This instrument is the Petroleum Resource Rent Tax Assessment Regulations 2024.

2 Commencement

(1) Each provision of this instrument specified in column 1 of the table commences, or is taken to have commenced, in accordance with column 2 of the table. Any other statement in column 2 has effect according to its terms.

Commencement information
Column 1	Column 2	Column 3
Provisions	Commencement	Date/Details
1. The whole of this instrument	The day after this instrument is registered.	7 August 2024

Note: This table relates only to the provisions of this instrument as originally made. It will not be amended to deal with any later amendments of this instrument.

(2) Any information in column 3 of the table is not part of this instrument. Information may be inserted in this column, or information in it may be edited, in any published version of this instrument.

3 Authority

This instrument is made under the Petroleum Resource Rent Tax Assessment Act 1987.

4 Schedules

Each instrument that is specified in a Schedule to this instrument is amended or repealed as set out in the applicable items in the Schedule concerned, and any other item in a Schedule to this instrument has effect according to its terms.

Division 2—Definitions

5 Definitions

Note: Other definitions are set out in section 2 of the Act, including the following:

(a) excluded commodity;

(b) financial year;

(d) long‑term bond rate;

(e) marketable petroleum commodity;

(f) petroleum;

(g) petroleum project;

(h) sales gas;

(i) year of tax.

In this instrument:

Act means the Petroleum Resource Rent Tax Assessment Act 1987.

actual mass of project natural gas, for a relevant operation and a year of tax in which the operation produces project liquid or project electricity, means the mass of project natural gas that was used to produce project liquid or project electricity.

actual volume of project natural gas, for a relevant operation and a year of tax in which the operation produces project liquid or project electricity, means the volume of project natural gas that was used to produce project liquid or project electricity.

advance pricing arrangement has the meaning given by subsection 26(1).

annual allocation, for a capital cost, has the meaning given by section 47.

arm’s length conditions: see section 21.

assessable gas, for the purposes of working out assessable petroleum receipts relating to sales gas, means project sales gas.

assessment year means the year of tax for which an RPM price is to be worked out by applying the residual pricing method.

augmented, for a capital cost, has the meaning given by section 17.

capital allocation period:

(a) for a unit of property in relation to which an election under section 48 is made—has the meaning given by section 48; or

(b) for any other unit of property—has the meaning given by subsection 47(5).

Note: See also subsection 47(6), which affects the capital allocation period for capital costs incurred before the production date of a relevant operation.

capital allowance, for a financial year, has the meaning given by section 19.

capital cost has the meaning given by subsection 40(1).

commercial tolling fee: see section 20.

commercial tolling phase: see section 10.

comparable uncontrolled price or CUP, in relation to a relevant transaction for a volume or mass of project sales gas, has the meaning given by subsection 27(1).

cost‑plus price has the meaning given by section 30.

direct cost has the meaning given by section 37.

downstream, for a cost, has the meaning given by subsection 42(6).

downstream stage has the meaning given by:

(a) for a relevant GTL operation for the purposes of working out assessable petroleum receipts relating to sales gas—subsection 8(2); and

(b) for a relevant GTE operation for the purposes of working out assessable petroleum receipts relating to sales gas—subsection 8(3).

estimated average annual mass of project natural gas, for a relevant operation, has the meaning given by subsection 14(7).

estimated average annual volume of project natural gas, for a relevant operation, has the meaning given by subsection 14(6).

estimated operating life, of a relevant operation, has the meaning given by subsection 14(8).

included cost has the meaning given by section 39.

indirect cost has the meaning given by subsection 37(5).

mass coefficient, for a relevant operation in a year of tax, has the meaning given by subsection 16(2).

MPC production year has the meaning given by:

(a) for a relevant GTL operation—subsection 6(9); and

(b) for a relevant GTE operation—subsection 7(9).

multiple use, of a unit of property, has the meaning given by section 11.

netback price has the meaning given by section 31.

non‑arm’s length transaction has the meaning given by section 13.

non‑sale entitlement share has the meaning given by section 25.

non‑sale transaction has the meaning given by subsection 24(2).

operating cost has the meaning given by subsection 40(3).

operating life has the meaning given by:

(a) for a relevant GTL operation—subsection 6(8); and

(b) for a relevant GTE operation—subsection 7(8).

participant, in a relevant operation, has the meaning given by section 12.

personal cost has the meaning given by subsection 37(6).

petroleum product, of an operation, means petroleum, or a product of petroleum, that is recovered, produced or processed in the operation.

phase, of a relevant operation, has the meaning given by subsection 9(3), subject to section 10.

phase cost, for a phase of a relevant operation, means the phase cost worked out using subsections 42(2) and (3).

phase point: see sections 9 and 10.

production date has the meaning given by:

(a) for a relevant GTL operation—subsection 6(7); and

(b) for a relevant GTE operation—subsection 7(7).

production year has the meaning given by:

(a) for a relevant GTL operation—subsection 6(6); and

(b) for a relevant GTE operation—subsection 7(6).

project electricity, of a relevant GTE operation, has the meaning given by subsection 7(4).

project liquid, of a relevant GTL operation, has the meaning given by subsection 6(4).

project natural gas has the meaning given by:

(a) for a relevant GTL operation—subsection 6(2); and

(b) for a relevant GTE operation—subsection 7(2).

project product has the meaning given by:

(a) for a relevant GTL operation—subsection 6(5); and

(b) for a relevant GTE operation—subsection 7(5).

project sales gas has the meaning given by:

(a) for a relevant GTL operation—subsection 6(3); and

(b) for a relevant GTE operation—subsection 7(3).

reduced, for a capital cost, has the meaning given by section 18.

relevant GTE operation has the meaning given by subsection 7(1).

relevant GTL operation has the meaning given by subsection 6(1).

relevant operation means a relevant GTE operation or a relevant GTL operation.

relevant sector cost has the meaning given by subsection 37(2).

residual pricing method means the method statement in section 34.

RPM price, for a participant in a relevant operation in a year of tax, has the meaning given by sections 28 and 29.

sale entitlement share has the meaning given by section 23.

source project, in relation to a relevant operation, means the petroleum project from which petroleum is, or will be, recovered in the relevant operation.

start date, for a capital cost incurred in a relevant operation, means 1 January of the financial year in which the cost is incurred.

taxpayer, in relation to a relevant operation, means a person:

(a) who holds an interest in the operation that entitles the person, at the end of at least one phase, to:

(i) petroleum product of the operation, other than petroleum product that is destroyed, used as fuel or otherwise consumed in the operation; or

(ii) electricity produced in the operation; and

(b) whose assessable petroleum receipts in relation to sales gas from the operation are to be worked out under this instrument because of section 22 or 24.

tolling arrangement, in relation to a relevant operation, has the meaning given by section 20.

upstream, for a cost, has the meaning given by subsection 42(5).

upstream stage, for the purposes of working out assessable petroleum receipts relating to sales gas, has the meaning given by subsection 8(1).

volume coefficient, for a relevant operation in a year of tax, has the meaning given by subsection 15(2).

6 When a relevant GTL operation exists

(1) A relevant GTL operation exists if there is an operation (the overall operation) in which:

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

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

(2) The project natural gas of the relevant GTL operation is the petroleum (in the form of natural gas) mentioned in paragraph (1)(a) from which sales gas will be produced and processed into liquefied product within the overall operation (including any of that natural gas that is used in that production and processing).

(3) The project sales gas of the relevant GTL operation is the sales gas mentioned in paragraph (1)(b) that:

(a) will be processed into liquefied product within the overall operation; or

(b) will, after becoming an excluded commodity, be used in the downstream stage of the operation in relation to the processing of sales gas mentioned in paragraph (1)(b) into liquefied product.

(4) The liquefied product mentioned in paragraph (1)(c) is project liquid of the relevant GTL operation.

(5) The project natural gas, project sales gas and project liquid are project product of the relevant GTL operation.

(6) The production year for the relevant GTL operation is:

(a) if an election has been made in relation to the relevant GTL operation under section 54—the 2012‑13 year of tax; and

(b) otherwise—the year of tax in which processing first occurred.

(7) The 31 December of the production year is the production date for the relevant GTL operation.

(8) The period beginning with the production year and ending with the year of tax in which project sales gas is last processed into project liquid is the operating life of the relevant GTL operation.

(9) If the relevant GTL operation produces a marketable petroleum commodity other than project sales gas, the year of tax in which it is first produced is the MPC production year for the relevant GTL operation.

Operations where custody of the project product changes

(10) To avoid doubt, an operation may be a relevant GTL operation even if project product of the operation is not in the custody of participants in the operation for all of the phases of the operation.

7 When a relevant GTE operation exists

(1) A relevant GTE operation exists if there is an operation (the overall operation) in which:

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

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

(2) The project natural gas of the relevant GTE operation is the petroleum (in the form of natural gas) mentioned in paragraph (1)(a) from which sales gas will be produced and consumed in the production of electricity within the overall operation (including any of that natural gas that is used in that production).

(3) The project sales gas of the relevant GTE operation is the sales gas mentioned in paragraph (1)(b) that:

(a) will be consumed in the production of electricity within the overall operation; or

(b) will, after becoming an excluded commodity, be used in the downstream stage of the operation in relation to the production of electricity from sales gas mentioned in paragraph (1)(b).

(4) The electricity mentioned in paragraph (1)(c) is project electricity of the relevant GTE operation.

(5) The project natural gas, project sales gas and project electricity are project product of the relevant GTE operation.

(6) The year of tax in which the project sales gas is first consumed in the production of project electricity is the production year for the relevant GTE operation.

(7) The production date for the relevant GTE operation is 31 December of the production year.

(8) The period beginning with the production year and ending with the year of tax in which project sales gas is last consumed in the production of project electricity is the operating life of the relevant GTE operation.

(9) If the relevant GTE operation produces a marketable petroleum commodity other than project sales gas, the year of tax in which it is first produced is the MPC production year for the relevant GTE operation.

Operations where custody of the project product changes

(10) To avoid doubt, an operation may be a relevant GTE operation even if project product of the operation is not in the custody of participants in the operation for all of the phases of the operation.

8 Upstream and downstream stages of relevant operation

(1) For the purposes of working out assessable petroleum receipts relating to sales gas under section 22 or 24, the upstream stage of a relevant operation is a series of phases ending when all of the following actions have been completed:

(a) the recovery of project natural gas;

(b) any multiple use of units of property that are used in the recovery of project natural gas;

(d) any multiple use of the units of property that are used to store recovered project natural gas;

(e) the production of project sales gas;

(f) any multiple use of units of property that are used in the production of project sales gas;

(g) the transportation of project product for the recovery mentioned in paragraph (a) or the production mentioned in paragraph (e);

(h) any multiple use of units of property for transportation mentioned in paragraph (g);

(i) the storage of project sales gas at or adjacent to the place at which it is produced, if the storage occurs:

(i) before the sale referred to in paragraph 24(1)(d) of the Act; or

(ii) before the gas becomes or became an excluded commodity as described in paragraph 24(1)(e) of the Act;

(as the case requires);

(j) any multiple use of units of property that are used for the storage of project sales gas mentioned in paragraph (i).

(2) For the purposes of working out assessable petroleum receipts relating to sales gas under section 22 or 24, the downstream stage of a relevant GTL operation is a series of phases beginning when the upstream stage ends and ending when all of the following actions have been completed:

(a) the storage of project sales gas at or adjacent to the place at which it is produced, if the storage occurs:

(i) after the sale referred to in paragraph 24(1)(d) of the Act; or

(ii) after the gas becomes or became an excluded commodity as described in paragraph 24(1)(e) of the Act;

(as the case requires);

(b) the transportation (if any) of project sales gas from the upstream stage for processing into project liquid;

(d) any multiple use of units of property that are used in the processing of the project sales gas into project liquid;

(e) the transportation of project product for the processing of project sales gas mentioned in paragraph (c);

(f) any activity associated with an action mentioned in paragraphs (b) to (e) for the purpose of using project sales gas to produce project liquid;

(g) any multiple use of units of property for the transportation mentioned in paragraph (e);

(h) the sale of project liquid without further processing;

(i) the storage of project liquid at or adjacent to the place at which it is produced by the processing mentioned in paragraph (c);

(j) the loading of project liquid at a loading facility:

(i) adjacent to the place at which it is produced by the processing mentioned in paragraph (c); or

(ii) adjacent to the place at which it is stored as mentioned in paragraph (i);

(k) the transportation of project liquid between any or all of:

(i) the place at which it is produced by the processing mentioned in paragraph (c); and

(ii) the place at which it is stored as mentioned in paragraph (i); and

(iii) the place at which it is loaded as mentioned in paragraph (j);

(l) any multiple use of units of property for the storage, loading or transportation mentioned in paragraphs (i), (j) and (k).

(3) For the purposes of working out assessable petroleum receipts relating to sales gas under section 22 or 24, the downstream stage of a relevant GTE operation is a series of phases beginning when the upstream stage ends and ending when all of the following actions have been completed:

(a) the storage of project sales gas at or adjacent to the place at which it is produced, if the storage occurs:

(i) after the sale referred to in paragraph 24(1)(d) of the Act; or

(ii) after the gas becomes or became an excluded commodity as described in paragraph 24(1)(e) of the Act;

(as the case requires);

(b) the transportation (if any) of the project sales gas from the upstream stage for combustion to produce project electricity;

(d) any multiple use of units of property that are used in the combustion of the project sales gas to produce project electricity;

(e) any activity associated with an action mentioned in paragraphs (b) to (d) for the purposes of using project sales gas to produce project electricity;

(f) the sale of project electricity.

Note 1: Phases are explained in subsections 9(1) and (3).

Note 2: In general terms, a phase is a part of an operation during which the ratio of project product to total product flowing through the operation remains the same (and is expected to remain the same). The upstream and downstream stages of a relevant operation may include a number of phases, but each stage ends when the actions associated with the last phase have been completed.

9 Phase points of relevant operation

(1) Subject to section 10, the phase points of a relevant operation are:

(a) the point where the upstream stage ends and the downstream stage begins; and

(b) any point in the flow of project product through the operation at which there is expected to be a difference in the ratio of project product to total product flowing through the operation before and after the point; and

(i) there is a change in the person or persons who have custody of the project product; and

(ii) at least one of the persons who starts or stops having custody of the project product is a participant in the relevant operation who has or had custody of the petroleum product in the person’s capacity as a participant in that operation; and

(iii) the change occurs for the purpose of carrying out one or more of the actions mentioned in section 8 (including for the purpose of returning petroleum product to participants in the operation after one or more such actions are carried out).

Note 1: This section divides the relevant operation into phases in such a way that petroleum product is not brought into or taken out of the operation except at the beginning or end of a phase. In obtaining the cost‑plus and netback prices:

(a) the various joint costs incurred by participants in the operation are attributed to each phase (see section 42); and

(b) the capital costs are annualised (see Division 3 of Part 4); and

(c) the costs for the assessment year are apportioned between the project product and other product, using an energy coefficient appropriate for the phase (see section 49).

Note 2: If a new phase point emerges that was not identified before the production year, there may need to be a recalculation of the annualised capital costs.

Example 1: A relevant GTL operation begins with the recovery of natural gas and liquid petroleum, using the same extraction facilities. Separate pipelines are used to carry off the natural gas and the liquid petroleum, so that only the gas pipeline is part of the operation. The total product flowing through the operation is reduced, as the liquid petroleum is removed. The ratio of project product in relation to total product therefore changes at the beginning of the gas pipeline, and the beginning of the pipeline is therefore a phase point.

Example 2: At the sales gas production facility of a relevant GTL operation, natural gas from another source is added to the project natural gas. The point at which the natural gas is added is a phase point.

Example 3: Some of the sales gas produced in a relevant GTL operation is transported in a pipeline that is part of the operation, and therefore enters the downstream stage; it is then sold before liquefaction. The ratio of project product to total product changes when the sales gas is sold before liquefaction, as the total product flowing through the operation is reduced. The point of sale is therefore a phase point.

Example 4: A relevant GTL operation involves the recovery of natural gas that is processed into sales gas and then liquefied product. Additionally, under a tolling arrangement, natural gas (the shipper’s natural gas) from another operation enters the relevant GTL operation where it is processed into sales gas and then liquefied product (the shipper’s liquefied product). The shipper’s liquefied product then leaves the relevant GTL operation. There is a phase point when the shipper’s natural gas enters the relevant GTL operation, as the ratio of project product to total product flowing through the relevant GTL operation decreases at that time. There is another phase point when the shipper’s liquefied product leaves the relevant GTL operation, as the ratio of project product to total product flowing through the relevant GTL operation increases at that time.

(2) However, paragraphs (1)(b) and (c) do not apply to a relevant GTL operation for which an election has been made under section 54.

(3) The relevant operation is divided into phases by the phase points.

Note: In general terms, a phase is a stage of an operation during which the ratio of project product to total product flowing through the operation remains the same (and is expected to remain the same).

(4) The participants in the relevant operation must:

(a) in the financial year before the production year, notify the Commissioner of any phase points of the operation that are apparent to any of the participants at that time; and

(b) notify the Commissioner as soon as practicable of any phase point that becomes apparent at a later time.

(5) However, subsection (4) does not apply to a relevant GTL operation for which an election has been made under section 54.

(6) The participants in the relevant operation must satisfy the Commissioner that they can provide accurate records of the quantities of petroleum product before and after each phase point (for example, by including metering facilities at the phase point or using other reliable estimation techniques).

10 Commercial tolling phases

(1) This section applies to a relevant operation if:

(a) the relevant operation has a phase point (the start point) mentioned in paragraph 9(1)(c) that is not for the purpose of returning project product to participants in the relevant operation; and

(b) the relevant operation also has a phase point (the end point) mentioned in paragraph 9(1)(c) for the purpose of returning project product to participants in the relevant operation; and

(d) a commercial tolling fee is paid in consideration of that action or all of those actions (as the case requires); and

(e) no election under section 54 has been made for the relevant operation.

Phases that occur between the start point and the end point

(2) No phase points of the relevant operation, other than a phase point mentioned in paragraph 9(1)(a), are taken to occur between the start point and the end point.

Note 1: Paragraph 9(1)(a) provides for a phase point at the point where the upstream stage ends and the downstream stage begins.

Note 2: This subsection affects only the phase points of the relevant operation, and does not affect the phase points of any other operation whose facilities are used in carrying out the actions mentioned in paragraph (1)(c) of this subsection.

Note 3: This subsection affects phase points that would otherwise occur at any point in the flow of project product between the start point and the end point. If other petroleum product (which may also be project product) 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), this subsection does not affect any phase points that occur in relation to the flow of that petroleum product.

Example: A relevant GTL operation (the shipper operation) involves the recovery of natural gas that is processed into sales gas and then liquefied product. The shipper operation does not have sufficient capacity to process all of its natural gas into liquefied product. Under a tolling arrangement, the shipper operation transports some of its natural gas (the tolled gas) to another person (the host) for processing into liquefied product (the tolled product), and a commercial tolling fee is paid to the host. There is a phase point, the start point, where custody of tolled gas changes from the shipper operation to the host. There is another phase point, the end point, where custody of the tolled product changes from the host to the shipper operation. No phase points, other than a phase point (if any) mentioned in paragraph 9(1)(a), are taken to occur between the start point and the end point. However, this does not affect any phase points that may occur between the start point and the end point in relation to other petroleum product flowing through the shipper operation, such as the natural gas that is processed by the shipper operation rather than being transported to the host.

(3) If, after applying subsection (2), there are no phase points between the start point and the end point, then:

(a) there is a single phase between the start point and the end point; and

(b) that phase is a commercial tolling phase.

(4) If, after applying subsection (2), there is a phase point mentioned in paragraph 9(1)(a) (the stream change point) between the start point and the end point, then:

(a) there is a single phase between the start point and the stream change point; and

(b) there is a single phase between the stream change point and the end point; and

11 When there is multiple use of a phase

(1) A reference to multiple use of a phase relating to the recovery of project natural gas is a reference to the use of the unit of property, at any time during the operating life of the relevant operation, in operations to recover petroleum other than project natural gas from the petroleum project.

Example 1: An oil platform is used to recover both natural gas and liquid petroleum.

Example 2: An oil platform is used to recover petroleum from a petroleum project outside the operation.

(2) A reference to the multiple use of a phase relating to the production of project sales gas is a reference to the use of the unit of property, at any time during the operating life of the relevant operation, to produce marketable petroleum commodities other than project sales gas from petroleum (whether or not the petroleum was recovered from the petroleum project of the operation).

Example 1: Plant is used to produce sales gas, some of which is to be sold for direct consumption as energy.

Example 2: Plant is used to produce sales gas from natural gas recovered outside the operation.

(3) A reference to the multiple use of a phase relating to the processing of project sales gas into project liquid is a reference to the use of the unit of property, at any time during the operating life of the relevant GTL operation, to process marketable petroleum commodities other than project sales gas into liquefied product (whether or not the other marketable petroleum commodities were produced in the operation).

Example: Plant used to liquefy project sales gas is also used to liquefy sales gas produced outside the operation.

(4) A reference to the multiple use of a phase relating to the combustion of project sales gas to produce electricity is a reference to the use of the unit of property, at any time during the operating life of the relevant GTE operation, to combust petroleum products other than project sales gas to produce electricity (whether or not the other petroleum products were produced in the operation).

Example: Plant used to combust project sales gas is also used to combust sales gas produced outside the operation.

(5) A reference to the multiple use of a phase relating to the transportation of project product is a reference to the use of the unit of property, at any time during the operating life of the relevant operation, to transport petroleum product other than project product within the operation (whether or not the petroleum product was recovered or produced in the operation).

Example: A pipeline from an offshore petroleum recovery platform that carries natural gas to shore, only some of which is project natural gas.

(6) A reference to the multiple use of a storage facility is a reference to the use of the storage facility, at any time during the operating life of the relevant operation, to store petroleum product other than project product within the operation (whether or not the petroleum product was recovered or produced in the operation).

Example: The use of a storage facility both:

(a) to store project liquid; and

(b) to store petroleum that is not project liquid.

(7) A reference to the multiple use of a loading facility is a reference to the use of the loading facility, at any time during the operating life of the relevant GTL operation, to load petroleum product other than project product within the operation (whether or not the petroleum product was recovered or produced in the operation).

Example: The use of a loading facility to load petroleum product of another operation.

12 Participants in a relevant operation

A person is a participant in a relevant operation if the person holds an interest in the operation that entitles the person to petroleum product or electricity of the operation at the end of at least one phase.

13 Non‑arm’s length transaction

A transaction is a non‑arm’s length transaction if the Commissioner, having regard to any connection between the parties to the transaction or to any other relevant circumstances, is satisfied that the parties to the transaction are not dealing with each other at arm’s length in relation to the transaction.

14 Estimated average annual volume or mass of project natural gas

(1) The participants in a relevant operation must give to the Commissioner estimates of:

(a) the operating life of the operation, in years; and

(b) either:

(i) if the participants will measure by volume—the total volume of project natural gas to be recovered during the life of the operation; or

(ii) if the participants will measure by mass—the total mass of project natural gas to be recovered during the life of the operation.

(2) The estimates must be given to the Commissioner in the financial year before the production year.

(3) As soon as practicable after receiving an estimate (including a revised estimate under subsection (4)) from the participants, the Commissioner must notify the participants in writing that the Commissioner:

(a) accepts the estimate or revised estimate; or

(b) has substituted an estimate under subsection (5).

(4) If, from new information, it appears that an estimate notified by the Commissioner is inaccurate, the participants must give to the Commissioner a revised estimate.

(5) If, having regard to relevant information, the Commissioner is not satisfied that an estimate given by the participants for the purposes of subsection (1) or (4) is reasonable, the Commissioner may substitute an estimate that the Commissioner is satisfied is reasonable.

(6) For an operation in which natural gas will be measured by volume, the estimated average annual volume of project natural gas is (using the estimates notified by the Commissioner):

$Start formula start fraction Estimated total volume of project natural gas over Estimated operating life end fraction end formula$

(7) For an operation in which natural gas will be measured by mass, the estimated average annual mass of project natural gas is (using the estimates notified by the Commissioner):

$Start formula start fraction Estimated total mass of project natural gas over Estimated operating life end fraction end formula$

(8) The estimated operating life of the relevant operation is the period of years estimated as the operating life, as notified by the Commissioner, beginning with the production year.

15 Meaning of volume coefficient

(1) In this section, for a relevant operation in which natural gas is measured by volume:

base year means:

(a) if an election has been made in relation to the operation under section 54—the 2012‑13 year of tax; or

(b) otherwise—the year of tax in which the actual volume of project natural gas first exceeds the estimated average annual volume of project natural gas for the operation.

Note: If the estimated average annual volume of project natural gas changes from one year of tax to another, the base year for the calculation of the volume coefficient may also change.

(2) The volume coefficient for a relevant operation in which natural gas is measured by volume in a year of tax (the current year) is:

$Start formula start fraction V subscript A over V subscript B end fraction end formula$

where:

VA means the actual volume of project natural gas for the current year.

VB means:

(a) if the current year is before the base year—the estimated average annual volume of project natural gas; or

(b) if the current year is the base year—VA; or

where:

n means a year of tax, with the base year being year 1, the year after the base year being year 2, and so on.

N means the number of years of tax from the base year to the current year (inclusive).

Vn means the actual volume of project natural gas for year n.

16 Meaning of mass coefficient

(1) In this section, for a relevant operation in which natural gas is measured by mass:

base year means:

(a) if an election has been made in relation to the operation under section 54—the 2012‑13 year of tax; or

(b) otherwise—the year of tax in which the actual mass of project natural gas first exceeds the estimated average annual mass of project natural gas for the operation.

Note: If the estimated average annual mass of project natural gas changes from one year of tax to another, the base year for the calculation of the mass coefficient may also change.

(2) The mass coefficient for a relevant operation in which natural gas is measured by mass in a year of tax (the current year) is:

$Start formula start fraction M subscript A over M subscript B end fraction end formula$

where:

MA means the actual mass of project natural gas for the current year.

MB means:

(a) if the current year is before the base year—the estimated average annual mass of project natural gas; or

(b) if the current year is the base year—MA; or

where:

Mn means the actual mass of project natural gas for year n.

n means a year of tax, with the base year being year 1, the year after the base year being year 2, and so on.

N means the number of years of tax from the base year to the current year (inclusive).

17 Augmentation of a capital cost

A capital cost for a relevant operation is augmented for a number of years by applying the formula:

where:

capital allowance means the capital allowance for:

(a) in the case of subsection 43(2)—the final cost year; and

(b) in the case of subsection 44(2)—the production year; and

(d) in the case of paragraph 45(3)(a)—the MPC production year.

N means the number of years.

Note: The number of years is worked out in accordance with the provision that provides for the capital cost to be augmented. For example, in the case of augmentation under subsection 43(2), that subsection provides for the number of years for which the capital cost is to be augmented.

18 Reduction of a capital cost

A capital cost for a relevant operation is reduced for a number of years by applying the formula:

where:

capital allowance means the capital allowance for:

(a) in the case of paragraph 45(3)(b)—the MPC production year; and

(b) in the case of subsection 45(4)—the year of tax of the start date for the capital cost.

N means the number of years.

Note: The number of years is worked out in accordance with the provision that provides for the capital cost to be reduced. For example, in the case of reduction under subsection 45(4), that subsection provides for the number of years for which the capital cost is to be reduced.

19 Capital allowance

The capital allowance, for a financial year, is worked out using the formula:

20 Tolling arrangements and commercial tolling fees

(1) In this instrument, a tolling arrangement, in relation to a relevant operation (the shipper operation), is an arrangement for one or more actions mentioned in section 8 in relation to project product of the shipper operation (the tolled actions) to be carried out by one or more persons (the host parties), where:

(a) the parties to the arrangement are:

(i) one or more of the participants in the shipper operation (the shipper parties); and

(ii) the host parties (one or more of whom may also be a shipper party, subject to paragraph (b)); and

(b) either of both the following apply:

(i) at least one shipper party is not also a host party;

(ii) at least one host party is not also a shipper party; and

(d) under the arrangement, custody of the project product changes between:

(i) the shipper parties; and

(ii) the host parties;

at least once.

Note: Some of the shipper parties and host parties may be the same people (although not all, because of paragraph (b)). If they are, the requirements in paragraphs (c) and (d) may be met by payments, or changes in custody, between the shipper parties as a group and the host parties as a group.

(2) The amount or amounts mentioned in paragraph (1)(c) are a commercial tolling fee if the amount or amounts might be expected to have been arrived at in arm’s length conditions.

(3) If the Commissioner is satisfied that:

(a) there is a tolling arrangement in relation to a shipper operation; and

(b) under the arrangement, an amount or amounts are paid in consideration of the carrying out of the tolled actions in relation to the project product of the shipper operation; and

(d) an amount worked out by the Commissioner 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 project product of the shipper operation;

then:

(e) the amount worked out as mentioned in paragraph (d) is taken, for the purposes of working out an RPM price of a participant in the shipper operation under this instrument:

(i) to be a commercial tolling fee; and

(ii) to have been paid in consideration of the carrying out of the tolled actions; and

(iii) to have been paid, in whole or part, at a time or times determined by the Commissioner; and

(iv) to have been paid, in whole or part, by a person or persons determined by the Commissioner; and

(f) any amount paid in consideration of the carrying out of the tolled actions (disregarding paragraph (e)) is taken, for the purposes of working out an RPM price of a participant in the shipper operation under this instrument, not to be a cost associated with the shipper operation.

Note: If an amount or amounts are paid under a tolling arrangement, and the amount or amounts are not a commercial tolling fee under subsection (2) or this subsection, it may not be possible to use the RPM (see subsection 33(2)).

(4) In making a determination under subparagraph (3)(e)(iii) or (iv), the Commissioner must have regard to both 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.

21 Arm’s length conditions

(1) The arm’s length conditions, in relation to the 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.

Most appropriate and reliable method to be used

(2) In identifying the arm’s length conditions, use the method, or the combination of methods, that is the most appropriate and reliable, having regard to all relevant factors, including the following:

(a) the respective strengths and weaknesses of the possible methods in their application to the actual conditions;

(b) the circumstances, including the functions performed, assets used and risks borne by the entities;

(d) the degree of comparability between the actual circumstances and the comparable circumstances, including the reliability of any adjustments to eliminate the effect of material differences between those circumstances.

Comparability of circumstances

(3) In identifying comparable circumstances for the purpose of this section, have regard to all relevant factors, including the following:

(a) the functions performed, assets used and risks borne by the entities;

(b) the characteristics of any property or services transferred;

(d) the economic circumstances;

(e) the business strategies of the entities.

(4) For the purposes of this section, circumstances are comparable to actual circumstances if, to the extent (if any) that the circumstances differ from the actual circumstances:

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

(b) a reasonably accurate adjustment can be made to eliminate the effect of the difference on a condition that is relevant to the method.

Form and substance

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

Guidance

(6) Identify arm’s length conditions so as to best achieve consistency with the Transfer Pricing Guidelines for Multinational Enterprises and Tax Administrations, as approved by the Council of the Organisation for Economic Cooperation and Development and last amended on 7 January 2022.

Note: The Transfer Pricing Guidelines for Multinational Enterprises and Tax Administrations could in 2024 be viewed on the Organisation for Economic Co‑operation and Development’s website (https://oecd.org/).

Part 2—Assessable petroleum receipts

22 Assessable petroleum receipts—sales gas of relevant operation with non‑arm’s length sale

(1) For the purposes of subparagraph 24(1)(d)(iii) of the Act, this section applies to sales gas that has been sold if:

(a) it is project sales gas of a relevant operation; and

(b) the sale is a non‑arm’s length transaction.

Note: Paragraph 24(1)(b) of the Act applies to other sales of sales gas.

Advance pricing arrangement

(2) If an advance pricing arrangement applies to a taxpayer in relation to the sale, the amount of assessable petroleum receipts of the taxpayer is the amount worked out in accordance with the arrangement.

Comparable uncontrolled price

(3) The assessable petroleum receipts of a taxpayer in relation to the sale is the amount worked out under subsection (4) if:

(a) no advance pricing arrangement applies to the taxpayer in relation to the sale; and

(b) a comparable uncontrolled price exists for the sale; and

(4) The amount is the higher of:

(a) the consideration received or receivable, less any expenses payable, by the taxpayer in relation to the sale; and

(b) the comparable uncontrolled price multiplied by the taxpayer’s sale entitlement share for the sale.

Residual pricing method

(5) The assessable petroleum receipts of a taxpayer in relation to the sale is the amount worked out under subsection (6) if:

(a) no advance pricing arrangement applies to the taxpayer in relation to the sale; and

(b) either:

(i) no comparable uncontrolled price exists for the sale; or

(ii) an election has been made in relation to the relevant operation under section 54.

(6) The amount is the higher of:

(a) the consideration received or receivable, less any expenses payable, by the taxpayer in relation to the sale; and

(b) the RPM price, of project sales gas, for the taxpayer in the year of tax in which the sale took place multiplied by the taxpayer’s sale entitlement share for the sale.

23 Sale entitlement share

(1) For the purposes of subsections 22(4) and (6), a taxpayer’s sale entitlement share in relation to a sale of project sales gas of a relevant operation is to be worked out by applying the formula:

where:

entitlement proportion means the proportion of the receipts from the sale that the taxpayer is entitled to receive.

quantity of project sales gas means the volume or mass of project sales gas sold.

(2) For the purposes of subsection (1), a taxpayer’s entitlement proportion is to be worked out to 3 decimal places, rounding up if the fourth decimal place is 5 or more.

(3) The Commissioner may make fair and reasonable adjustments to a taxpayer’s sale entitlement share for the purpose of ensuring that the total of all sale entitlement shares of all participants in the relevant operation in relation to the sale is equal to the volume or mass of project sales gas sold.

24 Assessable petroleum receipts—sales gas of relevant operation becoming excluded commodity other than by being sold

(1) For the purposes of paragraph 24(1)(e) of the Act, this section applies to sales gas that:

(a) is project sales gas of a relevant operation; and

(b) becomes or became an excluded commodity (otherwise than as mentioned in subparagraph 24(1)(e)(i) or (ii) of the Act).

Note: Paragraph 24(1)(c) of the Act applies to other sales gas that becomes an excluded commodity.

(2) In this instrument:

non‑sale transaction means the act by which project sales gas to which this section applies becomes or became an excluded commodity.

Advance pricing arrangement

(3) If an advance pricing arrangement applies to a taxpayer in relation to the non‑sale transaction, the amount of assessable petroleum receipts of the taxpayer is the amount worked out in accordance with the arrangement.

Comparable uncontrolled price

(4) The assessable petroleum receipts of a taxpayer in relation to the non‑sale transaction is the amount worked out under subsection (5) if:

(a) no advance pricing arrangement applies to the taxpayer in relation to the transaction; and

(b) a comparable uncontrolled price exists for the transaction; and

(5) The amount is the comparable uncontrolled price multiplied by the taxpayer’s non‑sale entitlement share for the non‑sale transaction.

Residual pricing method

(6) The assessable petroleum receipts of a taxpayer in relation to the non‑sale transaction is the amount worked out under subsection (7) if:

(a) no advance pricing arrangement applies to the taxpayer in relation to the transaction; and

(b) either:

(i) no comparable uncontrolled price exists for the transaction; or

(ii) an election has been made in relation to the relevant operation under section 54.

(7) The amount is the RPM price, of project sales gas, for the taxpayer in the year of tax in which the non‑sale transaction took place multiplied by the taxpayer’s non‑sale entitlement share for the transaction.

25 Non‑sale entitlement share

(1) For the purposes of subsections 24(5) and (7), a taxpayer’s non‑sale entitlement share in relation to a non‑sale transaction is to be worked out by applying the formula:

where:

notional entitlement proportion means the proportion of the receipts from a sale of the project sales gas subject to the non‑sale transaction that the taxpayer would be entitled to receive if the project sales gas were sold.

quantity of project sales gas means the volume or mass of project sales gas subject to the non‑sale transaction.

(2) For the purposes of subsection (1), a taxpayer’s notional entitlement proportion is to be worked out to 3 decimal places, rounding up if the fourth decimal place is 5 or more.

(3) The Commissioner may make fair and reasonable adjustments to a taxpayer’s non‑sale entitlement share for the purpose of ensuring that the total of all non‑sale entitlement shares of all participants in the relevant operation in relation to the non‑sales transaction is equal to the volume or mass of project sales gas subject to the transaction.

26 Advance pricing arrangements

(1) The Commissioner may, at the request of a participant in a relevant operation, make an agreement (an advance pricing arrangement) with the participant about how the assessable petroleum receipts of the participant are to be worked out in relation to project sales gas to which paragraph 24(1)(d) or (e) of the Act applies.

(2) An advance pricing arrangement must specify:

(a) the term of the arrangement; and

(b) how the assessable petroleum receipts mentioned in subsection (1) are to be worked out; and

(3) In considering whether to make an advance pricing arrangement, the Commissioner:

(a) must have regard to whether it is impracticable to work out a comparable uncontrolled price under section 27 for the project sales gas; and

(b) must have regard to whether it is impracticable to use one or more steps of the residual pricing method in relation to the project sales gas for the participant; and

(i) will provide a reasonably accurate estimate of the results that the residual pricing method is likely to produce, or would be likely to produce if it were practicable to use the residual pricing method; and

(ii) is consistent with the calculation set out in section 28; and

(iii) provides for a capital allowance to be applied to capital costs, or for capital costs to be indexed, in a way that is consistent with sections 17, 18, 19 and 46; and

(iv) is otherwise consistent with the residual pricing method; and

(d) may have regard to any other matter the Commissioner considers relevant.

Part 3—The substitute prices

27 The comparable uncontrolled price

(1) A comparable uncontrolled price, or CUP, in relation to a relevant transaction for a volume or mass of project sales gas, is a price for sales gas under a transaction (the other transaction) where:

(a) the Commissioner is satisfied that the parties to the other transaction dealt with each other at arm’s length in relation to the other transaction; and

(b) the Commissioner is satisfied that the other transaction is comparable to the relevant transaction; and

(d) if subsection (4) applies (subject to subsection (5))—the price has been adjusted under subsection (4).

Relevant transaction

(2) For the purposes of this section, a relevant transaction, for a volume or mass of project sales gas, is:

(a) a sale of the gas to which paragraph 24(1)(d) of the Act applies; or

(b) an act by which the gas becomes an excluded commodity to which paragraph 24(1)(e) of the Act applies.

Comparable transactions

(3) In determining, for the purposes of paragraph (1)(b), whether the other transaction is comparable to the relevant transaction, the Commissioner must have regard to all relevant factors, including the following:

(a) the functions performed, assets used and risks borne by:

(i) the entities involved in the relevant transaction; and

(ii) the entities involved in the other transaction;

(b) the characteristics of any property or services transferred;

(i) between the parties to the relevant transaction; and

(ii) between the parties to the other transaction;

(d) the economic circumstances;

(e) the business strategies of:

(i) the entities involved in the relevant transaction; and

(ii) the entities involved in the other transaction.

(4) If the Commissioner is satisfied:

(a) that, to the extent (if any) that the other transaction differs from the relevant transaction, a reasonably accurate adjustment can be made to the price obtained for the other transaction in order to eliminate the effect of the difference; and

(b) that it is necessary to make the adjustment in order to identify a comparable uncontrolled price in relation to the relevant transaction;

the Commissioner may:

(d) treat the other transaction, as adjusted, as comparable to the relevant transaction for the purposes of this section.

(5) However, the Commissioner need not, and must not, make an adjustment under subsection (4) to account for a difference between the relevant transaction and the other transaction that arose only because:

(a) the parties to the other transaction dealt with each other at arm’s length in relation to the other transaction; but

(b) the parties to the relevant transaction did not deal with each other at arm’s length in relation to the relevant transaction.

(6) The Commissioner may be satisfied that the other transaction is comparable to the relevant transaction even if:

(a) the parties to the other transaction dealt with each other at arm’s length in relation to the other transaction; but

(b) the parties to the relevant transaction did not deal with each other at arm’s length in relation to the relevant transaction.

Relevant markets

(7) In determining, for the purposes of paragraph (1)(c), whether a market is a relevant market, the Commissioner must have regard to the following:

(a) the demand and supply characteristics of the market, including:

(i) the composition of sales gas sold in the market; and

(ii) geographic differences between the production facilities and the product delivery point of the sales gas sold in the market; and

(iii) the end use for the sales gas sold in the market;

(b) the terms of contracts usual in the market, including volumes, discounts, exchange exposures and other relevant conditions that would reasonably be considered to affect the price;

(d) the existence of spot sales (including market penetration sales) below or above marginal cost;

(e) processing costs;

(f) technology used in processing;

(g) any other factors that it would be reasonable to consider.

28 RPM price (transfer price using the residual pricing method)

Subject to this Part, if the cost‑plus price and the netback price of an assessable gas for a taxpayer in a year of tax can be obtained by applying the residual pricing method, the RPM price for the assessable gas for the taxpayer in the year of tax is the price given by the formula:

$Start formula start fraction Netback price plus Cost plus price over 2 end fraction end formula$

Note: The residual pricing method can be applied only if certain information is available (see subsection 33(1)), and cannot be applied if there is a tolling arrangement with a non‑commercial tolling fee (see subsection 33(2)).

29 RPM price where information is not available or where non‑commercial tolling fee is paid

(1) This section applies if:

(a) a taxpayer does not have sufficient information to work out the taxpayer’s RPM price for an assessable gas for a year of tax by applying the residual pricing method (see subsection 33(1)); or

(b) the taxpayer’s RPM price for an assessable gas for a year of tax cannot be worked out because of subsection 33(2) (non‑commercial tolling fees).

(2) If the taxpayer and the Commissioner are able to agree on a price for the purposes of this subsection, that price is the RPM price.

(3) If the Commissioner and the taxpayer cannot agree on a price, and the Commissioner is satisfied that a price worked out:

(a) by the Commissioner applying the residual pricing method (disregarding section 33); and

(b) using the information available from other participants in the relevant operation;

is a fair and reasonable price, that price is the RPM price.

(4) If the Commissioner and the participant cannot agree on a price, but the Commissioner is not satisfied as to a price under subsection (3), the RPM price is the price determined by the Commissioner as fair and reasonable.

Example 1: If a participant incurs direct costs in the participant’s own right in relation to the relevant operation, and there is no agreement between the participants as to how those costs are to be shared amongst them, information about those direct costs may not be available to the other participants to allow them to work out the RPM price.

Example 2: This section would apply if a person becomes a participant in the relevant operation, but does not have access to all the information required to work out the RPM price.

Example 3: This section would apply if a participant in a relevant operation, using the residual pricing method, has practical or commercial difficulties in accessing the information needed to apply that method because other participants in the operation are using one of the other methods prescribed by this instrument.

30 Cost‑plus price

The cost‑plus price of an assessable gas for a taxpayer who is a participant in a relevant operation in a year of tax is:

$Start formula start fraction open bracket Upstream capital costs times Quantity coefficient close bracket plus Upstream operating costs over Quantity of assessable gas end fraction end formula$

where:

quantity coefficient means:

(a) for a relevant operation that measures by volume—the volume coefficient for the year of tax; or

(b) for a relevant operation that measures by mass—the mass coefficient for the year of tax.

quantity of assessable gas means the quantity, measured by volume or mass, of the assessable gas that was produced in the operation in the year of tax.

upstream capital costs means the total amount of upstream capital costs incurred by the participants and allocated to the year of tax (see section 34).

upstream operating costs means the total amount of upstream operating costs incurred by the participants in the year of tax (see section 34).

31 Netback price

(1) The netback price of an assessable gas for a taxpayer who is a participant in a relevant operation in a year of tax is:

A formula for working out the netback price of an assessable gas for a taxpayer

where:

DCC (short for downstream capital costs) means the total amount of downstream capital costs incurred by the participants and allocated to the year of tax (see section 34).

DOC (short for downstream operating costs) means the total amount of downstream operating costs incurred by the participants in the year of tax (see section 34).

DPC (short for downstream personal costs) means the total amount of downstream personal costs of the taxpayer for the year of tax.

EPVal (short for end product value) means:

(a) if an election under section 55 has been made for the operation—the amount worked out under subsection (2) of this section; or

(b) otherwise—the total market value in the year of tax of:

(i) for a relevant GTL operation—the project liquid produced; or

(ii) for a relevant GTE operation—the project electricity produced.

QC (short for quantity coefficient) means:

(a) for a relevant operation that measures by volume—the volume coefficient for the year of tax; or

(b) for a relevant operation that measures by mass—the mass coefficient for the year of tax.

QTDG (short for quantity of taxpayer’s downstream gas) means the quantity, measured by volume or mass, of the assessable gas that was produced in the operation in the year of tax and:

(a) for a relevant GTL operation—processed into project liquid that the taxpayer was entitled to receive (including any of that gas that was used in that processing); or

(b) for a relevant GTE operation—consumed in the production of project electricity that the taxpayer was entitled to receive.

quantity of assessable gas means the quantity, measured by volume or mass, of the assessable gas that was produced in the operation in the year of tax.

(2) For the purposes of paragraph (a) of the definition of EPVal in subsection (1), work out the following for the taxpayer for the year of tax:

$Start formula start fraction Market value of taxpayer product over Quantity of taxpayer product end fraction times Quantity of total product end fraction end formula$

where:

market value of taxpayer product means the market value of the quantity of taxpayer product.

quantity of taxpayer product means:

(a) for a relevant GTL operation—the quantity, measured by volume or mass, of project liquid; or

(b) for a relevant GTE operation—the quantity of project electricity;

that the taxpayer was entitled to receive in the year of tax.

quantity of total product means:

(a) for a relevant GTL operation—the total quantity, measured by volume or mass, of project liquid; or

(b) for a relevant GTE operation—the total quantity of project electricity;

produced in the operation in the year of tax.

(3) If the taxpayer sells a quantity of project liquid or project electricity from the operation as part of the operation in the year of tax, and the sale is an arm’s length transaction, the market value of the quantity is taken to be the amount received for the sale.

(4) For a quantity of project liquid or project electricity to which subsection (3) does not apply, the market value of the quantity is the market value at the end of the downstream stage.

(5) If the Commissioner is not satisfied that sufficient information is available to determine a market value for the purposes of subsection (4), the market value of the quantity of project liquid or project electricity is the amount determined by the Commissioner as fair and reasonable.

(6) If the value of QTDG is zero, the value of DPC divided by QTDG is taken to be zero.

Part 4—The residual pricing method

Division 1—The residual pricing method

32 Costs are net of GST tax credits and adjustments

A reference in this Part to a cost incurred by a person is a reference to the cost as decreased by:

(a) an input tax credit to which the person is, or becomes, entitled; or

(b) a decreasing adjustment.

33 When the residual pricing method can be applied

(1) A cost‑plus price and netback price (and the related RPM price) can be worked out by applying the residual pricing method only if information is available about the direct costs (other than marketing and selling costs) associated with the relevant operation that were incurred:

(a) by all participants in the operation; and

(b) for the relevant year of tax and previous financial years.

Note 1: If the information is not available, then section 29 will apply.

Note 2: The residual pricing method identifies:

(a) the pooled costs of the operation attributable to the project product; and

(b) the personal costs of the taxpayer attributable to the taxpayer’s share of project product.

Note 3: These pooled costs are used to work out the major element of the cost‑plus and netback prices, and will be the same for each taxpayer participating in the operation. In contrast, the personal costs are used only to work out a minor element of the netback price, and will vary for each taxpayer.

Note 4: These pooled costs and personal costs are used to work out the taxpayer’s cost‑plus price and netback price, which are then used to work out the RPM price under section 28.

Note 5: If the participants in the operation pay a commercial tolling fee in consideration of the carrying out of one or more actions mentioned in section 8, a cost‑plus price and netback price (and the related RPM price) may be able to be worked out even if information is not available about the costs incurred in carrying out the action or actions (see subsection 35(5), which provides that certain costs are not to be treated as costs associated with the relevant operation).

(2) Despite anything else in this Part, a cost‑plus price and netback price (and the related RPM price) cannot be worked out for a taxpayer who is a participant in a relevant operation in an assessment year if:

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

(b) an amount or amounts are paid under the tolling arrangement in consideration of the carrying out of one or more actions mentioned in section 8 in relation to project product of the relevant operation; and

Note 1: If an RPM price cannot be worked out because of this subsection, then section 29 will apply.

Note 2: See also section 20 (tolling arrangements and commercial tolling fees).

34 The residual pricing method for working out cost‑plus price and netback price

This method statement is the residual pricing method for working out a cost‑plus price and netback price (and the related RPM price) for a taxpayer who is a participant in a relevant operation in the assessment year:

Method statement

Step 1. Under section 35, identify all types of cost associated with the relevant operation up to and including the assessment year.

Step 2. Under section 36, exclude certain types of cost.

Step 3. Under section 37, classify each remaining type of cost as a direct cost or an indirect cost of the relevant operation, or a personal cost of a participant.

Step 4. Under section 38, exclude any personal costs of other participants. The costs that are left are the included costs for the taxpayer (see section 39).

Step 5. Under section 40, classify each included cost (other than personal costs) as an operating cost or a capital cost.

Step 6. Identify the amount of:

(a) each included operating cost incurred in the assessment year; and

(b) each included capital cost incurred up to and including the assessment year.

When doing so, use section 41 (about the amount and timing of certain included capital costs) if that section applies to an included capital cost.

Step 7. Under section 42:

(a) classify each included direct cost as a phase cost of one of the phases of the relevant operation; and

(b) classify each phase cost as an upstream cost or a downstream cost; and

Step 8. Under section 43 (about capital costs for units of property completed over several years), adjust the amount and timing of an included capital cost if that section applies to that cost.

Step 9. Under sections 44, 45 and 46, adjust the amount and timing of an included capital cost whenever one of those sections applies to that cost.

Step 10. For each included capital cost, allocate to each year of tax from the production year onward a cost with the amount given by section 47.

Step 11. The costs for the assessment year are:

(a) the included upstream and downstream operating costs for the assessment year; and

(b) the upstream and downstream capital costs allocated to the assessment year under step 10; and

Step 12. For each phase cost for the assessment year, adjust the amount of that cost under section 49 if that section applies to the phase cost.

Step 13. Use the costs for the assessment year to work out the participant’s cost‑plus price (see section 30) and netback price (see section 31) for the assessment year.

Note 1: This cost‑plus price and netback price can then be used to work out the participant’s RPM price for the assessment year (see section 28).

Note 2: Step 12 removes that part of each cost attributable to multiple use of a phase.

Division 2—Identifying and classifying included costs

35 Types of cost associated with relevant operation

(1) For the purposes of step 1 of the residual pricing method, identify all costs associated with a relevant operation in accordance with this section.

(2) Include all costs incurred by or on behalf of the participants that are attributable, indirectly attributable or partly attributable to the operation, whether incurred during the operating life of the operation or before the production year.

(3) However, do not include, under subsection (2), a cost incurred by or on behalf of a participant that relates to acquiring an interest, directly or indirectly, in a brought‑in unit of property.

Note: For example, if a participant purchases a brought‑in unit of property for use in the relevant operation, the cost of purchasing the unit is not included. Instead, certain capital costs incurred in respect of the construction, improvement or maintenance of the unit may be included (see subsection (10)).

(4) A payment or allowance between participants is not a cost associated with the relevant operation, unless it is a commercial tolling fee.

Tolling

(5) A cost incurred by or on behalf of a participant is not a cost associated with the relevant operation to the extent that:

(a) the cost is incurred in carrying out one or more actions mentioned in section 8 in relation to petroleum recovered from the source project of the relevant operation; and

(b) a commercial tolling fee is paid by or on behalf of one or more participants in the relevant operation in consideration of the action or actions.

Note: The commercial tolling fee may be a cost associated with the relevant operation.

Costs partly attributable to the relevant operation

(6) A capital cost that was incurred in relation to a unit of property that:

(a) was not, at the time it was incurred, used in the relevant operation; and

(b) was later used in the operation;

may be treated as a cost partly attributable to the operation.

(7) If a cost is only 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.

(8) Subsections (6) and (7) do not apply to capital costs included under subsection (10).

Capital costs for units of property brought into the relevant operation

(9) For the purposes of this section, a unit of property is a brought‑in unit of property if:

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

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

(c) before the unit of property was first used as mentioned in paragraph (b), the unit of property was not used to carry out any of the actions mentioned in section 8 in relation to any relevant operation.

Note: The actions mentioned in section 8 all relate to petroleum recovered from a petroleum project. This means that the unit of property may have previously been used to process petroleum that was not recovered from a petroleum project. (For the meaning of petroleum project, see sections 19 and 20 of the Act.)

(10) Include a capital cost incurred in relation to a brought‑in unit of property to the extent that all of the following apply to the cost:

(a) the cost was incurred by a person who was the owner, or an owner, of the unit of property at the time the cost was incurred;

(b) the cost was incurred in respect of the construction, improvement or maintenance of the unit of property;

(d) 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;

(e) the cost was not incurred for the purpose of preparing the unit of property to be used in the relevant operation;

(f) either or both of subparagraphs 40(1)(c)(ii) and (iii) apply to the cost.

(11) A cost included under subsection (10) may be treated as a cost partly attributable to the operation if the brought‑in unit of property has also been used to carry out any of the actions mentioned in section 8 in relation to another relevant operation.

(12) If a cost included under subsection (10) is only 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.

36 Exclusion of certain costs of relevant operation

For the purposes of step 2 of the residual pricing method, exclude a cost associated with the relevant operation if it is any of the following:

(a) exploration expenditure incurred by a person in relation to a petroleum project (see section 37 of the Act);

(b) a cost incurred in carrying out a feasibility or environmental study before the production of project sales gas;

(d) an environmental restoration or site restoration cost;

(e) expenditure listed in paragraphs 44(1)(a) to (h) of the Act.

37 Direct, indirect and personal costs

(1) For the purposes of step 3 of the residual pricing method, classify the remaining costs associated with the relevant operation as direct costs or indirect costs in accordance with this section.

(2) A cost is a relevant sector cost if:

(a) it is wholly and directly attributable to one or more of the following activities of the operation:

(i) production;

(ii) transport;

(iii) storage;

(iv) marketing;

(v) selling; or

(b) it is a commercial tolling fee.

(3) A relevant sector cost that is wholly attributable to either the upstream stage or the downstream stage of the operation is a direct cost.

(4) A relevant sector cost that:

(a) is not wholly attributable to either the upstream stage or the downstream stage; and

(b) is greater than the threshold amount;

is taken to be divided into 2 direct costs, attributed to the upstream and downstream stages, each of the amount that can reasonably be apportioned to that stage.

(5) A cost that is not a direct cost because of subsection (3) or (4) is an indirect cost.

Note: Examples of indirect costs are business insurance, office expenses, administrative and accounting costs, payments in respect of land and buildings used in connection with administrative or accounting activities, intra company charges, contract penalties, legal and audit costs, travel and buyer liaison costs.

(6) If a cost is related to the marketing and selling of project liquid or project electricity, the cost is a personal cost of the participant that incurred it.

(7) For the purposes of this section, the threshold amount for a taxpayer for a financial year is:

(a) an amount agreed by the taxpayer and the Commissioner for that financial year; or

(b) if the taxpayer and the Commissioner cannot agree on an amount for a financial year:

(i) if that financial year is the financial year 2005–2006 or an earlier financial year—$20 million; or

(ii) if that financial year is a later financial year—$20 million indexed by the GDP factor as applied under the Act, adjusted from 1 January each year.

38 Exclusion of personal costs of other participants

For the purposes of step 4 of the residual pricing method, exclude any personal cost that was incurred by another participant in the operation.

39 Included costs

A cost associated with a relevant operation is an included cost for the taxpayer if it is not excluded after applying sections 36 and 38.

Note: These included costs are the pooled non‑personal costs of all the participants in the relevant operation, and the personal costs of the taxpayer.

40 Capital costs and operating costs

(1) For the purposes of step 5 of the residual pricing method, an included cost for a participant in a relevant operation is a capital cost if:

(a) it is not a personal cost; and

(b) it is not a commercial tolling fee; and

(i) it was incurred before the production date;

(ii) the unit of property for which it was incurred is a depreciating asset for the purposes of section 40–30 of the Income Tax Assessment Act 1997;

(iii) it is a project amount within the meaning of section 40‑840 of the Income Tax Assessment Act 1997.

Note: Subparagraph (c)(i) applies if, for example, a person incurs operating expenses before the production date. Those expenses will be capital costs for the purposes of this instrument.

(2) A cost that is a capital cost only because of subparagraph (1)(c)(i) is taken to have been incurred on 1 January in the financial year in which it was incurred.

Note: Costs that relate to a unit of property that is constructed over several years of tax are dealt with in section 43.

(3) For the purposes of step 5 of the residual pricing method, an included cost for a participant in a relevant operation is an operating cost if:

(a) it is not a personal cost; and

(b) it is not a capital cost.

41 Amount and timing of included capital cost

(1) This section applies to an included capital cost if:

(a) the cost is for a relevant GTL operation for which an election has been made under section 54; and

(b) the cost was incurred before 1 July 2012.

(2) For the purposes of step 6 of the residual pricing method, the included capital cost is taken to have been incurred on 1 July 2012 and not incurred when it was actually incurred.

Note: This will affect how steps 8 to 10 of the method apply to the included capital cost. The steps of the method work sequentially. So, (assuming this subsection applies to the cost) the next applicable step or provision that refers to the start date for the cost will be referring to 1 January in the 2012‑13 financial year.

(3) For the purposes of step 6 of the residual pricing method, if the included capital cost was for a unit of property that was completed before 2 May 2010, the amount of the cost is taken to be the depreciated replacement cost of the unit as at 1 May 2010.

(4) In this section:

depreciated replacement cost has the same meaning as in Accounting Standard AASB 136 Impairment of Assets as in effect on 1 May 2010.

42 Phase costs and upstream and downstream costs

(1) For the purposes of step 7 of the residual pricing method, the included direct and indirect costs are attributed to the various phases or stages of the relevant operation in accordance with this section.

Attributing costs to phases

(2) For each phase of the relevant operation, each included direct cost that can be wholly attributed to the phase is a phase cost for the phase.

(3) If a direct cost for the relevant operation cannot be wholly attributed to activities of a single phase:

(a) the cost is taken to be made up of separate costs for each phase, each of the amount (if any) that can reasonably be apportioned to that phase; and

(b) each of those costs is attributed to the appropriate phase.

Attributing costs to stages

(4) Each included indirect cost for the relevant operation is taken to be made up of 2 costs of equal amounts, of which one is attributable to the upstream stage and one to the downstream stage.

Note: As these costs are not phase costs, section 49 does not apply to them, so they are not reduced because of the multiple use of a phase.

(5) A cost that is a phase cost of a phase in the upstream stage, or an indirect cost allocated to the upstream stage by subsection (4), is an upstream cost.

(6) A cost that is a phase cost of a phase in the downstream stage (which will include marketing and selling costs), or an indirect cost allocated to the downstream stage by subsection (4), is a downstream cost.

Division 3—Allocating capital costs to years of tax

43 Capital costs incurred for a unit of property completed over several years

(1) This section applies to an included capital cost for the taxpayer if the cost is incurred in relation to a unit of property:

(a) that is constructed over a period of time; and

(b) for which the last capital cost is incurred in a later financial year (the final cost year).

(2) For the purposes of step 8 of the residual pricing method, the included capital cost:

(a) is augmented for the number of calendar years between the start date for the included capital cost and 1 January in the final cost year; and

(b) is taken to be incurred in the final cost year.

Note 1: The start date for the included capital cost may have been affected by subsection 41(2).

Note 2: The steps of the method work sequentially. So, (assuming this subsection applies to the cost) the next applicable step or provision that refers to the cost will be referring to:

(a) the cost as augmented under this subsection; and

(b) a start date for the cost of 1 January in the final cost year.

(3) This section does not apply to an included capital cost that is included under subsection 35(10).

44 Capital costs incurred before the production year—project sales gas produced first

(1) For the purposes of step 9 of the residual pricing method, this section applies to an included capital cost for the taxpayer if:

(a) the included capital cost is incurred before the production year; and

(b) the MPC production year for the operation, if any, is not before the production year; and

(2) The included capital cost:

(a) is augmented for the number of calendar years between the start date for the included capital cost and the production date; and

(b) is taken to be incurred in the production year.

Note 1: The start date for the included capital cost may have been affected:

(a) by subsection 43(2), if that subsection applied to the cost; or

(b) by subsection 41(2), if subsection 43(2) did not apply to the cost and an election was made under section 54.

The amount of the cost may also have been affected by subsection 43(2), if that subsection applied to the cost.

Note 2: The steps of the method work sequentially. So, (assuming this subsection applies to the cost) the next applicable step or provision that refers to the cost will be referring to:

(a) the cost as augmented under this subsection; and

(b) a start date for the cost of 1 January in the production year.

45 Capital costs incurred before the production year—other marketable petroleum commodities produced first

(1) For the purposes of step 9 of the residual pricing method, this section applies to an included capital cost for the taxpayer if:

(a) the included capital cost is incurred before the production year; and

(b) marketable petroleum commodities other than project sales gas are produced in the operation; and

Note 1: The start date for the included capital cost may have been affected:

(a) by subsection 43(2), if that subsection applied to the cost; or

(b) by subsection 41(2), if subsection 43(2) did not apply to the cost and an election was made under section 54.

The amount of the cost may also have been affected by subsection 43(2), if that subsection applied to the cost.

Note 2: The steps of the method work sequentially. So, (assuming this section applies to the cost) the next applicable step or provision that refers to the cost will be referring to:

(a) the cost as augmented or reduced under subsection (2), (3) or (4); and

(b) a start date for the cost of 1 January in the production year (see subsection (5)).

(2) If the included capital cost is incurred for a unit of property that will be used solely for:

(a) the recovery of project natural gas; or

(b) the production of project sales gas; or

(d) the combustion of project sales gas to produce project electricity; or

(e) the transportation or storage of project product;

the included capital cost is augmented for the number of calendar years between the start date for the included capital cost and the production date.

(3) If subsection (2) does not apply, and the included capital cost is incurred before the MPC production year, the included capital cost is:

(a) augmented for the number of calendar years between the start date for the included capital cost and the 31 December of the MPC production year; and

(b) reduced for the number of calendar years between the 31 December of the MPC production year and the production date.

(4) If subsection (2) does not apply, and the included capital cost is incurred in or after the MPC production year and before the production year, the included capital cost is reduced for the number of calendar years between the start date for the included capital cost and the production date.

(5) An included capital cost as reduced, or as augmented and reduced, under this section is taken to be incurred in the production year.

46 Capital costs for units of property not originally used, or intended to be used, in a relevant operation

(1) For the purposes of step 9 of the residual pricing method, this section applies to an included capital cost for the taxpayer if the cost is included under subsection 35(10) in relation to a unit of property.

(2) The included capital cost is indexed by applying the formula:

$Start formula Included capital cost times start fraction GDP deflator for the first processing year over GDP deflator for the start year end fraction end formula$

where:

GDP deflator for the first processing year means the GDP deflator (within the meaning of section 2A of the Act) for the year of tax in which the unit of property was first used to carry out any of the actions mentioned in section 8 of this instrument in relation to the relevant operation.

GDP deflator for the start year means the GDP deflator (within the meaning of section 2A of the Act) for the year of tax of the start date for the capital cost.

(3) The included capital cost, as indexed under subsection (2), is taken to be incurred in 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.

47 Allocating capital costs to a year of tax

(1) For the purposes of step 10 of the residual pricing method, this section applies to an included capital cost for the taxpayer that was incurred in a year of tax (the cost year) in relation to a unit of property (the unit) and has, if appropriate, been augmented, reduced or indexed under section 44, 45 or 46.

Note: If the taxpayer does not know whether or not an election under section 48 has been made in relation to the unit of property, or does not know the details of such an election, the taxpayer may be unable to apply the residual pricing method (see subsection 33(1)) and it may be necessary to use section 29 to determine an RPM price for the taxpayer.

(2) The annual allocation for the capital cost is allocated to the cost year and to each subsequent year of tax during the remainder of the capital allocation period for the unit.

(3) If the capital allocation period for the unit is 15 years or less, the annual allocation for the capital cost is:

A formula for working out an annual allocation for a capital cost that has a capital allocation period of 15 years or less

where:

N means the number of calendar years in the capital allocation period for the unit.

(4) If the capital allocation period for the unit is more than 15 years, the annual allocation for the capital cost is:

(5) If no election is made under section 48 for the unit of property, then:

(a) the capital allocation period for the unit of property is the period of calendar years between:

(i) the start date for the capital cost; and

(ii) the 31 December of the last year of tax that is within the estimated operating life of the operation and during which the unit of property is expected to be used for the operation; and

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

(6) Despite subsection (5) and section 48, a cost that is a capital cost only because of subparagraph 40(1)(c)(i) is taken to have been incurred in relation to a unit of property that has a capital allocation period that is the estimated operating life of the operation.

48 Election of capital allocation period for unit of property

(1) 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.

Note: If the participants do not make an election under this section for a particular unit of property, the capital allocation period for the unit of property will be determined under subsection 47(5) (subject to subsection 47(6)).

(2) An election under this section:

(a) must be made by all participants in the operation jointly; and

(b) must be made in writing; and

(d) may be made only before a return under section 59 or 60 of the Act is furnished to the Commissioner where:

(i) the return relates to the source project for the relevant operation; and

(ii) the return relates to the year of tax beginning on 1 July 2024, or a later year of tax; and

(iii) the return is the first such return to be furnished to the Commissioner at or after the time the unit of property is first used in the relevant operation; and

(e) is irrevocable.

(3) If an election has been made under this section and one or more new participants are later added to the relevant operation:

(a) the election continues in force for the participants who made it; and

(b) any new participant is also taken to have made the election.

(4) If an election has been made under this section for a particular unit of property, the election continues to apply to the unit even if:

(a) the unit ceases being used in the relevant operation; or

(b) the unit is used in another relevant operation.

Elections for units of property in use at commencement

(5) Despite paragraph (2)(d), if a unit of property was first used in the relevant operation before the commencement of this section, an election under this section may be made for the unit of property at any time:

(a) at or after the commencement of this section; and

(b) before a return under section 59 or 60 of the Act is furnished to the Commissioner where:

(i) the return relates to the source project for the relevant operation; and

(ii) the return relates to the year of tax beginning on 1 July 2024.

(6) An election mentioned in subsection (5):

(a) may be made only at or after the commencement of this section; and

(b) applies in relation to each year of tax that begins after the day the election is made.

Division 4—Accounting for multiple use of a phase

49 Applying the energy coefficients to costs of each phase

(1) For the purposes of step 12 of the residual pricing method, the amount of each phase cost for a phase, for the year of tax, is taken to be:

$Start formula C times start fraction Phase project energy over Total phase energy end fraction end formula$

where:

C means the amount of the cost before the application of this section.

phase project energy means the energy content of the project product that enters the phase in the year of tax.

total phase energy means the energy content of all the petroleum product, from any operation, that enters the phase in the year of tax.

(2) This section does not apply to a phase cost of a commercial tolling phase.

(3) Without limiting subsection (2), this section does not apply to a phase cost to the extent that the phase cost is a commercial tolling fee.

Part 5—Notional tax amount—sales gas

50 Notional tax amount when RPM price not used

For the purposes of paragraphs 97(1AA)(b) and 97(1BB)(b) of the Act, if any of the following is used in working out assessable petroleum receipts for a person under section 22 or 24 of this instrument:

(a) the comparable uncontrolled price;

(b) the consideration received or receivable, less any expenses payable, by the person in relation to the sale;

the amount that is to be included in working out the current period liability under subsection 97(1A) of the Act, or the current period receipts under subsection 97(1BA) of the Act, is the amount of assessable petroleum receipts worked out under section 22 or 24 of this instrument.

51 Notional tax amount when RPM price used

(1) This section applies if a participant in a relevant operation uses an RPM price for an assessable gas in working out assessable petroleum receipts under section 22 or 24, and had an RPM price for the previous year of tax.

(2) For the purposes of paragraphs 97(1AA)(b) and 97(1BB)(b) of the Act, the amount that is to be included in working out the current period liability under subsection 97(1A) of the Act, or the current period receipts under subsection 97(1BA) of the Act, is:

$Start formula EPVal times start fraction RPM subscript PREV times QAG subscript PREV over EPVal subscript PREV end fraction end formula$

where:

EPVal (short for end product value) means the end product value for the participant in the instalment period.

EPValPREV means the end product value for the participant in the previous year of tax.

QAGPREV means the quantity of the assessable gas, measured by volume or mass, that was in the previous year of tax:

(a) for a relevant GTL operation—processed into project liquid that the participant was entitled to receive in the downstream stage (including any of that assessable gas that was used in that processing); or

(b) for a relevant GTE operation—consumed in the production of project electricity that the participant was entitled to receive in the downstream stage.

RPMPREV means the RPM price for the assessable gas for the participant for the previous year of tax.

(3) If the participant sells a quantity of project liquid or project electricity from the operation as part of the operation in the period, and the sale is an arm’s length transaction, the market value of the quantity is taken to be the amount received for the sale.

(4) For a quantity of project liquid or project electricity to which subsection (3) does not apply, the market value of the quantity is the market value at the end of the downstream stage.

52 Notional tax amount when no previous RPM price

(1) This section applies if a taxpayer uses an RPM price for an assessable gas in working out assessable petroleum receipts under section 22 or 24, but does not have an RPM price for the previous year of tax.

(2) For the purposes of paragraphs 97(1AA)(b) and 97(1BB)(b) of the Act, and subject to subsection (3) of this section, the amount that is to be included in working out the current period liability under subsection 97(1A) of the Act, or the current period receipts under subsection 97(1BA) of the Act, is:

where:

quantity of assessable gas means the quantity of assessable gas, measured by volume or mass, that in the instalment period was:

(b) for a relevant GTE operation—consumed in the production of project electricity that the taxpayer was entitled to receive in the downstream stage.

RPM price means the RPM price for the assessable gas worked out under section 28 or 29 as if the instalment period were the assessment year.

(3) If the taxpayer became a participant in the assessment year because of a transfer of interests from a participant or participants (the previous participants), the taxpayer may elect to apply subsection 51(2) as if the factors in the formula were replaced by the following:

EPValPREV is the total end product value for the previous participants in the previous year of tax.

QAGPREV is the total quantity of the assessable gas, measured by volume or mass, that was in the previous year of tax:

(a) for a relevant GTL operation—processed into project liquid that the previous participants were entitled to receive in the downstream stage (including any of that assessable gas that was used in that processing); or

(b) for a relevant GTE operation—consumed in the production of project electricity that the previous participants were entitled to receive in the downstream stage.

RPMPREV is the average RPM price for the assessable gas for the previous participants for the previous year of tax, weighted according to the end product value for each of the previous participants in the previous year of tax.

Part 6—Miscellaneous

53 Review of decisions—prescribed decisions

For the purposes of section 106A of the Act, a person dissatisfied with any of the following decisions under this instrument may object against it in the manner set out in Part IVC of the Taxation Administration Act 1953:

(a) a decision under section 13 whether a transaction is a non‑arm’s length transaction;

(b) a decision to substitute an estimate under subsection 14(5);

(c) a decision under subsection 27(1) (about comparable uncontrolled prices) that the Commissioner is not satisfied of a matter mentioned in paragraph 27(1)(a), (b) or (c);

(d) a decision under subsection 27(4) to make a particular adjustment, or not to make an adjustment, to the price obtained for a transaction;

(e) a determination of the RPM price under section 29;

(f) a determination under subsection 31(5) or 51(5) of the market value of project liquid or project electricity.

54 Election to apply a modified residual pricing method—relevant GTL operations existing before 2 May 2010

(1) The participants in a relevant GTL operation that first processed project sales gas into project liquid before 2 May 2010 may elect to apply a modified form of the residual pricing method.

(2) An election under this section:

(a) must be made by all participants in the operation jointly; and

(b) must be in a form approved by the Commissioner; and

(3) If an election has been made under this section and one or more new participants are later added to the relevant GTL operation:

(a) the election continues in force for the participants who made it; and

(b) any new participant is also taken to have made the election at the time the new participant is added to the relevant GTL operation.

Note: If an election has been made under this section, a number of provisions in this instrument apply or operate differently. The differences include changes to the rules about capital costs (see section 41), and a reduction in the number of phases in an operation (see section 9).

55 Election to use individual participant‑based end product values

(1) The taxpayers who are participants in a relevant operation may elect to use, for the operation, the method for working out end product value set out in subsection 31(2) for a year of tax if each of the taxpayers is entitled to receive in the year of tax:

(a) for a relevant GTL operation—project liquid; or

(b) for a relevant GTE operation—project electricity.

(2) An election under this section:

(a) must be jointly made by all of those taxpayers who apply the residual pricing method in working out the amount of their assessable petroleum receipts relating to the operation; and

(b) must be made after the end of the first year of tax to which the election is to apply; and

(d) must be given to the Commissioner no later than:

(i) the day a return under section 59 or 60 of the Act for the project to which the operation relates is due for the first year of tax to which the election is to apply; or

(ii) a later day that the Commissioner allows; and

(e) is irrevocable; and

(f) expires at the first time in a later year of tax when not all of the taxpayers who apply the residual pricing method in working out the amount of their assessable petroleum receipts relating to the operation are entitled to receive:

(i) for a relevant GTL operation—project liquid; or

(ii) for a relevant GTE operation—project electricity;

in that later year of tax.

Part 7—Transitional matters

56 Things done under previous regulations

(1) A thing done:

(a) before the commencement of this instrument; and

(b) under a provision of:

(i) the Petroleum Resource Rent Tax Assessment Regulations 2005; or

(ii) the Petroleum Resource Rent Tax Assessment Regulation 2015;

has effect after that commencement as if the thing had been done under the corresponding provision of this instrument.

(2) Without limiting subsection (1), a thing includes an election, a notification, a determination and a decision.

57 Transitional provision—advance pricing arrangements

Without limiting section 56, an advance pricing arrangement in effect immediately before the commencement of this instrument continues in effect, at and after that commencement, as if it had been made under this instrument.

58 Application of this instrument and repeal of previous instrument

The following apply in relation to a year of tax beginning on or after 1 July 2024:

(a) this instrument;

(b) the repeal of the Petroleum Resource Rent Tax Assessment Regulation 2015 by this instrument.