Australia's Future Tax System

Final Report: Detailed Analysis

Chapter C: Land and resources taxes

C1. Charging for non-renewable resources

C1–2 Existing resource charging arrangements

Australia underprices its resources

In Australia, governments allow private businesses to exploit non-renewable resources and in return collect a charge for resource production, predominantly through taxation arrangements. The form of tax varies across jurisdictions. While governments have typically adopted output-based royalties, the Australian government also includes a charge on some resource rents.3 The community undercharges for non-renewable resources under both of these systems, though the causes vary.

Output-based royalties collect a greater share of the returns to non-renewable resources when profitability is low or negative and collect a smaller share of returns when profitability is high. This was particularly evident over the period from 2003–04 to 2008–09 when mineral profits increased with higher commodity prices (see Chart C1–1). The strength of prices for Australia's non-renewable resources is expected to continue for decades to come, driven by demand from China and India. While governments can increase royalty rates in response to increases in profitability, and have done so in recent years, this may discourage investment by increasing sovereign risk.

Chart C1–1: Mineral tax and royalties as a share of mineral profits(a)

Chart C1–1: Mineral tax and royalties as a share of mineral profits(a)

  1. Mineral profits before tax and royalties are measured using income less an allowance for corporate capital.

Source: Australian Treasury estimates.

The Australian government charges for non-renewable resources extracted in offshore waters.4 Petroleum is the only non-renewable resource currently extracted offshore and is generally subject to the PRRT, which is levied at a rate of 40 per cent on the positive annual net cash flow of each petroleum project.5 A cash refund is not provided for negative cash flows, but excess deductions are carried forward with an interest uplift to preserve their value. Exploration expenditure can also be transferred from a PRRT project with expenditure exceeding receipts to a PRRT-paying project with common ownership from the time the expenditure is incurred. The payment of PRRT is a deductible expense in the calculation of income tax.

Although the current PRRT collects a more stable share of rents in varying economic conditions, it fails to collect an appropriate and constant share of resource rents from successful projects due to uplift rates that over-compensate successful investors for the deferral of PRRT deductions. For example, an uplift rate of the long-term bond rate plus 5 percentage points (currently 11 per cent in total) applies to general expenditure. On average, this rate is higher than the corporate bond rate, which is a useful proxy to compensate investors in the absence of a full loss offset.6 Typically, the corporate bond rate is around 7 to 8 per cent. Furthermore, the uplift rate for exploration within five years of the granting of a production licence (the long-term bond rate plus 15 percentage points, currently 21 per cent) is significantly higher than the average corporate bond rate. However, the uplift rate for exploration more than five years before the granting of the production licence (set equal to the GDP implicit price deflator, currently around 5 per cent) is lower than the average corporate bond rate.

The PRRT may also fail to collect the appropriate share of rents when the gas transfer pricing regulations are applied. The regulations provide a framework for determining the price for gas in the case of an integrated gas-to-liquids project and include a residual pricing method. Essentially, the residual pricing method applies an arbitrary cost of capital allowance uplift (long-term bond rate plus 7 percentage points) and splits in half the rents associated with the integrated process between the upstream and downstream processes.

The community's share of petroleum rents collected under the PRRT is less than the statutory PRRT rate and declined from 2004–05 to 2007–08 as industry profitability increased (see Chart C1–2). These outcomes may have arisen due to the North West Shelf project being subject to output-based royalties and excessive PRRT uplift rates.

Chart C1–2: Petroleum tax and royalties as a share of petroleum rents(a)

Chart C1–2: Petroleum tax and royalties as a share of petroleum rents(a)

  1. Petroleum profits before tax and royalties are measured using income less an allowance for corporate capital. There may be differences in the timing of profits using this measure of profit compared to the PRRT measure of profit.

Source: Australian Treasury estimates.

Company income tax as a resource rent tax

The company income tax system applies to rents as well as to the normal return on investment. This feature has placed a constraint on the government in setting the company income tax rate. In particular, the benefits of attracting mobile investment to Australia by reducing the company income tax rate must be balanced against the loss of tax revenue that could have been collected from location-specific investments, such as investments in non-renewable resources projects (see Section B1 Company and other investment taxes).

The reduction in the company income tax rate over the past two decades has reduced the combined statutory tax rate on resource rents. The combined statutory tax rate on petroleum resources at the company level has fallen by 9.6 percentage points (from 67.6 per cent to 58.0 per cent) since the introduction of the PRRT in 1987. While the PRRT rate has not changed, the company income tax rate has fallen by 16 percentage points from 46 per cent to 30 per cent.

To the extent resource companies are owned by Australian residents, the company income tax does not act as a final charge due to dividend imputation.


Australia's current resource charging arrangements fail to collect an appropriate return for the community from allowing private firms to exploit non-renewable resources, mainly because these arrangements are unresponsive to changes in profits.

Investment and production decisions are distorted, further eroding returns

The current resource charging arrangements, and associated mechanisms for allocating exploration permits, distort investment and production decisions and thereby lower the return to the community.

Under output-based royalties, firms are likely to invest and produce less than they otherwise would. The calculation of such royalties does not take production costs into account. This leads to less exploration, lower industry output and earlier closure of projects. In addition, some investments may not be undertaken due to higher sovereign risk — specifically the risk of governments making ad hoc adjustments to royalty rates in response to changes in profitability.

Recent examples include changes to coal royalties in Queensland and NSW. The 2008–09 Queensland budget introduced a two-tier coal royalty, with a 7 per cent rate applying up to $100 per tonne and a new 10 per cent rate applying thereafter. This followed a change in 2002 that denied deductions for rail and transport costs when calculating the coal price subject to royalty. The 2008–09 NSW mini-budget increased coal royalties by 1.2 percentage points and excluded transport costs in calculating the royalty.

Under the PRRT, firms may invest and produce less than they would otherwise. Successful firms share their returns with government through the PRRT, but unsuccessful firms do not receive refunds from the government for the tax value of their loss. This discriminates against risky exploration and production projects. Further, there is an incentive for successful firms to delay production so that they can carry forward negative cash flows to take advantage of the excessive PRRT uplift rates described above. These delays erode the return to resources available for the community.

Current methods of allocating exploration permits may also erode resource rents

The mechanisms used to allocate exploration permits to private businesses can also erode resource rents, as they may not allocate exploration permits to the most efficient producer or may promote inefficient exploration.

The States typically assess a prospective investor on a first-come first-served basis, with a nominal application processing fee. The first-come first-served basis of allocation creates an incentive for firms to undertake exploration sooner than they would have if property rights had been clearly defined.

The Australian government allocates offshore exploration permits under a work program bidding system. Exploration permits are allocated to the firm with the preferred exploration work program. Work program bidding creates an incentive for exploration expenditure above a commercially sensible level. To win exploration permits, firms may commit to a work program that spends the expected resource rents on over-exploration. Work program bidding can dissipate all the expected rents if bidding is competitive and the tax system is efficient (Fane & Smith 1986).

Irrespective of the mechanism used or jurisdiction, exploration permits and production licences are tradeable. This enables the transfer of these rights so that the most efficient firm can explore and produce resources and thereby increase the resource rent available for the community. However, the Australian and State governments impose some fees, not related to administration costs, and stamp duties on the transfer of interests. This imposes a transaction cost that inhibits the efficient transfer of rights to projects and may therefore erode the value of the resource rent. (For further discussion of the inefficiencies arising from stamp duties, see Section C2 Land tax and conveyance stamp duty.)

Governments issue exploration permits, retention leases and production licences with a limited tenure. Exploration permits are generally granted for periods of two to six years, with renewals being subject to reductions in the exploration area covered by the permit. Retention leases are generally granted for five years with provisions for renewal and a priority right for a production licence. Production licences can be granted for up to 21 years.

These time limits may create an incentive for firms to inefficiently bring forward exploration and production, but may also serve to restrict the incentive for firms to delay exploration and production in order to gain from the spillover benefit of information generated by activity in neighbouring fields.

Exploration tax incentives

Under the PRRT, exploration expenditure in areas designated as 'frontier' from 2004 to 2009 is eligible for a 150 per cent deduction. This concession was introduced to stimulate exploration activity in frontier areas and increase the likelihood of discovering a new petroleum province. However, the concession only benefits owners of projects that already pay PRRT, because the benefits are only available when the deduction can be used to reduce a PRRT liability. The concession does not appear to correct any market failure.

Exploration expenditure is also favourably treated under income tax. Businesses are allowed to deduct exploration expenditure immediately, regardless of whether the exploration succeeds or fails. However, for businesses without income (typically smaller businesses) the treatment of income tax losses — which are carried forward on a conditional basis and without an uplift — may discourage exploration (see Section B1 Company and other investment taxes).


Australia's current resource charging arrangements and the mechanisms for allocating exploration permits distort investment and production decisions, further lowering the community's return from the exploitation of its non-renewable resources.

3 The Northern Territory government imposes a profit-based royalty on non-renewable resources and the Western Australian government imposes a resource rent royalty on the Barrow Island project.

4 In addition, the Australian government imposes an income-based tax on resources (extracted onshore and offshore) through the income tax system and imposes a royalty on uranium extracted in the Northern Territory.

5 Before 1 July 1986, offshore petroleum projects were subject to output-based royalties. These were replaced by the PRRT, except for petroleum extracted from the North West Shelf, which is still subject to output-based royalties. The Bass Strait project was brought into the PRRT regime in 1990.

6 In cases where expenditure is not transferable, the hypothetical project bond rate is a better proxy for the appropriate uplift rate, but this rate is typically unobservable as most debt is issued at the corporate level.