EXPLANATORY STATEMENT

Issued by authority of the Treasurer

Petroleum Resource Rent Tax Assessment Act 1987

Petroleum Resource Rent Tax Assessment Regulations 2024

Section 114 of the Petroleum Resource Rent Tax Assessment Act 1987 (Act) provides that the Governor‑General may make regulations prescribing matters required or permitted by the Act to be prescribed, or necessary or convenient to be prescribed for carrying out or giving effect to the Act.

Section 24 of the Act provides that the regulations may, for certain cases, provide the amount of assessable petroleum receipts derived by a person in relation to a petroleum project.

Section 97 of the Act provides that the regulations may, in certain cases, provide for the working out of the current period liability or current period receipts for a person for the purposes of determining the notional tax amount of the person.

Section 106A of the Act provides that the regulations may prescribe decisions that are made under the Act or the regulations as decisions that a person may object to in the manner set out in Part IVC of the Taxation Administration Act 1953.

On 7 May 2023, the Government announced that it would introduce changes to the Petroleum Resource Rent Tax (PRRT) to deliver a fairer return to the Australian community from their natural resources. The changes respond to the Treasury Gas Transfer Pricing Review (GTP Review). The GTP Review recommended significant changes be made to the PRRT system, including accounting for changing commercial circumstances in the liquified natural gas (LNG) industry, ensuring an appropriate arm’s length price for gas at the taxing point is reflected in all circumstances, and improving transparency and reducing complexity in the way the rules operate. The Regulations implement recommendations 3, 5, 6, 7, 8 and 11 of the GTP Review.

The purpose of the Petroleum Resource Rent Tax Assessment Regulations 2024 (Regulations) is to remake the Petroleum Resource Rent Tax Assessment Regulation 2015 (2015 Regulations), which are due to sunset on 1 April 2026.

The Regulations make various minor changes to update the drafting of the 2015 Regulations, as well as substantive changes that align with the GTP Review, including:

•                 various changes to better accommodate commercial tolling arrangements;

•                 requiring an irrevocable election to be made to use either the shorter or longer asset life formula;

•                 equalising the treatment of the notional upstream and downstream entities between loss and profit situations when using the residual pricing method (RPM);

•                 updating the comparable uncontrolled price (CUP) rules to align with current guidelines from the Organisation of Economic Cooperation and Development (OECD);

•                 modifying the advanced pricing arrangement rules (APA) to provide additional guidance to both industry and the Commissioner of Taxation (Commissioner) on the principles to consider in agreeing to an APA;

•                 ensuring that when a new facility is brought into the PRRT regime for the first time, that the value of the plant for use in the RPM is the historical cost of the facility.

The Act does not specify any conditions that need to be satisfied before the power to make the Regulations may be exercised.

An exposure draft of the changes to the Regulations for tolling arrangements was released for public consultation from 22 December 2023 to 9 February 2024. Another exposure draft of the other substantive changes to the Regulations was released for public consultation from 18 March 2024 to 12 April 2024. Treasury received four submissions in response to those consultations and held follow-up discussions with the LNG industry participants and the Australian Taxation Office (ATO). Minor changes that are consistent with the policy intention were made following consultation.

Paragraph 14(1)(b) of the Legislation Act 2003 allows a legislative instrument to incorporate any document in writing which exists at the time the legislative instrument commences, or at a time before its commencement. The Regulations refer to an Accounting Standard published by the Australian Accounting Standards Board (AASB) and a document published by the OECD. The Accounting Standard is AASB 136 Impairment of Assets as in effect on 1 January 2010, which could in 2024 be viewed on the AASB’s website at https://aasb.gov.au/. The OECD document is the Transfer Pricing Guidelines for Multinational Enterprises and Tax Administrations as last amended on 7 January 2022, which could in 2024 be viewed on the OECD’s website at https://oecd.org/.

The Regulations are a legislative instrument for the purposes of the Legislation Act 2003.

The Regulations are subject to sunsetting under section 50 of the Legislation Act 2003.

The Regulations commenced on the day after their registration on the Federal Register of Legislation and apply to years of tax beginning on or after 1 July 2024. This application is consistent with the Government’s announcement on 7 May 2023 and provides clarity for taxpayers and the ATO on how the Regulations apply. The application from 1 July 2024 is unaffected by subsection 12(2) of the Legislation Act 2003.

Details of the Regulations are set out in Attachment A.

A statement of Compatibility with Human Rights is at Attachment C.

The Office of Impact Analysis has been consulted (OIA ref: OIA23-04673) and agreed that details relating to the impacts of the updates to the Regulations are referenced in the GTP Review. The compliance cost has been measured as minimal.

The changes made by the Regulations are estimated to have an unquantifiable financial impact.

ATTACHMENT A

Details of the Petroleum Resource Rent Tax Assessment Regulations 2024  

Section 1 – Name

This section provides that the name of the regulations is the Petroleum Resource Rent Tax Assessment Regulations 2024 (Regulations).

Section 2 – Commencement

The Regulations commenced on the day after registration on the Federal Register of Legislation.

Section 3 – Authority

The Regulations are made under the Petroleum Resource Rent Tax Assessment Act 1987 (Act).

Section 4 – Schedule

This section provides that each instrument that is specified in the Schedules to this instrument is amended or repealed as set out in the applicable items in the Schedules, and any other item in the Schedules to this instrument has effect according to its terms.

All legislative references are to the Regulations unless otherwise indicated.

This attachment refers to provisions being ‘changed’ to help explain how the Regulations differ from the Petroleum Resource Rent Tax Assessment Regulation 2015 (2015 Regulations). However, the Regulations are not technically amending the 2015 Regulations but are rather repealing and remaking them. A finding table for the corresponding provisions between the Regulations and the 2015 Regulations can be found in Attachment B.

Overview of the Regulations

The Petroleum Resource Rent Tax (PRRT) was enacted in 1987 by the Act and the Petroleum Resource Rent Tax Act 1987. The PRRT is a profits-based tax applied to petroleum production from petroleum projects. The PRRT is applied at a rate of 40 per cent on the taxable profit of a person for a year of tax in relation to a petroleum project (see sections 4 and 5 of the Petroleum Resource Rent Tax (Imposition—General) Act 2012).

Under the Act, assessable petroleum receipts are usually determined at the point where a marketable petroleum commodity (MPC) becomes an excluded commodity. An MPC is defined as including stabilised crude oil, sales gas, condensate, liquefied petroleum gas, ethane, and shale oil. An MPC becomes an excluded commodity either by:

•                 being sold;

•                 being further processed or treated (after being produced);

•                 being moved away from the place of its production other than to a storage site adjacent to that place; or

•                 being moved away from a storage site adjacent to the place of its production.

In most cases, assessable petroleum receipts will reflect the consideration received from the sale of the MPC. However, in some cases, an MPC does not become an excluded commodity by a sale but rather undergoes further processing to another product. In those cases, there is no observable arm’s-length price for when the MPC becomes an excluded commodity from which assessable petroleum receipts can be derived. Consequently, the Act normally requires assessable petroleum receipts to be based on the market value of the MPC (see paragraph 24(1)(c) of the Act). However, this ‘market value’ method does not apply to an MPC that is sales gas where:

•                 the regulations apply to the sales gas (see sections 22 and 24 of the Regulations); and

•                 either of the following are satisfied;

–               the sales gas produced from petroleum from the project becomes or became an excluded commodity by virtue of being sold (see paragraph 24(1)(d) of the Act);

–               the sales gas becomes or became an excluded commodity otherwise than by virtue of being sold; or treated or processed, or moved, for re-injection or destruction or for use in carrying on or providing operations, facilities or other things of a kind referred to in section 37 (about exploration expenditure), 38 (about general project expenditure) or 39 (about closing-down expenditure) of the Act in relation to the relevant petroleum project (see paragraph 24(1)(e) of the Act).

Instead, the assessable receipts for such sales gas are worked out in accordance with the framework set out in the Regulations. The core of this framework is set out in sections 22 and 24 of the Regulations. Section 22 tells you how to work out the assessable petroleum receipts for the sales gas of a relevant operation with a non-arm’s length sale. In determining if the sale is a non-arm’s length transaction, section 13 requires the Commissioner of Taxation (Commissioner) to have regard to any connections between the parties to the transaction or to any other relevant circumstances to determine if the parties are dealing with each other at arm’s length in relation to the transaction. Section 24 tells you how to work out the assessable petroleum receipts for the sales gas of a relevant operation which became an excluded commodity otherwise than by being sold.

The Regulations remake the 2015 Regulations and implement recommendations 3, 5, 6, 7, 8 and 11 of Treasury Gas Transfer Pricing Review (GTP Review).

Changes of a minor or machinery nature, such as technical changes to ensure the Regulations accord with modern drafting practices, are generally not explained in this Attachment.

Section 26 – Changes to the advance pricing arrangement rules

Changes to section 26 of the Regulations implement recommendation 7 of the GTP Review. Recommendation 7 relates to updating the advance pricing arrangement (APA) rules to provide guidance to industry and the Commissioner on the principles that must be considered in agreeing an APA.

An APA is an agreement between the Commissioner and a taxpayer that establishes an agreed method to work out the amount of assessable petroleum receipts for the taxpayer. The Commissioner may, at the request of a participant in a relevant operation, make an APA with the participant.

Section 26 is changed to require the Commissioner to have regard to additional criteria in making an APA with a participant of an operation.

The changes require the Commissioner to have regard to whether it is impracticable:

•                 to work out a CUP under section 27 for the project sales gas; and

•                 to use one or more steps of the residual pricing method (RPM) in relation to the project sales gas for the participant.

Additionally, the Commissioner must have regard to whether the working out of assessable receipts under the APA will:

•                 provide a reasonably accurate estimation for any RPM steps that are impracticable to use;

•                 be consistent with the calculation in section 28 (being the calculation which provides the RPM price);

•                 provide for a capital allowance to be applied to capital costs in a way that is consistent with sections 17, 18, 19 or 46; and

•                 otherwise, be consistent with the RPM.

Generally, the above factors have the effect of weighing against the Commissioner entering into an APA with a person if it would provide a more favourable outcome for the person than the RPM. Additionally, in considering whether to make an APA, the Commissioner may have regard to any other matter the Commissioner considers relevant.

The Commissioner is not required to consider or give significant weight to the length of any related sales contract when agreeing the period over which an APA applies. The overarching consideration for the Commissioner in agreeing an APA is whether the APA would give effect to the RPM (to the extent that this can be reasonably ascertained).

Where an APA was entered into prior to the changes to section 26, that APA will remain in effect under section 58. This will be the case even where the existing APA could not have been entered into under the amended section 26. Participants to an existing APA may request an amendment of the APA. However, any amendment, if agreed to by the Commissioner, may only be made if the APA (as amended) complies with the requirements of section 26.

Section 27 – Changes to the comparable uncontrolled price rules

Changes to section 27 of the Regulations implement recommendation 6 of the GTP Review. Recommendation 6 relates to updating the comparable uncontrolled price (CUP) rules to better align with relevant OECD guidelines. In particular, the analysis under the CUP rules is broadened to consider all relevant factors to determine a comparable transaction. Reasonably accurate adjustments can be made to the price obtained for the comparable transaction.

Section 27 is changed so that:

•                 inconsistencies between the previous CUP method and the OECD guidelines are removed; and

•                 the factors that the Commissioner is required to take into account when assessing a proposed comparable transaction are broadened.

The Commissioner must now be satisfied, in addition to previous criteria, that a price for sales gas was obtained for a comparable transaction and at an arms-length price.

Subsection 27(1) outlines where a CUP will exist in relation to a relevant transaction, which will broadly exist where:

•                 the Commissioner is satisfied that the parties to the other transaction were dealing with each other at arm’s length;

•                 the Commissioner is satisfied that the other transaction is a comparable transaction to the relevant transaction; and

•                 the other transaction was entered into in a market that the Commissioner is satisfied is a relevant market.

Subsection 27(2) reflects former subsection 23(5) of the 2015 Regulations and effectively defines ‘relevant transaction’ as the sale or act by which the project sales gas becomes subject to the Regulations (see paragraphs 24(1)(d) and 24(1)(e) of the Act and sections 22 and 24).

Comparable transaction

Subsection 27(3) outlines the factors relevant to determining a ‘comparable transaction’, which means, in relation to a relevant transaction, another transaction that the Commissioner is satisfied is comparable to the relevant transaction. These factors include the:

•                 functions performed, assets used, risks borne by, and business strategies of, the entities involved in both the relevant transaction and the other transaction;

•                 terms of any relevant contracts between the parties involved in both the relevant transaction and parties to the other transaction;

•                 characteristics of any property or services transferred; and

•                 economic circumstances.

Subsection 27(4) allows the Commissioner to make a reasonably accurate adjustment to a price obtained for the other transaction to eliminate the effect of any difference between the other transaction and the relevant transaction. To do this, the Commissioner must be satisfied that doing so is necessary to identify a CUP in relation to the relevant transaction.

Subsection 27(5) ensures that the Commissioner does not make adjustments which undermine the arm’s length nature of the other transaction, as doing so would undermine the purpose of paragraph 27(1)(a) (which is about the Commissioner being satisfied that other transaction was done at arm’s length).

Once any adjustment has been made, the Commissioner may treat the adjusted price of the other transaction as the CUP to the relevant transaction.

Subsection 27(6) provides that the Commissioner may be satisfied that the other transaction is comparable to the relevant transaction even if the parties to the other transaction dealt with each other at arm’s length in relation to the other transaction, but the parties to the relevant transaction did not deal with each other at arm’s length in relation to the relevant transaction. This subsection ensures that the mere fact that the parties to the relevant transaction did not deal with each other at arm’s length does not prevent a comparable transaction from being identified.

Relevant market

Subsection 27(7) provides that, in order to be satisfied that a market is a ‘relevant market’ (which is a requirement of paragraph 27(1)(c)), the Commissioner must take into account:

•                 the supply and demand characteristics of the market, including:

–               the composition of the sales gas sold in the market and

–               geographic differences between the production facilities and the product delivery point of the sales gas sold in the market and

–               the end use for the sales gas sold in the market;

•                 the terms of contracts usual in the market, and conditions reasonably considered to affect the price;

•                 market strategies;

•                 spot sales (including market penetration sales) below or above marginal cost;

•                 processing costs;

•                 technology used in processing; and

•                 any factor that would be reasonable to consider.

Section 28 - Equalising treatment of notional upstream/downstream entities between loss and profit situations

Changes to sections 28 and 29 implement recommendation 5 of the GTP Review. Recommendation 5 relates to equalising the treatment of the notional upstream and downstream entities between loss and profit situations.

Section 28 is changed so that the formula in that section now applies in all circumstances. Prior to this change, the formula in paragraph 24(b) of the 2015 Regulations only applied in profit situations (i.e., where the netback price is greater than the cost-plus price). The amendment prevents a project’s notional loss (i.e., where the netback price is less than the cost-plus price) being attributed solely to the upstream part of the project and, in doing so, provides a symmetrical treatment between the netback and cost-plus price in both profit and loss situations.

Section 35 - Accommodating units of property entering the PRRT regime for the first time

Changes to section 35 implement recommendation 11 of the GTP Review. Recommendation 11 relates to ensuring that where certain units of property enter the PRRT regime for the first time, then the value of the units of property for use in RPM calculations is the historical cost of the units of property uplifted by the GDP deflator to the date of first production for PRRT purposes.

Step 1 of the RPM requires taxpayers to, under section 35, identify all types of cost associated with the integrated operation up to and including the assessment year.

Broadly, new provisions in section 35 operate in relation to ‘brought-in units of property’. These are units of property which were not originally intended to be used in the relevant operation but are later used in the relevant operation (otherwise than under a tolling arrangement in relation to the relevant operation). The new provisions in section 35 are intended to remove all costs incurred in relation to these units of property from the scope of subsection 35(2) and for these costs to instead be exclusively dealt with under subsection 35(10). Subsection 35(10) only allows for some of these costs to be included, which are generally the construction, improvement, and maintenance costs of the unit of property. To bring these original costs to current values, the original costs are indexed by the GDP deflator formula at subsection 46(2).

The Regulations introduce new subsection 35(3). This subsection ensures that costs incurred in relation to the acquisition of a brought-in unit of property (e.g., purchasing and leasing costs) are not included under subsection 35(2).

Subsection 35(9) provides the meaning of ‘brought-in unit of property’. A unit of property is a brought-in unit of property if:

•                 when the unit of property was created, the unit of property was not used or intended to be used in any other relevant operation;

•                 the unit of property was later used in the relevant operation (otherwise than under a tolling arrangement in relation to the relevant operation); and

•                 before the unit of property was first used in the relevant operation, the unit of property was not used in any other relevant operation.

Subsection 35(10) provides which capital costs incurred in relation to a brought-in unit of property are included. Costs are included to the extent all of the following conditions are satisfied in relation to the cost:

•                 The cost was incurred by a person who was an owner of the unit of property at the time the cost was incurred.

•                 The cost was incurred in respect of the construction, improvement or maintenance of the unit of property.

•                 The cost was not a payment or allowance between owners of the unit of property.

•                 The cost was incurred before the 31 December of the year of tax in which the unit of property was first used to carry out any of the actions mentioned in section 8 in relation to the relevant operation.

•                 The cost was not incurred for the purpose of preparing the unit of property to be used in the relevant operation.

•                 Either or both of subparagraphs 40(1)(b)(ii) and (iii) apply to the cost (broadly, ensuring the cost is of a capital nature).

A cost included under subsection 35(10) may be treated as a cost partly attributable to the relevant operation if the brought-in unit of property has also been used in relation to another relevant operation. If it is partly attributable to the relevant operation, the amount of the cost is taken to be the amount that can reasonably be apportioned to the operation.

Section 46 indexes included capital costs included under subsection 35(10). For the purposes of step 9 of the RPM, section 46 applies to costs included under subsection 35(10). The cost is indexed by applying the following formula:

Broadly, the formula increases the value of included capital costs to their present-day value. The formula achieves this in relation to the period from the time when the cost was originally incurred to the time when the relevant property was first used in the relevant operation.

Where taxpayers do not have sufficient information about the original costs, this will generally mean that section 29 (RPM price where information is not available) will apply.

Example 1

 Included costs for a brought-in unit of property

Caladenia Co is the sole participant in the Ninnes operation. Caladenia Co purchased an onshore processing facility comprising multiple units of property for $500m from another company for the purposes of processing its project natural gas into project sales gas and then into project liquid. The units of property were not previously used to process petroleum from any offshore petroleum project.

For the purposes of the Ninnes operation, the units of property are brought-in units of property because when they were originally constructed, they were not used in any relevant operation, but are now going to be used in the Ninnes relevant GTL operation. Consequently, Caladenia Co is not able to claim the $500m purchase price as a cost associated with the Ninnes relevant GTL operation, as this amount represents a cost incurred related to acquiring an interest in the brought-in units of property (see subsection 35(3)).

However, Caladenia Co may be able to claim some of the historical costs incurred by the previous owner (or owners) of the brought-in units of property as costs associated with the Ninnes operation. To this end, the costs must:

•                 relate to the construction, improvement or maintenance of the units of property;

•                 have been incurred before 31 December of the first year of tax in which the units of property was first used in the Ninnes relevant GTL operation; and

•                 either:

:                 be incurred in relation to a unit of property that was a depreciating asset for the purposes of section 40-30 of the Income Tax Assessment Act 1997; or

:                 be a project amount within the meaning of section 40-840 of the Income Tax Assessment Act 1997.

However, Caladenia Co may not claim any historical costs related to the brought-in units of property if they were payments or allowances between owners of the brought-in units of property.

Sections 47 and 48 – Requiring projects to make an irrevocable election for asset life formula

Changes to section 47 and the insertion of new section 48 implement recommendation 3 of the GTP Review. Recommendation 3 relates to requiring projects to make an irrevocable election to use either the shorter or longer asset life formula. This removes the integrity risk that projects change the operating life of units of property to benefit from a higher capital allocation amount allowable under the shorter asset life formula.

Step 10 of the RPM requires taxpayers to allocate to each year of tax from the production year onward a cost for each included capital cost, with the amount of the cost given by section 47. Broadly, section 47 (as amended) sets out how capital costs are allocated to a year of tax, with this being done in reference to the ‘capital allocation period'.

'Capital allocation period’ means:

•                 for a unit of property in relation to which an election under section 48 is made, the meaning given by section 48; or

•                 for any other unit of property, the meaning given by subsection 47(5).

However, despite section 48 and subsection 47(5), subsection 47(6) provides a special rule in relation to costs that are capital costs only because of subparagraph 40(1)(c)(i) (about capital costs incurred before the production date). These costs are taken to have been incurred in relation to a unit of property that has a capital allocation period that is the expected operating life of the operation.

New section 48 provides that the participants in a relevant operation may, for a unit of property used in the relevant operation, elect to use a particular number of calendar years as the capital allocation period for the unit of property for the purposes of section 47. There are various rules applying to the written, irrevocable election, including that the election:

•                 must be made jointly, by all participants in the operation.

•                 must specify the capital allocation period for the unit of property; and

•                 may only be made before the first time a PRRT return, for the 2024-25 year or a later year, is given to the Commissioner, where the return relates to the relevant project for the relevant operation and the return is the first such return to be given to the Commissioner after the time the unit of property is first used in the relevant operation.

Subsections 48(5) and (6) provide transitional rules in relation to units of property in use at the time the Regulations commence.

Where an election has been made and one or more new persons later become participants in the relevant operation, then the election continues in force for the participants who made it, and the new participants are also taken to have made the election. The election also continues to apply to a unit of property even if the unit ceases being used in the relevant operation or the unit is used in another relevant operation.

If the participants do not make an election under section 48 for a particular unit of property, the capital allocation period for the unit of property will be determined under subsection 47(5), which broadly provides that:

•                 the capital allocation period for the unit of property is the period of calendar years between the time the cost was incurred and the time the unit of property is expected to no longer be used in the operation; and

•                 the method in subsection 47(4) must be used to work out the annual allocation for capital costs incurred in relation to the unit of property.

Clarifying the operation of sections 22 and 24

Paragraphs 24(1)(e) and 24(1)(d) of the Act are the main provisions under which the Regulations are made.

Paragraph 24(1)(e) of the Act provides that for the purposes of the Act, a reference to assessable petroleum receipts derived by a person in relation to a petroleum project is a reference to, where the regulations apply to any sales gas produced from petroleum from the project and that sales gas becomes or became an excluded commodity otherwise than by virtue of being:

•                 sold; or

•                 treated or processed, or moved, for re-injection or destruction or for use in carrying on or providing operations, facilities or other things of a kind referred to in section   37 (about exploration expenditure), 38 (about general project expenditure) or 39 (about closing-down expenditure) of the Act in relation to the petroleum project;

the amount worked out in accordance with the Regulations.

Subsection 24(1) then provides that for the purposes of paragraph 24(1)(e) of the Act, section 24 applies to sales gas that is project sales gas of a relevant operation and becomes or became an excluded commodity (otherwise than as mentioned in subparagraph 24(1)(e)(i) or (ii) of the Act). The remaining provisions in section 24 provide the amount of assessable petroleum receipts of the taxpayer.

Changes are made to the provisions in section 24 of the Regulations to ensure those provisions clearly and consistently provide the amount of assessable petroleum receipts of a taxpayer. To this end, the term ‘non-sale entitlement share’ is introduced into the section. Broadly, a taxpayer’s non-sale entitlement share is the proportion of the receipts from the sale of project sales gas that the taxpayer would be entitled to receive if the project sales gas was sold, multiplied by the volume or mass of project sales gas subject to the non-sale transaction. ‘Non-sale transaction’ means the act by which project sales gas to which this section applies becomes or became an excluded commodity. The taxpayer’s entitlement share is then multiplied by the relevant CUP or RPM price.

As a broad example, if entities ‘A’ and ‘B’ are the only participants in a relevant operation and are equal participants in that operation (in the sense that they are equally entitled to the project sales gas of the operation), then A and B would both have a non‑sale entitlement share of 50 percent.

Similar changes are made in relation to section 22, which relates to paragraph 24(1)(d) of the Act.

A minor and technical amendment is intended to be progressed to section 26 of the Act to remove the reference to paragraph 24(1)(e) of the Act in that section. This amendment reflects the fact that paragraph 24(1)(e) of the Act provides the amount of assessable petroleum receipts derived by a person in relation to a petroleum project.

Section 19 – Updating the capital allowance formula

A minor change is made to the capital allowance formula in section 19 to ensure the formula is clear. The reference to ‘7 percentage points’ is replaced with a reference to ‘0.07’. This change is not intended to alter the substance of the capital allowance formula. Instead, this change reflects the fact that the long-term bond rate is defined in the Act as a decimal number, rather than as a percentage.

The formula will now work to add 0.07 to the long-term bond rate. If desired, this decimal can then be expressed as a percentage. For example, if the long-term bond rate for a given financial year is 0.04, then the capital allowance for that year is 0.11 or 11 percent.

Updating the Regulations for tolling arrangements

Several changes are made to the Regulations to ensure they better account for tolling arrangements, including:

•                 making clear how relevant operations which involve a tolling arrangement are recognised and treated under the Regulations;

•                 ensuring that the phase points and phases of a relevant operation work appropriately for operations which involve a tolling arrangement; and

•                 ensuring there is a clear and robust framework for how tolling fees are recognised under the RPM.

Generally, tolling arrangements exist in the liquified natural gas (LNG) industry and involve a ‘shipper’ and a ‘host’. The shipper will generally have an interest in a petroleum project and will recover petroleum from that project. However, the shipper may not have facilities to process that petroleum into a liquefied product. The host does have those facilities (the host may have these facilities because they built them to process their own petroleum). Rather than building their own facilities, the shipper pays the host a ‘tolling fee’ for the host to process the shipper’s petroleum into a liquified product. The shipper then sells the liquified product and they retain the profits from that sale.

The Regulations recognise tolling arrangements where custody of the project product changes between the shipper and host at least once. Broadly, for a change in custody to occur there must be change in physical control over the project product (it is not necessary for there to be change in the ownership or profit rights in relation to the project product).

The terms ‘shipper’ and ‘host’ are used in the following parts of this Explanatory Statement to help explain certain concepts. These particular terms are used in this Explanatory Statement in a general sense and are generally not used or defined in the Regulations.

Section 6 and 7 – Relevant operation

A central concept and definition in the Regulations is ‘relevant operation’. ‘Relevant operation’ is defined in section 5 as meaning a relevant GTE (gas to electricity) operation or a relevant GTL (gas to liquid) operation.

Sections 6 sets out when a relevant GTL operation exists. A relevant GTL operation exists if there is an operation (the ‘overall operation’) in which:

•                 petroleum is, or will be, recovered from a petroleum project; and

•                 sales gas is, or will be, produced from some or all of the petroleum; and

•                 some or all of the sales gas is, or will be, processed into a liquefied product.

An operation may be a relevant GTL operation even if the project product of the operation is not in the custody of participants in the operation for all of the phases of the operation. Accordingly, an operation may be a relevant GTL operation notwithstanding any tolling arrangement in relation to the operation.

In the case of a tolling arrangement where:

•                 a shipper recovers petroleum from a petroleum project; then

•                 the shipper delivers the petroleum to a host; then

•                 the host produces sales gas from the petroleum; then  

•                 the host processes the sales gas into liquefied product;

the intention is that all of these activities form part of the same relevant GTL operation. Additionally, for the purposes of determining the ‘production year’ under paragraph 6(6)(b), this is determined in relation to the year of tax in which processing first occurred in relation to the petroleum that the shipper recovered from the petroleum project, rather than any other petroleum that the host (or another person) recovered from another petroleum project and processed at the host’s facilities (the recovery and processing of that other petroleum may constitute another relevant operation).

Subsection 6(3) is changed to make clear the intended meaning of ‘project sales gas’. The project sales gas of an integrated GTL operation is the sales gas (being the sales gas that is, or will be, produced from some or all of the petroleum) that:

•                 will be processed into liquefied product within the overall operation; or

•                 will, after becoming an excluded commodity, be used in the downstream stage of the operation in relation to the processing of sales gas (being the sales gas that is, or will be, produced from some or all of the petroleum) into liquefied product.

Where sales gas (the ‘destroyed sales gas’) is destroyed in relation to the processing of other sales gas into liquefied product, then the destroyed sales gas is intended to be taken to have been used in relation to the processing of the other sales gas into liquefied product.

Similar changes are made in relation to section 7, which deals with relevant GTE operations.

Section 9 – Phase points

Changes to this section provide additional phase points for a relevant operation.

Under paragraph 9(1)(c), there is a phase point if there is a change in custody of the project product at any point in the flow of the project product through the operation and the change occurs for the purpose of carrying out one of the actions in section 8.

In a tolling scenario, for a shipper operation, there is a phase point at the point where the project product moves from the custody of the shipper to the host for the purposes of allowing the host to carry out any section 8 actions on the shipper’s project product. There is also a phase point at the point where the project product is returned to the shipper.

For a host that is also a relevant operation, there is a phase point when shipper product enters the operation and a phase point when that product leaves the operation, as the ratio of the host’s project product to total product flowing through the operation will have changed at the point the shipper product enters or leaves (see paragraph 9(1)(b)). New example 4 to subsection 9(1) makes this clear.

For a phase point to occur under paragraph 9(1)(c), at least one of the persons who starts or stops having custody of the project product must be a participant in the relevant operation. This requirement means that where custody of the project product changes hands between third parties, none of whom are participants in the relevant operation, there will not be a phase point. This may occur where the project product changes custody between the host and a third party.

Section 10 – Commercial tolling phases

Section 10 introduces commercial tolling phases. Where there is a relevant operation that is a shipper operation and it has a tolling arrangement with a commercial toll fee, no phase points, aside from a phase point mentioned in paragraph 9(1)(a) (at the point where the upstream stage ends and the downstream stage begins), are taken to occur between the start point (the change of custody of project product from shipper to host) and the end point (the change of custody of project product from host to shipper). A legislative note and example to subsection 10(2) make it clear that if other petroleum also flows through the operation but does not undergo a change in custody at the start point or the end point (for example, because that petroleum product is not subject to a tolling arrangement), then section 10 does not affect any phase points that occur in relation to the flow of that petroleum.

For a relevant operation that has a tolling arrangement with a commercial toll fee, there may be a phase point taken to occur between the start point and the end point if the actions performed by the host encompass both upstream and downstream actions, such that the stream change point occurs while the project product is in the custody of the host. Alternatively, there may be no phase point taken to occur between the start point and end point if the tolling services occur entirely within either the upstream or downstream stages.

If there are no phase points between the start point and end point, then there is a single phase called a commercial tolling phase. If there is a phase point between the start point and the end point, then there is a phase between the start point and stream change point, and between the stream change point and end point. These phases are also called commercial tolling phases.

This section ensures that, where there is a tolling arrangement with a commercial toll fee, the participants in a relevant operation are not required to have information pertaining to the phases that occur while the project product is in the custody of the host (aside from the stream change point).

Example 2

Tolling arrangement only covers downstream stage

Cycads Co is the sole interest holder in the Cycads petroleum project, and sole participant in the Cycads operation. Cycads Co enters into a tolling arrangement with Diuris Co, who does not currently have an interest in a petroleum project but owns an onshore liquefaction facility. Cycads Co pays Diuris Co a commercial tolling fee to cover:

•                 transportation of Cycads project sales gas to Diuris Co’s facility;

•                 liquefaction of that sales gas into LNG; and

•                 transportation of that LNG back to the facilities of the Cycads operation.

As the tolling arrangement only covers activities that occur in the downstream stage of the operation, the Cycads operation is taken to have one commercial tolling phase, being the phase between the point at which Diuris Co takes custody of the project product and the point at which the product is returned to the custody of Cycads Co.

Example 3

Tolling arrangement covers both upstream and downstream stage

Eucalyptus Co and Ficus Co are both interest holders in the Parham petroleum project and are participants in the Parham operation. However, the Parham project only has offshore facilities capable of extracting the petroleum, performing some refining of the product, and then transporting it onshore.

Eucalyptus Co and Ficus Co enter into a tolling arrangement with several parties who are owners of onshore processing and liquefaction facilities (the host parties). A tolling fee is paid by Eucalyptus Co and Ficus Co to the host parties in exchange for the:

•                 processing of project natural gas into project sales gas;

•                 liquefaction of the project sales gas into project liquid (LNG); and

•                 transport of the LNG to the port where Eucalyptus Co and Ficus Co will ship their product to international markets.

As the tolling arrangement covers activities that occur in both the upstream and downstream stages of the operation, the Parham operation is taken to have two commercial tolling phases:

•                 the first being between the point at which the host parties take custody of the project product and the stream change point where the upstream stage ends and the downstream stage begins; and

•                 the second, between the stream change point and the point at which Eucalyptus Co and Ficus Co retake custody of the project product from the host parties.

Sections 20 and 21 – Tolling arrangements and commercial tolling fees

Section 20 contains important concepts and definitions in relation to tolling arrangements.

Subsection 20(1) defines the term ‘tolling arrangement’. A ‘tolling arrangement’, in relation to a relevant operation (the shipper operation), is an arrangement in relation to which all of the following are satisfied:

•                 Under the arrangement, one or more actions mentioned in section 8 (this section lists the various actions which comprise the upstream and downstream stages of a relevant operation) in relation to project product of the shipper operation (the tolled actions) are to be carried out by one or more persons (the host parties).

•                 The parties to the arrangement are one or more of the participants in the shipper operation (the shipper parties) and the host parties. One or more of the host parties may also be a shipper party.

•                 At least one shipper party is not also a host party, or at least one host party is not also a shipper party.

•                 Under the arrangement, an amount or amounts are paid in consideration of the carrying out of the tolled actions.

•                 Under the arrangement, custody of the project product changes, at least once, between the shipper parties and the host parties.

A legislative note makes clear that some of the shipper parties and host parties may be the same people (although not all, because paragraph 20(1)(b) does not allow the shipper parties and the host parties to be the same). If some, but not all, of the shipper parties and host parties are the same, then the requirements in paragraphs 20(1)(c) (about payments) and 20(1)(d) (about custody) may be met by payments, or changes in custody, between the shipper parties as a group and the host parties as a group.

There may be future arrangements where an entity (entity ‘A’) pays another entity (entity ‘B’) a fee for entity B to recover petroleum from a petroleum project and to then transport it to entity A’s processing facilities. Entity A produces sales gas from the petroleum and then process the sales gas into liquefied product. Under this arrangement, entity A has exclusive rights to the proceeds from the sale of the petroleum and any products produced from it. Such arrangements are intended to be capable of being a tolling arrangement under subsection 20(1). For such arrangements, entity B will be ‘host party’ mentioned in subsection 20(1). 

Subsection 20(2) defines the term ‘commercial tolling fee’. The amount or amounts paid for of the carrying out of the tolled actions are a ‘commercial tolling fee’ if the amount or amounts might be expected to have been arrived at in ‘arm’s length conditions’. Tolling fees are subject to this test to ensure their integrity before they are recognised under the RPM. This is important as many tolling arrangements involve related party dealings which may, absent the commercial tolling fee test in subsection 20(2), lack commercial tension.  

Section 21 defines ‘arm’s length conditions’. The arm’s length conditions, in relation to conditions that operate between an entity and another entity, are the conditions that might be expected to operate between independent entities dealing wholly independently with one another in comparable circumstances.

In identifying the arm’s length conditions regard must be had to both the form and substance of the relations between the entities. However, the form of those relations is disregarded to the extent (if any) that it is inconsistent with the substance of those relations.

In identifying the arm’s length conditions, taxpayers must use the method, or the combination of methods, that is the most appropriate and reliable, having regard to all relevant factors, including the factors set out in subsection 21(2). Additionally, taxpayers must identify arm’s length conditions so as to best achieve consistency with the Transfer Pricing Guidelines for Multinational Enterprises and Tax Administrations as last amended on 7 January 2022 (this document could in 2024 be viewed on the OECD’s website at https://oecd.org/). These Guidelines provide further information, guidance and context about the ‘arm’s length principle’ and explain the methods taxpayers may use to identify the arm’s length conditions. Identifying arm’s lengths conditions consistent with the OECD’s transfer pricing guidelines also assists in determining a non‑arm’s length transaction under section 13. A decision under section 13 on whether a transaction is a non-arm’s length transaction is subject to objection in the manner set out in Part IVC of the Taxation Administration Act 1953 (TAA 1953) (see subsection 53(a)).

In identifying comparable circumstances, regard must be had to all relevant factors, including the factors set out in subsection 21(3). Additionally, circumstances that are different to the actual circumstances are nevertheless treated as comparable if:

•                 the difference does not materially affect a condition that is relevant to the method; or

•                 a reasonably accurate adjustment can be made to eliminate the effect of the difference on a condition that is relevant to the method (see subsection 21(4)).

If the Commissioner is satisfied the amount or amounts, considered together, paid for the carrying out of the tolled actions are not a commercial tolling fee and an amount worked out by the Commissioner might be a commercial tolling fee, then the amount the Commissioner worked out is instead taken to be the commercial tolling fee for the purposes of the RPM. Additionally, the Commissioner may determine the time or times at which the commercial tolling fee is taken to have been paid, and the person or persons who are taken to have paid the fee. When determining these matters, the Commissioner must have regard to the form and substance of the tolling arrangement (however, the Commissioner must disregard the form of the arrangement to the extent (if any) that it is inconsistent with the substance of the arrangement). The time at which costs are incurred is relevant for the purposes of step 1 of the RPM, which involves identifying all types of cost associated with the relevant operation up to and including the assessment year.

The ability for the Commissioner to substitute in a commercial tolling fee under subsection 20(3) is an important part of ensuring the integrity of such fees without entirely discounting them in the event the fees paid under the tolling arrangement are non‑commercial tolling fees. Additionally, it prevents taxpayers with non‑commercial tolling fees from defaulting into section 29 (section 29 is about the RPM price being determined by the Commissioner where information is not available or where a non‑commercial tolling fee is paid).

If the Commissioner reaches an updated or new state of satisfaction in relation to the matters mentioned subsection 20(3), the Commissioner may amend the relevant taxpayer’s assessments to give effect to their updated state of satisfaction. This includes amending the taxpayer’s assessments to give effect to an updated:

•                 substituted commercial tolling fee;

•                 time or times at which that fee is taken to be paid; and

•                 person or persons taken to have paid the fee.

The Commissioner’s power to amend a taxpayer’s assessment (including amending an amended assessment) is governed by the rules in Division 3 of Part VI of the Act.

Taxpayers who are dissatisfied with a substituted toll fee may, in effect, object against it by objecting against their relevant assessment in accordance with section 66 of the Act. Section 66 of the Act broadly provides that a taxpayer who is dissatisfied with their assessment may object against it in the manner set out in Part IVC of the TAA 1953.

Taxpayers are expected to keep appropriate records in line with section 112 of the Act. Additionally, taxpayers may keep detailed records and analysis in relation to how they understand sections 20 and 21 apply in relation to their tolling arrangement and tolling fees.

Sections 29 and 33 – Tolling arrangements and the RPM

Section 33 sets out when the RPM can be applied.

New note 5 to subsection 33(1) makes clear that the RPM can be applied where there is a tolling arrangement and a commercial tolling fee. New subsection 35(5) is also relevant to achieving this result, as that subsection broadly provides that where there is a tolling arrangement and a commercial tolling fee, then the underlying costs in relation to that tolling arrangement are not costs associated with the relevant operation, meaning that information is not required to be known about those underlying costs under subsection 33(1).

Provisions are added to section 33 to provide that the RPM cannot be applied in relation to a taxpayer who is a participant in a relevant operation in an assessment year where:

•                 there is a tolling arrangement in effect in relation to the relevant operation at any time in the assessment year; and

•                 there is a tolling fee paid under the arrangement; and

•                 the tolling fee is not a commercial tolling fee.

Broadly, this means that where there is a non-commercial tolling fee, then section 29 will apply in relation to the relevant taxpayer(s).

Consequential changes are made to section 29 as that section now also applies where there is a non-commercial tolling fee.

Section 35 and other sections – Commercial tolling arrangements and the RPM

Where there is a commercial tolling fee, the amount of the fee may be able to be included under the RPM calculation. Such fees can be included under subsection 35(2) where it is a cost incurred by or on behalf of the participants that is attributable to the operation, whether incurred during the operating life of the operation or before the production year.

Subsection 35(4) provides that a payment or allowance between participants is not a cost associated with the relevant operation, unless it is a commercial tolling fee. The exception for commercial tolling fees recognises that:

•                 commercial tolling fees are subject to a robust arm’s length test under subsection 20(2) and section 21; and

•                 in certain cases, an entity may be a participant in the shipper operation and part of the host operation or enterprise.

Subsection 35(5) ensures that, to the extent costs for certain actions (being actions mentioned in section 8) are otherwise covered by a commercial tolling fee in relation to those actions, then those costs are not included under the RPM. This subsection ensures that the commercial toll fee is recognised in the RPM calculation and that double counting of costs does not occur where there is a tolling arrangement.

Additionally, subsection 35(9) ensures that where a unit of property was later used in a relevant operation under a tolling arrangement that, unit of property is not a ‘brought-in unit of property’. For example, where a host operation is using a unit of property to toll a shipper operation’s project product, the exclusion in paragraph 35(9)(b) means that the historical costs of that unit of property cannot be included under subsection 35(10) for the shipper operation. 

Other changes ensure that commercial tolling fees are a relevant sector cost under section 37 and are an operating cost under section 40. These changes ensure the proper and intended treatment of tolling fees.

Section 49 – Energy coefficient for tolling arrangements

Step 12 of the RPM calculation requires that for each phase cost for the assessment year, taxpayers adjust the amount of that cost under section 49 if that section applies to the phase cost. Section 49 is changed so that the calculation of an energy coefficient does not apply to a phase cost of a commercial tolling phase or a cost that is a commercial tolling fee. This is because, under a commercial tolling arrangement, special arrangements apply in regard to working out phase points and costs associated with the commercial tolling phases. There is no need to further apportion those costs under section 49.

Examples relating to tolling arrangements:

Example 4

Tolling arrangement with a commercial toll fee

Grevillea Co and Hakea Co are both interest holders in the Hammond petroleum project and participants in the Hammond operation. They enter into a contract with Isolepis Co, the sole interest holder in the nearby Rudall petroleum project and sole participant in the Rudall operation.

Under the contract, Grevillea Co and Hakea Co will pay Isolepis Co to take custody of the Hammond project petroleum when it reaches the shore, transport the petroleum to the processing and liquefaction facilities of the Rudall operation and process the petroleum into LNG, after which the Hammond participants will organise transportation of the LNG from the Rudall facility to their own loading facility.

The contract is a tolling arrangement. The participants of the Hammond operation pay a fee under an arrangement with Isolepis Co. Under the arrangement, Isolepis Co performs various actions under section 8 in relation to the project product of the Hammond operation.

The Hammond operation participants and Isolepis Co negotiate a commercial toll fee for Isolepis Co’s services under the tolling arrangement. The Hammond operation participants may include the toll fee as a cost associated with the operation under subsection 35(2).

Example 5

 Commissioner substitutes in a commercial toll fee

Acacia Co and Banksia Co are participants in the Barabba operation, in which natural gas will be recovered from the Barabba petroleum project and be processed into liquefied product. However, the Barabba operation does not have any facilities available to process the Barraba operation’s natural gas into LNG.

Salsola Co is the sole participant in the Kadina operation, which does have processing and liquefaction facilities. In June 2023, Acacia Co, Banksia Co and the participants of the Barabba operation enter into a tolling arrangement with  Salsola Co. Acacia Co and Banksia Co will pay a fee to Salsola Co to produce liquefied product from the natural gas sourced from the Barabba petroleum project in the facilities of the Kadina operation. When Acacia Co and Banksia Co file their PRRT returns for the 2024-2025 year, they self-assessed that the fee paid under this tolling arrangement is a commercial tolling fee under subsection 20(2).

However, upon receiving Acacia Co’s return and various information in relation to the toll fee, the Commissioner is satisfied that the fee paid is not a commercial tolling fee. The Commissioner worked out an amount that might be expected in arm’s length conditions to be paid under the tolling arrangement in consideration of the carrying out of the tolled actions in relation to the Barabba operation’s project product. The amount the Commissioner worked out is then taken to be a commercial tolling fee and paid in consideration for the tolled actions performed by Salsola Co. That amount is then included in the RPM calculation for Acacia Co and Banksia Co. The amount actually paid by Acacia Co and Banksia Co to Salsola Co is taken not to be a cost associated with the Barabba operation and cannot be included as a cost under section 35 (section 20(3)).

Example 6

Section 29 applies to determine RPM price

Juncus Co and Livistona Co are both interest holders in the Danggali petroleum project and participants in the Danggali operation.

Juncus Co and Livistona Co, the participants of the Danggali operation, enter into a tolling arrangement with another nearby operation, the Terowie operation. Livistona Co is an interest holder in the Terowie petroleum project and is a participant in the Terowie operation. Under the tolling arrangement, the Danggali operation participants pay a toll fee to the Terowie operation participants to process project product from the Danggali operation.

Apart from Livistona Co, the Terowie project has two other interest holders, which are also participants in the Terowie operation.

Juncus Co and Livistona Co both self-assessed that the fee paid under the tolling arrangement is a commercial tolling fee. However, the Commissioner is satisfied that the fee is not a commercial tolling fee because the amount of the fee is not an amount that might be expected to have been arrived at in arm’s length conditions under subsection 20(2). Additionally, the Commissioner is not satisfied under subsection 20(3) that an amount worked out by the Commissioner might be expected, in arm’s length conditions, to be paid under the tolling arrangement. Accordingly, an RPM price cannot be calculated because of subsection 33(2) and consequently, section 29 applies.

The Commissioner and the taxpayers cannot agree on a price under subsection 29(2) nor is the Commissioner satisfied under subsection 29(3) that a fair and reasonable price can be worked out by applying the RPM, using information available from the other participants in the Danggali operation. Consequently, the Commissioner determines an RPM price that they consider to be fair and reasonable in the circumstances (subsection 29(4)). Juncus Co and Livistona Co each use this RPM price for the purposes of subsection 24(7).

Example 7

 Multiple tolling arrangements entered into by shipper participants

Rhagodia Co and two other companies are participants in the Gulnare operation. The participants in the Gulnare operation enter into a tolling arrangement with Vappodes Co. Under the arrangement (the first tolling arrangement), Vappodes Co will transport the project product of the Gulnare operation through Vappodes Co’s offshore pipelines and into Vappodes Co’s onshore processing facilities to process the petroleum from the Gulnare petroleum project into sales gas.

The participants in the Gulnare operation then enter into another tolling arrangement with Westringia Co (the second tolling arrangement). Under the second tolling arrangement, Westringia Co will transport the project product of the Gulnare operation from the facilities of Vappodes Co to Westringia Co’s liquefaction facility, where Westringia Co will process the Gulnare operation’s sales gas into LNG.

Rhagodia Co self-assessed that the fees paid under both tolling arrangements are commercial tolling fees.

The Commissioner is satisfied that the fee paid under the first tolling arrangement is a commercial tolling fee.

However, the Commissioner is not satisfied that the fee paid under the second tolling arrangement, with Westringia Co, is a commercial tolling fee. The Commissioner is satisfied that another amount worked out by the Commissioner might be expected, in arm’s length conditions, to have been paid under the second tolling arrangement. The amount worked out by the Commissioner (the substituted tolling fee) is taken to be a commercial tolling fee paid by the participants in the Gulnare operation under the second tolling arrangement, and the actual fee paid under the second tolling arrangement is taken not to be a cost associated with the Gulnare operation.

The Commissioner assesses Rhagodia Co on the basis that the actual tolling fee for the first tolling arrangement is included under the RPM and the substituted tolling fee for the second tolling arrangement is included under the RPM.

Example 8

Included costs for a tolling arrangement with commercial tolling fee

Phaius Co is a participant in the Fregon operation. The Fregon operation’s participants have a tolling arrangement with the participants of the nearby Spalding operation, under which the Fregon participants pay the Spalding participants a commercial tolling fee in exchange for liquefaction services. Phaius Co works out under section 10 that the Fregon operation has one commercial tolling phase, as the activities performed by the Spalding participants are all downstream activities (see paragraphs 8(2)(b), (c) and (k)).

Under subsection 35(5), any costs incurred by the Spalding participants in relation to carrying out any section 8 actions on the Fregon operation’s project petroleum are not costs associated with the Fregon operation, as the commercial tolling fee was paid in consideration for these actions being performed. Instead, as the commercial tolling fee paid by the Fregon participants to the Spalding participants meets the criteria in subsection 35(2), it is included under step 1 of the RPM.

Under Step 3 of the RPM, the commercial toll fee is classified as a relevant sector cost under paragraph 37(2)(b). As it is wholly attributable to the downstream stage of the operation, it is then classified as a direct cost under subsection 37(3).

Under Step 5 of the RPM, the commercial toll fee is further classified as an operating cost under subsection 40(3), as it is neither a capital cost (because of paragraph 40(1)(b)) nor a personal cost.

Under Step 7 of the RPM, in attributing the commercial tolling fee to a phase, the commercial tolling fee is classified as a phase cost of the commercial tolling phase under subsection 42(2). As the cost is wholly attributable to the downstream phase it is therefore considered a downstream cost under subsection 42(6).

Example 9

 Included costs where one entity is on both sides of tolling arrangement

Zieria Co and Thelymitra Pty Ltd are equal participants in a shipper operation and are both entitled to an equal share of the natural gas produced from the operation.

Zieria Co owns facilities which can process the natural gas from the operation into LNG. Zieria Co and Thelymitra Pty Ltd enter into a tolling arrangement with Zieria Co. The terms of the tolling arrangement provide that Zieria Co and Thelymitra Pty Ltd will each pay Zieria Co $500m ($1bn total) to process the operation’s natural gas into LNG.

When considering the substance of the tolling arrangement, it becomes apparent that:

•               the purported payment from Zieria Co to itself is not a payment; and

•               the purported provision of tolling services from Zieria Co to itself is not a provision of services but rather Zieria Co performing services for itself.

Zieria Co is not a shipper party to the tolling arrangement because the substance of the tolling arrangement is that Thelymitra Pty Ltd is paying Zieria Co $500m to process Thelymitra Pty Ltd’s share of the operation’s natural gas. It is this substance which is recognised under sections 20 and 21.

Assuming that the $500m paid by Thelymitra Pty Ltd to Zieria Co is a commercial tolling fee under subsection 20(2), then that cost can be included under subsection 35(2) when calculating the RPM price for the participants in the operation.

Additionally, a proportion of Zieria Co’s processing costs can be included under subsection 35(2), noting that subsection 35(5) does not exclude all of Zieria Co’s processing costs. As Zieria Co and Thelymitra Pty Ltd are equal participants in the operation, the proportion of Zieria Co’s processing costs that can be included are 50% of those processing costs.

Example 10

 Commercial toll fee covers multiple petroleum products

 Nypa Co is the sole participant in the Wudinna operation. Nypa Co enters into a tolling arrangement with Olearia Co. Under the arrangement, Olearia Co will perform processing services on petroleum from the Wudinna operation. These processing services encompass not only the processing of sale gas into LNG but also the processing of several other petroleum products.

The tolling fee for the processing of LNG and for the processing of the other petroleum products was determined to be at arm’s length conditions and is a commercial tolling fee (section 20 and 21).  For the purposes of Step 1 of the RPM, Nypa Co may include the tolling fee as a cost associated with the operation under subsection 35(2).

 However, because the commercial tolling fee covers more than just services performed on the project product of the Wudinna operation, the tolling fee is only partly attributable to the relevant operation. As such, Nypa Co may only include the amount of the tolling fee that can reasonably be apportioned to the relevant operation (see subsection 35(7)).

Sections 50, 51 and 52 – Consequential amendments for the deductions cap legislation

Sections 50, 51 and 52 are updated to account for amendments to the Act made by Schedule 5 to the Treasury Laws Amendment (Tax Accountability and Fairness) Act 2023 (the deductions cap legislation). Those sections of the Regulations referred to subsection 97(1A) and paragraph 97(1AA)(b) of the Act, which concern calculating the notional tax amount derived by a taxpayer for instalment purposes. The deductions cap legislation inserted new subsections into section 97 of the Act to cover circumstances where a taxpayer is subject to the deductions cap in a particular year.

Consequential amendments are made to sections 50, 51 and 52 to include references to new paragraph 97(1BB)(b) and subsection 97(1BA) of the Act.

Part 7 – Transitional matters

Section 58 provides that the Regulations apply in relation to a year of tax beginning on or after 1 July 2024.

The Regulations also includes a general sunsetting transitional provisions to ensure that actions, such as the making of applications or elections and the giving of notices and permissions, taken under the Petroleum Resource Rent Tax Assessment Regulations 2005 or 2015 Regulations continue to apply as if they had been taken under the Regulations (see section 56).

The 2015 Regulations are repealed on the basis that the Regulations remake and replace the 2015 Regulations.

Remaking of existing provisions

The overarching structure and mechanics of the Regulations are remade with relatively little change.

Division 1 of Part 1 contains preliminary provisions relating to things such as the name of the Regulations and commencement.

Division 2 of Part 1 contains various definitional provisions which support the wider operation of the Regulations.

Section 14 of the Regulations requires participants in an operation to give the Commissioner an estimate of the operating life of the operation and the volume or mass of project natural gas expected to be recovered during the life of the operation. These estimates are necessary for the working out of the volume or mass coefficients (as relevant) and the costs of an operation, for the purposes of the cost-plus and netback prices under the RPM. If  there is new information, the person may provide the Commissioner with a revised estimate under subsection 14(4) of the Regulations.

The Commissioner may substitute a reasonable estimate only if after having regard to relevant information the Commissioner is not satisfied that an estimate given by the participants is reasonable. In substituting a reasonable estimate, the Commissioner may have regard to various sources and information in the Commissioner’s possession, including publicly available information, information about the operation from the operator and/or other participants in the operation, information about the operation’s reserves, and the expected duration of such reserves. The Commissioner’s substitution is subject to objection in the manner set out under Part IVC to the TAA 1953 (see subsection 53(b))

Part 2 contains provisions relating to how taxpayers work out assessable petroleum receipts.

Section 23 of the Regulations provides for the working out of a taxpayer’s ‘sale entitlement share’ in relation to a non‑arm’s length sale of project sales gas. Section 25 contains an equivalent provision for the working out of a taxpayer’s ‘non-sale entitlement share’ in relation to a non‑sale transaction where project sales gas becomes an excluded commodity. As an integrity rule, the Commissioner may make fair and reasonable adjustments to a taxpayer’s sale entitlement share or non-sale entitlement share to ensure that the total of all sale entitlement shares or non-sale entitlement shares is equal to the volume or mass of project sales gas subject to the transaction. The adjustment the Commissioner makes to either the sale entitlement share or the non-sale entitlement share must be fair and reasonable. If a Commissioner makes an adjustment under sections 23 or 25, a taxpayer’s PRRT assessment may be impacted, therefore a taxpayer who is dissatisfied with an assessment may object in the manner set out in Part IVC of the TAA 1953 (see section 66 of the Act).

Part 3 contains provisions relating to the substitute prices, which relate to how taxpayers are required to work out assessable petroleum receipts under Part 2.

Section 31 of the Regulations sets out the calculation method for the netback price, which is one of the inputs in calculating a taxpayer’s RPM price for a year of tax. This calculation includes an integer based on the value of the end product - either project liquid produced or project electricity produced, depending on the project. Generally, this is equivalent to the market value of the end product, calculated by reference to the amount the taxpayer received for the sale of the product in an arm’s length transaction, or if there is no sale in an arm’s length transaction, the market value of the product at the end of the downstream stage. Section 51 also contains an equivalent power for circumstances where the taxpayer had an RPM price in a previous year of tax. These discretionary powers in subsections 31(5) and 51(5) only apply where the taxpayer did not sell the:

•                 product at the end of the downstream stage; or

•                 project liquid; or

•                 project electricity,  

in an arm’s length transaction and there is no sufficient information to determine a market value. In these limited circumstances where the Commissioner is not satisfied there is sufficient information available to determine a market value, the Commissioner may substitute in a fair and reasonable price for the value of the end product. The Commissioner may determine a fair and reasonable price by leveraging information from various sources, for example, the market in which the end product is sold, historic pricing information for the product and whether any comparison can be made to other transactions in the market that occur between unrelated parties. A taxpayer who is dissatisfied with the Commissioner’s determination under subsections 31(5) or 51(5) may object in the manner set out in Part IVC of the TAA 1953 (see subsection 53(f)).

Part 4 contains various provisions relating to the RPM. Generally, most taxpayers will use the RPM to work out their assessable petroleum receipts. The RPM is also relevant to the other substitute prices and whether they can be used.

Part 5 contains provisions relating to notional tax amounts for PRRT instalment purposes.

Part 6 contains various miscellaneous provisions, such as prescribed decisions which can be reviewed and election provisions.

Section 53 of the Regulations is empowered by section 106A of the Act which provides that decisions are subject to review in accordance with Part IVC of the TAA 1953. Taxpayers who are dissatisfied with a decision made under the Act or the Regulations may lodge an objection against the decision. If a taxpayer is dissatisfied with the outcome from the objection, they may seek external review by the Administrative Review Tribunal or an appeal to the Federal Court.

Any decisions made under the Regulations that are not prescribed for the purposes of section 53 of the Regulations are reviewable under the Act, as part of the PRRT assessment. This is because any adjustments made by the Commissioner that affect the taxpayer’s total RPM price therefore also impact the amount of assessable petroleum receipts derived by the taxpayer under section 24 of the Act. If the Commissioner makes any decision affecting a taxpayer’s liability under the Act, the taxpayer would be issued with an amended assessment and, subject to certain conditions, the taxpayer may lodge an objection under section 66 of the Act. Therefore, any of the Commissioner’s discretionary decisions made under the Regulations are reviewable either specifically (if prescribed under section 53 of the Regulations) or generally under the process for objecting to an assessment under Part IVC of the TAA 1953.

Part 7 deals with transitional matters, including the application of the Regulations.

In section 41, the reference to Accounting Standard AASB 136 Impairment of Assets (as in effect on 1 May 2010) is maintained. That Accounting Standard provides the meaning of ‘depreciated replacement cost’ for the purposes of section 41. The Accounting Standard could in 2024 be viewed on the AASB’s website at https://aasb.gov.au/.

Readers may wish to consult the Explanatory Statements to the 2005 Regulations and 2015 Regulations for further context and explanation on the remade provisions in the Regulations.

ATTACHMENT B

Finding tables

As a result of some of the changes outlined in Attachment A, it was necessary to renumber the provisions in the Regulations. This explanatory statement includes finding tables to assist in identifying which provision in the Regulations corresponds to a provision in the old law that has been rewritten or consolidated.

In the finding table, in the ‘old law’ column the term 'no equivalent' means that this is a new provision that has no equivalent in the old law.

ATTACHMENT C

Statement of Compatibility with Human Rights

Prepared in accordance with Part 3 of the Human Rights (Parliamentary Scrutiny) Act 2011

Insert Title of Instrument

This Legislative Instrument is compatible with the human rights and freedoms recognised or declared in the international instruments listed in section 3 of the Human Rights (Parliamentary Scrutiny) Act 2011.

Overview of the Legislative Instrument

On 7 May 2023, the Government announced that it would introduce changes to the Petroleum Resource Rent Tax (PRRT) to deliver a fairer return to the Australian community from their natural resources. The changes respond to the Treasury Gas Transfer Pricing Review (GTP Review). The GTP Review recommended significant changes be made to the PRRT system, including accounting for changing commercial circumstances in the liquified natural gas (LNG) industry, ensuring an appropriate arm’s length price for gas at the taxing point is reflected in all circumstances, and improving transparency and reducing complexity in the way the rules operate. The Regulations implement recommendations 3, 5, 6, 7, 8 and 11 of the GTP Review.

The purpose of the Petroleum Resource Rent Tax Assessment Regulations 2024 (Regulations) is to remake the Petroleum Resource Rent Tax Assessment Regulation 2015 (2015 Regulations), which are due to sunset on 1 April 2026.

The Regulations make various minor changes to update the drafting of the 2015 Regulations, as well as substantive changes that align with the GTP Review, including:

•                 various changes to better accommodate commercial tolling arrangements;

•                 requiring an irrevocable election to be made to use either the shorter or longer asset life formula;

•                 equalising the treatment of the notional upstream and downstream entities between loss and profit situations when using the residual pricing method (RPM);

•                 updating the comparable uncontrolled price (CUP) rules to align with current guidelines from the Organisation of Economic Cooperation and Development (OECD);

•                 modifying the advanced pricing arrangement rules (APA) to provide additional guidance to both industry and the Commissioner of Taxation (Commissioner) on the principles to consider in agreeing to an APA;

•                 ensuring that when a new facility is brought into the PRRT regime for the first time, that the value of the plant for use in the RPM is the historical cost of the facility.

Human rights implications

This Legislative Instrument does not engage any of the applicable rights or freedoms.

Conclusion

This Legislative Instrument is compatible with human rights as it does not engage any human rights issues.