superprofits that may never eventuate. The marginal investments encouraged by such a scheme may no longer be relevant in an impending future of stranded assets.
2.63
Mr Mark Ogge of the Australia Institute suggested that companies exaggerate revenue which never eventuates in order to get projects approved, and that they should be held accountable for anticipated revenue:
… companies put out releases and reports that claim that they'll make enormous contributions to revenue over the period of the project, and then years go by and no revenue is collected. They make those claims in the beginning to get the projects approved and then the payment to the Australian people never materialises. I think that when they make those claims, those claims need to be given much more scrutiny and they should be held accountable later on for making those claims—
2.64
Dr Kraal stated that annual payments under the PRRT peaked in 2000–01 at around $2.5 billion and that, at the time of writing, they were less than half that amount (for example: just over $1 billion in 2019–20 on LNG exports of nearly $55.5 billion), and much lower as a share of the economy and as a share of gas exported. Dr Kraal found that 'unlike oil projects, gas projects only provide utility rates of return, not "super profits"' and so the PRRT was not delivering as anticipated:
The overall performance of the PRRT is not operating as intended, in terms of the tax principles of simplicity, efficiency and neutrality between taxpayers, and providing an equitable return to the Australian community.
2.65
Dr Murray told the committee that all forms of resource taxation combined—including gas royalties, crude oil excise tax and the PRRT—provide a return of just 10 per cent on oil and gas revenues. He also observed the falling share of profits taxed by the PRRT—from around 50 per cent prior to 2000, to less than 20 per cent since 2010. Dr Murray concluded that:
Australia is a resource-rich nation that has only minimally attempted to recoup the value of the public's vast natural resources, despite being wealthy and politically stable. This has led to Australian governments at both the State and Federal levels missing out on a share of the windfall gains from a resource boom that began in 2004-05 and has subsequently unwound in terms of prices, but with elevated export volumes.
2.66
The Australia Institute, Mr Kevin Morrison and the Conservation Council of WA told the committee that this is due to overly generous deductions for expenditure such as that incurred by decommissioning, with deductions automatically increasing each year by an uplift rate. The Conservation Council stated that:
… [oil and gas projects] will need to be made safe and dismantled at an estimated cost of more than US$21 billion ($31 billion) and taxpayers will bear up to 58 per cent of this cost. So not only will some projects pay very little PRRT but they will get much of it refunded to cover decommissioning costs.
2.67
Professor Chandler highlighted the costs of decommissioning in the Bass Strait and the extent of PRRT decommissioning deductions:
… [there's a] deal being done between BHP and Woodside, which I think has Woodside having an allowance of $1.5 billion for the decommissioning cost of the Bass Strait. What's interesting about that is that the gross cost is $2.5 billion or more, but the amount they're going to reduce it by getting back PRRT and income tax is over $1.5 billion. Those are figures that people should know about.
2.68
The Conservation Council of WA said that cost overruns and delays have negatively impacted the payment of PRRT, enabling larger deductions and allowing time for deductions to grow over time. Chevron Australia acknowledged that cost overruns occur but are not intended to do so.
2.69
It has been reported that some LNG projects will never pay PRRT, despite extracting large volumes of gas. The IEEFA referred the committee to INPEX's Ichthys LNG project by way of example. It was reported in 2017 that the project would export $195 billion of LNG, liquified petroleum gas (LPG) and condensate over the next 30 years but will pay zero dollars in PRRT.
2.70
In defence of the oil and gas industry both APPEA and Mr Bill Townsend, Vice President Corporate at INPEX told the committee that the current regulatory and fiscal settings are vital to ensuring that oil and gas companies take risks and invest in Australian projects and that there are multiple benefits for the Australian community, with the Ichthys project expected to commence PRRT payments in the 2030s.
Other taxes, royalties, and excise…
2.71
Royalties are levied at a state level for onshore oil and gas and at a federal level from the North West Shelf (NWS), Barrow Island and some onshore production in Western Australia (WA) from pre-1979 leases, generally at a rate of 10 to 12.5 percent of the market value at the wellhead. NWS royalties are shared between the Commonwealth and WA, with WA receiving approximately two-thirds of gross payments.
2.72
Excise duties are applied under state jurisdiction and the NWS project and are levied on production or revenue at the time of production at between zero and 55 per cent.
2.73
APPEA estimated that around $43.8 billion has been paid to state and federal governments in production excise, royalties and fees between 1987 and 2019.
Maximising jobs for Australians
2.74
APPEA told the committee that Australia has benefited from over $450 billion of investments into its oil and gas industry, with the direct employment of around 30 000 people and indirect employment of a further 80 000 people in services areas which support oil and gas.
2.75
Modelling commissioned by APPEA forecasts that a high growth scenario will result in jobs growth, with the cumulative creation of over 220 000 jobs to 2040. By way of contrast, cumulative jobs created in a low growth scenario are forecast at 105 000 to 2040. The forecast growth is expected to stimulate demand, growth indirect employment, especially in finance and professional services, and trade and communications.
2.76
Modelling commissioned by National Energy Resources Australia (NERA) predicts that by 2030 the direct oil and gas workforce could decrease by as much as 5 000 jobs (net) or result in a net increase of between 1 000 and 3 000 jobs by 2030, depending on the growth scenario (see Figure 2.4). Growth of 2 000 jobs in total by 2030 is forecast as being most likely, with flow on effects to indirect services.
2.77
The Australia Institute advised the committee that the oil and gas is a small, low-labour intensive employer with 0.4 worker per million dollars output in 2020.
2.78
Their research found that:
Australian's overestimate the size of oil and gas industry employment by a factor of 46, believing it employs 9.2 per cent of the total workforce. In reality, oil and gas employment makes up less than 0.2 per cent of the workforce.
2.79
The Institute also noted that the industry cut around 3 800 jobs—or around 10 per cent of its workforce—in the year to May 2021 due to the impacts of COVID-19, lowering the estimated direct workforce to 25 000.
2.80
Mr Tegg from the AMWU also told the committee that employment in the oil and gas industry is actually 'very small':
The LNG industry employs, potentially in an ongoing fashion, a very small number of workers, certainly compared with manufacturing, which is closing in on 900,000 to a million—and that's directly employed manufacturing workers.
2.81
Industry insiders reported that, in the longer term as fields mature, margins tighten and the oil and gas industry looks to automation and artificial intelligence to improve safety, efficiency and margins, further job losses are forecast. At the very least, the changes will result in the shifting of jobs from repetitive diagnostic, administrative or manual work to data and information technology related roles.
2.82
Meanwhile, Strategic Sustainability Consultants and Global Goals Australia advised the committee that there is more that oil and gas companies could do to improve social sustainability through investment in local development to lower the risk of unemployment, particularly as the industry transitions:
Investing in development in the local areas not only includes infrastructure and social services but skills development to ensure a skilled workforce is able to continue to operate in the area once oil and gas operations have ceased. Supporting inclusive and sustainable urbanisation in communities near operations should be a priority in assessing social sustainability and ensuring operations are not creating emerging social inequalities in the local area.
Community and social benefits
2.83
Many community and social benefits have flowed to Australians as a result of oil and gas exploitation, but spending on these initiatives represents just a fraction of the profits garnered by the oil and gas industry:
employment opportunities, including for First Nations peoples;
provision of common-use infrastructure, including social infrastructure not related directly to oil and gas exploitation (such as roads, power and water infrastructure, swimming pools, housing, health facilities);
access to new water resources;
investment in universities, research, and training organisations;
developments in regional areas such as Gladstone, Roma, and the Pilbara;
benefits agreements with traditional owners; and
provision of social programs and partnerships with local communities (for example: Powering Careers in Energy program to increase energy literacy in schools, sponsorship of Perth Festival).
Environmental benefits
2.84
The oil and gas industry submitted that certain environmental benefits have flowed to Australians as a result of oil and gas exploitation which has included baseline studies and data; and environmental monitoring programs.
2.85
In contrast, other witnesses warned of the environmental problems created by the exploitation and use of oil and gas—with economic effects—including in relation to decommissioning and greenhouse gas emissions in the processing, transport and burning of fossil fuels. These issues are discussed further in Chapters 5 and 6.
How do other nations capture benefit from their oil and gas?
2.86
CICTAR compared Australia's revenue collection from oil and gas with that of other countries, telling the committee that:
… the UK as the only OECD [Organization for Economic Cooperation and Development] country where the fiscal regime for oil and gas was a greater failure than Australia's. Norway, Denmark and the Netherlands all collect significantly more government revenue from their hydrocarbon resources. If Australia's fiscal regime were equivalent to Denmark's or Norway's, for the period 2008-2015 Australia would have received an additional $104 to $122 billion in oil and gas revenues. However, Australia's LNG production has peaked since 2015 and the current and future losses in revenue would be much more significant.
2.87
Bearing in mind the varying geographical, geological, political, policy and fiscal positions of different jurisdictions, it is useful to look to at how other nations maximise returns from their oil and gas resources.
Benefit in overseas jurisdictions
2.88
Some overseas regimes—notably the US, Canada, UK and Norway—require national interest tests, or that resource management and exploitation is carried out for national economic benefit. While Australia's National Resource Statement contains a broad benefits statement there are no specific benefit requirements or actions to support this outcome in legislation or regulations. Moreover, Norway and the UK have strengthened their regulators over time because their initial approaches did not serve the national interest.
2.89
The UK belatedly realised the implications of not having a holistic approach and national benefit requirement, with the 2014 Wood report recommending the development of a new strategy for maximising economic recovery and improved regulation (amongst other things), as discussed in Box 2.2.
2.90
As a result, the government established the Maximising Economic Recovery of UK petroleum strategy (MER UK) strategy and legislated to place a duty on the new regulator to apply the strategy in all its relevant statutory and non-statutory duties:
Relevant persons must, in the exercise of their relevant functions, take the steps necessary to secure that the maximum value of economically recoverable petroleum is recovered from the strata beneath relevant UK waters.
Box 2.2: Case study: The Wood Review (UK)
In June 2013, the UK government established a review of UK offshore oil and gas recovery and its regulation. This review was led by Sir Ian Wood, a former oil industry executive. The Wood review was published in February 2014.
It surveyed the state of the oil and gas industry and identified a number of issues behind market trends, including:
a lack of focus on maximising economic recovery;
inappropriate government stewardship and regulatory oversight;
poor industry asset stewardship;
a lack of collaboration and overzealous legal and commercial behaviour between operators; and
poor implementation of strategy.
In relation to benefit, Sir Ian made a number of findings:
governments have not taken a holistic approach in regulating exploration, development and production and this had affected economic recovery of the UK's oil and gas resources;
there is a divergence of interests between oil and gas companies pursuing individual commercial objectives and the national interest to maximise recovery across fields and make the most efficient use of infrastructure; and
in many cases companies have constrained asset investment and expenditure in a drive to delivery short-term returns. Operators are not maintaining and utilising infrastructure and assets in a manner that would maximise the economic recovery from the fields under this licences and with consideration to adjacent resources.
The review made four key recommendations:
government (regulator and The Treasury) and industry develop and commit to a new strategy for Maximising Economic Recovery of UK petroleum strategy (MER UK);
a new arm's length regulatory body be established to effectively steward and regulate the industry and guide exploration, development and production investment decisions towards achieving the MER UK strategy;
the regulator be given additional powers to enforce the MER UK strategy; and
sector strategies should be developed and implemented, including for exploration, asset stewardship, regional development, infrastructure, technology, and decommissioning.
The UK government generally supported all the recommendations of the Wood review, though emphasised the need to ensure any regulation did not reduce competition or affect the market economy. It did not agree to give the regulator all the powers Wood had recommended, only to review whether more were necessary and to emphasise the regulator would work in partnership with industry. In response to the findings the government:
Developed the MER UK Strategy;
established the commendation the Oil and Gas Authority (UK) (OGA) to undertake licencing, exploration and development regulatory functions, giving them additional powers to enhance its alibility to encourage and facilitate collaboration and dispute resolution; and
agreed to the development of sector strategies as the building blocks of the MER UK strategy.
The MER UK strategy contained five high-level principles:
all stakeholders should be obliged to maximise the expected net value of economically recoverable petroleum from relevant UK waters, not the volume expected to be produced;
compliance with the Strategy is intended to lead to investment and operational activities that, on an expected basis, add net value overall to the UK;
compliance with the Strategy may oblige individual companies to allocate value between them, matching risk to reward. However, while the net result should deliver greater value overall, it will not be the case that all companies will always be individually better off;
compliance with the Strategy will not lead to any individual company investing in a project or operating existing assets where there is not a satisfactory expected commercial return on that investment or activity. Such a return does not necessarily mean a return commensurate with the overall corporate return on their portfolio of investment; and
in determining whether something is consistent with the principal objective the OGA will need to balance the benefit of economic recovery of petroleum with the need to maintain the confidence of new and current investors to invest in exploration and production of petroleum from relevant UK waters, taking into account market conditions at the time of making its determination.
In mid-2020 the OGA conducted consultation on its intention to review and update the core aim of the MER UK, including a requirement for industry to help the government achieve the target of net zero greenhouse gas emissions by 2050. It did this through its central and supporting obligations and required actions. The revised strategy—the OGA Strategy—was published in December 2020 and came into force on 11 February 2021.
The OGA believes that the industry has skills, technology and capital that can help the UK achieve the net zero target, without compromising economic activity, and that the oil and gas industry needs to move faster or 'risk losing its social licence to operate'. The OGA envisaged a role for renewable energy sources, as well as carbon capture, utilisation, and storage (CCUS) and hydrogen, as well as measures aimed at maximising value of existing reserves, minimising emissions, energy efficiency measures and requirements for access and collaboration. 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.
Norway
2.91
Norway is regularly cited as having an effective system to capture the economic value of its oil and gas reserves for public benefit.
2.92
The Norwegian Government Pension Government Pension Fund Global (GPF‑G), formerly called the Petroleum Fund of Norway, is now the largest sovereign wealth fund in the world—in 2021 the fund was worth around $1.7 trillion. The Norwegian state's ability to invest substantial amounts abroad combined with relatively moderate fiscal spending compares favourably with other countries where governance structures have been exposed to large resource-driven income streams.
2.93
While Norway has access to cheaper, and more accessible gas than Australia, the returns are nevertheless impressive at a rate of 63 per cent return on industry revenues. It captures these returns through company tax, a special rate petroleum tax and royalties, as well as direct ownership in private oil companies, and through profits from the national oil company Equinor, with the bulk of the returns through the petroleum tax system and direct ownership.
2.94
With the state holding a 30 per cent direct financial interest it is able to exert significant shareholder influence (for example, in relation to tax compliance), and if the company does minimise its tax the government can earn back 30 per cent of the lost tax as shareholder profit.
2.95
The Norwegian company tax rate is 22 per cent, with a special rate petroleum tax applied at 56 per cent, to give a marginal tax rate of 78 per cent on oil and gas companies. Norway limits its carry-over and cost escalation allowance to 5.4 per cent, rather than Australia's 15 per cent above the long-term bond rate.
Qatar
2.96
Prosper Australia explained that Qatar does not levy a petroleum rent tax, rather it calculates petroleum royalties via a five per cent withholding tax, with arrangements available to minimise this rate. Bonuses are also payable at specified points, and there are cost recovery and profit-sharing arrangements.
2.97
A minimum 35 per cent income tax rate is also applied to mining and gas operations. Compliance focuses on tax avoidance strategies and monitoring debt loading. The Qatari government has a direct stake in all stages of oil and gas activities through the state-owned Qatar Petroleum.
2.98
The government of Qatar was forecast to collect $26.6 billion in royalties from its LNG reserves in 2021. In the same year Australia was forecast to receive $800 million for the same volume of gas.
Israel
2.99
Prosper Australia also described Israel's oil and gas arrangements, with royalties of 12.5 per cent levied at the wellhead from day one of production. Additionally, a deductable profit levy of zero to 50 per cent is levied on a 150 per cent return on investment, after which the levy increases on a sliding scale from 20–50 per cent over a number of years, depending on the size of the field. A small lease fee is also required.
2.100
When combined with the corporate income tax rate of 23 per cent, the government tax rate was 52–62 per cent, however changes in 2012 reduced this to a top rate of 57.5 per cent.
2.101
In 2018 revenue from Israel's oil and gas industry was $371.5 million (₪878 million), dropping in 2019 to $365.5 million (₪864 million).
2.102
Israel also requires lease holders to provide an adjustable bank guarantee, to a maximum of US$50 million per lease upon commencement of gas flow. This ensures that leaseholders meet all lease and permit requirements, with the guarantees remaining in force even after the expiration of the leases, until the Petroleum Commissioner deems them no longer necessary.
2.103
The Commissioner is entitled to collect all or part of the guarantee if development or production does not commence as planned, in the event of safety or environmental events, if decommissioning and remediation does not occur as planned, amongst other things.
Where is benefit in the current oil and gas framework?
2.104
Australia's oil and gas legislation, the Offshore Petroleum and Greenhouse Gas Storage Act 2006 (OPGGS Act) refers generally to 'public interest' but does not specifically require or confer responsibility for the effective management of oil and gas resources:
I think that this [responsibility for maximising the return to the Australian public] is something that is not, in my view, sufficiently clearly specified. I think it falls on government at the moment in a fairly general sense as part of government's duty. Insofar as it being in Commonwealth waters, it's the Commonwealth government which has sovereign rights over the petroleum … a lot of statutes in Australia say, 'This is a statute about mining,' or, 'This is a statute about petroleum.' They don't actually set out what it is the statute is trying to achieve, and the OPGGSA is exactly like that.
2.105
Professor Chandler told the committee that the policy framework also does not adequately address benefit—it does not include specific economic objectives or social values—and 'there is no duty to maximise the value received, to ensure that development is carried out sustainably or, more basically, to have a strategy or plan to manage the costs, benefits and risks.' Rather, he states, the current regime relies on the economic activity generally contributing to government revenue and jobs:
2.106
Senator Rex Patrick expended considerable energy trying to establish where in government any responsibility for maximisation of benefit lies. While the broad responsibilities of specific agencies were noted—in relation to science, taxation, and regulation—tying down ultimate responsibility for benefit was like trying to catch a fish in an oil slick. Mr Paul Trotman, Head of the Resources Division, Department of Industry, Science, Energy and Resources (DISER) suggested that ultimately the Minister for Resources and Water is responsible, in conjunction with the Treasurer.
2.107
While this may be so, it appears that no department is required to consider the economic benefits and returns to Australians—a situation Professor Chandler found difficult to comprehend:
The whole point of a nation disposing of its national petroleum assets is to derive economic benefits, particularly tax. In effect it is a sale by the nation of its property for tax revenue. It therefore seems bizarre that, so far as I can gather, Treasury and the ATO apparently sit off to one side and, for example, are not involved in the review of the approval of projects. In my submission there should be a clear line of sight reporting to the tax collected by individual projects.
2.108
In Australia, no agency has an expressed objective or function to protect the country's economic return on the disposal of public property—which includes its oil and gas reserves.
2.109
Benefit considerations are also missing from the responsibilities of the Joint Authorities—the major decision makers under the Act—and the National Offshore Petroleum Titles Administrator (NOPTA). NOPTA's current legislation does not permit infrastructure oversight, although recent legislative changes to the OPGGS Act have strengthened the regulator's ability to assess applicant financial suitability and titleholder dealings.
2.110
The broad nature of the existing policies associated with oil and gas decision making and approvals and their lack of measurable objectives and supporting criteria means that there are real gaps in accountability and public benefit.
2.111
It also appears that 'it is impossible to calculate from publicly available information the total return to the Australian people from any individual project. Governments in Australia do not appear to produce this information for their own administrative purposes'. This appeared to be backed up with evidence from The Treasury, with Mr Francis advising 'I'm not aware of anyone having compiled a total picture of the economy. I would say there are a few different channels through which the benefits flow'.
2.112
Moreover, it appears that modelling of anticipated economic benefits to taxpayers are not required to be submitted by industry as part of project approvals, and projected of revenues, inclusive of costs to the Australian people, are not completed by government.
Improving benefit to Australia
2.113
The Centre for Mining, Energy and Natural Resources Law submitted to the committee that a key characteristic of concession-based regimes (such as those in Australia, Norway, and the UK) is that oil and gas companies are obliged to act in the company's (shareholders') interests, not those of the country or other licensees. As such, companies will look to maximise their immediate profits from the licence area, not from the region, because the maximisation of resource extraction from a region is complex and requires cooperation between companies. The Centre argued that this in-built conflict of interest needs to be actively managed.
2.114
A licence area approach means that production from the oilfield is not as efficient as it could be—excessive infrastructure and lack of shared facilities results in unnecessarily high capital, operating and decommissioning costs, significant amounts of oil left behind, and the flaring of any excess gas produced. As Australia's oil and gas basins mature this creates more challenges.
2.115
Professor Chandler argued that Australia's regime has focussed on exploration and exploitation with light touch regulation and that it relies on companies and government having the same interests in profitable production. However, as there is no penalty for poor performance—or even knowing what the performance is—there is a gap in the regulatory system; the same regulatory system that has seen some projects return little or no PRRT and governments having to bear decommissioning costs.
2.116
Norway introduced legislative changes which included state control and a requirement for non-renewable resource management 'to be carried out in a long-term perspective for the benefit of the Norwegian society as a whole' in 1972. In 2015 the MER UK and subsequent OGA Strategy sought to manage this conflict of interest, but also established a framework that would produce significant production and cost savings—a win-win for both government and industry.
2.117
The Centre for Mining, Energy and Natural Resources Law recommended a Wood-style review of Australia's oil and gas industry to gauge potential economic gains, ensure regulation in which benefits would outweigh the costs, and increase the accountability of NOPTA and NOPSEMA. Furthermore, Professor Chandler argued that the federated system means that states focus on the quantity of production, rather than the overall quality or profitability of production. He suggested that a domestic review would take into account Australia's particular circumstances, with lessons to be learnt from the UK.
Requirement to meet national interest, economic, environmental and infrastructure outcomes
2.118
International Monetary Fund (IMF) research pointed to the challenges associated with resource wealth management including overreliance on non-renewable natural resource revenue, and the risk that some governments will rely on depletion of natural resources rather than the development of a longer-term development strategy that develops other competitive exports. The IMF advocated for strong policy frameworks that consider the interests of both current and future generations, the development of human capital and economic diversification to address these challenges.
2.119
Likewise, Professor Chandler argued that Australia's licence model must evolve to consider public benefit:
To achieve those things [accountability and good regulation] requires the duties of ministers and regulators to be articulated and reported on, so there is transparency in whether beneficial outcomes are achieved for the Australian people. The issues raised apply beyond non-renewable resources to any activity relying on the private sector to dispose of public property or to provide a service delivering value to the community. They go to the heart of government accountability for its dealings with public property.
2.120
He recommended changes in two key areas:
that there be a clearly stated national interest objective with stewardship duties placed on public officials to maximise benefit from non-renewable resource project and to consider projects holistically; and
that this be supported by specific outcomes, requirements, reporting review, and appropriate compliance actions to ensure the outcomes are realised.
2.121
Mr Steve Walker, who led the investigation of matters leading to the administration and liquidation of the NOGA group of companies and the abandonment of the Northern Endeavour observed that there was potential for NOPTA or a similar body to play a bigger role in maximising benefit, telling the committee that 'they talk about optimum resource recovery, but I felt that, because of their powers and their roles, there were legal restrictions and other constraints that went against that sort of bigger vision'.
2.122
Under the current provisions the focus is on commercial viability and early development, rather than a holistic view of the benefit, economic return and environmental sustainability of the development. There is considerable scope for Australia to apply economics, costs or taxes and environment sustainability approval criteria and to require additional reporting and performance data (discussed further in Chapter 4) which can be benchmarked and published to drive improvements and on which ongoing project approval is contingent—including in relation to project returns.
2.123
Professor Chandler advised that field development plans (FDPs) have the potential to be used as a critical tool to drive improved economic, environmental and infrastructure outcomes, including by testing the economic viability of the project, assuring the viability of the operator/s, and quality of the development plan and its execution.
2.124
Mr Mark Ogge from the Australia Institute supported the need for evaluation and verification of delivered benefits, stating:
… these companies put out releases and reports that claim that they'll make enormous contributions to revenue over the period of the project, and then years go by and no revenue is collected. They make those claims in the beginning to get the projects approved and then the payment to the Australian people never materialises. I think that when they make those claims, those claims need to be given much more scrutiny and they should be held accountable later on for making those claims—