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SLI 2005 No. 329 Regulations as amended, taking into account amendments up to Petroleum Resource Rent Tax Assessment Amendment Regulation 2013 (No. 1)
Administered by: Treasury
Registered 24 Jul 2013
Start Date 29 Jun 2013
End Date 01 Apr 2016
Date of repeal 01 Apr 2016
Repealed by Petroleum Resource Rent Tax Assessment Regulation 2015

Commonwealth Coat of Arms

Petroleum Resource Rent Tax Assessment Regulations 2005

Select Legislative Instrument No. 329, 2005 as amended

made under the

Petroleum Resource Rent Tax Assessment Act 1987

Compilation start date:                     29 June 2013

Includes amendments up to:            SLI No. 154, 2013

About this compilation

The compiled instrument

This is a compilation of the Petroleum Resource Rent Tax Assessment Regulations 2005 as amended and in force on 29 June 2013. It includes any amendment affecting the compiled instrument to that date.

This compilation was prepared on 10 July 2013.

The notes at the end of this compilation (the endnotes) include information about amending Acts and instruments and the amendment history of each amended provision.

Uncommenced provisions and amendments

If a provision of the compiled instrument is affected by an uncommenced amendment, the text of the uncommenced amendment is set out in the endnotes.

Application, saving and transitional provisions for amendments

If the operation of an amendment is affected by an application, saving or transitional provision, the provision is identified in the endnotes.

Modifications

If a provision of the compiled instrument is affected by a textual modification that is in force, the text of the modifying provision is set out in the endnotes.

Provision ceasing to have effect

If a provision of the compiled instrument has expired or otherwise ceased to have effect in accordance with a provision of the instrument, details of the provision are set out in the endnotes.

 

  

  

  


Contents

Part 1—Preliminary                                                                                                             1

1............ Name of Regulations........................................................................... 1

2............ Commencement................................................................................... 1

Part 2—Definition provisions                                                                                         2

3............ Definitions.......................................................................................... 2

4............ When an integrated GTL operation exists........................................... 6

4A......... When integrated GTE operation exists................................................ 7

5............ Upstream and downstream stages of integrated operation................... 8

6............ Phase points of integrated operation.................................................. 13

7............ When there is multiple use of a phase............................................... 15

8............ Participants in integrated operation.................................................... 17

8A......... Non‑arm’s length transaction............................................................ 17

9............ Estimated average annual volume or mass of project natural gas...... 17

10.......... Meaning of volume coefficient........................................................... 18

10A....... Meaning of mass coefficient.............................................................. 19

11.......... Augmentation of a capital cost.......................................................... 20

12.......... Reduction of a capital cost................................................................. 21

13.......... Capital allowance.............................................................................. 21

Part 3—Assessable petroleum receipts                                                                    22

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

15.......... Assessable petroleum receipts—sales gas of integrated operation becoming excluded commodity other than by being sold................................................................................................... 23

16.......... Assessable petroleum receipts—natural gas of onshore integrated operation with non‑arm’s length sale                24

18.......... Advance pricing arrangements.......................................................... 25

Part 4—The substitute prices                                                                                        27

19.......... The comparable uncontrolled price.................................................... 27

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

21.......... RPM price where information is not available.................................. 28

22.......... Cost‑plus price.................................................................................. 29

23.......... Netback price.................................................................................... 30

Part 5—The residual pricing method                                                                      32

Division 5.1—The residual pricing method                                                     32

24.......... Costs are net of GST tax credits and adjustments............................. 32

25.......... The residual pricing method for working out cost‑plus and netback prices              32

Division 5.2—Identifying and classifying included costs                         36

26.......... Types of cost associated with integrated operation............................ 36

27.......... Exclusion of certain costs of integrated operation............................. 36

28.......... Direct, indirect and personal costs..................................................... 37

29.......... Exclusion of personal costs of other participants.............................. 38

30.......... Included costs................................................................................... 38

31.......... Capital and operating costs................................................................ 38

31A....... Amount and timing of included capital cost...................................... 39

32.......... Phase costs and upstream and downstream costs.............................. 39

Division 5.3—Allocating capital costs to years of tax                              41

33.......... Capital costs incurred for a unit of property completed over several years               41

34.......... Capital costs incurred before the production year—project sales gas produced first                41

35.......... Capital costs incurred before the production year—other marketable petroleum commodities produced first          42

36.......... Allocating capital costs to a year of tax............................................. 43

Division 5.4—Accounting for multiple use of a phase                               45

37.......... Applying the energy coefficients to costs of each phase................... 45

Part 6—Notional tax amount—sales gas                                                                46

38.......... Notional tax amount when RPM price not used (Act s 97(1AA)(b)) 46

39.......... Notional tax amount when RPM price used (Act s 97(1AA)(b))..... 46

40.......... Notional tax amount when no previous RPM price.......................... 47

Part 7—Miscellaneous                                                                                                       50

41.......... Review of decisions—prescribed decisions...................................... 50

42.......... Election to use residual pricing method—participant in onshore GTL operation      50

43.......... Election to use modified residual pricing method—integrated GTL operation existing before 2 May 2010             50

44.......... Election to use depreciated replacement cost method—integrated onshore operation existing before 2 May 2010   51

Endnotes                                                                                                                                    52

Endnote 1—Legislation history                                                                             52

Endnote 2—Amendment history                                                                           53

Endnote 3—Uncommenced amendments [none]                                          56

Endnote 4—Misdescribed amendments [none]                                             57

 


Part 1Preliminary

  

1  Name of Regulations

                   These Regulations are the Petroleum Resource Rent Tax Assessment Regulations 2005.

2  Commencement

                   These Regulations commence on the day after they are registered.

Part 2Definition provisions

  

3  Definitions

                   In these Regulations:

Act means the Petroleum Resource Rent Tax Assessment Act 1987.

actual mass of project natural gas, in relation to an integrated 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, in relation to an integrated 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 subregulation 18(1).

annual allocation, of a capital cost, has the meaning given by regulation 36.

arm’s length price means the consideration received or receivable in relation to a transaction in which the parties are dealing with each other at arm’s length.

assessable gas means:

                     (a)  in relation to calculating assessable petroleum receipts relating to sales gas—project sales gas; and

                     (b)  in relation to calculating assessable petroleum receipts relating to natural gas—project natural gas.

assessment year means the year of tax for which an RPM price is to be calculated using the residual pricing method.

augmented, in relation to a capital cost, has the meaning given by regulation 11.

capital allowance, for a financial year, has the meaning given by regulation 13.

capital cost has the meaning given by subregulation 31(1).

comparable uncontrolled price or CUP:

                     (a)  in relation to sales gas: see subregulation 19(1); and

                     (b)  in relation to natural gas: see subregulation 19(1A).

direct cost has the meaning given by regulation 28.

downstream, in relation to a cost, has the meaning given by subregulation 32(6).

downstream stage:

                     (a)  of an integrated GTL operation for the purposes of calculating assessable petroleum receipts relating to sales gas: see subregulation 5(2); and

                     (b)  of an integrated GTE operation for the purposes of calculating assessable petroleum receipts relating to sales gas: see subregulation 5(3); and

                     (c)  of an integrated GTL operation for the purposes of calculating assessable petroleum receipts relating to natural gas: see subregulation 5(5); and

                     (d)  of an integrated GTE operation for the purposes of calculating assessable petroleum receipts relating to natural gas: see subregulation 5(6).

estimated average annual mass of project natural gas for an integrated operation: see subregulation 9(7).

estimated average annual volume of project natural gas for an integrated operation: see subregulation 9(6).

expected operating life of an integrated operation: see subregulation 9(8).

included cost has the meaning given by regulation 30.

indirect cost has the meaning given by subregulation 28(5).

integrated GTE operation: see subregulation 4A(1).

integrated GTL operation: see subregulation 4(1).

integrated operation means an integrated GTE operation or an integrated GTL operation.

mass coefficient, for an integrated operation in a year of tax: see subregulation 10A(2).

MPC production year:

                     (a)  for an integrated GTL operation: see subregulation 4(9); and

                     (b)  for an integrated GTE operation: see subregulation 4A(9).

multiple use, of a unit of property, has the meaning given by regulation 7.

non‑arm’s length transaction: see regulation 8A.

operating cost has the meaning given by subregulation 31(2).

operating life:

                     (a)  of an integrated GTL operation: see subregulation 4(8); and

                     (b)  of an integrated GTE operation: see subregulation 4A(8).

participant, in an integrated operation, has the meaning given by regulation 8.

personal cost has the meaning given by subregulation 28(6).

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

phase, of an integrated operation, has the meaning given by subregulation 6(2).

phase cost, for a phase of an integrated operation, means the phase cost worked out using subregulations 32(2) and (3).

production date:

                     (a)  for an integrated GTL operation: see subregulation 4(7); and

                     (b)  for an integrated GTE operation: see subregulation 4A(7).

production year:

                     (a)  for an integrated GTL operation: see subregulation 4(6); and

                     (b)  for an integrated GTE operation: see subregulation 4A(6).

project electricity, of an integrated GTE operation: see subregulation 4A(4).

project liquid, of an integrated GTL operation, has the meaning given by subregulation 4(4).

project natural gas:

                     (a)  of an integrated GTL operation: see subregulation 4(2); and

                     (b)  of an integrated GTE operation: see subregulation 4A(2).

project product:

                     (a)  of an integrated GTL operation: see subregulation 4(5); and

                     (b)  of an integrated GTE operation: see subregulation 4A(5).

project sales gas:

                     (a)  of an integrated GTL operation: see subregulation 4(3); and

                     (b)  of an integrated GTE operation: see subregulation 4A(3).

reduced, in relation to a capital cost, has the meaning given by regulation 12.

residual pricing method has the meaning given by regulation 25.

RPM price, for a participant in an integrated operation in a year of tax, has the meaning given by regulations 20 and 21.

start date, in relation to capital cost incurred in an integrated operation, means 1 January of the financial year in which the cost is incurred.

taxpayer means a person who is a participant in an integrated operation and whose assessable petroleum receipts in relation to sales gas or natural gas from that operation are to be worked out under these Regulations because of regulation 14, 15 or 16.

upstream, in relation to a cost, has the meaning given by subregulation 32(5).

upstream stage:

                     (a)  of an integrated operation for the purposes of calculating assessable petroleum receipts relating to sales gas: see subregulation 5(1); and

                     (b)  of an integrated operation for the purposes of calculating assessable petroleum receipts relating to natural gas: see subregulation 5(4).

volume coefficient, for an integrated operation in a year of tax: see subregulation 10(2).

Note:          For the definitions of the following terms, see section 2 of the Act:

(a)    excluded commodity;

(b)    financial year;

(c)    instalment period;

(d)    long‑term bond rate;

(e)    marketable petroleum commodity;

(f)    onshore petroleum project;

(g)    petroleum;

(h)    petroleum project;

(i)     sales gas;

(j)     year of tax.

4  When an integrated GTL operation exists

             (1)  An integrated 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

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

             (2)  The project natural gas of the integrated GTL operation is the petroleum (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 integrated GTL operation is the sales gas mentioned in paragraph (1)(b) that will be processed into liquefied product within the overall operation (including any of that sales gas that is used in that processing).

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

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

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

                     (a)  if an election has been made in relation to the integrated GTL operation under regulation 43—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 integrated 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 integrated GTL operation.

             (9)  If the integrated 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 integrated GTL operation.

4A  When integrated GTE operation exists

             (1)  An integrated 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

                     (c)  some or all of the sales gas is, or will be, consumed in the commercial production of electricity.

             (2)  The project natural gas of the integrated GTE operation is the petroleum (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 integrated GTE operation is the sales gas mentioned in paragraph (1)(b) that will be consumed in the production of electricity within the overall operation (including any of that sales gas that is used in that production).

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

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

             (7)  The production date for the integrated 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 projects sales gas is last consumed in the production of project electricity is the operating life of the integrated GTE operation.

             (9)  If the integrated 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 integrated GTE operation.

5  Upstream and downstream stages of integrated operation

Assessable petroleum receipts relating to sales gas

             (1)  For the purposes of calculating assessable petroleum receipts relating to sales gas under regulation 14 or 15, the upstream stage of an integrated 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;

                     (c)  the storage of recovered project natural gas before being used in the production of sales 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;

                      (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 calculating assessable petroleum receipts relating to sales gas under regulation 14 or 15, the downstream stage of an integrated 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 transportation (if any) of project sales gas from the upstream stage for processing into project liquid;

                     (b)  the processing of the project sales gas into project liquid;

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

                     (d)  the transportation of project product for the processing of project sales gas mentioned in paragraph (b);

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

                      (f)  any multiple use of units of property for the transportation mentioned in paragraph (d);

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

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

                      (i)  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 (b); or

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

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

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

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

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

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

             (3)  For the purposes of calculating assessable petroleum receipts relating to sales gas under regulation 14 or 15, the downstream stage of an integrated 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 transportation (if any) of the project sales gas from the upstream stage for combustion to produce project electricity;

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

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

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

                     (e)  the sale of project electricity.

Assessable petroleum receipts relating to natural gas

             (4)  For the purposes of calculating assessable petroleum receipts relating to natural gas under regulation 16, the upstream stage of an integrated 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;

                     (c)  the storage of recovered project natural gas before use in the production of sales gas, if the storage occurs before the sale referred to in paragraph 24(1)(f) of the Act;

                     (d)  any multiple use of the units of property that are used to store recovered project natural gas (including units of property that are used to store recovered project natural gas before use in the production of sales gas, if the storage occurs before the sale referred to in paragraph 24(1)(f) of the Act);

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

                      (f)  any multiple use of units of property for transportation referred to in paragraph (e).

             (5)  For the purposes of calculating assessable petroleum receipts relating to natural gas under regulation 16, the downstream stage of an integrated 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 recovered project natural gas, if the storage occurs after the sale referred to in paragraph 24(1)(f) of the Act;

                     (b)  any multiple use of the units of property that are used to store recovered project natural gas (including units of property that are used to store recovered project natural gas, if the storage occurs after the sale referred to in paragraph 24(1)(f) of the Act);

                     (c)  the production of project sales gas;

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

                     (e)  the transportation of project product for the production mentioned in paragraph (c);

                      (f)  any multiple use of units of property for transportation mentioned in paragraph (e).

                     (g)  the storage of project sales gas at or adjacent to the place at which it is produced;

                     (h)  any multiple use of units of property that are used for the storage of project sales gas mentioned in paragraph (g);

                      (i)  the transportation (if any) of project sales gas for processing into project liquid;

                      (j)  the processing of the project sales gas into project liquid;

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

                      (l)  the transportation of project product for the processing of project sales gas mentioned in paragraph (j);

                    (m)  any activity associated with an action mentioned in paragraphs (i) to (l) for the purpose of using project sales gas to produce project liquid;

                     (n)  any multiple use of units of property for the transportation mentioned in paragraph (l);

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

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

                     (q)  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 (h); or

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

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

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

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

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

                      (s)  any multiple use of units of property for the storage, loading or transportation mentioned in paragraphs (p), (q) and (r).

             (6)  For the purposes of calculating assessable petroleum receipts relating to natural gas under regulation 16, the downstream stage of an integrated 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 production of project sales gas;

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

                     (c)  the transportation of project product for the production mentioned in paragraph (a);

                     (d)  any multiple use of units of property for transportation mentioned in paragraph (c).

                     (e)  the storage of project sales gas at or adjacent to the place at which it is produced;

                      (f)  any multiple use of units of property that are used for the storage of project sales gas mentioned in paragraph (e);

                     (g)  the transportation (if any) of the project sales gas for combustion to produce project electricity;

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

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

                      (j)  any activity associated with an action mentioned in paragraphs (g) to (i) for the purposes of using project sales gas to produce project electricity;

                     (k)  the sale of project electricity.

Note:          Phases are explained using subregulations 6(1) and (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 an integrated operation may include a number of phases, but each stage ends when the actions associated with the last phase have been completed.

6  Phase points of integrated operation

Note:          This regulation divides the integrated 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:

·            the various joint costs incurred by participants in the operation are attributed to each phase (regulation 32); and

·            the capital costs are annualised (Division 5.3); and

·            the costs for the assessment year are apportioned between the project product and other product, using an energy coefficient appropriate for the phase (regulation 37).

                   This procedure assumes that the same phase points apply over the life of the project. 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.

             (1)  The phase points of an integrated 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.

Example 1:    An integrated 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 an integrated 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 an integrated GTL operation is transported in a pipeline that is part of the operation, and therefore enters the down stream phase; 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 in the operation is reduced. The point of sale is therefore a phase point.

          (1A)  However, paragraph (1)(b) does not apply to an integrated GTL operation for which an election has been made under regulation 43.

             (2)  The integrated 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).

             (3)  The participants in the integrated 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 them at that time; and

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

          (3A)  However, subregulation (3) does not apply if an election has been made in relation to the integrated operation under regulation 43.

             (4)  The participants in the integrated 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).

7  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 integrated 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 integrated 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 integrated 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.

          (3A)  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 integrated 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.

             (4)  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 integrated 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.

             (5)  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 integrated 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.

             (6)  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 integrated 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.

8  Participants in integrated operation

                   A person is a participant in the 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.

8A  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.

9  Estimated average annual volume or mass of project natural gas

             (1)  The participants in an integrated 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:

                     (a)  if an election has been made in relation to the integrated operation under regulation 43—no later than:

                              (i)  the day on which the participants must give to the Commissioner a starting base return under subclause 22(2) of Schedule 2 to the Act; or

                             (ii)  a later day that the Commissioner allows.

                     (b)  otherwise—in the financial year before the production year.

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

                     (a)  accepts the estimate or revised estimate; or

                     (b)  has substituted an estimate under subregulation (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 subregulation (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):

             (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):

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

10  Meaning of volume coefficient

             (1)  In this regulation, for an integrated 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 regulation 43—the 2012‑13 year of tax; and

                     (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 an integrated operation in which natural gas is measured by volume in a year of tax (the current year) is:

                  

where:

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

VB is:

                     (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

                     (c)  if the current year is after the base year—the amount calculated using the formula:

                           

                            where:

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

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

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

10A  Meaning of mass coefficient

             (1)  In this regulation, for an integrated 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 regulation 43—the 2012‑13 year of tax; and

                     (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 an integrated operation in which natural gas is measured by mass in a year of tax (the current year) is:

where:

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

MB is:

                     (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

                     (c)  if the current year is after the base year—the amount calculated using the formula:

                            where:

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

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

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

11  Augmentation of a capital cost

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

                  

where:

Capital allowance is:

                     (a)  for subregulation 33(2)—the capital allowance for the final cost year; and

                     (b)  for subregulation 34(3)—the capital allowance for the production year; and

                     (c)  for subregulation 35(3)—the capital allowance for the production year; and

                     (d)  for paragraph 35(4)(a)—the capital allowance for the MPC production year.

N is the number of years.

12  Reduction of a capital cost

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

                  

where:

Capital allowance is:

                     (a)  for paragraph 35(4)(b)—the capital allowance for the MPC production year;

                     (b)  for subregulation 35(5)—the capital allowance for the year of tax of the start date for the capital cost.

N is the number of years.

13  Capital allowance

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

long‑term bond rate + 7 percentage points

Part 3Assessable petroleum receipts

  

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

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

                     (a)  it is project sales gas of an integrated 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 the sale, the amount of assessable petroleum receipts of a taxpayer is the amount calculated in accordance with the arrangement.

Comparable uncontrolled price

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

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

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

                     (c)  no election has been made in relation to the integrated operation under regulation 42 or 43.

             (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 volume or mass of project sales gas sold.

Residual pricing method

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

                     (a)  no advance pricing arrangement applies 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 integrated operation under regulation 42 or 43.

             (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 volume or mass of project sales gas sold.

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

             (1)  For paragraph 24(1)(e) of the Act, this regulation applies to sales gas that becomes or became an excluded commodity if it is project sales gas of an integrated operation.

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

Advance pricing arrangement

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

Comparable uncontrolled price

             (3)  The assessable petroleum receipts of a taxpayer in relation to the transaction is the amount calculated under subregulation (4) if:

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

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

                     (c)  no election has been made in relation to the integrated operation under regulation 42 or 43.

             (4)  The amount is the comparable uncontrolled price multiplied by the volume or mass of project sales gas subject to the transaction.

Residual pricing method

             (5)  The assessable petroleum receipts of a taxpayer in relation to the transaction is the amount calculated under subregulation (6) if:

                     (a)  no advance pricing arrangement applies 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 integrated operation under regulation 42 or 43.

             (6)  The amount is the RPM price of project sales gas for the taxpayer in the year of tax in which the transaction took place multiplied by the volume or mass of project sales gas subject to the transaction.

             (7)  In this regulation:

transaction means the act by which the project sales gas becomes or became an excluded commodity.

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

             (1)  For subparagraph 24(1)(f)(ii) of the Act, this regulation applies to natural gas that has been sold if:

                     (a)  it is project natural gas of an integrated operation that recovers petroleum from an onshore petroleum project; and

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

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

Advance pricing arrangement

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

Comparable uncontrolled price

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

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

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

                     (c)  no election has been made in relation to the integrated operation under regulation 42 or 43.

             (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 volume or mass of project natural gas sold.

Residual pricing method

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

                     (a)  no advance pricing arrangement applies 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 integrated operation under regulation 42 or 43.

             (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 natural gas for the taxpayer in the year of tax in which the sale took place multiplied by the volume or mass of project natural gas sold.

18  Advance pricing arrangements

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

             (2)  An advance pricing arrangement must specify:

                     (a)  the term of the arrangement; and

                     (b)  how the assessable receipts of the participant are to be calculated; and

                     (c)  conditions under which the arrangement will apply.

Part 4The substitute prices

  

19  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:

                     (a)  that was obtained for a sale in a market that the Commissioner is satisfied is a relevant market in relation to the transaction; and

                     (b)  that the Commissioner is satisfied is an observable arm’s length price.

          (1A)  A comparable uncontrolled price, or CUP, in relation to a sale of a volume or mass of project natural gas to which paragraph 24(1)(f) of the Act applies, is a price for natural gas:

                     (a)  that was obtained for a sale in a market that the Commissioner is satisfied is a relevant market in relation to the transaction; and

                     (b)  that the Commissioner is satisfied is an observable arm’s length price.

             (2)  In determining whether a market is relevant, the demand and supply characteristics of the market must be taken into account, including:

                     (a)  the composition of sales gas or natural gas sold in the market; and

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

                     (c)  the end use for the sales gas or natural gas sold in the market.

Example:    Retail, wholesale, manufacturing, feedstock, domestic.

             (3)  In determining whether a market is relevant, the following factors must also be taken into account:

                     (a)  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;

                     (b)  market strategies;

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

                     (d)  processing costs;

                     (e)  technology used in processing;

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

             (4)  In this regulation:

relevant transaction, for a volume or mass of project sales gas, means:

                     (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.

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

                   Subject to this Part, the RPM price of an assessable gas for a taxpayer in a year of tax, is:

                     (a)  if the cost‑plus price of the assessable gas is higher than the netback price—the netback price; and

                     (b)  otherwise—the price given by the formula:

                           

where the cost‑plus price and the netback price of the assessable gas are obtained by following Steps 1 to 13 of the residual pricing method.

21  RPM price where information is not available

             (1)  This regulation applies if a taxpayer does not have sufficient information to work out the taxpayer’s RPM price for an assessable gas for a year of tax using the residual pricing method.

             (2)  If the taxpayer and the Commissioner are able to agree on a price for this subregulation, 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 by the Commissioner using the residual pricing method, and using the information available from other participants in the integrated 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 subregulation (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 integrated operation, and there is no agreement between the participants as to how these 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:    If a person becomes a participant in the integrated operation, but does not have access to all the information required to work out the RPM price, then this regulation would apply.

22  Cost‑plus price

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

where:

QAG (quantity of assessable gas) is the quantity, measured by volume or mass, of the assessable gas that was produced in the operation in the year of tax.

QC (quantity coefficient) is:

                     (a)  for an integrated operation that measures by volume—the volume coefficient for the year of tax; and

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

UCC (upstream capital costs) is the total amount of upstream capital costs incurred by the participants and allocated to the year of tax (see regulation 25).

UOC (upstream operating costs) is the total amount of upstream operating costs incurred by the participants in the year of tax (see regulation 25).

23  Netback price

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

where:

DCC (downstream capital costs) is the total amount of downstream capital costs incurred by the participants and allocated to the year of tax (see regulation 25).

DOC (downstream operating costs) is the total amount of downstream operating costs incurred by the participants in the year of tax (see regulation 25).

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

EPVal (end product value) is the total market value in the year of tax of:

                     (a)  for an integrated GTL operation—the project liquid produced; or

                     (b)  for an integrated GTE operation—the project electricity produced.

QAG (quantity of assessable gas) is the quantity, measured by volume or mass, of the assessable gas that was produced in the operation in the year of tax.

QC (quantity coefficient) is:

                     (a)  for an integrated operation that measures by volume—the volume coefficient for the year of tax; and

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

QTDG (quantity of taxpayer’s downstream gas) is 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 an integrated 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 an integrated GTE operation—consumed in the production of project electricity that the taxpayer was entitled to receive.

             (2)  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.

             (3)  For a quantity of project liquid or project electricity to which subregulation (2) does not apply, the market value of the quantity is the market value at the end of the downstream stage.

             (4)  If the Commissioner is not satisfied that sufficient information is available to determine a market value for subregulation (3), the market value of the quantity of project liquid or project electricity is the amount determined by the Commissioner as fair and reasonable.

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

Part 5The residual pricing method

Division 5.1The residual pricing method

24  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 reduced by:

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

                     (b)  a decreasing adjustment.

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

                   The residual pricing method of calculating an RPM price for a taxpayer, in relation to the assessment year, is the following:

 

When the method can be used

An RPM price can be calculated by this method only if information about the direct costs of all the participants (other than marketing and selling costs) is available. Information about the operating costs is required for the year of tax concerned. Information about the capital costs is required for all previous financial years as well (except if an election under regulation 43 or 44 applies to the operation, in which case less information is needed for capital costs incurred before 2 May 2010). If the information is not available, regulation 21 will apply.

What the method does

The method identifies the pooled costs of the operation attributable to the project product, and the personal costs of the taxpayer attributable to the taxpayer’s share of project product. The pooled costs are used to calculate the major element of the cost‑plus and netback prices; this element will be the same for each taxpayer participating in the operation. The personal costs are used only to calculate a minor element of the netback price; this element will vary with the individual taxpayer.

First, the costs that were incurred by the participants in relation to the integrated operation are identified.

Certain costs relating to exploration, etc, are excluded.

That portion of the costs that is not attributable to the integrated operation is excluded.

The personal costs of other participants are excluded. The personal costs of the taxpayer are included, but treated separately.

The included costs, where necessary divided into separate costs, are attributed to the various phases of the operation.

Capital costs are spread over the life of the operation and the costs for the assessment year identified.

The amount of each cost attributed to an assessment year is adjusted to account for the use of facilities of the operation for activities that are not part of the project.

The direct costs of all the participants (other than marketing and selling costs) that are attributable to the production of assessable gas and project liquid (for an integrated GTL operation) or project electricity (for an integrated GTE operation) are pooled to give unit costs that apply to the operation as a whole. The personal costs of the taxpayer (marketing and selling costs) attributable to the taxpayer’s shares of assessable gas and project liquid or project electricity are applied to give supplementary unit costs. These are then used to calculate the taxpayer’s cost‑plus and netback prices.

Step 1

Identify the types of cost associated with the operation

Apply regulation 26 to identify all types of cost associated with the integrated operation up to and including the assessment year. At this point, only the type of cost needs to be known—information about individual costs and their amounts is not necessary.

Step 2

Exclude exploration costs, etc

Apply regulation 27 to exclude certain types of cost, including costs of such matters as exploration or feasibility studies.

Step 3

Identify direct and indirect costs for the operation

Apply regulation 28 to classify each type of cost not so far excluded as a direct cost or an indirect cost.

Step 4

Exclude personal costs of other participants

Apply regulation 29 to exclude personal costs of other participants.

The costs that are left are the included costs for the taxpayer (regulation 30). These consist of the pooled non‑personal costs of all the participants in the integrated operation, and the personal costs of the taxpayer.

Step 5

Classify the included costs as operating or capital costs

Apply regulation 31 to classify each included cost as an operating cost or a capital cost.

Step 6

Identify the amounts of the relevant included costs

Identify the amount of:

·     each included operating cost incurred in the assessment year; and

·     each included capital cost incurred up to and including the assessment year.

If an election has been made under regulation 43 or 44 in relation to an integrated GTL operation, apply regulation 31A to capital costs that were incurred before the 2012‑13 year of tax.

Step 7

Attribute the direct costs to the different phases

Apply regulation 32 to classify each direct cost as a phase cost of one of the phases of the integrated operation, or as a combination of such phase costs. Regulation 32 also divides phase costs and indirect costs into upstream and downstream costs.

Step 8

Augment capital costs for units of property that take several years to complete

If a capital cost was incurred in a year before the completion year of the unit of property for which it was incurred, augment it as appropriate, then treat it for Step 9 (if applicable) or Step 10 (otherwise) as having been incurred in the completion year for that unit of property (regulation 33).


Step 9

Augment and reduce early capital costs

If a capital cost was incurred before the production year, augment it and reduce it as appropriate, then treat it for Step 10 as having been incurred in the production year (regulations 34 and 35).

Step 10

Allocate capital costs to years of tax

For each capital cost, allocate to each year of tax from the production year onward a cost with the amount given by regulation 36.

Step 11

Identify costs for the assessment year

The costs for the assessment year are:

·     the included operating costs for the assessment year; and

·     the capital costs allocated to the assessment year under Step 10.

Step 12

Apply the energy coefficients to the costs

For each cost for the assessment year, apply regulation 37 with the energy coefficient appropriate for the phase to which the cost has been attributed.

Note:       This removes that part of each cost attributable to multiple use of a phase.

Step 13

Obtain the cost‑plus and netback prices

Use the costs for the assessment year to calculate the participant’s cost‑plus price (regulation 22) and netback price (regulation 23) for the assessment year.

Step 14

Obtain the RPM price

Apply regulation 20 to determine the participant’s RPM price for the assessment year.

Division 5.2Identifying and classifying included costs

26  Types of cost associated with integrated operation

             (1)  For Step 1 of the residual pricing method, costs associated with an integrated operation include all costs incurred by or on behalf of the participants that are attributable, or indirectly attributable, or partly attributable, to the operation, whether incurred during the operating life of the operation or before the production year.

             (2)  For Step 1 of the residual pricing method, a payment or allowance between participants is not a cost associated with the integrated operation.

             (3)  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 integrated operation; and

                     (b)  was later used in the operation;

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

             (4)  If a cost is only partly attributable to the integrated operation, the amount of the cost is taken to be the amount that can reasonably be apportioned to the operation.

27  Exclusion of certain costs of integrated operation

                   For Step 2 of the residual pricing method, a cost associated with an integrated operation is excluded from the costs of the operation if it is one of the following:

                     (a)  an exploration cost under section 37 of the Act;

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

                     (c)  a cost incurred in removing infrastructure facilities used for an integrated GTL operation;

                     (d)  an environment or site restoration cost;

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

28  Direct, indirect and personal costs

             (1)  For Step 3 of the residual pricing method, costs associated with an integrated operation are divided into direct costs and indirect costs in accordance with this regulation.

             (2)  A cost is a relevant sector cost if it is wholly and directly attributable to 1 or more of the following activities of the operation:

                     (a)  production;

                     (b)  transport;

                     (c)  storage;

                     (d)  marketing;

                     (e)  selling.

             (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 two 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 subregulation (3) or (4) is an indirect cost.

Examples of indirect costs

Business insurance, office expense, administrative and accounting costs, payment 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 this regulation, the threshold amount 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; and

                             (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.

29  Exclusion of personal costs of other participants

                   For Step 4 of the residual pricing method, a personal cost that was incurred by another participant is excluded.

30  Included costs

                   A cost associated with an integrated operation is an included cost for the taxpayer if it is not excluded under regulation 27 or 29.

31  Capital and operating costs

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

                     (a)  it is not a personal cost; and

                     (b)  either:

                              (i)  it was incurred before the production date; or

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

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

Example of application of subparagraph (1)(b)(i)

If a person incurs operating expenses before the production date, they are treated as capital costs for the purposes of these Regulations.

             (2)  For Step 5 of the residual pricing method, an included cost for a participant in an integrated operation is an operating cost if:

                     (a)  it is not a personal cost; and

                     (b)  it is not a capital cost.

             (3)  A cost which is a capital cost only because of subparagraph (1) (b) (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 regulation 33.

31A  Amount and timing of included capital cost

             (1)  For Step 6 of the residual pricing method, this regulation applies to an included capital cost if:

                     (a)  the cost is for:

                              (i)  an integrated GTL operation for which an election has been made under regulation 43; or

                             (ii)  an integrated onshore operation for which an election has been made under regulation 44; and

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

             (2)  An included capital cost to which this regulation applies is taken, for the purpose of the residual pricing method, to have been incurred on 1 July 2012 and not incurred when it was actually incurred.

Note:          This will affect the operation of Steps 8 to 10 of the method.

             (3)  If the 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 at 1 May 2010.

             (4)  In this regulation:

depreciated replacement cost has the same meaning as in Accounting Standard AASB 136 Impairment of Assets.

32  Phase costs and upstream and downstream costs

             (1)  For Step 7 of the residual pricing method, the included direct and indirect costs are attributed to the various phases of the operation in accordance with this regulation.

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

             (3)  If a direct cost for the integrated 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.

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

Note:          Regulation 37 does not apply to these costs, so that 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 subregulation (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 subregulation (4), is a downstream cost.

Division 5.3Allocating capital costs to years of tax

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

             (1)  For Step 8 of the residual pricing method, this regulation applies to an included capital cost for the taxpayer that is incurred in relation to a unit of property that is constructed over a period of time and for which the last capital cost is incurred in a later financial year (the final cost year).

             (2)  The included capital cost is augmented for the number of calendar years between the start date for the included capital cost and the 1 January of the final cost year.

Note:          Regulations 34 and 35 are also relevant to the included capital cost.

             (3)  The included capital cost so augmented is taken to be incurred in the final cost year.

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

             (1)  For Step 9 of the residual pricing method, this regulation 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.

             (2)  The included capital cost:

                     (a)  is taken to be the amount that has been augmented in accordance with regulation 33; and

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

and is not to be the actual included capital cost incurred when it was actually incurred.

             (3)  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.

             (4)  The included capital cost so augmented is taken to be incurred in the production year.

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

             (1)  For Step 9 of the residual pricing method, this regulation 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

                     (c)  the MPC production year for the operation is before the production year.

             (2)  The included capital cost:

                     (a)  is taken to be the amount that has been augmented in accordance with regulation 33; and

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

and is not to be the actual included capital cost incurred when it was actually incurred.

             (3)  If the included capital cost is incurred for a unit of property that will be used solely for the recovery of project natural gas, the production of project sales gas, the processing of project sales gas into project liquid, the combustion of project sales gas to produce project electricity or 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.

             (4)  If subregulation (3) 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.

             (5)  If subregulation (3) 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.

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

36  Allocating capital costs to a year of tax

             (1)  For Step 10 of the residual pricing method, this regulation applies to an included capital cost for the taxpayer (the capital cost) 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 or reduced under regulation 34 or 35.

             (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 expected life of the unit.

             (3)  If the expected operating life of the unit is 15 years or less, the annual allocation for the capital cost is:

                  

where:

Capital allowance is the capital allowance for the cost year (regulation 13).

N is the number of calendar years in the expected operating life of the unit.

             (4)  If the expected operating life of the unit is more than 15 years, the annual allocation for the capital cost is:

                  

where:

Capital allowance is the capital allowance for the cost year (regulation 13).

             (5)  If, at the end of the assessment year, the expected operating life of the unit has changed since the end of the cost year:

                     (a)  the annual allocation of the capital cost for the assessment year is calculated using the new expected operating life of the unit; and

                     (b)  the annual allocations of the capital cost for the calculation of RPM prices for years before the change are unaffected.

             (6)  For this regulation, the expected operating life of the unit is the period of N calendar years between:

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

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

             (7)  For this regulation, a cost that is a capital cost only because of subparagraph 31(1)(b)(i) is taken to have been incurred in relation to a unit of property that has an expected operating life that is the expected operating life of the operation.

Division 5.4Accounting for multiple use of a phase

37  Applying the energy coefficients to costs of each phase

                   For 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:

                  

where:

C is the amount of the cost before the application of this regulation.

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

Total phase energy is the energy content of all the petroleum product that enters the phase in the year of tax.

Part 6Notional tax amount—sales gas

  

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

                   For paragraph 97(1AA)(b) of the Act, if any of the following is used in working out assessable petroleum receipts for a person under regulation 14, 15 or 16:

                     (a)  the comparable uncontrolled price;

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

                     (c)  an advance pricing arrangement;

the amount that is to be included in calculating the current period liability under subsection 97(1A) of the Act is the amount of assessable petroleum receipts worked out under regulation 14, 15 or 16.

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

             (1)  This regulation applies if a participant in an integrated operation uses an RPM price for an assessable gas in working out assessable petroleum receipts under regulation 14, 15 or 16, and had an RPM price for the previous year of tax.

             (2)  For paragraph 97(1AA)(b) of the Act, the amount that is to be included in calculating the current period liability under subsection 97(1A) of the Act is:

where:

EPVal is the end product value for the participant in the instalment period.

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

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

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

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

             (3)  The end product value for the participant in a period is the total market value of:

                     (a)  for an integrated GTL operation—the project liquid to which the participant is entitled in the period; or

                     (b)  for an integrated GTE operation—the project electricity to which the participant is entitled in the period.

             (4)  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.

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

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

40  Notional tax amount when no previous RPM price

             (1)  This regulation applies if a taxpayer uses an RPM price for an assessable gas in working out assessable petroleum receipts under regulation 14, 15 or 16, but does not have an RPM price for the previous year of tax.

             (2)  Subject to subregulation (3), the amount that is to be included in calculating the current period liability under subsection 97(1A) of the Act is:

where:

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

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

RPM price is the RPM price for the assessable gas calculated as if the instalment period were the assessment year (including under regulation 21, if applicable).

             (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 subregulation 39(2) as if the factors in the equation 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 an integrated 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 an integrated 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 7Miscellaneous

  

41  Review of decisions—prescribed decisions

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

                     (a)  a decision under regulation 8A whether a transaction is a non‑arm’s length transaction;

                     (b)  a decision to substitute an estimate under subregulation 9(5);

                     (c)  a determination under regulation 19 that no comparable uncontrolled price exists;

                     (d)  a determination of the RPM price under regulation 21;

                     (e)  a determination under subregulation 23(4) or 39(6) of the market value of project liquid or project electricity.

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

             (1)  A participant in an integrated GTL operation that recovers petroleum from an onshore petroleum project may elect to use the residual pricing method.

             (2)  An election under this regulation:

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

                     (b)  must be given to the Commissioner in the financial year before the production year for the operation.

             (3)  An election under this regulation is irrevocable.

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

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

             (2)  An election under this regulation:

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

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

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

                              (i)  the day on which the participants must give to the Commissioner a starting base return under subclause 22(2) of Schedule 2 to the Act; or

                             (ii)  a later day that the Commissioner allows.

             (3)  An election under this regulation is irrevocable.

Note:          If an election has been made under this regulation, a number of provisions in these Regulations apply or operate differently. The differences include changes to the rules about capital costs (regulations 31 and 31A), and a reduction in the number of phases in an operation (regulation 6).

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

             (1)  The participants in an integrated onshore operation may elect to use the depreciated cost method.

             (2)  An election under this regulation:

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

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

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

                              (i)  the end of the financial year before the production year; or

                             (ii)  a later day that the Commissioner allows.

             (3)  An election under this regulation is irrevocable.


Endnotes

 

Endnote 1—Legislation history

This endnote sets out details of the legislation history of the Petroleum Resource Rent Tax Assessment Regulations 2005.

 

 

Number and year

FRLI registration date

Commencement
date

Application, saving and transitional provisions

329, 2005

19 Dec 2005 (see F2005L03882)

20 Dec 2005

 

154, 2013

28 June 2013 (see F2013L01219)

29 June 2013

 

Endnote 2—Amendment history

This endnote sets out the amendment history of the Petroleum Resource Rent Tax Assessment Regulations 2005.

 

ad. = added or inserted    am. = amended    rep. = repealed    rs. = repealed and substituted    exp. = expired or ceased to have effect

Provision affected

How affected

Part 2

 

r. 3......................................

am. No. 154, 2013

Note to r. 3..........................

ad. No. 154, 2013

r. 4......................................

am. No. 154, 2013

r. 4A....................................

ad. No. 154, 2013

r. 5......................................

rs. No. 154, 2013

Heading to r. 6.....................

rs. No. 154, 2013

Note to r. 6 heading.............

am. No. 154, 2013

r. 6......................................

am. No. 154, 2013

r. 7......................................

am. No. 154, 2013

Heading to r. 8.....................

rs. No. 154, 2013

r. 8......................................

am. No. 154, 2013

r. 8A....................................

ad. No. 154, 2013

r. 9......................................

rs. No. 154, 2013

r. 10....................................

am. No. 154, 2013

r. 10A..................................

ad. No. 154, 2013

r. 11....................................

am. No. 154, 2013

r. 12....................................

am. No. 154, 2013

r. 13....................................

am. No. 154, 2013

Part 3

 

Heading to Part 3.................

am. No. 154, 2013

r. 14....................................

rs. No. 154, 2013

r. 15....................................

rs. No. 154, 2013

r. 16....................................

rs. No. 154, 2013

r. 17....................................

rep. No. 154, 2013

r. 18....................................

am. No. 154, 2013

Part 4

 

r. 19....................................

am. No. 154, 2013

Heading to r. 20...................

rs. No. 154, 2013

r. 20....................................

am. No. 154, 2013

r. 21....................................

am. No. 154, 2013

r. 22....................................

rs. No. 154, 2013

r. 23....................................

am. No. 154, 2013

Part 5

 

Division 5.1

 

r. 25....................................

am. No. 154, 2013

Division 5.2

 

Heading to r. 26...................

rs. No. 154, 2013

r. 26....................................

am. No. 154, 2013

Heading to r. 27...................

rs. No. 154, 2013

r. 27....................................

am. No. 154, 2013

r. 28....................................

am. No. 154, 2013

r. 30....................................

am. No. 154, 2013

r. 31....................................

am. No. 154, 2013

r. 31A..................................

ad. No. 154, 2013

r. 32....................................

am. No. 154, 2013

Division 5.3

 

r. 33....................................

am. No. 154, 2013

r. 35....................................

am. No. 154, 2013

Part 6

 

r. 38....................................

am. No. 154, 2013

r. 39....................................

am. No. 154, 2013

r. 40....................................

am. No. 2013

Part 7

 

r. 41....................................

am. No. 154, 2013

r. 42....................................

ad. No. 154, 2013

r. 43....................................

ad. No. 154, 2013

r. 44....................................

ad. No. 154, 2013

 

Endnote 3—Uncommenced amendments [none]

There are no uncommenced amendments.

 

Endnote 4—Misdescribed amendments [none]

There are no misdescribed amendments.