Chapter 5

Offshore oil and gas

5.1        Natural resources, including oil and gas, are often regarded as commonly owned and, reflecting this, are subject to payments to government in addition to ordinary taxes on companies. In this chapter, payments directly associated with the extraction of natural resources are referred to as taxes (in particular the Petroleum Resource Rent Tax). However, it is questionable whether these payments should be considered taxes at all.[1] That said, this chapter uses the word 'taxation' to apply to royalties, excise and the PRRT. In general it will not discuss more general aspects of aggressive tax avoidance and minimisation as these are dealt with in the previous chapters and interim reports.

5.2        This chapter:

Other reviews

5.3        Issues regarding the structure and administration of oil and gas royalty schemes were highlighted in the 2016 Australian National Audit Office (ANAO) report into the collection of NWS Royalty Revenue. The report found, among other things, that there are some significant shortcomings in the framework for calculating NWS royalties and there is a risk of significant errors in the claiming of deductions.[2]

5.4        The Treasurer announced a review of the Petroleum Resource Rent Tax, crude oil excise and associated Commonwealth royalties on 30 November 2016, to be chaired by Mr Michael Callaghan AM PSM. Mr Callaghan was asked specifically to:

...lead a review into the design and operation of the Petroleum Resource Rent Tax, crude oil excise and associated Commonwealth royalties to provide advice on the extent to which they are operating as intended.[3]

5.5        In announcing the review, the Treasurer said:

The review will advise the Government to what extent the [PRRT] is operating as it was originally intended, and shall address the reasons for the rapid decline of Australian PRRT revenues. The Government will then refer to these findings and recommendations to reform the PRRT.[4]

5.6        The review dealt with both offshore and onshore operations. It received 77 submissions, which are publicly available on the Treasury website (under the heading Consultation). The review report was released by the Treasurer on 28 April 2017—incidentally, the day of the committee's first hearing on this issue. The report is referred to here as the Callaghan report.[5]

5.7        On 30 June 2017 (the last working day prior to the second hearing on this issue), the Treasurer announced the Government's interim response to the Callaghan report.[6] Treasury published a consultation paper, Options to address the design issues identified in the Petroleum Resource Rent Tax Review and invited submissions from the public by 28 July 2017.[7] The submissions have been published.[8]

The state of the industry

5.8        The oil and gas industry is an important part of the Australian economy, through the supply of energy to households and industry, the investment of hundreds of billions of dollars of capital, the payment of taxes to governments, the direct employment of thousands of Australians, and the generation of significant amounts of export earnings. 

5.9        It is worth noting that the industry is largely foreign owned, so it does not pay large dividends to Australian shareholders. It is also capital intensive, so once the initial construction stages are complete it is not paying a large amount of wages or payroll taxes.

5.10      Oil and gas extraction constitutes about 2.0 per cent of Australia's GDP. Industry revenue is approximately $34 billion.[9] The decade from 2004 to 2014 saw an unprecedented resources boom in Australia. In a time of high world prices for minerals and petroleum, there was a huge inflow of investment funds for exploration and capital expenditure. Many of the projects begun at that time are now only just beginning to produce oil and gas.

5.11      While industry output by volume increased at an average 7.6 per cent a year over the last five years, revenue for the industry has fallen at an average of 4.6 per cent a year, in line with reduced world oil and gas prices. However some industry commentators project growth at over 10 per cent a year in coming years.[10]

5.12      In recent years, seven plants to liquefy natural gas for export have come on stream, with a further three in development. Liquefaction makes export of gas feasible. Liquefied natural gas (LNG) is poised to become Australia's biggest export. In 2016, LNG was Australia's fifth biggest export. It constituted 5.4 per cent of exports by value, having grown at an average of 9.6 per cent a year for the previous five years. The value of LNG exports is projected to increase from an estimated $23 billion in 2016–17 to $37 billion in 2018–19. Growth in export earnings will be supported by higher export volumes and, to a lesser extent, higher prices.[11]

5.13      Crude petroleum accounted for another 1.6 per cent of exports in 2016, but it has been falling rapidly.[12]

5.14      Of the $34 billion in industry revenue in 2016–17, $28.5 billion (or 84 per cent) was associated with exports. While the high level of exports is welcome economically, it is becoming controversial in the context of rising domestic gas prices and fears that there will be insufficient gas to power Australian industry.

5.15      While there are 384 businesses active in the oil and gas extraction industry, over half of the market is accounted for by five companies: Woodside Petroleum Ltd, BHP Billiton Ltd, Chevron Australia Holdings Pty Ltd, ExxonMobil Australia Pty Ltd, and Santos Ltd.[13] BP Developments Australia Pty Ltd, Shell Australia Pty Ltd, INPEX and ConocoPhillips Australia are also significant players.

5.16      Woodside, BHP and Santos are Australian based. The others are foreign owned.

5.17      The industry's performance depends on world energy prices and supply and demand, exchange rates, and the supply of new oil and gas discoveries.

5.18      On a much smaller scale is the petroleum exploration industry. It has revenue of $1.5 billion, and is very dispersed, with no dominant players.[14] The oil and gas extraction industry is its principal customer.

Major projects

5.19      Geoscience Australia states that Australia has approximately 0.3 per cent of world oil reserves, noting that:

Most of Australia’s known remaining oil resources are condensate and liquefied petroleum gas (LPG) associated with giant offshore gas fields in the Browse, Carnarvon and Bonaparte basins. In addition oil resources are identified in the Perth, Canning, Amadeus, Cooper/Eromanga, Bowen/Surat, Otway, Bass and Gippsland basins.[15]

5.20      The major Australian offshore oil and gas production and exploration projects are located in the Bass Strait, and off the coast of the Northern Territory and Western Australia. Onshore projects are in the area where the borders of South Australia and Queensland meet. In addition, there are reserves of coal seam gas in several locations, with the furthest developments being in Queensland. (See Figure 1.)

5.21      The exploration stage of a petroleum project typically takes more than six years, with up to a further 10 years in project development. Production can last between 10 and 20 years, followed by decommissioning, which in itself is a major undertaking over several years.

Bass Strait

5.22      The Gippsland basin in Bass Strait was developed by BHP in partnership with ExxonMobil in the 1960s. At the peak of production in the early 1980s, the venture was delivering 10 per cent of total Commonwealth revenue. It now meets 40 per cent of Australia's east coast gas needs.[16] The original fields are still producing but as indicated in Figure 1, the reserves will come to the end of their life soon. Further projects are being developed there, including the Kipper Tuna Turrum (KTT) project, which uses some of the existing infrastructure, and in which Santos has a 35 per cent share along with BHP Billiton and ExxonMobil. The joint venture is also undertaking new exploration in the area. There is continuing exploration in the Otway basin on the western side of Bass Strait.

Figure 1: Major oil and gas projects

Source: Geoscience Australia, Australian crude oil, condensate and naturally-occurring LPG resources, infrastructure, past production and remaining resources

Carnarvon basin

North West Shelf

5.23      The Woodside-operated North West Shelf (NWS) Project in the Carnarvon basin off the north-west coast was for many years Australia’s largest oil and gas development. It is owned in equal shares by Woodside, BHP Billiton, BP Developments, Chevron, Shell Australia and Japan-Australia LNG. It was first explored in the 1970s and developed in the 1980s. It includes the Karratha Gas Plant and other LNG processing facilities, and exports a large part of its production to China and Japan.[17]

Barrow Island

5.24      Oil was discovered on Barrow Island in the 1960s, and it has been the largest onshore oil field in Australia, operated by Chevron.[18]

5.25      The Gorgon gas field is the largest single resource development in Australia. It started LNG production in 2016. It is a joint venture between Chevron (47 per cent owner), ExxonMobil, Shell and several much smaller shareholders. Its LNG plant is on Barrow Island.[19]

Wheatstone

5.26      The Wheatstone project is 64 per cent owned by Chevron, with Kuwait Foreign Petroleum Exploration Company and Woodside each holding 13 per cent. It is a large project with a 30 year life span and began production in October 2017. Most of its product will be exported to Asia.[20] 

Pluto

5.27      Woodside developed Pluto from discovery in 2005 to production in 2012. The gas is piped to an onshore LNG plant.[21] There are plans to increase production.[22]

Bonaparte Basin

Darwin LNG

5.28      The Bonaparte Basin is off the north coast of the Northern Territory and Western Australia. Darwin LNG began production in 2006 and is operated by Conoco Phillips. Santos was a founding partner. The companies, who own further exploration permits, are considering (with Origin and others) a multi-field expansion to keep the plant running. Current reserves will run out in 2022.[23]

Browse basin

5.29      The Browse basin is off north-western Australia. It is in very deep water, so, despite good exploration results, it has been developed later than other areas.

Ichthys

5.30      The Ichthys project is being developed by INPEX, a Japanese company. It will involve initial processing in a floating offshore facility. Most production will then be directly shipped to global markets. Some of the gas will be piped 890 kilometres to onshore processing facility near Darwin. The project will cost US$34 billion. Production was scheduled to commence in March 2018.[24]

Prelude

5.31      INPEX also owns 17.5 per cent of Shell's Prelude development. It will be serviced by a floating LNG plant—'the biggest ship in the world'. The gas procecced will be directly exported. It is envisaged that the plant can be used to exploit other reserves when the current reserves run out. The Prelude project is also expected to commence production in 2018.[25]

Onshore projects

5.32      Large coal seam gas reserves have been discovered in Queensland and to a lesser extent New South Wales. At present the gas is being processed for export at the Curtis LNG, Gladstone LNG and Australia-Pacific LNG projects in Gladstone, Queensland. There are also several other proposals for Coal Seam Gas CSG-LNG plants under consideration for Gladstone and potentially other areas of Queensland.

Summary—Year of project entry into PRRT system

5.33      The Callaghan report lists projects which are producing or near producing:[26]

The logic of taxes on oil and gas

5.34      The characteristics of a good tax system are generally said to be:

5.35      Any system of taxation of resources attempts to balance the right of the owners of the resources—the general public—to a fair return for the finite resources against the right of the resource developers to a fair return on their risky investment. The balance is said to be necessary to ensure that exploration and development continue. This is desirable not only because of the return by way of resources taxes but also because of the economic benefits of resources activity. These benefits include direct employment and taxation of profits, and downstream and spinoff benefits from the activity.

5.36      In general, ownership of minerals including petroleum in Australia rests with governments on behalf of the community. The states and territories own minerals onshore to the three mile territorial limit, and the Commonwealth owns resources beyond the three mile limit and in the external territories.[28] Governments impose charges on oil and gas extraction to ensure that the community receives a benefit from their development. Charges on the extraction of resources in Australia have historically included specific Commonwealth and state government taxes.[29]

5.37      Conceptually, there are three different ways of thinking about taxes on petroleum—excises, royalties and resource rent taxes.

5.38      An excise can be charged by the Commonwealth on the volume of the resource extracted. This approximates to the community charging a price for the resources. It has the advantage of simplicity. It has the disadvantage that it has to be set at a level where it will not discourage exploration and development if prices are low, which means that if prices are high the community will not share in the windfall.

5.39      Some variations on excise include an element of price. The Australian Government imposes an excise on eligible crude oil and condensate production from coastal waters, onshore areas, and some North West Shelf projects in Australian waters. Excise liability is worked out by applying the relevant crude oil excise rate to the volume weighted average price. The first 30 million barrels of crude oil and condensate from a field are excise exempt. The 'relevant rate' depends on factors to do with when the project was developed.[30]

5.40      Royalties are usually based on the value of petroleum extracted. They can be levied by the Commonwealth or the states or jointly. Onshore royalties are levied by the states, generally at a rate of 10 per cent of value extracted. In 1967, the Commonwealth and the states agreed on an Offshore Constitutional Settlement. The agreement includes a 60:40 revenue sharing of a 10 per cent royalty on the well-head value. Any royalties exceeding 10 per cent go entirely to the State.

5.41      It is possible for the Commonwealth to waive excise in return for a revenue sharing agreement with a state known as a Resource Rent Royalty. Currently such an agreement exists only for Barrow Island. The revenue is shared 75:25.[31]

5.42      Like excise, royalties can be simple. In some cases, however, they are complicated by the rules governing what can be written off against the value of production. Because they are calculated without regard to profitability, they could be a disincentive to investment in marginal projects.[32]

5.43      A resource rent tax has a different basis. In economics, a rent is a profit made over and above the return that is necessary for an activity to continue. Thus it makes sense to tax rents because the tax will not distort economic activity. Petroleum prices can vary widely, so it is possible that any one project in some years is highly profitable and in other years only breaks even. While excise and royalties are taxes on production, and company tax is a tax on current profit, a rent tax is a tax on excess (or super) profits.

5.44      A rent tax has the advantage of being counter-cyclical: when the economy is booming and prices are high, the tax taken is high and may dampen production and investment activity slightly. When the economy is sluggish and prices are low, less tax is taken and there is less dampening effect from the tax.

How the PRRT works[33]

General description

5.45      The Petroleum Resource Rent Tax (PRRT) was introduced in 1987 to replace Commonwealth excise and royalties in offshore developments. In 2012 it was extended to apply to apply to all Australian onshore and offshore oil and gas projects, including the North West Shelf and coal seam gas projects.

5.46      It is project based (rather than company based)—although some trading off among projects owned by an entity is possible. Any entity with an interest in a petroleum project is liable for its proportion of the PRRT on that project.

5.47      Two or more projects may be treated as a single project if the Commonwealth Minister for Resources considers the individual projects are sufficiently related.

5.48      PRRT applies to products as they are extracted, and not to value added. Thus it does not apply to LNG, only to the original gas.

5.49      It is levied at 40 per cent of the net revenues (sales receipts less eligible expenditures) from a project. The basis of this calculation is somewhat different from, and more generous than, the basis for company tax. The amount of PRRT paid is deducted from company income for company tax purposes.

5.50      Eligible expenditures include exploration expenditure and all project development and operating expenditures, but some different treatments apply to these different classes of expenditure.

Closing down expenditures

5.51      Closing-down expenditures, including offshore platform removal and environmental restoration, are also deductible in the year in which they are incurred. If receipts during the year the project is closed down are less than the closing down expenditures, a credit is available, depending on whether the project has previously paid PRRT, for offset against other liabilities owed to the Australian Government.

Carrying forward unused deductions

5.52      Undeducted exploration expenditure incurred after 1 July 1990 is transferable to other projects with a taxable profit if, at the time the expenditure was incurred, the projects were held by the same entity. Similar rules apply in relation to the transfer of expenditure between projects held by companies in a company group.

5.53      In years where eligible deductions are greater than revenue, the undeducted amounts are compounded annually at set 'uplift' rates. The compounded amount is then deducted against assessable receipts in the following year. The compounding with 'uplift' is intended to offset the risk that a company will not be able to use the deduction.

5.54      The uplift rate for exploration expenditure is 15 percentage points above the Australian Government long term bond rate (LTBR), except that exploration expenditure incurred more than five years before the issue of a production licence is uplifted at the inflation rate.

5.55      The uplift rate for other expenditure, including capital and operating expenditure, is 5 percentage points above the LTBR.

5.56      All exploration expenditure incurred in areas covered by the PRRT is deductible against all PRRT liable projects held by that entity subject to compliance with anti-avoidance provisions. In the case of a company in a company group, the expenditure will be deductible against all PRRT liable projects held by the group. This ensures that the pattern of exploration is not affected by taxation arrangements. Non-exploration expenditure is not transferable between projects.

5.57      Where exploration expenditure has been transferred between projects, compounding is set by reference to the date of the production licence of the receiving project. If there is more than one project to which exploration expenditure can be transferred, the expenditure must be transferred to the project with the most recent production licence.

5.58      Exploration expenditure in areas designated as frontier between 2004 and 2008 are eligible for 150 per cent uplift under the PRRT.

5.59      There are expenditures that are not deductible. These include financing costs, private override royalty payments, income tax, goods and services tax, cash bidding payments and certain indirect administrative costs.

5.60      There is an order of deduction for different categories of expenditure. General project expenditure is deducted first, then exploration expenditure incurred within the project, closing down expenditure, and finally exploration expenditure that is transferred from another project.

5.61      Royalties and excise payments are credited against PRRT liability.

2012 starting bases

5.62      With the extension of the PRRT on 1 July 2012 to onshore petroleum interests and interests in the North West Shelf project, projects that existed as at 2 May 2010 (when the new arrangement was announced) were given a ‘starting base amount’. The starting base is intended to provide a shield against a PRRT liability in respect of projects that were not subject to the PRRT when they were established. Once a petroleum interest becomes a petroleum project, the starting base amount is immediately deductible. Any unused amounts are uplifted by the LTBR plus five per cent each financial year. Starting base amounts are not transferable between projects.[34]

Revenue from taxation of oil and gas companies

5.63      The Australian Petroleum Production & Exploration Association (APPEA) has estimated the level of company and resource tax payments made by the Australian oil and gas industry. APPEA notes that tax payments generally averaged between $7 billion and $8 billion per annum between 2007–08 and 2013–14 but were lower in 2014–15. It notes that the industry paid $5 billion in tax in that year even though it operated at a loss because of a significant reduction in commodity prices and the continued decline in petroleum liquids production.[35]

5.64      This figure has now been updated to a combined loss of $4.5 billion, with taxes paid of $4.25 billion. Total revenue fell from $29.99 billion to $23.73 billion.[36] This was partly due to lower prices and lower production, but also included non-cash depreciation and amortisation costs. These have increased in recent years because of the massive investment during the boom. One commentator noted:

So operating cash profits were still coming in, even after interest and tax payments were made. When non-cash depreciation and amortisation costs are taken out, the industry made an after-tax profit of $5.11bn in 2015–16, down from $9.83bn in 2014–15 and the lowest since 1999–2000.[37]

5.65      The Treasury in its Issues Note for the Callaghan review tracked the fall in PRRT takings from an average of 0.2 per cent of GDP through the 1990s and early 2000s, to an average of 0.12 per cent of GDP from 2002–03 to 2015–16, and around 0.05 per cent over the forward estimates. Crude oil excise collections averaged 0.05 per cent of GDP from 2000–01 to 2012–13, but have been declining since and are now very small. Commonwealth royalties have tracked similarly, from an average of 0.04 per cent of GDP for the period from 2000–01 to 2011–12 to less than half that now.[38]

5.66      There is some volatility in the estimates, because of fluctuating world energy prices and exchange rates. For example, the estimate of PRRT revenue for 2016–17 varied by $130 million (14.1 per cent) between the 2016–17 Mid-Year Economic and Fiscal Outlook in December 2016 and the 2017–18 Budget in May 2017; for the estimate of revenue for 2017–18, the variation in the two estimates (that is, between MYEFO and Budget) was 11.2 per cent.[39]

5.67      There has been a change in the mix of production. Resources from older projects, which had deducted all their expenses and were paying PRRT, are becoming exhausted. New LNG projects, which have incurred a lot of deductible expenditure, are now coming on stream, but they are not yet paying PRRT.[40] 

Issues in the taxation of oil and gas

Public concern about the level of taxation

5.68      The taxation of resources in Australia has been controversial at least since gold miners' monthly licence fees were a precipitating factor in the Eureka Rebellion of 1854. The resources are regarded as belonging to the community at large, but those extracting them have to go to considerable effort and expense, at risk, before they have any returns that can be taxed. A part of the solution to the unrest at Eureka was the replacement of the licence fee with an annual miner's right and the imposition of a tax on the value of gold exported.

5.69      Interest in the management of petroleum resources is not confined to Australia. There is a large economic literature on the 'resources curse' which suggests that resource wealth can damage an economy directly through macroeconomic effects and indirectly through corroding its institutions.[41] Some of the interest is more specifically focused on lobbying by the mining industry: for example, Publish What You Pay Australia is part of a global initiative campaigning in 40 countries for transparency and accountability in the mining and oil and gas industries.[42]

5.70      Concerns about the structure and operation of oil and gas taxation schemes in Australia have been voiced by various stakeholders. For example, the International Transport Workers' Federation (ITF) claims that of the top five LNG exporters in 2014, Australia has the lowest government revenue from oil and gas (table 1). The ITF released several briefing papers in 2015 and 2016 that outlined the oil and gas taxation issue.[43]

5.71      The ITF notes that, with the exception of the North West Shelf (NWS), Australia has no royalty payable on offshore oil and gas production in Commonwealth waters. The PRRT is not a royalty payment but a profit-based tax. While the tax rate is set at 40 per cent, significant investments in development and exploration mean that the PRRT is not forecast to collect any revenue on LNG production for decades.[44]

Table 1: Top Five LNG Exporters in 2014—Government Revenue from Oil and Gas

Rank among LNG exporters, 2014

Country

Oil and gas production ('000 oil-equivalent barrels

Government revenues from oil and gas (US$m, 2014)

Government revenues as % of production values, 2014

1

Qatar

1 838 018

$88 246

4.80%

2

Malaysia

660 746

$20 286

3.07%

3

Australia

511 357

$7 275

1.42%

4

Nigeria

1 104 559

$36 952

3.35%

5

Indonesia

772 666

$25 824

3.34%

Source: International Transport Workers' Federation, An International Comparison of Australian Government Revenues from Oil and Gas Production, November 2016, p. 2.

5.72      The Tax Justice Network Australia (TJN-Aus) has conducted a sustained campaign arguing that the industry does not pay its fair share of tax.[45] It too notes the Australian Government's revenue from oil and gas production, adjusted for volumes, is significantly lower than other large LNG exporters.

5.73       TJN‑Aus contends that the PRRT was designed for a very different petroleum industry, and suffers from design flaws that make it excessively generous and not fit for purpose in an industry dominated by integrated gas-to-LNG production. However, even removing opportunities for profit shifting and incentives for inefficient allocation of capital is unlikely to generate PRRT revenue for some time given the industry has already accumulated $238 billion in PRRT credits (see below).[46]

5.74      The advocacy organisation GetUp! has also campaigned on the issue of taxation of petroleum companies. It commissioned academic work, which it furnished as an attachment to its submission, which suggested that faults in the design of the PRRT and inappropriate debt loading of Australian operations meant that petroleum companies were not paying a fair share of tax.[47]

5.75      Oxford academic Dr Juan Carlos Boué has calculated that if Australia had applied the same effective tax rates to its petroleum resources as did Denmark or Norway, it would have reaped an additional US$71 billion or US$84 billion respectively in the period 2008–15. Dr Boué concedes that the cost structures are not identical—unit costs are actually higher in Denmark—so the comparison is not simple. But he suggests that the onus of proof should be on those who suggest the comparison is not reasonable.[48]

5.76      Several submissions have pointed to the revenue effects of the PRRT arrangements. For example, the Community and Public Sector Union, referring to modelling by forecasting group Macroeconomics, said:

There is a growing and widespread acceptance that Australia did not receive the full benefit it should have from the recent mining boom and this mistake should not be repeated. The CPSU notes modelling that shows if Australia had used the windfall from the mining boom to create a sovereign wealth fund, it would now have a $290 billion dollar fund.[49]

5.77      Various commentators have argued that the benefit Australia gets from its oil and gas is too little.[50] On the other hand, 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 petroleum resource rent tax has collected around $33 billion for the people of Australia.[51]

5.78      To some extent the question of taxation of the industry has been seen in the context of domestic price rises and threatened shortages resulting from over-ambitious export contracts.

Compliance with the PRRT

5.79      The Australian Taxation Office reports that compliance with the PRRT is very good.[52] This is consistent with the view in the industry that the tax is well designed and functions well:

For 30 years, the Commonwealth's approach to taxing the oil and gas industry has been based on some fundamental and, we think, pragmatic principles. It is more efficient and, over the life of resource projects, more lucrative to tax profits than production. Giving investors confidence they can achieve an appropriate risk adjusted rate of return will maximise investment and therefore, over time, tax revenues. Once projects recover their costs, achieve appropriate returns, resource taxation can be applied at far higher rates than a crude royalty or excise without deterring investment. In a nutshell, the most effective approach is to tax heavily economic rent rather than tax lightly production.[53]

5.80      Similarly, companies support the tax:

From Woodside's perspective, the PRRT is operating as intended, delivering $200 billion worth of projects and a fair return to Australians for their resources, ensuring projects are developed, jobs are created and taxes are paid. The current regime has supported, and continues to support, the development of economically challenging projects. Under more onerous fiscal settings, these projects would likely not be developed...[54]

5.81      Dr Juan Carlos Boué agrees that the PRRT is working as it is designed to, but is less sanguine:

...the alarming downward trend in petroleum fiscal revenues that has featured so prominently in Australian public debate of late...is not necessarily a consequence of tax avoidance and optimisation practices...  Rather, the paltriness of the fiscal receipts that the Australian government is currently getting (and is likely to get in future) in connection with the exploitation of the country’s hydrocarbon resources should be seen as a design feature of the Australian fiscal regime currently in force...[It] is producing exactly the sort of fiscal outcomes that it was designed and intended to produce, and will continue to do so in the future unless the Australian government changes tack by radically overhauling this fiscal regime.[55]

Design of the PRRT

5.82      Issues of the design of the PRRT have been canvassed thoroughly in the Callaghan report and in submissions to that review as well as to this inquiry. It is beyond the capacity of this inquiry to deal with them in detail. What follows is a high level summary which attempts to explain the dimensions of each issue.

Deductions: uplift rates

5.83      Undeducted expenses are carried forward with an 'uplift factor'. For project expenses, the uplift factor is the long term bond rate (LTBR) plus 5 per cent; for exploration expenses, it is the LTBR plus 15 per cent. As a witness observed, this means that the value of undeducted exploration expenses can double in four years.[56]

5.84      The original rationale for the uplift factors was to compensate the companies for the risk that they would not be able to use the deductions.[57] However, there was some ambiguity at the time the tax was introduced.[58] Uplift factors are understood by the sector as a compensation for the riskiness of the industry. For example:

The principle is that the companies need that assurance, if you like, that there is a reasonable risk adjusted rate of return on the costs that they have accumulated, because there is a very long payback period, so for many years the costs that you have incurred are not recovered, so they are carried forward. To ensure that there is that risk adjusted rate of return available to the businesses, there is an uplift factor applied...The compounding rate is there to, in fact, reflect the risk of the activity.[59]

5.85      The idea that companies should be protected from risk is contested by the Uniting Church:

The [Justice and International Mission] Unit’s concern is that it makes the community share the risk with the corporations no matter how badly they manage their exploration activities. Many other businesses take risks and if they fail and make no profit, then they have to carry their loss as there is no profit to claim deduction against. It is unclear why it is so important that gas corporations be able to get tax deductions for all exploration activities, no matter how poorly conceived or carried out.[60]

5.86      Exploration costs are also transferable between projects within a company or group. This further reduces the risk that the deductions will not be used—although it can also mean that the deductions are used earlier, instead of compounding:

This transferability of exploration deductions is one of the factors that is holding PRRT payments down now, but one positive out of it all is that it is helping take the deductions out of the system before they continue to compound and can hold down and lower future PRRT payments.[61]

5.87      Transferability has become more significant in the light of the starting bases created with the 2012 legislation (see below).

Order of deductions

5.88      The order in which expenses are deducted can make a big difference to tax liability. As a project comes on stream and generates profits:

...the general order of deductions is that you deduct own project expenditure first and then when you become cashflow positive you have got a PRRT liability. But if you have exploration in other projects then that transfers to that profitable project to be deducted and, under the rules, it transfers to the project with the most recent production licence that is profitable.[62]

5.89      Thus the deductions with the highest compounding rate can be kept for longer.

5.90      There is a large stock of deductions that will be acquitted ahead of PRRT payments. It has increased very rapidly recently, from $18 billion in 2011–12 to $188 billion in 2014–15 and $237 billion in 2015–16. A good part of the increase is due to the extension of the PRRT to the North-West Shelf and onshore projects. The deductible expenditure includes royalties and excise already paid and past exploration expenditure, as well as starting base expenditure. Of the total, almost half are non-transferable to other projects, although they can be carried forward at the relevant uplift rates.[63]

Starting bases

5.91      There has been a good deal of criticism that the starting bases allocated to existing projects being drawn into the PRRT in 2012 were too generous. The starting bases began with the market value of the projects, including the value of resources: this was a proxy for capital costs. They were calculated at a time when the oil price was high, so they were very large. In effect they mean that the North-West Shelf and the onshore gas projects will not pay PRRT, unless the oil price increases dramatically.[64]

5.92      One reason for the generosity of the starting bases was the need to allow for the fact that onshore projects would still be subject to state government royalty charges. It was not intended that projects would pay both royalties and PRRT.[65]

5.93      There is an anomaly in allowing the project valuation, including the value of the resources, as part of the tax-free starting base, since the value of the project includes the future income stream from the resources and it is thus by definition PRRT free, even if it generates an otherwise taxable profit after royalties. The Callaghan Report says:

The review’s modelling confirms that transitioning projects are not expected to pay PRRT under existing arrangements even at average oil prices of $US100 per barrel to 2050.[66]

Gas transfer pricing

5.94      Gas is usually converted to LNG in an integrated operation. The PRRT is levied on the value of the unprocessed resource. This cannot be the sale price, as it is the LNG that is sold. This means that a notional point of transfer and a method for attributing a price have to be identified. This is a highly technical matter:

The consultation paper released on Friday on options to address the design issues in the PRRT notes that numerous parts of system are opaque. For example, there is no transparency on how the gas transfer price is calculated.[67]

5.95      Similarly, Mr Lance McCallum from the Australian Council of Trade Unions expressed concern regarding how the gas transfer price is calculated:

To further increase the transparency of the PRRT, we think that the value and calculation method of wellhead gas should also be made public and that the current practice, where prices are calculated behind closed doors and where there is no market really to compare with these is inappropriate.[68]

5.96      The method currently used is the residual pricing method. Dr Diane Kraal of Monash University has summarised the calculation as follows:

  1. Downstream: uses the Net Back method to determine a gas price. A price is calculated by taking the LNG sales price and multiplying by gas volumes, less downstream costs that include the liquefaction plant. The net result is divided by gas volumes.
  2. Upstream: uses the cost plus method to determine a gas price. A price is calculated by adding all upstream costs from the wellhead to the boundary of the liquefaction plant, and dividing by gas volumes.
  3. The final step is to add together the calculated gas prices from upstream and downstream, and divide by two to derive the ‘gas transfer price’.[69]

5.97      There appears to be agreement that gas is being undervalued for tax purposes and the issue needs to be addressed:

...the gas transfer price method as prescribed by the PRRT regulations should be put under scrutiny. The gas transfer price method is flawed, leading to an underpayment of PRRT, thus disadvantaging the community.[70]

5.98      Mr Michael Callaghan warned that this could entail a significant change to how the tax works:

The arrangements that have been developed under the PRRT now for the gas transfer-pricing point are very complex. Looking at them, the conclusion is that they do need to have another hard [look] at [them] to ensure they are consistent with getting this equitable return. But the nature of those changes could be very substantial in terms of the impact on the industry.[71]

5.99      Dr Diane Kraal discusses the gas pricing mechanism in some depth. She concludes that the current method, the residual pricing method, should be replaced by the net back method. This would start with the LNG price and deduct the costs that had been incurred. It would be simpler and more transparent. She suggests that this method should be applied to all gas extracted in future, not just that from new projects. This is the method that is used in the North West Shelf royalty calculation.[72]

Incentive effects

5.100         A central theme in the development of the PRRT is the balance between a proper return to the community and maintaining incentives to discover and develop Australian resources. In particular, arrangements for uplift and transferability of deductions were intended to reduce risk and encourage exploration:

That is the very reason that we say transferability of exploration is important for Santos. It gives us an incentive to explore and we are able to recover that exploration in other projects.[73]

5.101         There was a huge investment in resources in the period 2002–2012, which resulted in big deductions to be carried forward. However, Mr Graham Salmond of BHP observed that although the deductions regime appears generous there is in fact little current investment in exploration, and this does not bode well for the future of the industry:

We talk about the attractiveness of some of the uplifts and the transferability associated with exploration. While it may appear attractive on the face of it, it is not actually attracting exploration activity, which is more alarming.[74]

5.102         It is possible that transferability creates a distortion such that firms already in the PRRT system actually have lower costs than newcomers, and this could deter some exploration by new participants in the industry.[75]

5.103         The impact of the design of the tax, which smooths the effects of commodity prices for the firms, could be to encourage production which was not timed to deliver the best return for the community:

The [Justice and International Mission] Unit fears the current design of the PRRT is to stimulate exploitation of Australia’s non-renewable oil and gas reserves as soon as possible, rather than across a period of time when the return to the Australian public would be greatest. Based on the best available long-term predictions of demand for natural gas and natural gas pricing, the PRRT appears to dud the Australian public in favour of foreign multinational corporations.[76]

Designed for oil, not gas?

5.104         The original design of the tax was for oil projects, which are very profitable for a relatively short period. Today's major projects are gas projects, which have longer lives but smaller profits. This makes a difference to the existence of rents:

The PRRT was designed for the oil industry. If you look at the production profile of oil, it spikes up and that is where the secondary tax, the PRRT, comes in. It grabs the super-profits. That is the nature of the production profile of the oil industry. With the gas industry, it is a flat production profile. There are no spikes and, generally speaking, there are no super-profits.[77]

5.105         It also magnifies the impact of the uplift factors:

Why the change in the industry is very important is oil projects are not as capital intensive. They have much faster turnaround periods, so they become cash positive a lot quicker. The uplift rates are not as significant in determining how much and when PRRT is paid. When you move into the world of gas, it is much more capital intensive. The size of the investment is much larger. These projects can go over a decade. It can take a long time before a project becomes cash positive and would start to pay PRRT...Over that long period, the size of the uplift rate, the size that the deductions are being augmented each year can compound and can have a significant impact on how much PRRT is going to be paid.[78]

Excise and royalties

5.106         The Callaghan Report examined excise and royalties, although, as a witness to this inquiry remarked, there had been less attention to that part of the report.[79] This is despite total excise and royalty payments generally being higher than PRRT payments.[80] Crude oil excise revenue is no longer separately reported in the Commonwealth Budget papers. The royalty payments largely go to the states.

5.107         Crude oil excise is levied by the Commonwealth on condensate from onshore projects. It may be in addition to state royalties on the same project. It is not applied to gas (although royalties may be). The amount of excise varies depending on when the oil was discovered. Generally, there is a threshold quantity of oil which may be extracted before excise is payable.

5.108         Several submissions suggested that a Commonwealth royalty would be a useful addition to the Commonwealth taxing regime because of the certainty that it will be collected. It could then be deducted from PRRT if any became otherwise payable.[81] Dr Diane Kraal proposes that royalties be applied specifically to natural gas-to-liquids projects as a partial solution to the problem that the tax was designed for oil rather than gas.[82]

5.109         Mr Jason Ward, spokesperson for the Tax Justice Network Australia, noted that:

Most of the companies involved in the new offshore LNG projects are already paying a 10 per cent royalty. In fact, Chevron's submission may unwittingly make the most compelling argument for extending a 10 per cent royalty to new offshore LNG projects. Chevron's submission shows that the royalty and excise payments from its one-sixth interest in the North West Shelf have produced more than 5½ times as much revenue as it has paid in corporate income tax over the last seven years.[83]

5.110         Dr Craig Emerson argued that imposing a royalty would create sovereign risk, and also be a disincentive to future investment:

...the application of a royalty effectively reduces the price that the investor gets for continuing to extract the gas then that means they are not maximising the resource rent, and the whole genesis of the resource rent was in response to these distorting taxes that lead to disincentives for exploration and development and the full recovery of the resource.[84]

Administration of the taxation of oil and gas

The PRRT

5.111         The PRRT relies on companies involved to keep their own records and make their own assessment of tax liability. Some submitters and witnesses suggested that the self-assessment of the tax left it open to abuse. For example, Mr Ward contended that:

The opportunities for transfer pricing in this situation are phenomenal. This system, the PRRT system, is based on self-reporting and voluntary compliance—so, I am determining what the price is at this point before I run the gas through my manufacturing process. If I am a company and looking to reduce my tax liability, I am going to say that this is a worthless product that I took out of the ground and that all of the value is created in my manufacturing process.[85]

5.112         Mr Ward even suggested that it made compliance 'voluntary':

There is a complete lack of transparency in the whole PRRT system. It is self-reporting and voluntary compliance.[86]

5.113         However, a spokesperson for the ATO pointed out that self-assessment is a normal part of the tax system:

Under the self-assessment regime, which now applies to all income tax returns from everybody in this room in their individual capacity, all the way to the largest taxpayers and indeed to the PRRT, the base of the self-assessment regime is that people will take due care in preparing their returns and lodge returns. If they are uncertain, they have access to a ruling system, to ask for rulings before they lodge. Equally, with the benefit of not having the ATO do a full assessment on your return before you lodge it, the ATO has the ability to review the return after lodgement, and if you have made incorrect statements to levy appropriate penalties as well as late-payment interest.[87]

5.114         It is worth noting that an Australian National Audit Office reported on the conduct of the ATO's external compliance assurance process pilot. It concluded that the process for large business taxpayers:

...was conducted effectively and demonstrated the potential for better client experiences, cost reductions and increased efficiency, by satisfactorily verifying factual matters in company tax returns.[88]

5.115         There was also a good practical effect of self-assessment in that the amount of tax was owing from when a return was lodged, rather than from the date of the ATO's assessment. In any event, because there are so few firms involved, the ATO has a close relationship with them which is effectively the same as assessment:

[There are] so few taxpayers that it is possible for us to have a very detailed, one-on-one relationship with each of the significant participants in the industry. So we do not struggle in obtaining information.[89]

5.116         Industry representatives similarly spoke of a close relationship with the ATO:

The relationship we have with the tax office is real time and it requires us to raise issues of technical or administrative uncertainty. We address them at the time. The tax office is fully aware then of our tax profile and our tax affairs, and that negates the need for audits of prior transactions because we have dealt with them in real time.[90]

5.117         One observer noted that the fact that most projects were owned and run by joint ventures increased the level of transparency:

...it is perhaps easier for the ATO to be confident that it is being administered kind of correctly, just because the degree of suspicion amongst the joint venture operators is enough to ensure that the information is there for the project operator and, therefore, for the ATO.[91]

5.118         The change in the industry from oil to gas has had an impact on administration. For oil projects, the period from the beginning of exploration to liability for PRRT is relatively short. For gas projects, it can be 10 years between the incurring of expenses and the need to report them. This can create problems in the accuracy of reporting and the possibility of auditing.[92]

5.119         Publish What You Pay Australia observed that it was hard to find out just how much tax was being paid, and that the public was entitled to better information in order to be able to assess the system of taxation. It further argued that any rules about transparency should be aligned with the European Union and Canada, so that comparisons can easily be made.[93]

North West Shelf Royalty

5.120         The Australian National Audit Office (ANAO) was highly critical of the Department of Industry Innovation and Science's role in the administration of the North West Shelf Royalty regime. DIIS is responsible for collecting the royalty, which is then shared with Western Australia, with the Commonwealth retaining about a third of the revenue.

5.121         The ANAO found that there was no formal agreement as to the respective responsibilities of DIIS and the Western Australian Government. There was no comprehensive procedure manual. There were shortcoming in calculating the royalties, and the meters that were relied on had not been properly tested. Deductions had been allowed without proper checking, and some deductions that were claimed were not in fact allowable.[94]

Prospects for change

5.122         Greenpeace Australia Pacific distinguishes between changes in taxation of companies already in the system (which it does not object to) and measures which it argues subsidise the discovery and exploitation of further fossil fuel reserves:

Aspects of the PRRT, including the uplift rates for exploration, constitute a clear subsidy. Australia (along with all other G20 countries) has committed to ending fossil fuel subsidies.[95]

5.123         The Callaghan Review proposed a number of changes to the PRRT regime. The proposed changes were divided into two groups: those that would alter the design of the tax, and procedural rules. The former group includes changing the uplift rates, the order of deductions, the rules for transferability, and the gas transfer arrangements. The latter group is concerned with such issues as rules for combining projects and lodging single returns, and when companies should start lodging annual returns.

5.124         Essentially, the first group of recommendations would make the biggest difference to the tax liability of companies. The Callaghan Report proposed that these should apply only to future projects, while the second group could apply to all projects. Mr Callaghan told the committee:

...with the fiscal risk of these things investors need to have confidence in the way the government is setting the tax regime—it is well designed, it is coherent and it is set on a coherent, comprehensive basis. One of the concerns of fiscal tweaks is that once a government starts to tweak things, they are trying to tweak things to get more money and an investor will ask when it is going to stop—there are going to be more tweaks...[A]rbitrary tweaks...can really influence an investor's confidence in a country.[96]

5.125         Dr Craig Emerson similarly argued that the uplift rates were perhaps too high but could not be changed for existing projects.

...[The uplift rate] was very much a reflection of the perceived riskiness of petroleum exploration in Australia. I think it would be damaging to investor confidence to just put a line through that for pre-existing investments. But for investments in the future it may warrant a reconsideration, and perhaps reducing that to the bond rate, plus 5 per cent.[97]

5.126         There has been a huge flow of investment funds into Australian oil and gas on the basis of the existing tax regime. It is often argued that that regime cannot be changed for existing players. To do so would be to breach trust, and to increase the level of sovereign risk which Australia is perceived to present. Dr Malcom Roberts, Chief Executive of the Australian Petroleum Production and Exploration Association, argued:

To date, we have compensated for high costs with low sovereign risk. Retrospective changes to our tax regime means high sovereign risk. We cannot hope to attract investment and jobs as a high-cost, high-risk country.[98]

5.127         BP Developments Australia pointed out that:

Investments in this 'wave' [of investment in 2006–2017] were supported based on, amongst other things, Australia's stable fiscal terms and the understanding these would essentially apply over the life of the projects. The prospect of any material change would therefore cause alarm given the scale of recent investment.[99]

5.128         More specifically, examples of the results of tax changes in similar jurisdictions were recounted:

There is research linking the decline in economic activity and the loss of investor confidence in both Alaska and Alberta to adverse changes in taxes specific to the oil and gas industry.[100]

5.129         However, Mr Ward  was sceptical of these arguments:

While some companies have suggested that changes to the tax regime will deter future investment, this is a scare tactic to preserve the status quo, which is overly generous to the industry and short-changing Australians...Even with the extension of a 10 per cent royalty to new offshore gas, Australia will continue to have one of the most generous fiscal regimes in the world for the oil and gas industry. The extension of a royalty to these five offshore LNG projects does not fundamentally change the economic returns on these projects over their long life spans.[101]

5.130         Dr Diane Kraal gave a historical example:

Put it this way: go back to the Whitlam government, which introduced excise. Oil prices were at record levels and the Australian government needed to get a share of those super profits. The Fraser government came in and carried on the excise—not only that, but increased it—and the companies kept coming. The oil kept being extracted. Bass Strait has been very successful, as have other oil projects...both governments wanted a decent return for the Australian community. You could say that is the sovereign risk situation, but investment continued.[102]

5.131         Clearly, there will always be an interaction between the competitiveness and the stability of the tax system:

...it is important to distinguish between having a competitive tax regime versus other jurisdictions which have similar resources, as well as sovereign risk, which is often used to describe the effect on future investment if past rules are changed—the view being that it would affect future investment at a general level of uncertainty in the country. I would say that I rarely hear the phrase 'sovereign windfall' when laws change the other way...[103]

5.132         Not surprisingly, views on how real and how important is the risk involved in changing policy depend on the interests of those holding them.

Committee view

5.133         The committee notes the importance of the oil and gas industry and the goals of taxing resources: to give the community a fair return on the resources which belong to them, and to encourage—or not discourage—investment in extracting them.

5.134         The committee further notes the broad range of work recently done in this area, and particularly the Treasury's Review of the Petroleum Resource Rent Tax, the submissions to it and the Treasury's subsequent consultation paper.

5.135         The committee stresses that it is important that the government deliver on its commitment to an equitable return on petroleum resources, and notes the long time that has elapsed since the announcement of the Callaghan Review. As such, the committee is particularly disappointed that the 2018–19 Budget did not contain any measures relating to the PRRT, as the government has had the findings of the Callaghan Review for over 12 months and the subsequent Treasury consultation process was due for completion by the end of September 2017.

5.136         The committee believes that there is a broad consensus among non-industry players that the arrangements surrounding the PRRT are too generous. It notes the possibility that compounding of deductions can completely offset potential revenue.

5.137         The committee endorses the direction of the Callaghan Review's recommendations. In particular, it concludes that:

5.138         The committee agrees with the conclusions of the Callaghan Review, that changes are necessary but that, in order to maintain certainty for the sector, they should apply only to future projects.

5.139         The committee notes that the ATO already maintains close contact with companies in the PRRT system. It believes that consideration should be given to establishing a specific body, possibly within the ATO, to monitor administration of the PRRT, and to ensure that the self-assessment processes work appropriately. Whatever arrangements are in place, it is essential that they be adequately resourced.

5.140         The committee notes the arguments for a royalty on all projects. It sees a good deal of merit in them, but believes that a properly functioning PRRT, in conjunction with the base erosion and profit-shifting measures discussed elsewhere in this report, would meet the objectives of ensuring the oil and gas companies appropriately contribute to government revenue.

Recommendation 10

5.141         The committee recommends that the government finalise and release its response to the Callaghan report into the Review of the Petroleum Resource Rent Tax.

Recommendation 11

5.142         The committee recommends that the government overhaul uplift rates for future Petroleum Resource Rent Tax eligible projects, so as to make them less generous.

Recommendation 12

5.143         The committee recommends that the ordering of deductions be rationalised for future Petroleum Resource Rent Tax eligible projects so that those with the highest compounding rates are used first for tax deduction purposes.

Recommendation 13

5.144         The committee recommends that the gas transfer pricing method for Petroleum Resource Rent Tax eligible projects be reformed to make it simpler and more transparent so as to ensure that it delivers a fair return to the community.

Senator Chris Ketter
Chair

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