Federal Register of Legislation - Australian Government

Primary content

SLI 2015 No. 254 Regulations as made
This regulation repeals and remakes the Petroleum Resource Rent Tax Assessment Regulations 2005.
Administered by: Treasury
Registered 17 Dec 2015
Tabling HistoryDate
Tabled HR02-Feb-2016
Tabled Senate02-Feb-2016

EXPLANATORY STATEMENT

Select Legislative Instrument No. 254, 2015

Issued by authority of the Assistant Treasurer

Petroleum Resource Rent Tax Assessment Act 1987

Petroleum Resource Rent Tax Assessment Regulation 2015

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

Section 24 of the PRRTAA provides that regulations may specify the calculation method to determine the assessable petroleum receipts arising from sales gas and natural gas in relation to a petroleum project.

The purpose of the Petroleum Resource Rent Tax Assessment Regulation 2015 (the Regulation) is to remake the Petroleum Resource Rent Tax Assessment Regulations 2005 (the 2005 Regulations). 

The Legislative Instruments Act 2003 (LIA) provides that all legislative instruments, other than exempt instruments, progressively ‘sunset’ on the first 1 April or 1 October falling on or after the tenth anniversary of registration of the instrument.  As the 2005 Regulations were registered on 19 December 2005, they are due to sunset on 1 April 2016.   When a legislative instrument sunsets, it is automatically repealed under section 50 of the LIA.

The Regulation remakes the 2005 Regulations, with some minor changes to modernise the drafting style, reduce compliance costs for industry and ensure that the Regulation is fit‑for‑purpose. Consistently with the Government’s deregulation agenda, the key changes are designed to reduce costs and regulatory burden by:

                allowing taxpayers to jointly make an election for an onshore integrated gas‑to‑liquid (GTL) operation to aggregate the relevant costs into one upstream phase. For integrity reasons, the election is subject to restrictions;

                allowing an election for an onshore integrated operation to use the depreciated replacement cost method, to be made by taxpayers that use the Residual Pricing Method (RPM). This changes the current requirement that the election be made by all of the participants in the integrated operation;

                allowing taxpayers to jointly make an election, for an integrated operation, to use the value of their own share of the end products as a component of the netback price in specified circumstances, instead of requiring them to obtain the value of the end products of all of the taxpayers in the operation. For integrity reasons, this election is subject to restrictions;

                adding an example to the Regulation to clarify that the Commissioner of Taxation’s (the Commissioner’s) power to agree to or to determine an RPM price can be used when required information is not accessible for practical or commercial reasons; and

                correcting the inconsistent treatment of storage costs for project sales gas in an integrated operation so that the cost for storage of sales gas after a non-arm’s length sale is treated as a downstream cost.

Further details on the Regulation and the Statement of Compatibility with Human Rights are set out in the Attachment.

The PRRTAA does not specify any conditions that need to be met before the power to make the Regulation may be exercised.

The Regulation is a legislative instrument for the purposes of the LIA.

All references to legislative provisions in this Explanatory Statement are to the Regulation. 

The Regulation applies to a limited number of taxpayers who are in the petroleum industry and also only applies to particular projects within the industry.  To ensure that the Regulation is fit-for-purpose, a number of consultation processes were undertaken with industry and the Australian Taxation Office (ATO) as part of the ‘sunsetting’ review process. Targeted consultation with industry and the ATO was also undertaken on the draft Regulation.

Prior to the making of the Regulation and in accordance with the Office of Best Practice Regulation’s Guidance Note on sunsetting instruments, the Department of the Treasury self-assessed that the Petroleum Resource Rent Tax Assessment Regulations 2005 were operating effectively and efficiently, and therefore a Regulation Impact Statement was not required. This assessment was informed by the process of consultation with industry (OBPR reference 19560).

The Regulation will commence on 1 April 2016.

 

 


ATTACHMENT

Details of the Petroleum Resource Rent Tax Assessment Regulation 2015

Background

The Petroleum Resource Rent Tax (PRRT) was enacted in 1987 through the Petroleum Resource Rent Tax Act 1987 and the PRRTAA, and is a profits-based tax applied to petroleum production from petroleum projects.

The PRRT is applied at a rate of 40 per cent on the ‘taxable profit’ of a project, calculated as assessable receipts less project related expenditures, including eligible exploration expenditures. Where project related expenditure is not able to be immediately deducted in the year incurred (due to expenditures being greater than receipts), it is carried forward and augmented by specific amounts dependent on the kind of expenditure, and is able to be deducted against receipts in future years. PRRT payments are income tax deductible.

Under the PRRTAA, assessable petroleum receipts are usually determined at the point where a marketable petroleum commodity (MPC) becomes an excluded commodity. An MPC, which is defined as including stabilised crude oil, condensate, liquefied petroleum gas (LPG), shale oil, ethane, and sales gas, becomes an excluded commodity either by being sold, or by being further processed, or moved away from its place of production.

In most cases assessable petroleum receipts will reflect the consideration received from the sale of the MPC. However, in some cases, an MPC does not become an excluded commodity via a sale but rather undergoes further processing to another product as part of an integrated process. In that situation there is no observable
arm’s-length price for the MPC from which assessable petroleum receipts can be derived. Consequently, the PRRTAA normally requires that assessable receipts be based on the market value of the MPC.

However, this ‘market value’ method does not apply to the MPC, ‘sales gas’ in situations where it is used as feedstock in an integrated gas-to-liquid (GTL) or gas‑to‑electricity (GTE), and becomes an excluded commodity other than by sale, or where it becomes an excluded commodity via a non-arm’s length transaction. Instead, the assessable receipts for the sales gas are calculated in accordance with the framework set out in the Regulation.

The Regulation

The Regulation provides a framework for determining assessable petroleum receipts where sales gas is used as a raw material for use in an integrated GTL or GTE operation in circumstances where there is no price or only a non-arm’s length price for the sales gas. The Regulation also provides a framework for determining assessable petroleum receipts when natural gas recovered from an onshore petroleum project is sold in a non-arm’s length transaction for use in an integrated GTL or GTE operation.

Sections 6 and 7 of the Regulation define an integrated operation as an operation in which:

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

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

                some or all of the sales gas is, or will be, processed into a liquefied product or consumed in the commercial production of electricity.

The petroleum recovered from a petroleum project to produce sales gas that is processed into a liquefied product or consumed in the production of electricity is referred to in the Regulation as project natural gas (subsections 6(2) and 7(2)).

The sales gas that is produced and then processed into a liquefied product or consumed in the production of electricity is referred to in the Regulation as project sales gas (subsections 6(3) and 7(3)).

The elements comprising an integrated operation are also defined and divided into two stages, specifically:

                the upstream stage.

               for project sales gas, this stage commences with the recovery of project natural gas (that is, the natural gas from which project sales gas will be produced and liquefied or turned into electricity within the operation) and ends with the production of project sales gas;

               for project natural gas, the upstream stage commences with the recovery of project natural gas and continues up to the point of sale; and

                the downstream stage.

               for project sales gas, this stage commences with the transportation of project sales gas from the upstream stage for processing into project liquid or project electricity and ends with the storage or loading of project liquid at an adjacent facility;

               for project natural gas, the downstream stage is expanded to include the production of project sales gas. Related transport and storage of project sales gas will from part of the downstream stage.

Where an integrated operation exists, the gas transfer price (that is, the ‘price’ of the project sales gas/project natural gas (assessable gas) used to determine assessable receipts for the purposes of the PRRTAA) is to be determined via the following hierarchy:

1.             if an Advance Pricing Arrangement (APA) has been agreed between the taxpayer and the Commissioner, the amount calculated in accordance with the arrangement;

2.             if there is no APA, but a comparable uncontrolled price (CUP) exists for the assessable gas, the CUP. A CUP refers to a price that can be observed in a relevant market place for the sale of the relevant commodity. Section 23 of the Regulation defines CUP for the purposes of the Regulation and the conditions under which a CUP can be observed; or

3.             if there is no APA, and no CUP exists for the assessable gas, the price is determined in accordance with the RPM, which is set out in the Regulation.

In relation to onshore integrated GTL projects, participants may make an election to apply the RPM as the default method for determining assessable petroleum receipts (section 49).

The Residual Pricing Method (RPM)

The RPM notionally treats the upstream and downstream stages of an integrated operation as separate arm’s length businesses buying and selling assessable gas (project sales gas or project natural gas as the case requires), in order to determine a gas transfer price.

The gas transfer price (for the purposes of the PRRTAA) determined via this method is referred to as the ‘RPM price’.

The RPM incorporates both a ‘cost-plus’ and ‘netback’ calculation.

                the cost-plus calculation is applied to the upstream stage to determine a ‘costplus price’ for the assessable gas. The cost-plus price reflects the minimum price at which the upstream stage of the integrated operation would need to sell the assessable gas produced in order to cover its costs (including an allowance for capital investment); and

                the netback calculation is applied to the downstream stage (netting off the downstream costs from the value of the final product to determine a ‘netback price’ for the assessable gas). The netback price reflects the maximum price for assessable gas that would allow the downstream stage to recover its costs (including an allowance for capital investment) for a given sale price for the project liquid/project electricity.

The ‘gap’ between the cost-plus and netback prices reflects the residual, or ‘excess’ profit of the integrated operation as a whole. This residual profit is divided equally between the upstream and downstream stages of the operation (implying an equal share of rents between the upstream and downstream stages of the operation) to determine the RPM price.

The operation of the RPM is illustrated in Figure 1.

Figure 1


The steps for working out the cost-plus price, netback price and related RPM price in relation to assessable gas of an integrated operation are set out in section 30.

2013 Amendments

The application of the 2005 Regulations to onshore projects was the result of amendments in 2013. These amendments followed the extension of the PRRT to onshore projects in 2012 and allowed onshore operations to have access to the same integrated GTL pricing mechanism under the Regulations as offshore operations. The 2013 amendments also extended the framework in the Regulations to GTE operations.

Drafting improvements and transitional provisions

The Regulation makes a number of drafting improvements to the 2005 Regulations. It simplifies the structure of certain provisions and uses clearer language.

For example, provisions in the 2005 Regulations are referred to as ‘regulations’ and ‘subregulations’, however, provisions in new principal legislative instruments, such as the Regulation, are now referred to as ‘sections’ and ‘subsections’.  Similarly, principal legislative instruments are now referred to as a ‘Regulation’ rather than as ‘Regulations’.  These drafting changes to the structure and terminology for the provisions are not intended to alter the current operation of the equivalent provisions in the 2005 Regulations.    

The Regulation also includes transitional provisions to ensure that actions, such as the making of applications and the giving of notices and permissions, taken under the 2005 Regulations continue to apply as if they had been taken under the Regulation. [section 53]

Finding tables are included at the end of this Attachment to assist in identifying which provisions in the Regulation correspond to provisions in the 2005 Regulations, and vice versa.

Changes to the Petroleum Resource Rent Tax Assessment Regulations 2005

The Regulation makes a number of small changes to the 2005 Regulations. Changes 1, 2, 3 and 4 are in response to feedback from industry stakeholders, and ensure that the Regulation is fit‑for‑purpose and that compliance costs are reduced where possible. Some of these changes address practical difficulties that arise from applying the framework in the 2005 Regulations to onshore integrated operations, which may have a different structure to the offshore integrated operations for which the 2005 Regulations were originally designed.

These amendments were subject to a consultation process with industry stakeholders and consultation bodies throughout their development.

Changes 5 and 6 correct anomalies in the 2005 Regulations.

 

 

 

Change 1 – Election for one upstream phase

The Regulation allows taxpayers in an integrated onshore GTL operation to make an election to aggregate the relevant costs into one upstream phase.

Background:

Each integrated operation is divided into phases. Where a phase begins and ends is determined by a ‘phase point’. Subsection 9(1) describes where the phase points of the integrated operation occur. These are:

                the point where the upstream stage ends and the downstream stage begins; and

                any point in the flow of project product through the integrated 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 that point.

Differences in the total amount of petroleum product flowing through an integrated operation may be the result of either project product leaving an integrated operation or non-project petroleum product from outside entering the integrated operation.

Costs of the operation are attributed to the various phases of the operation in accordance with section 38. For each phase, the costs are apportioned between project product and other petroleum product by applying an energy coefficient in accordance with section 43. The energy coefficient is the result of dividing phase project energy by total phase energy.

The intent of these provisions is that the RPM should only reflect costs associated with project product. If non-project product flows through parts of the integrated operation for certain phases, then costs associated with these phases should be adjusted so that only those that are attributable to the project product are factored into the RPM.

Consultation

Consultation with industry indicated that the structure of onshore GTL operations often involves having gas from various projects comingled. This may trigger a substantial number of phase points. Because the volume of gas in each phase is required to be recorded, this requires substantial metering capability. The metering capability required for this may be greater than the commercial metering requirements of the project.

This represents a compliance burden to taxpayers that potentially prevents the use of the RPM. This is particularly the case as taxpayers are required to notify phase points and related record keeping matters to the Commissioner under subsections 9(5) and 9(7) respectively.

 

 

 

 

The new election

To reduce compliance costs, the Regulation allows taxpayers in an integrated onshore GTL operation to make an election to aggregate the relevant costs into one upstream phase.

Making the election

This election is able to be made when the following criteria are met.

1.             The election must be made jointly by all the taxpayers who are participants in the operation who use the RPM.

Without this requirement, different taxpayers who are participants in the same operation would have phase points that do not align, meaning that costs would not be treated consistently between taxpayers in an operation. The requirement to make the election jointly will also avoid confusion regarding the phase points and related record keeping matters that are notified to the Commissioner under subsections 9(5) and 9(7). [Paragraph 48(2)(a)]

Furthermore, changing the number of phases in the upstream stage could (depending on the circumstances and the operation’s structure) potentially affect who is considered to be a ‘participant’. The requirement for the election to be jointly made by all taxpayers will avoid confusion as to who is a participant in an operation.

2.             The election may only be made where the assessable petroleum receipts of all of the taxpayers are to be worked out under section 21.

Section 21 provides for the working out of assessable petroleum receipts in cases where project natural gas produced from petroleum recovered from an onshore petroleum project is sold via a non-arm’s length transaction for the purposes of paragraph 24(1)(f) of the PRRTAA. This means that the election cannot be made where a taxpayer in an operation has assessable petroleum receipts that are to be worked out under section 19 or 20, with respect to project sales gas. [Paragraph 48(1)(b)]

3.             The election must be made by a particular time and is irrevocable.

The election must be given to the Commissioner in the financial year before the production year for the operation, or by a later day that the Commissioner allows. Once the election for an integrated operation is made it is irrevocable, and will apply with respect to the integrated operation notwithstanding that the taxpayers in that operation change. The election must be in the form approved by the Commissioner. [Paragraphs 48(2)(b), (c), and (d)]

The election only applies for limited purposes. For example, the election does not relieve a taxpayer calculating an RPM from having to obtain information about the costs of the other participants that sold project natural gas to an aggregator.

 

No Energy Coefficient applied when election is made

Where an election is made under section 48 to use one upstream phase, the energy coefficient is not applied for this phase.   

Normally, where non-project product is processed in a phase, the costs attributable to that phase are reduced by means of the energy coefficient so that only costs attributable to the project product are factored into the RPM.

However, where an election is made to use one upstream phase (under section 48), no energy coefficient for this phase is applied. This is because, in the absence of the identification of all the points at which the ratio of project product to non-project product changes, it is not possible to come to an energy coefficient that accurately reflects the costs that are attributable to the project product and those that are attributable to the non-project product. [Subsection 43(2)]

Change 2 – Election to use the depreciated replacement cost method need only be made by taxpayers using RPM (for integrated onshore operations)

The Regulation allows an election to use the depreciated replacement cost method to be made jointly by the participants in an integrated onshore operation that are taxpayers that use the RPM. This is a change from the 2005 Regulations, which require that the election be jointly made by all of the participants in the operation. [Paragraph 51(2)(a)]  

Background

The 2013 amendments extended the 2005 Regulations to integrated onshore operations. Those amendments allowed participants in an integrated onshore operation to elect to use the depreciated replacement cost method to determine the included cost of units or property of the operation that were completed prior to 2 May 2010.

This recognises that integrated onshore operations being developed may incorporate petroleum projects that have been operating for a significant period of time prior to becoming part of the integrated operation, and for which there are insufficient records to verify historic costs.

Consultation

In the consultation process, industry identified that the depreciated replacement cost method was difficult to apply because of the requirement that it be made jointly by all of the participants in the operation.

For integrated onshore operations, it may be practically or commercially difficult for a taxpayer to obtain agreement to make the election from all participants in the operation.

For example, onshore GTL operations often have multiple related and unrelated participants. The structure of these operations may involve a number of petroleum projects selling natural gas to a special purpose entity referred to as an ‘aggregator’ in order to source a sufficient supply of gas for the downstream liquefaction facilities as well as to streamline gas processing services and transportation. Furthermore, some participants that are taxpayers may have APAs, and therefore the election will not be relevant to them.

The current requirement that all participants jointly make the election means that this option can be unavailable to otherwise eligible taxpayers.

Changes to the election

The Regulation allows the election to be made by all of the participants that are taxpayers in the relevant operation that use the RPM. This means that only the taxpayers affected will need to make the election. The election in the Regulation better aligns with the structure of integrated onshore operations, and reduces compliance costs for industry. [Paragraph 51(2)(a)]    

Taxpayers that make this election will need to make sure that they are able to report the included capital costs of the operation, including those of all of the participants using the depreciated replacement cost method. The fact that this election need not be made by all participants does not affect the need for a taxpayer using the RPM to obtain all the relevant cost information required to use the RPM.

 

Change 3 – Election to use new participant-based formula for the end product value (EPVal)

Background

As part of the RPM calculation, taxpayers are required to work out the market value of the end product (project liquid produced or project electricity produced) of the integrated operation. This is known as the end product value (EPVal).

Under the 2005 Regulations, the EPVal is worked out by using the total market value in the year of tax of all of the end product produced by the integrated operation. For an integrated GTL operation, this is the project liquid produced. For an integrated GTE operation, this is the project electricity produced.

Consultation

The current EPVal formula requires each taxpayer to obtain the market value of all of the end product produced by the integrated operation. The consultation process indicated that this may be commercially and practically difficult where individual taxpayers separately market and sell their share of the end product. This information may be confidential, meaning that taxpayers are not willing to share the information with other taxpayers.

The new alternative method

To address this, and to reduce compliance costs, the Regulation introduces an alternative means by which taxpayers can work out the EPVal. This alternative, referred to as the participant-based formula, derives an EPVal from the market value of the taxpayer’s own project liquid or project electricity (rather than that of all the end product produced by the operation).

This alternative takes the market value of the taxpayer’s own project liquid or project electricity (the taxpayer product) and applies the average value of the taxpayer’s product to the quantity of all of the project liquid or project electricity produced by the integrated operation. [Subsection 27(2)]  

Making the election

In order to make this election, all taxpayers in the relevant integrated operation that use the RPM must do so jointly. Once the election is made it is irrevocable and will continue to apply with respect to the integrated operation. These conditions help to ensure that this change is revenue neutral, and that it will operate to reduce compliance costs, rather than providing an opportunity for tax planning. [Paragraphs 52(2)(a) and (e)] 

RPM taxpayers must be entitled to end product

The election to use the participant-based EPVal formula is only available where all taxpayers in the integrated operation are entitled to end product (project liquid/project electricity) in the year of tax for which the election is first made. This condition is necessary because the participant-based formula is not effective for a taxpayer that is not entitled to end product: there is no taxpayer product on which to base a calculation of the EPVal, which, in turn, would prevent the RPM price from being calculated accurately. [Subsection 52(1)]  

The election must be made after the end of the first year of tax to which it applies. This is because it is only at this point that it will be known that, for the first year of tax, all of the RPM taxpayers who were participants in the operation were entitled to end product in that year of tax. [Paragraph 52(2)(b)]  

The election must be given to the Commissioner by no later than the due date for the PRRT return for the first year of tax to which the election applies, or, by a later day that the Commissioner allows. The election must be in a form approved by the Commissioner. [Paragraphs 52(2)(b) and (d)]  

 

The election is irrevocable and will continue for later years of tax with respect to the integrated operation. This means that all taxpayers who use the RPM for the integrated operation will have to use the participant-based formula for EPVal when calculating an RPM, including any new participant who uses the RPM. [Paragraph 52(2)(e)]

However, the election will only remain effective for as long as all of the taxpayers in the integrated operation that use the RPM are entitled to end product. This means that the election will expire in a later year of tax when an RPM taxpayer who is not entitled to end product joins an integrated operation. It will also expire at the point at which, in a later year of tax, an existing RPM taxpayer ceases to be entitled to end product in that later year of tax. Again, this is because the participant-based formula for calculating EPVal is not effective for a taxpayer that is not entitled to end product.  [Paragraph 52(2)(f)]

 

 

 

 

Change 4 – New example for RPM price where insufficient information available

Section 25 applies where there is insufficient information available for a taxpayer to determine its own RPM price.

If the Commissioner and the taxpayer can agree on a price, that becomes the RPM price under subsection 25(2). If the Commissioner and the taxpayer cannot agree, but the Commissioner is satisfied that the price worked out using the RPM method on the basis of information from other participants in the operation is a fair and reasonable price, that price becomes the RPM price under subsection 25(3).

Under subsection 25(4), if the participant and the Commissioner cannot agree on a price and the Commissioner is not satisfied with a price determined under subsection 25(3), the RPM price is the price as determined by the Commissioner as being fair and reasonable. Under paragraph 47(d), such a decision is subject to objection and review under Part IVC in the Taxation Administration Act 1953.

New example

The Regulation includes a new example in section 25, with respect to onshore integrated GTL operations where an election is made under section 49 to use the RPM. This new example clarifies that the process for determining an RPM in section 25 can be used when the required information is not accessible for practical or commercial reasons, because the other participants in the operation do not elect to use the RPM. [Section 25]

This may occur, for example, where a taxpayer does not have an interest in each of the production licences that are covered by the project combination certificate. This means that they may have difficulties in accessing the information required to determine a cost-plus price for the RPM calculation.  

Change 5 – Storage costs

Section 8 divides integrated operations into upstream and downstream stages. It does this to work out assessable petroleum receipts for the purposes of sections 19 and 20, with respect to sales gas, and section 21, with respect to natural gas.

Under the RPM, the upstream stage comprises of those processes necessary for the production and storage of project sales gas up to the point that the gas becomes an excluded commodity. 

However, the 2005 Regulations contain an anomaly wherein storage of sales gas is treated as part of the upstream stage, irrespective of whether it occurs before or after a non-arm’s length sale or before or after the conversion of sales gas into an excluded commodity.

The Regulation corrects this anomaly. Where the storage occurs after the non-arm’s length sale, or after the conversion of the gas into an excluded commodity, the storage costs will be treated as part of the downstream stage.  Where the storage of sales gas occurs either prior to the non-arm’s length sale of the sales gas or prior to the sales gas becoming an excluded commodity, it will be treated as part of the upstream stage. [Paragraphs 8(1)(i), 8(2)(a), and 8(3)(a)]  

 

Change 6 - Heading of section 51

A small change to the heading of this section is made. The heading in the equivalent 2005 Regulation (regulation 44) refers to integrated onshore operations existing before 2 May 2010. However, this election and the effect of this election apply to an integrated onshore operation that had completed units of property before 2 May 2010 or incurred costs before 1 July 2012. [Section 51]

Finding Tables

 

Petroleum Resource Rent Tax Assessment Regulation 2015 to Petroleum Resource Rent Tax Assessment Regulations 2005

 

Petroleum Resource Rent Tax Assessment Regulation 2015

Petroleum Resource Rent Tax Assessment Regulations 2005

Section

Regulation

1– Name

1 – Name of Regulations

2 - Commencement

2 – Commencement

3 – Authority

N/A

4 – Schedules

N/A

5 – Definitions

3 – Definitions

6 – When an integrated GTL operation exists

4 – When an integrated GTL operation exists

7 – When an integrated GTE operation exists

4A – When an integrated GTE operation exists

8 – Upstream and downstream stages of integrated operation

5 – Upstream and downstream stages of integrated operation

9 – Phase points of integrated operation

6 – Phase points of integrated operation

10 – When there is multiple use of a phase

7 – When there is multiple use of a phase

11 – Participants in integrated operation

8 – Participants in integrated operation

12 – Non-arm’s length transaction

8A – Non-arm’s length transaction

13 – Estimated average annual volume or mass of project natural gas

9 – Estimated average annual volume or mass of project natural gas

14 – meaning of volume coefficient

10 – meaning of volume coefficient

15 – meaning of mass coefficient

10A – meaning of mass coefficient

16 – Augmentation of a capital cost

11 – Augmentation of a capital cost

17 – Reduction of a capital cost

12 – Reduction of a capital cost

18 – Capital allowance

13 – Capital allowance

19 – Assessable petroleum receipts – sales gas of integrated operation with non-arm’s length sale

14 – Assessable petroleum receipts – sales gas of integrated operation with non-arm’s length sale

20 – Assessable petroleum receipts – sales gas of integrated operation becoming excluded commodity other than by being sold

15 – Assessable petroleum receipts – sales gas of integrated operation becoming excluded commodity other than by being sold

21 – Assessable petroleum receipts – natural gas of onshore integrated operation with non-arm’s length sale

16 – Assessable petroleum receipts – natural gas of onshore integrated operation with non-arm’s length sale

22 – Advance pricing arrangements

18 – Advance pricing arrangements

23 – The comparable uncontrolled price

19 – The comparable uncontrolled price

24 – RPM price (transfer price using the residual pricing method)

20 – RPM price (transfer price using the residual pricing method)

25 – RPM price where information is not available

21 – RPM price where information is not available

26 – Cost-plus price

22 – Cost-plus price

27 – Netback price

23 – Netback price

28 – Costs are net of GST tax credits and adjustments

24 – Costs are net of GST tax credits and adjustments

29 – When the residual pricing method can be used

25 – The residual pricing method for working out cost-plus and netback prices

30 – The residual pricing method for working out cost-plus price and netback price

25 – The residual pricing method for working out cost-plus and netback prices

31 – Types of cost associated with integrated operation

26 – Types of cost associated with integrated operation

32 – Exclusion of certain costs of integrated operation

27 – Exclusion of certain costs of integrated operation

33 – Direct, indirect and personal costs

28 – Direct, indirect and personal costs

34 – Exclusion of personal costs of other participants

29 – Exclusion of personal costs of other participants

35 – Included costs

30 – Included costs

36 – Capital costs and operating costs

31 – Capital and operating costs

37 – Amount and timing of included capital cost

31A – Amount and timing of included capital cost

38 – Phase costs and upstream and downstream costs

32 – Phase costs and upstream and downstream costs

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

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

40 – Capital costs incurred before the production year – project sales gas produced first

34 – Capital costs incurred before the production year – project sales gas produced first

41 – Capital costs incurred before the production year – other marketable petroleum commodities produced first

35 – Capital costs incurred before the production year – other marketable petroleum commodities produced first

42 – Allocating capital costs to a year of tax

36 – Allocating capital costs to a year of tax

43 – Applying the energy coefficients to costs of each phase

37 – Applying the energy coefficients to costs of each phase

44 – Notional tax amount when RPM price not used

38 – Notional tax amount when RPM price not used (Act s 97(1AA)(b))

45 – Notional tax amount when RPM price used

39 – Notional tax amount when RPM price used (Act s 97(1AA)(b)

46 – Notional tax amount when no previous RPM price

40 – Notional tax amount when no previous RPM price

47 – Review of decisions – prescribed decisions

41 – Review of decisions – prescribed decisions

48 – Election for a single upstream phase point – integrated onshore GTL operations

N/A

49 – Election to apply the residual pricing method – integrated onshore GTL operations

42 – Election to use residual pricing method – participant in onshore GTL operation

50 – Election to apply a modified residual pricing method – integrated GTL operations existing before 2 May 2010

43 – Election to use modified residual pricing method – integrated GTL operation existing before 2 May 2010

51 – Election to use the depreciated replacement cost method – integrated onshore operations

44 – Election to use depreciated replacement cost method – integrated onshore operation existing before 2 May 2010

52 – Election to use individual participant-based end product values

N/A

53 – Things done under the Petroleum Resource Rent Tax Assessment Regulations 2005

N/A

 

 

 

Petroleum Resource Rent Tax Assessment Regulations 2005 to Petroleum Resource Rent Tax Assessment Regulation 2015

 

Petroleum Resource Rent Tax Assessment Regulations 2005

Petroleum Resource Rent Tax Assessment Regulation 2015

Regulation

Section

1 – Name of Regulations

1 - Name

2 – Commencement

2 - Commencement

3 – Definitions

5 – Definitions

4 – When an integrated GTL operation exists

6 – When an integrated GTL operation exists

4A – When an integrated GTE operation exists

7 – When an integrated GTE operation exists

5 – Upstream and downstream stages of integrated operation

8 – Upstream and downstream stages of integrated operation

6 – Phase points of integrated operation

9 – Phase points of integrated operation

7 – When there is multiple use of a phase

10 – When there is multiple use of a phase

8 – Participants in integrated operation

11 – Participants in integrated operation

8A – Non-arm’s length transaction

12 – Non-arm’s length transaction

9 – Estimated average annual volume or mass of project natural gas

13 – Estimated average annual volume or mass of project natural gas

10 – meaning of volume coefficient

14 – meaning of volume coefficient

10A – meaning of mass coefficient

15 – meaning of mass coefficient

11 – Augmentation of a capital cost

16 – Augmentation of a capital cost

12 – Reduction of a capital cost

17 – Reduction of a capital cost

13 – Capital allowance

18 – Capital allowance

14 – Assessable petroleum receipts – sales gas of integrated operation with non-arm’s length sale

19 – Assessable petroleum receipts – sales gas of integrated operation with non-arm’s length sale

15 – Assessable petroleum receipts – sales gas of integrated operation becoming excluded commodity other than by being sold

20 – Assessable petroleum receipts – sales gas of integrated operation becoming excluded commodity other than by being sold

16 – Assessable petroleum receipts – natural gas of onshore integrated operation with non-arm’s length sale

21 – Assessable petroleum receipts – natural gas of onshore integrated operation with non-arm’s length sale

18 – Advance pricing arrangements

22 – Advance pricing arrangements

19 – The comparable uncontrolled price

23 – The comparable uncontrolled price

20 – RPM price (transfer price using the residual pricing method)

24 – RPM price (transfer price using the residual pricing method)

21 – RPM price where information is not available

25 – RPM price where information is not available

22 – Cost-plus price

26 – Cost-plus price

23 – Netback price

27 – Netback price

24 – Costs are net of GST tax credits and adjustments

28 – Costs are net of GST tax credits and adjustments

25 – The residual pricing method for working out cost-plus and netback prices

30 – The residual pricing method for working out cost-plus price and netback price

26 – Types of cost associated with integrated operation

31 – Types of cost associated with integrated operation

27 – Exclusion of certain costs of integrated operation

32 – Exclusion of certain costs of integrated operation

28 – Direct, indirect and personal costs

33 – Direct, indirect and personal costs

29 – Exclusion of personal costs of other participants

34 – Exclusion of personal costs of other participants

30 – Included costs

35 – Included costs

31 – Capital and operating costs

36 – Capital costs and operating costs

31A – Amount and timing of included capital cost

37 – Amount and timing of included capital cost

32 – Phase costs and upstream and downstream costs

38 – Phase costs and upstream and downstream costs

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

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

34 – Capital costs incurred before the production year – project sales gas produced first

40 – Capital costs incurred before the production year – project sales gas produced first

35 – Capital costs incurred before the production year – other marketable petroleum commodities produced first

41 – Capital costs incurred before the production year – other marketable petroleum commodities produced first

36 – Allocating capital costs to a year of tax

42 – Allocating capital costs to a year of tax

37 – Applying the energy coefficients to costs of each phase

43 – Applying the energy coefficients to costs of each phase

38 – Notional tax amount when RPM price not used (Act s 97(1AA)(b))

44 – Notional tax amount when RPM price not used

39 – Notional tax amount when RPM price used (Act s 97(1AA)(b)

45 – Notional tax amount when RPM price used

40 – Notional tax amount when no previous RPM price

46 – Notional tax amount when no previous RPM price

41 – Review of decisions – prescribed decisions

47 – Review of decisions – prescribed decisions

42 – Election to use residual pricing method – participant in onshore GTL operation

49 – Election to apply the residual pricing method – integrated onshore GTL operations

43 – Election to use modified residual pricing method – integrated GTL operation existing before 2 May 2010

50 – Election to apply a modified residual pricing method – integrated GTL operations existing before 2 May 2010

44 – Election to use depreciated replacement cost method – integrated onshore operation existing before 2 May 2010

51 – Election to use the depreciated replacement cost method – integrated onshore operations

 

Statement of Compatibility with Human Rights

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

Petroleum Resource Rent Tax Assessment Regulation 2015

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

Overview of the Legislative Instrument

The Petroleum Resource Rent Tax Assessment Regulation 2015 remakes the Petroleum Resource Rent Tax Assessment Regulations 2005

The Legislative Instruments Act 2003 (LIA) provides that all legislative instruments, other than exempt instruments, progressively ‘sunset’ on the first 1 April or 1 October falling on or after the tenth anniversary of registration of the instrument.  As the Petroleum Resource Rent Tax Assessment Regulations 2005 was registered on 19 December 2005, the legislative instrument is due to sunset on 1 April 2016.   When a legislative instrument sunsets, it is automatically repealed under section 50 of the LIA.

As well as remaking the Petroleum Resource Rent Tax Assessment Regulations 2005, this legislative instrument also makes some minor changes to reduce compliance costs for industry and ensure that this legislative instrument is fit-for-purpose. The key changes are:

                allowing taxpayers to jointly make an election for an onshore integrated gas‑to‑liquid operation to aggregate the relevant costs into one upstream phase. For integrity reasons, the election is subject to restrictions;

                allowing an election for an onshore integrated operation to use the depreciated replacement cost method, to be made by taxpayers that use the Residual Pricing Method (RPM) . This changes the current requirement that the election be made by all of the participants in the integrated operation;

                allowing taxpayers to jointly make an election, for an integrated operation, to use the value of their own share of the end products as a component of the netback price in specified circumstances, instead of requiring them to obtain the value of the end products of all of the taxpayers in the operation. For integrity reasons, this election is subject to restrictions;

                adding an example to the Regulation to clarify that the Commissioner of Taxation’s power to agree to or to determine an RPM price can be used when required information is not accessible for practical or commercial reasons; and

                correcting the inconsistent treatment of storage costs for project sales gas in an integrated operation so that the cost for storage of sales gas after a non-arm’s length sale is treated as a downstream cost.

 

Further details of this legislative instrument are set out in the Attachment to the Explanatory Statement.

Human Rights Implications

This legislative instrument does not engage any of the applicable rights or freedoms.

Conclusion

This legislative instrument is compatible with human rights as it does not raise any human rights issues.