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  • Transfers of PRRT exploration expenditure

    If an entity's exploration expenditure for a petroleum interest is more than the assessable receipts derived for the interest in that financial year, the expenditure is carried forward so that it can be deducted against assessable receipts for that interest derived in later years.

    However, when the entity (or another company in the wholly owned group) holds an interest in a petroleum project that has a notional taxable profit, transferable exploration expenditure must be transferred to that petroleum project (if certain conditions are met) to reduce its taxable profit.

    Exploration expenditure incurred on or after 1 July 1990 is the only category of eligible real expenditure that can be transferred. The following categories of eligible real expenditure are not able to be transferred:

    • general project expenditure
    • exploration expenditure incurred before 1 July 1990
    • resource tax expenditure
    • acquired exploration expenditure
    • starting base expenditure
    • closing-down expenditure
    • exploration expenditure incurred before 1  July 2012 in relation to onshore petroleum projects or the North West Shelf project.

    See also:

    General transfer rules

    Transferable exploration expenditure can be transferred to:

    • other petroleum projects of the entity
    • petroleum projects of group companies.

    An entity needs to meet the following conditions before it can transfer transferable exploration expenditure:

    • the petroleum project receiving the transfer needs to have a notional taxable profit
    • the entity can only transfer so much of transferable exploration expenditure to the receiving project as reduces the taxable profit of the receiving project to zero
    • a common ownership rule needs to be met.

    Broadly, the common ownership rule requires the entity (or the wholly-owned group company) to have held the interest in the transferring exploration permit, retention lease or petroleum project and the receiving petroleum project from the time the exploration expenditure was incurred up until the time of the transfer.

    Transfers need to be made in a specific order. Firstly, an entity needs to transfer as much of the transferable exploration expenditure as can be transferred to any petroleum projects it holds an interest in (excluding petroleum projects of group companies).

    Secondly, transferable exploration expenditure needs to be transferred to the petroleum project with the most recent production licence first.

    Transferable exploration expenditure needs to be categorised (with reference to the receiving project) into either of the following categories:

    • class 2 augmented bond rate (ABR) expenditure
    • class 2 gross domestic product (GDP) factor expenditure.

    An entity needs to transfer amounts of class 2 ABR exploration expenditure before it can transfer any class 2 GDP factor expenditure. Once it has classed its amounts of transferable exploration expenditure, the expenditure incurred in the earliest year needs to be transferred first.

    Once an entity has worked out which petroleum project it needs to transfer to and the class of expenditure it is transferring, it transfers that amount to the receiving project. This amount is then augmented based on the class of expenditure in relation to the receiving project.

    The amount transferred, including augmentation can only reduce the taxable profit of the receiving project to zero.

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    If an entity still has transferable exploration expenditure remaining, it needs to transfer as much of the remaining transferable exploration expenditure as can be transferred to any petroleum projects of a group company, in the same order as detailed above.

    For an entity that holds interests in onshore petroleum projects, exploration permits and retention leases that transitioned into the PRRT on 1 July 2012 because of the extension of PRRT to onshore petroleum interests and the North West Shelf project, only exploration expenditure incurred on or after 1 July 2012 may be transferred.

    Effect of the transfer rules

    If an entity transfers an amount of transferable exploration expenditure to a petroleum project (one of its petroleum projects or a petroleum project of another company in the group), it needs to lodge a notice with us specifying the details of the transfer, including the amount of transferable exploration expenditure being transferred.

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    The entity that holds the interest in the receiving project needs to bring that amount into the calculation of its taxable profit. Exploration expenditure incurred in the transfer year is not uplifted when offset against the receiving project's assessable receipts.

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    Group companies

    Broadly, unused transferable exploration expenditure is transferable from one group company to another, in relation to a project, if the common ownership test is met.

    The test is met if, throughout the period from when the exploration expenditure was incurred up until the end of the transfer year, the transferor and transferee were group companies that respectively:

    • held the interest in the project from which the exploration expenditure is to be transferred
    • held the interest in the project to which the expenditure is to be transferred.

    This test needs to be met during the whole period. If either or both of the companies were not in existence for part of the period, the test needs to be met for the period during which both companies were in existence. A company is to be treated as coming into existence during a period if it was incorporated during that period.

    Generally, if an existing company is acquired or disposed of during the period by the related company group, it will not be taken to be part of the group for the period.

    Example: applying the transfer rules

    Verona Sands Ltd holds an interest in an offshore exploration permit (granted during the year of tax ending 30 June 2009) and one offshore petroleum project. It has also wholly-owned Nilon Nickel Ltd since 1988, which has a single offshore petroleum project.

    Petroleum project

    Production licence granted

    2012 Year Notional taxable profit

    Parsnip (Verona Sands)   2008   $140 million  
    Swede (Nilon Nickel)   2009   $40 million  

    Verona Sands Ltd has $160 million of transferable exploration expenditure available from its interest in the exploration permit as follows:

    • $150 million incurred in the year ending 30 June 2012
    • $10 million incurred in the year ending 30 June 2011.

    Verona Sands owned the exploration permit and both the production licences from when the amounts of exploration expenditure were incurred, until the time of the transfer, therefore the ownership test is met.

    Even though Swede has the most recently issued production licence, Verona Sands Ltd needs to transfer to its own project Parsnip first, as Swede is a project of a group company. The exploration expenditure incurred in the earliest year needs to be transferred first.

    The production licences for Parsnip and Swede were granted in the years of tax ended 30 June 2008 and 30 June 2009 respectively. As both were granted within 5 years of the exploration expenditure being incurred, all transferable exploration expenditure is class 2 ABR exploration expenditure.

    Verona Sands needs to transfer the transferable exploration expenditure that was incurred in the earliest year first, which is the exploration expenditure incurred in 2010-11 year of tax.

    It transfers the $10 million to Parsnip and then uplifts it as follows:

    $10 million x 1.2031 = $12.03 million

    Parsnip's taxable profit is now $127.97 million ($140 million - $12.03 million).

    Verona Sands Ltd can now transfer its current year transferable exploration expenditure, which is not uplifted.

    It transfers the $150 million as follows:

    • $127.97 million to Parsnip to reduce its taxable profit to zero
    • the balance of transferable exploration expenditure of $22.03 million ($150 million – $127.97 million) to Swede.

    Swede's taxable profit is now $17.97 million ($40 million – $22.03 million).

    End of example

    Commissioner's powers

    If an entity does not transfer transferable exploration expenditure, the Commissioner of Taxation has the power to make the transfer.

    A transfer we make has the same effect as if it had been made by the entity. A transfer can be varied or revoked if we receive new information relating to the original transfer.

    We need to give notice in writing to the entity within 30 days of the transfer, variation or revocation.

    Lodging a transfer notice

    If an entity transfers transferable exploration expenditure to a project held by the entity or one held by a related group company, it needs to give us written notice of the transfer within 60 days of the end of the financial year. The notice can be lodged with the receiving project's PRRT return.

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      Last modified: 24 Nov 2016QC 37062