Tax and commercial

Key Legislation: Petroleum Acts (various state/territories) Petroleum (Submerged Lands) Acts (various states/territories) Commonwealth Petroleum (Submerged Lands)(Royalty) Act 1967

Federal Government royalties are applied to licence areas in offshore waters that are not subject to PRRT (production sourced from exploration permits WA-1-P and WA-28-P). The states and Northern Territory also apply royalties on the production of petroleum under their respective Petroleum and P(SL) Acts.

Royalties are generally assessed as a percentage of the wellhead value of production. This is calculated by subtracting from the sales value of all petroleum products sourced from the well, the cost of transportation and processing involved in bringing the raw products from the wellhead to a point at which marketable products are sold.

Deductions from the sales that which are allowed when determining the wellhead value include:

• crude oil production excise (for Commonwealth royalties only);
• a proportion of the platform costs;
• certain processing and transportation costs, including costs associated with shipping liquefied natural gas (LNG) from the North West Shelf to Japan;
• interest on the depreciated value of capital items (the cost of debt and equity capital); and
• specified depreciation and operating expenses.

Royalties are levied at a rate between 10 and 12.5 per cent of the wellhead value (depending on the jurisdiction involved). In general, the states and Northern Territory retain all royalties collected under the respective legislative provisions. But in some instances, royalties collected from submerged lands that were previously covered by Commonwealth titles are shared with the Federal Government. At present, this sharing of royalty revenues is limited to some projects covered by the provisions of WA Petroleum (Submerged Lands) Act 1982.

For Commonwealth royalties, the Federal Government retains a basic 4 percentage points of the royalty, while the remainder (between 6 and 8.5 percentage points) is paid to Western Australia.

Key Legislation: Excise Tariff Act 1921
Petroleum Excise (Prices) Act 1987

Before 1 July 1990, crude oil excise applied to all production sourced from the Bass Strait and North West Shelf project areas, as well as all areas under state or Northern Territory jurisdiction (i.e. those not covered by the provisions of the Commonwealth Petroleum (Submerged Lands) Act 1967). The scope of the crude oil excise system was considerably narrowed from this date following the Federal Government's decision to extend the PRRT to include production from Bass Strait.

Crude oil excise is payable on production from individual prescribed production areas that are subject to the provisions of the Excise Tariff Act 1921. Excise is calculated as a percentage of the volume-weighted average of realised free-on-board prices (VOLWARE) made from a designated region.

Higher excise rates apply to higher levels of production from each prescribed production area. The excise scales that apply to production from each prescribed production area depend on the date of discovery and/or the start of production. In May 2008, the Government announced that the regime would be extended to cover condensate produced from non-PRRT areas.

The following table outlines the respective excise rates and the types of excisable oil (this table incorporates modifications made in late 2001).

In addition to the above, the crude oil excise provisions allow for:

• exemption from excise of the first 30 million barrels of cumulative production from each field where excise applies
• exemption from excise of all gas production, including liquefied petroleum gas, liquefied natural gas and commercial gas/ethane.

Crude oil excise receipts are retained wholly by the Federal Government. Collections for the period 1975/76 to 2007/08 were as follows: Crude oil excise receipts are retained wholly by the Federal Government. Collections for the period 1975/76 to 2004/05 were as follows:

Forecast collections for 2008/09 is $1,050m
*Bass Strait was moved from the Excise/Royalty Regime to the PRRT regime with effect from 1 July 1990

Key Legislation: Petroleum Resource Rent Tax Assessment Act 1987

PRRT is levied under the provisions of the Petroleum Resource Rent Tax Assessment Act 1987. It applies to all projects seawards of the outer limits of the territorial sea.

The exceptions to this coverage are for those production licences drawn from the North West Shelf project area (Exploration Permits WA-1-P and WA-28-P) where Commonwealth excise and royalty applies (including Australia's only LNG export operation), and permits within the Timor Leste / Australia Joint Petroleum Development Area (see proposed changes below).

The basic features of the PRRT are:

• it is assessed on a project basis;
• liability to pay PRRT is on a producer/company basis;
• it is levied before company tax and PRRT payments are deductible for company tax;
• it is assessed at a rate of 40 per cent;
• is payable quarterly on an instalment basis;
• a liability is incurred when all allowable expenditures (including compounding) have been deducted from assessable receipts;
• assessable receipts include the amounts received from the sale of all petroleum (or a marketable petroleum commodity);
• deductions include capital or operating costs that directly relate to the petroleum project, and are deductible in the year they are incurred;
• deductible expenditures include exploration, development, operating and closing activities; non-deductible expenditures include financing costs, some indirect administration costs, income tax, and cash bidding payments; and
• undeducted expenditures are compounded forward at a variety of set rates depending on the nature of those expenditures and the time that they are incurred prior to the granting of a production licence.

PRRT was substantially altered in 1990 to allow undeducted exploration expenditure incurred after that date to be transferred to other projects. Simultaneously, the carry-forward rate of undeducted general projects expenditures was significantly reduced from the long-term bond rate plus 15 percentage points to the LTBR plus 5 percentage points.

The wider deductibility provisions were limited by applying several restrictions and conditions on this area of the legislation. Changes made in 1992 and 1993 clarified the treatment of transferable expenditure as well as lodgement provisions. A technical amendment passed in 2000 addressed an uncertainty associated with the treatment of expenditures when a party "walks-away" from a continuing joint venture. In 2001, a number of changes were made to the operation of the five-year GDP factor rule and the introduction of a gas transfer pricing mechanism.

The regime was further modified and extended in 2003 to clarify the treatment of income and expenditures in which a project is used to toll or process external or third-party petroleum. In 2004, the government introduced a 150% incentive to assist exploration in nominated frontier areas. This was incentive lapsed in 2010.

From 1 July 2006, several technical enhancements were introduced to improve the regime’s operation and efficiency. A transfer notice requirement was introduced for vendors disposing of an interest in a permit; a deduction for transferable exploration expenditure was now required when calculating quarterly instalments; and taxpayers could now use self-assessment provisions.

Proposed changes

In July 2010, the Government announced a decision to extend the coverage of PRRT to all onshore oil and gas production and existing offshore production not currently covered by the PRRT (excluding that production sourced from the JPDA). It is proposed that the new arrangements will apply from 1 July 2012, subject to passage by Federal Parliament. Legislation was tabled in late 2011. Existing royalties and production excise will continue to apply from these areas, but will be creditable against future PRRT liabilities from each individual project.

PRRT receipts are retained wholly by the Federal Government. Collections for the period 1989/90 to 2010/11 were as follows:

APPEA seeks a petroleum taxation system that encourages investment in oil and gas while also ensuring that the Australian community receives an appropriate return for the use of its resources. Governments must ensure that the burden of the overall tax take – including company income tax, resource taxes and indirect taxes (such as tariff and excise duties) – does not discourage investments in what would otherwise be commercially viable projects.

Resource taxation became a first-order political issue in 2010. APPEA has argued for a fairer and more workable petroleum tax system that lets the industry compete equally with other energy sources.

Subject to consideration by Parliament, the petroleum resource rent tax (PRRT) may be extended to include onshore oil and gas projects previously not covered by the regime. But much work remains to be done on finalising the details of an expanded PRRT. APPEA is arguing for a system that is fairer, less cumbersome and more responsive to smaller oil and gas companies' needs.

The likely extension of the PRRT regime creates new burdens for many oil and gas companies, but it also provides an opportunity to streamline the system, remove uncertainty and make the regime fairer and and more appropriate for the 21st Century.

In late 2009, the Australian Taxation Office released several discussion papers addressing important technical and administrative aspects of the PRRT regime. This was followed by the release of three draft rulings in June 2010 that sought to formalise a series of potentially complex treatments and administrative obligations on taxpayers.

APPEA has formally requested that these matters be referred to the Argus-Ferguson Committee, which is considering how to implement the new resource taxation provisions. The committee’s terms of reference include addressing compliance and administrative issues. APPEA has also asked the committee to consider concerns on how the PRRT could affect smaller projects’ viability.

APPEA also continues to seek tax-related exploration incentives. The preferred option remains a flow-through share scheme similar to the model that has stimulated resources exploration and production in Canada.