Petroleum Resource Rent Tax Assessment Regulations 2005

Explanatory Statement

Issued by the Authority of the Minister for Revenue and Assistant Treasurer

Petroleum Resource Rent Tax Assessment Act 1987

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

In addition, section 24 of the Act provides for regulations to determine the value of sales gas in integrated gas-to-liquid (GTL) projects. In these circumstances, sales gas is the relevant marketable petroleum commodity for PRRT purposes. It is profit from the production of sales gas that is taxed under the PRRT.

The purpose of the Regulations is to provide the petroleum industry with certainty in the application of the Act to integrated GTL operations. There are a number of proposals for GTL projects that benefit from the increased certainty provided by the Regulations. Such projects usually have common ownership of the upstream production stage, which extracts the natural gas, and the downstream processing stage, which transforms the gas to a liquefied product. Further, an arm's length sale of sales gas does not occur in the circumstances where there is common ownership of all stages of the operation. Consequently, the Regulations provide a framework to determine a price for the sales gas that moves from the upstream stage to the downstream stage of the operation. This price is required for the purpose of calculating the PRRT liability of the project.

In particular, the Regulations:

define an integrated GTL project;
specify the division of the project into phases for the purpose of allocating project costs to participants and project operations;
provide three options for determining assessable petroleum receipts in an integrated GTL project: an Advanced Pricing Agreement, a Comparable Uncontrolled Price or the Residual Price Methodology (RPM); and
specify the methodology for calculating an RPM.

Extensive consultation was undertaken in preparing the Regulations. The upstream petroleum industry supports the Regulations.

Details of the Regulations are set out in the Attachments.

The Regulations commenced on registration.

Regulation impact statement

Policy objective

The policy objective of the Regulations is to provide a framework to determine a price for gas in the case of an integrated gas-to-liquids (GTL) operation. The framework enables a petroleum resource rent tax (PRRT) liability to be calculated in the upstream component of an integrated GTL operation where there is no arm's length price and no comparable uncontrolled price (ie no price that can be observed in a relevant market place for the sale of gas in an arm's length transaction).

The proposal was announced by the Treasurer and the former Minister for Industry, Science and Resources in Media Release No. 58 of 23 December 1998.

Background

The PRRT was enacted in 1987 through the Petroleum Resource Rent Tax Assessment Act 1987 (the Act). PRRT is an income-tax-deductible profits based tax applied to petroleum production. It is applied at a rate of 40 per cent on the taxable profit of a project (ie assessable receipts less project related expenditures including eligible exploration expenditures). If expenditures are not immediately deducted (due to expenditures being greater than receipts), they are carried forward and are augmented by various amounts depending on the kind of expenditure.

For gas that is to be further processed in an integrated GTL operation, the PRRT taxing point is where a marketable petroleum commodity (sales gas) is produced (ie the upstream component) and not where the gas is liquefied (ie the downstream component). GTL operations are likely to have the same ownership of the upstream production component and the downstream processing component. The downstream component of an integrated GTL operation is not subject to PRRT.

There is uncertainty surrounding the application of the Act to integrated GTL operations because there may not be an arms length transaction in the transfer of gas between the upstream and downstream components. Further, the same uncertainty arises where the product is sold under a non-arm's length transaction and there is no comparable uncontrolled price. Consequently, in these cases a gas transfer price is required to value sales gas for the purpose of calculating the PRRT liability. The Taxation Laws Amendment Act (No. 6) 2001 made amendments to the Act to enable a framework or methodology to determine the gas transfer price to be incorporated in regulations. However, without such a framework, the Act does not provide any guidance to the Commissioner of Taxation in determining what may be a fair and reasonable price where the gas is used in an integrated GTL operation.

Implementation options

Options

There are three options to implement the policy objective referred to above. The first option is to continue with the status quo. The Act requires the Commissioner of Taxation to determine a notional arm's length price where one does not exist. The second option is to use a shadow price approach. The shadow price approach involves using the price observed in an arm's length transaction between unrelated parties. The third option is introducing through regulations a framework for determining the gas transfer price. This includes introducing a methodology to value the gas where a sale of the gas does not take place at the taxing point, or a non-arm's length transaction takes place at the taxing point, or there is no comparable uncontrollable price.

The first option does not address the issues of transparency that is the basis of industry's concerns. The second option involving the shadow pricing methodology can only be used where there is an observable comparable arm's length price. It is not expected that the shadow pricing method could be reliably applied in the foreseeable future. Consequently, the third option of introducing through regulations a framework for calculating the gas transfer price is the only feasible approach.

Gas transfer price regulations

The Regulations allow for the gas transfer price to be determined by an advanced pricing arrangement agreed between the taxpayer and the Commissioner of Taxation, or by an uncontrollable comparable price, or by the residual price method. The amount of assessable petroleum receipts of the taxpayer, in relation to the project sales gas subject to the sale, is the amount calculated in accordance with any applicable advanced pricing arrangement. Where such an arrangement does not exist, the amount can be the comparable uncontrollable price for the sale of gas. In the case where an advanced pricing arrangement or comparable uncontrollable price does not exist, the residual price methodology (RPM) price is used by the taxpayer to determine the gas transfer price for the project sales gas of the integrated GTL operation. The RPM is set out in the Regulations. In essence, each taxpayer makes the choice between the advanced pricing arrangement and the residual price method, and the question of whether an uncontrollable comparable price is used is dependent on the facts and circumstances at the time. In the event that the residual price method produces an anomalous gas transfer price, the Regulations provide mechanisms to address such a result.

The RPM incorporates netback and cost-plus calculations to value the gas as defined by the Regulations. The cost-plus price is the price the upstream stage of an integrated GTL operation would sell its sales gas for in order to cover its upstream costs. The netback price is the price paid for sales gas that allows the downstream stage of the integrated GTL operation to cover its costs, given the price obtained for its project liquid. In both cases, the calculations allow for a rate of return on capital costs incurred.

The difference between the price generated by the netback formula and the price generated by the cost-plus formula identifies the residual profit for a project. Factors contributing to the residual profit for a project include intellectual property and know-how related to gas production, process and marketing.

Although the application of the netback and cost-plus formula define the residual profit in a project, no theoretical basis exists for determining how the residual profit should be split between the netback and cost-plus prices to arrive at a single price. Consequently, the RPM splits this differential equally. This split reflects the integrated and interdependent nature of an integrated GTL operation. It is also the most appropriate and equitable solution to split the difference between the netback price and the cost-plus price to arrive at the project's gas transfer price. Where the cost-plus price is greater than the netback price (ie a notional economic loss situation for the project overall), the transfer price gas is equal to the netback price and the loss is taken by the upstream part of the project.

Assessment of impacts

Impact group identification

The Regulations impact on the upstream petroleum industry, the Australian Taxation Office's administration of the PRRT and potentially the community in the event of an investment in an integrated GTL operation. In particular, the Regulations impact on companies intending to invest in an integrated GTL operation in Australia exploiting gas fields in PRRT liable areas. The number of companies expected to use the Regulations over the next decade or so could be around 10.

Analysis of costs/benefits

Business

Benefits

The framework set out in the Regulations provides a clearly-defined mechanism to determine the gas transfer price for sales gas. This provides increased regulatory transparency and certainty for companies involved, or planning on being involved, in an integrated GTL operation in Australia. Further, it provides companies with greater certainty, assisting them in assessing the viability of proposed projects. To the extent that providing greater certainty leads to increased investment, other industries may also benefit. For example, those planning industrial projects requiring large volumes of natural gas, such as petrochemical and iron and steel projects, may benefit from using the methodology in planning.

The magnitude of the benefits accruing to companies from creating a favourable investment environment, while significant, ultimately depends on the economics of individual projects undertaken. Consequently, the size of the benefits cannot be readily estimated at this point.

Costs

There is no additional compliance cost imposed on companies investing in an integrated GTL operation because a gas transfer price for sales gas has to be determined regardless of whether the Regulations are implemented. That said, it is noted that compliance costs will vary from project to project, depending on the systems in place to capture data for existing PRRT taxpayers and other factors such as the production of multiple petroleum products, the requirement to exclude or allocate costs in certain circumstances and the degree of vertical integration by project participants. Compliance costs could also depend on the nature of any advance pricing arrangement between the Australian Taxation Office (ATO) and the taxpayer. However, the compliance costs associated with an advance pricing arrangement could be broadly similar to adopting the RPM.

Administration

Benefits

The Regulations clarify administrative issues for the ATO in the case of an integrated GTL operation and may reduce the potential for protracted negotiation with industry. The Regulations provide an efficient method of determining a transfer price for gas for all integrated GTL operations for which an arm's length price cannot be determined.

The ATO is required to determine a gas transfer price under the Act. The implementation of the Regulations reduces administrative costs because a framework is in place to determine the gas transfer price. Without this framework, the ATO would need to incur the costs of investigating an appropriate framework to determine the gas transfer price for sales gas as well as implement that framework case by case and subject to uncertainty and potential for disagreement.

Costs

There are no additional administrative costs as a gas transfer price will need to be determined anyway.

Community

Benefits

To the extent that the Regulations provide greater certainty to companies investing in an integrated GTL operation, and this leads to increased development, there would be some benefits to the community. In particular, increased development may lead to the creation of employment opportunities and income. In addition, integrated GTL operations are export-orientated. In this context, the Regulations, by putting in place a framework to determine the gas transfer price, encourage the development of the liquefied natural gas industry which is in Australia's interest.

Costs

There are no costs to the community.

Revenue Costs

The impact of the Regulations on revenue collections is nil. This is because the Regulations provide a framework to determine the gas transfer price. That said, the Regulations provide integrity to the determination of the gas transfer price, ensuring that the revenue base is protected.

Other issues - consultation

The Regulations have been developed in response to industry concerns about the transparency for determining the gas transfer price in the case of an integrated GTL operation. The Regulations have been developed in consultation with the industry. This includes representations from the Australian Petroleum Production and Exploration Association, individual petroleum production and exploration companies, assessment by an independent consultant and consultation on exposure draft Regulations. The industry supports the framework set out in the Regulations.

Conclusion and recommended option

Prior to the amendments made by Taxation Laws Amendment Act (No. 6) 2001, the Commissioner of Taxation could determine a gas transfer price which is fair and reasonable, via the arm's length provisions in the Act. However, the Act does not provide any guidance to the Commissioner of Taxation in determining what may be a fair and reasonable price where the gas is used in an integrated GTL operation.

The favoured option is the introduction through Regulations of a framework to determine a gas transfer price. This provides greater certainty to industry and clarifies the application of PRRT to integrated GTL operations. The framework set out in the Regulations is expected to impose no additional compliance costs on companies and may lower the ATO's administrative costs.

The Treasury, the Department of Industry, Tourism and Resources, and the ATO will monitor the impact of the Regulations on an ongoing basis.

Attachment 1

Introduction

The Regulations are designed to determine a gas price to be used to calculate the petroleum resource rent tax (PRRT) liability of a taxpayer participating in an integrated gas-to-liquids (GTL) operation in a year of tax. An integrated GTL operation consists of an upstream stage and a downstream stage. The upstream stage covers the recovery of project natural gas and the processing of the project natural gas into project sales gas and the downstream stage consists of the processing of the project sales gas into project liquid. For an integrated GTL operation, PRRT applies only to the sales gas (and other petroleum and marketable petroleum products) produced in the upstream stage of an integrated GTL operation.

Section 24 of the Petroleum Resource Rent Tax Assessment Act 1987 (the Act) specifies that for determining assessable petroleum receipts for sales gas where there is a non-arm's length transaction, the amount is to be worked out in accordance with the Regulations. This is the case where sales gas is sold other than at arm's length, or if the sales gas becomes taxable without being sold. The Regulations are necessary because in an integrated GTL operation there is no arm's length sale or sales that can be used to calculate assessable receipts for PRRT purposes. In effect, the Regulations arrive at a notional arm's length price for sales gas, or gas transfer price, at which the upstream stage of an integrated GTL operation sells its sales gas to the downstream stage of the same project.

Where there is sales gas of an integrated GTL operation, the Regulations set out the framework for calculating a gas transfer price for that sales gas, and hence the taxpayer's assessable petroleum receipts from the operation for PRRT purposes. This framework is based on arm's length principles. The Regulations specify that, for a taxpayer participating in an integrated GTL operation, the gas transfer price is arrived at in one of the following ways:

An advanced pricing arrangement (APA) between the taxpayer and the Commissioner of Taxation (the Commissioner). This involves the taxpayer and the Commissioner agreeing on a gas transfer price (and the associated methodology to determine this price) in the context of the particular project.
If there is no APA, a comparable uncontrolled price (CUP) is used to determine the gas transfer price. A CUP is a price that can be observed in the relevant market place for the sale of sales gas in an arm's length transaction and that is applicable to the particular project.
If there is no APA or CUP, the residual pricing method (RPM) as outlined in the Regulations is used to determine the gas transfer price. The RPM uses an arm's length methodology to work out a gas transfer price that is ordinarily the average of the cost-plus price and the netback price. The RPM is a safe harbour for taxpayers and the Commissioner to determine a price for sales gas.
Where there is no APA and no CUP and where the taxpayer has insufficient information to use the RPM, the Commissioner and the taxpayer can agree on a gas transfer price. If the Commissioner and the taxpayer cannot agree, the Commissioner can set a fair and reasonable gas transfer price.

If sales gas is not processed into, or used in the production of, project liquid in an integrated GTL operation, then assessable receipts for the sales gas are worked out in the same way as for any other petroleum or marketable petroleum commodity. In that case, the assessable receipts will be based on the fair market value of the sales gas if it is not sold, or on the consideration that would be given at arm's length if it is sold other than arm's length.

Besides setting the approach used to determine the gas transfer price, the Regulations are primarily devoted to the method of calculation of the gas transfer price using the RPM approach. That is, the Regulations provide a step-by-step methodology to calculate the cost-plus and netback prices - and consequently, the gas transfer price - for an integrated GTL operation.

The cost-plus price is the calculated minimum price the upstream stage of an integrated GTL operation sells its sales gas for in order to cover its upstream costs as defined. The netback price is the calculated maximum price paid for sales gas that allows the downstream stage of the integrated GTL operation to cover its downstream costs as defined, and given the price obtained for project liquid. In both cases, the calculations allow for a rate of return on capital costs incurred. In general, the gas transfer price is equal to the netback price and the cost-plus price, divided by two. This is illustrated in Figure 1. However, if the netback price is lower than the cost-plus price, the gas transfer price is the netback price.

Figure 1: Stylised representation of the RPM

The Regulations also provide a basis for determining which costs are relevant to the RPM calculation and whether, and to what extent, they fall in the upstream or downstream stage of the project. All capital costs, which include any operating costs incurred before the production date, are treated according to the augmentation, reduction and allocation rules. Operating costs incurred after the production date are included in the year in which they are incurred. In general, these costs are shared between all participants. The RPM also allows individual marketing and selling costs to be included as downstream costs of each individual participant (rather than aggregating all such costs to be treated as shared costs between project participants). This means that each individual participant in an integrated GTL operation may have a unique gas transfer price. For each taxpayer, its gas transfer price is multiplied by its share of project sales gas to arrive at its PRRT assessable receipts.

The Regulations also recognise that an integrated GTL operation may be used to process gas from more than one petroleum project, and may produce other products as well as project liquid. When this occurs, the Regulations allow for the capital costs associated with those parts of the operation used to process gas of more than one petroleum project or produce more than one product to be apportioned. This means that the RPM price only reflects the share of the costs associated with producing project liquid from project natural gas.

Part 1: Preliminary

Regulation 1 - Name of Regulations

Regulation 1 names the Regulations the Petroleum Resource Rent Tax Assessment Regulations 2005.

Regulation 2 - Commencement

Regulation 2 states that the Regulations commence on the day after registration on the Federal Register of Legislative Instruments. From that date, assessable petroleum receipts derived in relation to sales gas are worked out in accordance with the Regulations where sales gas is not sold in an arm's length transaction, including where it becomes an excluded commodity without being sold at all: see subparagraph 24(1)(d)(ii) and paragraph 24(1)(e) of the Act. Decisions on whether or not the transaction is at arm's length are subject to objection and review according to the procedures of Part IVC to the Taxation Administration Act 1953 (see Regulation 41).

Part 2: Definition Provisions

Regulation 3 - Definitions

Regulation 3 defines the terms with a specific meaning for the purposes of the Regulations. As the Regulations are made for the purposes of the Act, they only include definitions additional to those already contained in the Act itself.

Regulation 3 includes the following definitions:

Act means the Petroleum Resource Rent Tax Assessment Act 1987.

Actual volume of project natural gas is defined in relation to an integrated GTL operation and a year of tax in which project liquid is produced. It means the volume of project natural gas that was used to produce project liquid.

This term is used in Regulation 10, which provides the methodology for calculating the volume coefficient. The volume coefficient is used in Regulations 22 and 23 to adjust the share of project capital costs used in calculations for each year according to the ratio of that year's gas volume and the expected, or once actual annual volume has been higher actual, average gas volume.

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.

Assessment year means the year of tax in relation to which a gas transfer price, and hence a level of assessable receipts, is to be calculated using the RPM.

Petroleum product of an operation means petroleum, or a product which is produced from petroleum, that is recovered, produced or processed in the operation. This includes all petroleum and products, whether or not they are marketable petroleum commodities. It is noted that many petroleum products are produced from marketable petroleum commodities.

Start date , in relation to capital costs incurred in an integrated GTL operation, means 1 January of the year of tax in which the capital cost is incurred. The start date is used in working out the augmentation and reduction of capital costs in certain circumstances, under Regulations 33 to 35. This provides a simpler approximation of the augmentation or reduction than using the actual date during a year of tax on which a capital cost was incurred.

Taxpayer means a person who is a participant in an integrated GTL operation and whose assessable receipts in relation to sales gas produced in that operation are to be worked out under Regulation 14 or 15. Such a taxpayer will be entitled to at least some project sales gas of the integrated GTL operation (ie, sales gas that becomes project liquid) that is either sold other than at arm's length or that becomes an excluded commodity other than by being sold.

Table 1 sets out other terms of specific use in the Regulations and the regulation that explains them.

Table 1
Term Regulation
'advance pricing arrangement' 18
'annual allocation' 36
'augmented' in relation to a capital cost 11
'capital allowance' 13
'capital cost' 31(1)
'comparable uncontrolled price' or CUP in relation to sales gas 19(1)
'direct cost' 28
'downstream' in relation to a cost 32(6)
'downstream stage' 5(b)
'estimated average volume of project natural gas' in relation to an integrated GTL operation 9(6)
'expected operating life' of an integrated GTL operation 9(7)
'included cost' 30
'indirect cost' 28(5)
'integrated GTL operation' 4 and 5
'MPC production year' for production of marketable petroleum commodity other than project sales gas by an integrated GTL operation 4(9)
'multiple use' of a unit of property 7
'operating cost' 31(2)
'operating life' of an integrated GTL operation 4(8)
'participant' in an integrated GTL operation 8
'personal cost' 28(6)
'phase' of an integrated GTL operation 6(2)
'phase cost' for a phase in an integrated GTL operation 32(2) and 32(3)
'production date' for an integrated GTL operation 4(7)
'production year' for an integrated GTL operation 4(6)
'project liquid' of an integrated GTL operation 4(4)
'project natural gas' of an integrated GTL operation 4(2)
'project product' of an integrated GTL operation 4(5)
'project sales gas' of an integrated GTL operation 4(3)
'reduced' in relation to a capital cost 12
'residual pricing method' 25
'RPM price' for a participant in an integrated GTL operation in a year of tax 20 and 21
'upstream', in relation to a cost 32(5)
'upstream stage' 5(a)
'volume coefficient' or 'VC' for an integrated GTL operation in a year of tax 10(2)

Regulation 4 - When an integrated GTL operation exists

Regulation 4 defines what an integrated GTL operation is, and relevant aspects of such an operation. Costs of the integrated GTL operation, including personal costs, are taken into account, and project production and project life are part of the calculation of costs and prices.

Under subregulation 4(1), an integrated GTL operation is an operation where the following activities take place:

petroleum (generally as natural gas) is, or will be, recovered from a petroleum project;
sales gas is, or will be, produced from some or all of the petroleum; and
some or all of that sales gas is, or will be, processed into a liquefied product.

The definition for petroleum project is drawn from section 19 of the Act rather than being specific to the Regulations and so a petroleum project is taken to exist " where an eligible production licence is in force".

This definition reflects that a broader range of activities may take place within the integrated GTL operation apart from the production and processing of project product as defined below. An integrated GTL operation can also include the production of product other than sales gas, the production of product other than liquefied product from sales gas, and the use of non-project petroleum or of non-project sales gas in producing liquefied product or producing other products. Phase costs are adjusted to take account of such other production (see regulation 37).

A feature of an integrated GTL operation is that there is generally common ownership of the operation which recovers the gas, converts it to sales gas and processes the sales gas into a liquefied product for sale. However, there may be other ownership interests in different parts of the operation, or the facilities may be used for the processing and production of petroleum product other than project product. The Regulations allow for differing ownership interests across the integrated GTL operation should these exist.

Subregulations 4(2) to (4) define the products that make up project product as defined in subregulation 4(5). The products are project natural gas, project sales gas and project liquid. The definitions are used frequently throughout the Regulations.

Subregulation 4(2) states that project natural gas is the natural gas or petroleum, recovered from the petroleum project, from which project sales gas is produced and converted into a liquefied product within, or used by, the integrated GTL operation. The main application of this definition is as a base on which the estimated average and actual annual volume of project natural gas and subsequent volume coefficient is calculated at Regulations 9 and 10. Project natural gas does not include any natural gas processed by the integrated GTL operation that is not recovered from the petroleum project. Project natural gas also includes natural gas that is used by the integrated GTL operation in the production and processing of project liquid.

Subregulation 4(3) states that project sales gas is that gas which has been processed from project natural gas (referred to in subregulation 4(2)) and is to be processed into liquefied product, or used within the integrated GTL operation in producing that liquefied product. An example of project product being used within an integrated GTL operation would be where some project sales gas may be used to generate electricity for use by the integrated GTL operation. For the purpose of the Act, sales gas is the commodity to which PRRT applies and for which a price is being determined under the Regulations. As such, project sales gas is the underlying commodity for which assessable petroleum receipts are determined in Part 3 (either by applying an APA or by multiplying the volume of gas by a required price to provide assessable receipts) and for which the substitute prices in Part 4 are found (see the denominators in the cost-plus and netback equations in Regulations 22 and 23).

Subregulation 4(4) provides that project liquid is the liquefied product into which project sales gas is processed as referred to in subregulation 4(3). Project liquid is a key concept in the netback equation of the RPM in Regulation 23 and for calculating the current period liability in Regulations 39 and 40.

Subregulation 4(5) provides that project product is project natural gas, project sales gas and project liquid produced, processed and used in the integrated GTL operation. Project product is used throughout the Regulations as a convenient way of grouping the three constituent products together at various times in the Regulations and, importantly, is the concept upon which the energy coefficient in Regulation 37 is based. The energy coefficient distinguishes between the proportion of costs relevant to calculating the RPM price (ie, those costs relevant to the production of project natural gas, project sales gas or project liquid) and the proportion of costs relevant to other products.

For the purpose of Regulation 4, the use of project product in the production process of an integrated GTL operation also includes project product that is lost within the integrated GTL operation as part of this process. For instance, some project product may be lost within the integrated GTL operation if some project product is vented for reasons of safety or enhanced production.

Project product used in the integrated GTL operation is included in calculating the energy coefficient in Regulation 37 and the cost-plus and netback prices in Regulations 22 and 23, respectively. The Regulations include these amounts of project product in the RPM calculation.

Subregulation 4(6) provides that the production year for the operation is the year of tax in which project sales gas is first converted into project liquid. Production year is used mainly at Division 5.3 of the Regulations for augmenting and reducing costs.

Subregulation 4(7) provides that the production date of an integrated GTL operation is 31 December of the production year. Production date is especially relevant to the definition of capital cost in Regulation 31(1) and to the augmentation and reduction of capital costs before allocating them among years of tax, in Division 5.3.

Subregulation 4(8) provides that the operating life of the integrated GTL operation is the period beginning with production year and ending with the year of tax in which project sales gas is last processed into project liquid. This is a key concept in determining the estimated average and actual annual volume of project natural gas for the volume coefficient (see regulations 9 and 10) and is the basis of the estimated operating life for allocating direct capital costs across years of tax (see Regulation 36).

Subregulation 4(9) provides an explanation for the term 'MPC production year'. This term is necessary to deal with situations where other marketable petroleum commodities (MPCs) are produced in an integrated GTL operation before the production year. An MPC is a petroleum product that is a trigger for PRRT under the Act. The MPC production year is the year of tax in which an MPC other than project sales gas is first produced. This definition has its main application where capital costs are augmented or reduced at Step 9 of the RPM, in Division 5.3 (see regulations 34 and 35).

Regulation 5 - What an integrated GTL operation consists of

An integrated GTL operation consists of an upstream stage and a downstream stage. The integrated GTL operation is specifically defined in order to clarify the operational aspects from which costs are derived to establish a gas transfer price, especially under the RPM. The cost-plus price under Regulation 22 is a unit price for the upstream stage, which is the price where all upstream costs are recovered. The netback price under Regulation 23 is a unit price for the downstream stage, which is the price where all downstream costs are recovered.

Regulation 5 also recognises that project facilities may be used for the purposes of recovering, producing, processing or transporting product other than that of the integrated GTL operation. This is referred to as 'multiple use' as defined in Regulation 7.

Subregulation 5(a) describes an upstream stage as being comprised of those processes necessary to the production of project sales gas up to the PRRT ringfence (ie, the PRRT taxing point) of the project. These processes include the recovery of project natural gas from the reservoir, pipelines to transport the gas to the processing facilities and, once at these facilities, any processes required to refine the gas into project sales gas. This refining process includes removing and disposing of any contaminants present in the project natural gas, such as carbon dioxide, moisture or other product (marketable or otherwise). The upstream stage also includes any associated storage, though in practice storage is unlikely to be a significant aspect of the upstream stage of an integrated GTL project.

Subregulation 5(b) describes the downstream stage as being comprised of those processes occurring after the production of project sales gas and continuing up to the point at which the project liquid is sold or, where it is not sold, is committed to some other use. Other uses may include being used for power generation outside the project, or for shipping, as feedstock for another process, or where the project sales gas or project liquid is taken from the project as consideration as part of a transaction. Typically, the downstream stage ends at the adjacent free-on-board shipping point and includes any transportation and storage required up to that point.

Regulation 6 - Phase points of an integrated GTL operation

The Regulations provide for the integrated GTL operation to be divided into phases by the phase points. Phase points are required to allow for the accurate apportionment of phase costs where multiple use of a phase occurs. Only those costs that relate to the production and processing of project sales gas into project liquid are included in the RPM for the determination of a gas transfer price. Regulation 7 further describes when multiple use occurs.

Costs of the operation are attributed to the various phases of the operation and the direct costs are apportioned between project product and other petroleum product of the operation using an energy coefficient appropriate for the phase (see Regulation 32 which attributes costs to each phase and Regulation 37 which applies the energy coefficient to the direct costs only).

Where a phase begins and ends is determined by a 'phase point'. Subregulation 6(1) describes where the phase points of the integrated GTL operation occur. These are:

the point where the upstream stage ends and the downstream stage begins; and
any point in the flow of project product through the integrated GTL operation where there is expected to be a difference in how much of the total amount of petroleum product flowing through the operation before and after that point is project product.

Differences in the total amount of petroleum product flowing through an integrated GTL operation may be the result of either project product leaving an integrated GTL operation or non-project petroleum product from outside entering the integrated GTL operation. Therefore, the beginning of the upstream stage and the end of the downstream stage are always phase points. However, activities which release volumes of gas to ensure the safe and efficient operation of the facility do not give rise to a phase point; nor does taking petroleum product to fuel the operation. These activities take proportionately from all the petroleum product of that phase.

A phase point does not arise merely because there is a change in the volume of petroleum product as at a production or processing point. For a phase point to arise, the integrated GTL operation's share of the total amount of petroleum product flowing through before and after the point must be different. In practice, a change in total amount of petroleum product may be measured by a change in its energy content or mass.

Examples of a phase point include the following:

Where natural gas sourced from outside the project is added to the project natural gas at the sales gas production facility of the integrated GTL operation. The point at which the natural gas is added is a phase point.
Where natural gas is taken out of the operation for immediate sale rather than further processing into project liquid. The point at which the natural gas is taken out of the operation is a phase point.

For clarification, subregulation 6(2) states that the integrated GTL operation is divided into phases by the phase points. For example, there is always the beginning and end of the project and at least one other phase point in the integrated GTL operation, at the point where the upstream stage ends and the downstream stage begins. Where there are no other phase points, the operation is said to be composed of only two phases, namely, the upstream phase and the downstream phase.

To ensure disclosure of relevant information by participants, subregulation 6(3) states that participants in an integrated GTL operation must:

in the year of tax before the production year, notify the Commissioner of identified phase points referred to in paragraph 6(1)(b); and
notify the Commissioner as soon as practicable of any phase point that is identified at a later time.

Therefore, it is not necessary for a participant to notify the Commissioner of the phase point that occurs between the upstream and downstream stages unless one of the events referred to in paragraph 6(1)(b) happens at that point. This is because the divide between the upstream and downstream stages is already a phase point as a result of paragraph 6(1)(a).

Participants of an integrated GTL operation are required to record the change in the amount of project product at beginning and end of each phase point for the purposes of the energy coefficient (Regulation 37) which apportions costs between project product and other products.

In keeping with sound tax administration, subregulation 6(4) requires that the participants of an integrated operation satisfy the Commissioner that they can provide accurate records of the volume of project product before and after each phase point. Metering, or any other reliable estimation technique, is acceptable for this purpose.

Regulation 7 - When there is multiple use of a phase

An integrated GTL operation may involve the use of a phase to recover, process or produce petroleum products other than project product. For example, a platform may be used to recover both natural gas (from which project sales gas will be recovered) and liquid petroleum (from which project sales gas may not be recovered). The multiple use of a phase requires an apportionment of the direct phase costs under the RPM to ensure that only those phase costs associated with the recovery, processing or production of project product are included in the determination of a GTP for sales gas at the PRRT taxing point.

Subregulations 7(1) to (6) describe stages of production and facilities of the integrated GTL operation where there may be multiple use of a phase. This description clarifies the apportionment of direct phase costs where multiple use takes place, whether they are costs of a unit of property or of other things. This is set out in Table 2 as follows:

Table 2
Phase subject to multiple use Other use of facilities subregulation
Recovery of project natural gas Facilities used to recover petroleum other than project natural gas.

Example: recovery of crude oil.

7 (1)
Production of project sales gas Produces petroleum products other than project sales gas from project or non-project petroleum. Produces sales gas that is not project sales gas, because produced from petroleum other than project petroleum.

Examples: domestic gas, sales gas from natural gas recovered from outside the operation.

7(2)
Process project sales gas into project liquid Processes petroleum products other than project sales gas into a liquefied product.

Example: liquefaction of sales gas from another project.

7(3)
Transportation of project product Transports petroleum product other than project product within the operation.

Example: A pipeline that carries both project sales gas and natural gas not part of the integrated operation.

7(4)
Storage of project product Storage of petroleum product other than project product.

Example: a facility that is used to store LNG produced by another operation.

7(5)
Loading of project product Loading of petroleum product other than project product.

Example: a loading facility that is shared by more than one GTL operation.

7(6)

Regulation 8 - Who the participants are in an integrated GTL operation

Regulation 8 defines how an interest in an integrated GTL operation gives rise to being a participant. An entity entitled to petroleum product of the integrated GTL operation at the end of at least one phase is a participant. Participants are a key concept in the Regulations for two main reasons. Firstly, all participants' included costs are used in the pool for determining the per unit cost in the netback and cost plus formulas (the whole costs of a phase must be aggregated before they can be adjusted for multiple uses). Secondly, participants include those taxpayers for whose project sales gas a gas transfer price is being determined to establish a PRRT liability.

In relation to the second point, Regulation 3 defines a taxpayer as a participant in the integrated GTL operation for whose assessable receipts in relation to project sales gas are to be worked out under the Regulations. This means that a participant is not necessarily a taxpayer, as a taxpayer is entitled to sales gas at, or before, the PRRT taxing point (ie, the end of the upstream stage). Whereas under Regulation 8, it is possible that a participant only becomes entitled to project product at some point in the downstream stage, in which case the participant is not a taxpayer for PRRT purposes, with respect to that project.

Regulation 9 - The estimated average annual volume of project natural gas

Regulation 9 sets out how the estimated average annual volume of project natural gas is calculated and the requirements for providing estimates or revised estimates to the Commissioner which form the basis of the calculation. This estimate is necessary for determining the volume coefficient calculated under Regulation 10.

Subregulation 9(1) requires participants of an integrated GTL operation to provide the Commissioner in the year of tax prior to the production year an estimate of:

the operating life of the operation (referred to as N );
the total volume of project natural gas to be recovered during the life of the operation (referred to as VNG ).

Subregulation 9(2) provides that the Commissioner must advise the participant in writing as soon as practicable:

whether the estimate or revised estimate has been accepted; or
if the Commissioner has substituted an estimate under subregulation 9(5).

Subregulation 9(3) states that these estimates (including a substituted estimate) are referred to as NE or VNGE.

Subregulation 9(4) provides that if new information is obtained that renders the estimate of either N or VNG inaccurate, the participants must provide the Commissioner with revised estimates. The original estimate may be inaccurate because, for example, the gas reserves may be larger than expected, leading to an increase in the total volume of project natural gas.

Subregulation 9(5) provides that if the Commissioner, having regard to all relevant information, is not satisfied that the estimates provided are reasonable, the Commissioner can substitute an estimate that is reasonable. A substitution by the Commissioner is subject to objection and review under the procedures of Part IVC to the Taxation Administration Act 1953 (see regulation 41).

Subregulation 9(6) provides that the estimated average annual volume of project natural gas for the operation is calculated by dividing the estimated total volume of project natural gas by the expected life of the integrated GTL operation, or:

Subregulation 9(7) states that the expected operating life of an integrated GTL operation is the period of expected (NE) years beginning with the production year.

Regulation 10 - Meaning of volume coefficient

In each year of tax, the upstream and downstream capital costs which have been allocated under regulation 32 need to be adjusted by that year's volume coefficient. This ensures that capital costs are spread across years according to the volume of gas produced in each year. As a result, prices are not distorted by high or low production volumes (relative to the expected average, or once average production has been exceeded, actual average) in a given year of tax.

Subregulation 10(1) provides that for this Regulation, base year means 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 integrated GTL operation (as determined under regulation 9).

It is noted that if the estimated average annual volume of natural gas changes from one year of tax to another, the base year for the calculation of the volume coefficient may also change. The estimated average annual volume may change due to a previous inaccurate measurement or a change in project circumstances.

Subregulation 10(2) provides that the volume coefficient (VC) for an integrated GTL operation in the current year of tax is the ratio of actual volume of project natural gas produced in the assessment year to the estimated average or average annual volume of project natural gas. The formula for the volume coefficient is set out in subregulation 10(1) as follows:

where:

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

-
if the current year is before the base year - the estimated average annual volume of project natural gas; or
-
if the current year is the base year - VA; or
-
if the current year is after the base year - the amount calculated using the formula:

where:

Vn is the actual volume of project natural gas for the nth year of tax, while n represents the year of tax where the base year is year 1.
N is the number of years of tax from the base year to the current year (inclusive).

Therefore, this formula sums the actual volumes of project natural gas for the base year and each following year up to the current year, and provides an average of these volumes.

Regulation 11 - Augmentation of a capital cost

Regulation 11 supports Step 8 of the RPM by defining the formula for augmenting capital costs (where relevant) and defining the terms of that formula.

Regulation 11 provides the formula to augment capital costs, which is:

Subregulations 11(a) to (d) specify the capital allowance to be used depending on the circumstances of the integrated GTL operation from which the augmentation is to apply. Division 5.3 outlines the approach to augmentation of capital costs in these circumstances (see regulations 33 to 35). The actual capital allowance rate is calculated in Regulation 13.

Regulation 12 - Reduction of a capital cost

Regulation 12, which supports Step 8 of the RPM, contains the formula for reducing a capital cost which is:

This formula is used to reduce capital costs where a unit of property is used for non-project purposes prior to its use in the production of project product. Subregulations 12(a) and (b) specify the capital allowance to be used depending on the circumstances of the cost to which the reduction is to apply. Regulation 35 outlines the approach to reduction of capital costs in these circumstances. The actual capital allowance rate is calculated in Regulation 13.

Regulation 13 - Capital allowance

The capital allowance is relevant to the RPM for both the augmentation and reduction of capital and the allocation of capital. This definitional regulation sets out how the capital allowance is to be computed.

The capital allowance provides a rate of return on the capital employed in an integrated GTL project, whether to the upstream or downstream stages of the project or both. As the RPM recognises the integrated nature of the risk-reward relationship between upstream and downstream GTL processes, a single overall project capital allowance is used for both the netback and cost plus calculations. The capital allowance is equal to the long-term bond rate plus 7 percentage points. This capital allowance represents a proxy for the cost of equity.

The capital allowance to be applied to capital costs is adjusted each year to account for the changing risk-free rate of return (assumed to be the long-term bond rate as defined in the Act). The capital allowance for the relevant year only applies to capital costs incurred in that year and is used to allocate costs to that and subsequent years of tax for the remaining expected operating life of the unit of property. Once determined the annual capital allocation for a capital cost does not change (except to reflect changes to the expected operating life of a unit of property, in which case the allocation changes for the year in which the operating life changed and subsequent years under paragraph 36(5)(a)).

Part 3: Assessable petroleum receipts for sales gas

Part 3 of the Regulations sets out how a taxpayer who produces project sales gas calculates their assessable petroleum receipts for the purposes of subparagraph 24(1)(d)(i) and paragraph 24(1)(e) of the Act.

Regulation 14 - Assessable petroleum receipts - sales gas becoming excluded commodity by being sold (Act s 24 (1) (d) (i))

Paragraph 24(1)(d) of the Act describes the amount to be included in a taxpayer's assessable petroleum receipts, for the purposes of determining their PRRT liability, where sales gas becomes or became an excluded commodity by virtue of being sold.

Regulation 14 sets out the method for calculating the amount of assessable petroleum receipts where subparagraph 24(1)(d)(i) of the Act applies - that is, where sales gas is sold under a non-arm's length transaction.

Subregulation 14 (2) provides that a taxpayer's assessable petroleum receipts are calculated under regulation 16 where:

the sales gas is project sales gas of an integrated GTL operation; and
the taxpayer is entitled to some of the project sales gas.

Subregulation 14(3) provides that for sales gas other than project sales gas the amount of assessable petroleum receipts of a taxpayer is determined under paragraph 24(1)(b) of the Act. Such PRRT taxpayers are referred back to the Act because the Regulations only provide a detailed methodology to apply to project sales gas of an integrated GTL operation. Assessable receipts for all other PRRT liable petroleum products are worked out in accordance with section 24 of the Act, either directly or by application of this Regulation.

Regulation 15 - Assessable petroleum receipts - sales gas becoming excluded commodity otherwise than by being sold (Act s 24 (1) (e))

Paragraph 24(1)(e) of the Act describes the amount to be included in a taxpayer's assessable petroleum receipts for the purposes of determining their PRRT liability where sales gas becomes or became an excluded commodity otherwise than by being sold, treated, or processed.

Regulation 15 sets out the method for calculating the amount of assessable petroleum receipts where paragraph 24(1)(e) of the Act applies - that is, where the sales gas is not sold.

Subregulation 15(2) provides that a taxpayer's assessable petroleum receipts are calculated under regulation 17 where:

the sales gas is project sales gas of an integrated GTL operation; and
the taxpayer is entitled to some of the project sales gas.

Subregulation 15(3) provides that for sales gas other than project sales gas the amount of assessable petroleum receipts of a taxpayer is determined under paragraph 24(1)(c) of the Act. Such PRRT taxpayers are referred back to the Act because the Regulations only provide a detailed methodology to apply to project sales gas of an integrated GTL operation. Assessable receipts for all other PRRT liable petroleum products are worked out in accordance with section 24 of the Act, either directly or by application of this Regulation.

Regulation 16 - Integrated GTL operations with non-arm's length sale

Regulation 16 sets out the method for calculating the assessable petroleum receipts of a taxpayer who sells their project sales gas under a non-arm's length transaction (as referred to in paragraph 14(2)(b)).

Subregulation 16(1) specifies a hierarchy of pricing arrangements that may apply to the sale of project sales gas.

Under paragraph 16(1)(a), the amount of assessable petroleum receipts is the amount calculated in accordance with an advance pricing arrangement (APA) if such an arrangement applies to the sale of project sales gas. An APA needs to be agreed between the Commissioner and the taxpayer (see regulation 18).

Under paragraph 16(1)(b), if an APA does not apply, but there is a comparable uncontrolled price (CUP) for the sale, the assessable receipts is based on the CUP amount for the sale (see Regulation 19).

Under paragraph 16(1)(c), if an APA does not apply and there is no CUP for the sale, assessable receipts in relation to the sale uses the RPM amount (see regulation 25).

Subregulations 16(2) and (3) set out how a taxpayer calculates their assessable petroleum receipts in this circumstance, and this is summarised in Table 3 as follows:

Table 3
Circumstance Amount to be included in assessable petroleum receipts Subregulation
A comparable uncontrolled price (CUP) exists The higher of:

an amount based on the CUP x Volume of project sales gas sold;

the consideration receivable less expenses payable in relation to sale.

16(2)
No CUP exists The higher of:

the RPM price* x Volume of project sales gas sold;

the consideration receivable less expenses payable in relation to sale.

16(3)

*RPM price means the residual pricing method determined gas transfer price for the taxpayer in relation to the integrated GTL operation in the year of tax in which the sale took place.

Regulation 17 - Integrated GTL operations with no sale

Regulation 17 sets out the method for calculating the assessable petroleum receipts of a taxpayer referred to in paragraph 15(2)(b), where project sales gas is not sold but the PRRT taxing point is reached.

As with the general structure of subregulation 16(1), subregulation 17(1) provides the taxpayer with the option to enter into an APA with the Commissioner for the purpose of providing an amount of assessable receipts in relation to project sales gas subject to the transaction (paragraph 17(1)(a)). Similarly, where no APA has been agreed, a CUP amount will be used for the transaction if it exists (paragraph 17(1)(b)). Otherwise, the taxpayer will use the RPM amount for the transaction (paragraph 17(1)(c)).

Subregulations 17(2) and (3) set out how a taxpayer calculates their assessable petroleum receipts in this circumstance, and is summarised in Table 4 as follows:

Table 4
Circumstance Amount to be included in assessable petroleum receipts Subregulation
A CUP exists Comparable uncontrolled price x Volume of project sales gas 17(2)
No CUP exists The RPM price* x Volume of project sales gas 17(3)

*RPM price means the residual price method determined gas transfer price for the taxpayer in relation to the integrated GTL operation in the year of tax in which the transaction took place.

Subregulation 17(4) defines the term 'transaction', as used in subregulation 17(1), as the act by which project sales gas becomes or became an excluded commodity under the Act. It is at this point that the assessable receipt is derived for PRRT purposes.

Regulation 18 - Advance pricing arrangements

Regulation 18 provides for the Commissioner, at the request of a participant, to make an agreement (called an 'advance pricing arrangement' or APA) with the participant about how the assessable receipts of the participant are to be calculated in relation to the project sales gas subject to subparagraph 24(1)(d)(i) or paragraph 24(1)(e) of the Act.

An APA between a taxpayer and the Commissioner establishes a methodology to determine an arm's length transfer price for the sale of gas between related parties in an integrated GTL operation for PRRT purposes. An APA is to be based on arm's length principles.

APAs are a well-established feature of Australian income tax administration of transfer pricing issues between related parties. In the context of the Regulations, the APA process is designed to resolve on a prospective basis, by agreement between the Commissioner and the taxpayer, any uncertainties surrounding the calculation of a gas transfer price and associated administrative arrangements. Any taxpayer who is a participant of the integrated GTL operation may apply for an APA.

APAs in relation to project sales gas have the potential to ease administrative burdens for taxpayers and for tax administration, and may reduce uncertainty about future assessable receipts and, hence, PRRT outcomes into the future.

Under paragraph 18(2)(a), the APA must specify the term of the arrangement. Generally, in the context of income tax, an APA is typically set for a period of 3 to 5 years, with an option to extend after that period. Such extensions are likely, as long as conditions governing the APA continue to be met. However, in the context of a typical integrated GTL operation, sales contracts for liquefied natural gas tend to be long term, perhaps over a period up to 20 years. A long term sales contract for project liquid may be a factor in determining the term of an APA in this circumstance. That said, the term of an APA could also be influenced by the strictness of the conditions in the sales contact and the APA itself.

Under paragraph 18(2)(b), the APA must specify how the assessable receipts of the participant are to be calculated. An APA may adopt one specific methodology, several methodologies, a mixture of commonly used methodologies (as the RPM does), or some other methodology or methodologies. Without limiting the scope for other methodologies to be used, the gas transfer price delivered by a CUP (where it exists) and by the RPM methodology is to be considered in setting an APA for the purpose of the Regulations.

Under paragraph 18(2)(c), the APA must specify the conditions under which the APA is to apply. An APA can only be valid as long as certain critical assumptions hold and so outcomes remain within a contemplated range or context. Otherwise, it is possible that the interests of taxpayers and of the revenue may be detrimentally affected.

Part 4: Substituted prices

As set out in Part 3 of the Regulations, a taxpayer's assessable petroleum receipts in relation to project sales gas can be determined by an APA or by prices (a CUP or an RPM price). Part 4 of the Regulations describes how these prices are determined.

Regulation 19 - The comparable uncontrolled price

Regulation 19 defines the term 'comparable uncontrolled price' (CUP) and the conditions under which it can be observed. A CUP is a price that can be observed in a relevant market place for the sale of the commodity (sales gas) in an arm's length transaction. Where a CUP exists, this is to be used to determine a taxpayer's assessable petroleum receipts.

CUPs are recognised internationally as the most appropriate transfer pricing valuation methodology. This is because, when available, they represent an objective arm's length price that is relevant and comparable to the circumstances of the transfer to which it is applied. The use of an APA does not imply inferiority of the CUP - an APA may still be necessary even if based on a CUP (or on other pricing adjusted for features which are not wholly comparable) in order to streamline administrative arrangements, or provide reduced uncertainty about future receipts for mutual advantage to the taxpayer and tax administration.

Subregulation 19(1) defines a CUP in relation to a transaction to which the Regulations apply as being a price for sales gas that:

is obtained for a sale in a market that the Commissioner is satisfied is a relevant market in relation to the transaction; and
the Commissioner is satisfied is an observable arm's length price.

The Commissioner needs to be satisfied, because whether a particular sale is sufficiently comparable is likely to involve a degree of judgment about and enquiry into the facts and circumstances of the particular sale. A decision by the Commissioner that there is no CUP is subject to objection and review according to Part IVC to the Taxation Administration Act 1953 (see regulation 41).

Subregulation 19(2) contains guiding principles as to whether a market place is relevant. This must be determined by taking into account demand and supply market characteristics. These explicitly include:

the composition of sales gas sold in the market;
geographic differences between the production facilities and the product delivery point of the sales gas sold in the market; and
the end functional use of the sales gas (eg, retail, wholesale, manufacturing).

Subregulation 19(3) contains the following comparability factors that must also be taken into account in determining whether a market is relevant:

Usual contract terms in the market, including volumes, discounts, exchange exposures and all other relevant conditions that would reasonably be considered to affect the price.
Market strategies.
The existence of spot sales (including market penetration sales) below or above marginal cost.
Processing costs.
Technology used in processing.
Any other factors that it would be reasonable to consider in assessing comparability between markets.

Subregulation 19(4) provides that a relevant transaction for which there may be a CUP means a circumstance where the Regulations apply to determine assessable receipts for project sales gas because the gas is sold other than at arm's length or because it otherwise becomes an excluded commodity (see section 24 of the Act).

Regulation 20 - The RPM price (the project sales gas transfer price using the residual pricing method)

Regulation 20 sets out how the RPM price for a participant in an integrated GTL operation is determined.

Figure 2 below sets out a stylised representation of the residual profit in a project that is split to determine the RPM price.

As illustrated in the diagram, the difference between the project sales gas price generated by the application of the netback formula compared to the cost-plus price is the residual profit for a project (the 'residual profit element'), where the cost-plus price is less than the netback price.

By using the netback and cost-plus concepts, the RPM incorporates two of the most readily utilised and recognised non-arm's-length transfer price methodologies for circumstances where a CUP does not exist. In particular, the netback and cost-plus methodologies are used extensively across many international jurisdictions in relation to petroleum transfer pricing issues.

The netback and cost-plus prices are determined by following Steps 1 to 13 set out in regulation 25. The cost-plus price is the price for sales gas that covers the upstream costs of the integrated GTL operation, including a return on capital invested. The netback price is the price paid for sales gas that allows the downstream stage of the integrated GTL operation to cover its costs, including a return on capital invested, and given the price obtained for project liquid.

A cost-plus price that is higher than the netback price implies a notional economic loss for the integrated GTL operation taken as a whole. Subregulation 20(a) provides that in such a circumstance, the RPM price for the project sales gas is equal to the netback price. Consequently, for PRRT purposes, an overall loss falls wholly on the assessable receipts of the upstream stage of an integrated GTL operation.

Subregulation 20(b) provides that where the netback price is higher than the cost-plus price (which is expected to be the usual case) the mid-point of these two prices is the RPM price for the project sales gas. The mid-point between the two prices is determined using the following formula:

The equal split between the netback and the cost plus prices, to arrive at the project's RPM price for project sales gas, reflects the integrated and interdependent nature of an integrated GTL project. As the cost-plus and netback prices each recover all relevant costs, there is no objective basis for allocating any remaining profit other than equally between the upstream and downstream stages.

Regulation 21 - RPM price where information is not available

Regulation 21 applies where there is insufficient information available for a participant to determine their own RPM price. Such situations may occur where information about costs is subject to confidentiality, or where a new participant does not have access to all the information required to work out the RPM price.

If the Commissioner and the taxpayer can agree on a price, that becomes the RPM price under subregulation 21(2). If the Commissioner and the taxpayer cannot agree, but the Commissioner is satisfied of a fair and reasonable price worked out using the RPM method on the basis of information from other participants in the operation, that price becomes the RPM price under subregulation 21(3).

Under subregulation 21(4), if the participant and the Commissioner cannot agree on a price and the Commissioner is not satisfied of a fair and reasonable price determined under subregulation 21(3), the RPM price is the price as determined by the Commissioner as being fair and reasonable. Such a decision is subject to objection and review under Part IVC to the Taxation Administration Act 1953 (see regulation 41).

Regulation 22 - Cost-plus price

Regulation 22 sets out the formula to determine the cost-plus price for the participants in an integrated GTL operation in a year of tax. Regulation 22 sets out the cost-plus formula as follows:

where:

UCC is the total amount of upstream capital costs incurred by the participants and allocated to the year of tax;
VC is the volume coefficient for the year of tax;
UOC is the total amount of upstream operating costs incurred by a participants in the year of tax; and
VPSG is the volume of project sales gas that was produced in the operation in the year of tax.

-
VPSG includes project sales gas used in producing and processing project liquid (see subregulations 4(2) and (3)).

The cost-plus formula calculates capital and operating costs per unit for the project's upstream stage. The cost-plus price is determined by adding the share of all upstream capital costs of the project allocated to the year of tax (including a return on capital to the start of recovery, and adjusting for any production volume differential for the year) plus upstream operating costs of the project for the year of tax and dividing by the volume of upstream project sales gas produced, to give a per unit price for the year of tax. Each participant shares this price regardless of their actual entitlement to a share of project sales gas and the cost to them of their entitlement as the price is not entitlement specific. That is, for a given project, it does not cost less overall to produce a unit of sales gas just because a participant is entitled to less gas, or pays more of the production cost, than another participant. Consequently, the cost-plus price represents the calculated minimum price the upstream sellers of sales gas collectively sell the sales gas for and cover their upstream costs as defined.

The upstream capital costs (UCC) attributed in the cost-plus formula to the participant, while incurred by the participant, are in fact held by the project. Therefore, in the event that a participant sells its interest in the project, for the purposes of the RPM, the purchaser inherits the upstream capital costs incurred by the seller. These costs continue to be considered in the cost-plus calculation. In this way the cost-plus calculation continues to be the same regardless of changes in interest of participants in the project.

Regulation 23 - Netback price

Regulation 23 sets out the formula for determining the netback price for a participant in an integrated GTL operation in a year of tax. Regulation 23 sets out the netback formula as follows:

where:

PLVal is the total market value of the project liquid produced in the year of tax;
DCC is the total amount of downstream capital costs incurred by the participants and allocated to the year of tax;
VC is the volume coefficient for the year of tax;
DOC is the total amount of downstream operating costs incurred by the participants in the year of tax;
VPSG is the volume of the project sales gas that was produced in the operation in the year of tax;

-
VPSG is the same amount that is used in the denominator of the cost-plus formula, and includes project sales gas used in producing and processing project liquid (see subregulations 4(2) and (3)).

DPC is the total amount of downstream personal costs of the taxpayer for the year of tax - these are all the selling and marketing costs of the taxpayer, as these are generally not shared by all participants; and
VTDG is the volume of project sales gas that was produced in the upstream stage in the year of tax and processed into project liquid that the taxpayer was entitled to receive and includes that taxpayer's share of project sales gas used in producing and processing project liquid (see subregulations 4(2) and (3)).

The netback equation calculates capital and operating costs per unit for the downstream stage of the integrated GTL operation, and includes an adjustment for each participant's personal costs. The netback price represents the calculated maximum price the downstream buyers of sales gas pay for this gas and cover their downstream costs as defined, given the price obtainable for project liquid.

The first part of the netback formula calculates the per unit direct costs of the whole downstream stage. This is common to all participants. The second part of the netback formula calculates the unit cost of each participant's personal costs, which are selling and marketing costs. This part of the equation provides a per unit of entitlement adjustment for personal costs specific to the individual taxpayer.

The remainder of regulation 23 sets out rules for how the project liquid is valued in circumstances where there is an arm's length transaction (use this as market value) and where there is not an arm's length transaction (still must use market value). Subregulation 23(3) specifies that, in a non-arm's-length sale, the market value of the project liquid is the value at the end of the downstream stage. If adjacent storage and loading are part of the integrated GTL operation, the market value is typically determined at the free-on-board shipping point. Where further processes or activities are undertaken after the end of the downstream stage of the integrated GTL operation and before the project liquid is sold, the actual sale price is likely to need to be adjusted to take account of these activities in arriving at the market value for the purposes of the RPM.

Where the Commissioner is not satisfied there is sufficient information to determine a market value for project liquid, the market value is the amount determined by the Commissioner to be fair and reasonable. Such a determination is subject to objection and review in accordance with Part IVC to the Taxation Administration Act 1953 (see Regulation 41).

Similar to regulation 22, the downstream capital costs (DCC) attributed in the netback formula to the participant, while incurred by the participant, are in fact those related to the project interest of the participant. Therefore, in the event that a participant sells its interest in the project, for the purposes of the RPM, the purchaser inherits the downstream capital costs incurred by the seller. These costs continue to be considered in the netback calculation. In this way, the homogenous element of the netback calculation continues to be the same for all successive participants in the project holding the same interest.

Part 5: The residual pricing method

Part 5 of the Regulations sets out the mechanics of the RPM, which includes:

identifying and classifying included costs of the operation;
allocating capital costs between years of tax;
accounting for the multiple use of facilities;
attributing costs to a participant for a year of tax; and
determining the participant's RPM price for the assessment year.

Division 5.1: The residual pricing method

Division 5.1 of the Regulations describes how a participant calculates their RPM price. This includes a 14 step method statement.

Regulation 24 - Costs are net of GST tax credits and adjustments

Regulation 24 indicates that a reference to 'cost' is a reference to the cost as reduced by:

goods and services tax (GST) input tax credits to which a taxpayer becomes entitled; or
a decreasing adjustment.

By taking into account any GST input tax credits that the taxpayer has received, or becomes entitled to receive, regulation 24 ensures that costs, and hence the RPM, are not overstated by the amount of the GST. The terms 'input tax credit' and 'decreasing adjustment' are defined in section 2 of the Act and are taken from the A New Tax System (Goods and Services Tax) Act 1999.

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

Regulation 25 sets out the necessary steps for calculating the RPM price for a taxpayer. It contains references to the appropriate regulations under which these steps are undertaken. There are a total of 14 steps to be carried out in determining the RPM price.

Figure 3 below sets out a stylised representation of the method statement.

Division 5.2: Identifying and classifying included costs

Division 5.2 identifies and classifies all those costs related to the integrated GTL operation that are to be included in the RPM calculations for the participant.

Regulation 26 - Types of costs associated with an integrated GTL operation

Step 1

Subregulation 26(1) sets out Step 1 of the RPM, which is to identify all costs associated with an integrated GTL operation. These costs include costs that are incurred by, or on behalf of, a participant including costs that are directly attributable, indirectly attributable or partly attributable to the operation including pre-production costs.

Subregulation 26(2) disallows a payment or allowance between participants in relation to their project to be a cost associated with the integrated GTL operation. This rule ensures that costs paid between participants for operations such as tolling are not double counted - by both the toller (identifying the actual costs, including capital costs, of the operations) and the tollee (treating the payment to other participants as operating costs of the operations). Instead, costs are limited to the costs of the project as a whole.

Subregulation 26(3) clarifies that capital costs incurred in relation to units of property which are not in use in the integrated GTL operation at the time the costs are incurred may be treated as costs partly attributable to the operation when the units of property are later used in the operation. Such costs, should they come into an integrated GTL operation, are subject to the rules setting the start date for capital costs, rules for augmenting or reducing capital costs as appropriate and rules for allocating capital costs across the life of the project. Consequently, the cost of a unit of property is the amount actually incurred, which is augmented or reduced as appropriate using the 'historical' capital allowances that related to the appropriate MPC production years and production date, and the capital allowance for the cost year.

Subregulation 26(4) provides an apportionment rule for costs that are only partly attributable to the integrated GTL operation. Under this rule, costs are attributed to the integrated GTL operation on a reasonable basis. As a result, total costs are only those of the integrated GTL operation. This is a separate rule to the 'multiple use' rule, which reduces costs to the extent that a phase involves more than project inputs and project outputs (see regulation 37).

Regulation 27 - Exclusion of certain costs of an integrated GTL operation

Step 2

Regulation 27 sets out Step 2 of the RPM, which excludes certain costs from the RPM calculation. The excluded costs are:

an exploration cost under section 37 of the Act;
a cost incurred in carrying out any feasibility or environmental study prior to the production of project sales gas;
a cost incurred in removing infrastructure facilities used for the integrated GTL operation;
environment and site restoration costs; and
expenditure listed under paragraphs 44(a) to (h) of the Act (including financing costs).

These costs are excluded because they are not incurred in the processing or production of project product and therefore should not be included in the netback and cost-plus formulas to calculate the price for the project sales gas. However, most of these costs remain eligible for deduction under the Act. The exclusion of such costs prevents them from both reducing assessable receipts and increasing deductible expenditure.

Regulation 28 - Direct, indirect and personal costs

Step 3

Subregulation 28(1) sets out Step 3 of the RPM, which categorises costs into direct and indirect costs. These definitions are used when performing subsequent operations within the RPM and form the basis for assigning the type of cost to the particular terms within the respective cost-plus and netback formulas. Regulation 32 assigns the actual dollar costs to specific stages and phases within the operation.

Under subregulation 28(2), costs which are wholly and directly attributable to certain activities of the integrated GTL operation are called relevant sector costs. Relevant sector costs relate to activities that occur in the upstream and downstream stages of the integrated GTL operation. These activities include:

production;
transport;
storage;
marketing; and
selling.

Subregulation 28(3) defines the meaning of a direct cost as a relevant sector cost that is wholly attributable to either the upstream or downstream stage of the operation.

Subregulation 28(4) deals with relevant sector costs that are not wholly attributable to either the upstream or downstream stage of the integrated GTL operation, but are greater than the threshold amount (as determined according to subregulation 28(7)). These costs are divided into two direct costs, one upstream and one downstream, according to a reasonable apportionment. An example of such direct costs would be costs of common downstream and upstream assets of a floating liquefied natural gas processing plant.

Under subregulation 28(5), costs that are not direct costs according to subregulation 28(3) and (4) are indirect costs. These may include relevant sector costs which are less than the threshold (as determined according to subregulation 28(7)) or not allocated to the upstream or downstream stages as a result of subregulations 28(3) and (4).

Indirect costs are typically overhead costs that cannot be attributed readily between upstream and downstream stages and as such usually relate to the integrated GTL project as a whole as opposed to any particular phase or stage of the operation. Such examples include:

business insurance;
office expenses;
administrative and accounting costs;
costs of land and buildings used in connection with administrative and accounting activities;
intra-company charges;
contract penalties;
legal and audit costs;
travel costs; and
buyer liaison costs.

Subregulation 28(6) specifies that a cost that is a cost related to marketing and selling is a personal cost of the participant who incurred them. Personal costs are excluded (by subregulation 31(1)) from being capital costs or operating costs for the purposes of the project-wide components of the cost-plus and netback price formulas in regulations 22 and 23. This ensures that personal costs are not double-counted in working out the RPM price.

Paragraph 28(7)(a) allows for the taxpayer and the Commissioner to agree to a threshold amount for the financial year. Direct costs over the threshold value are split between the upstream and downstream stages on the basis of reasonable apportionment by subregulation 28(4). This approach allows the taxpayer and Commissioner to agree to a threshold that is most appropriate to the taxpayer's circumstances and the Commissioner's needs. In general, an appropriate threshold would typically be consistent with the taxpayer's accounting systems.

Where the taxpayer and Commissioner cannot agree upon a threshold amount for the financial year, paragraph 28(7)(b) mandates that it shall be:

$20 million for financial year 2005-06; or
$20 million for a later financial year, indexed by the GDP factor as applied under the Act, adjusted from 1 January each year.

Regulation 29 - Exclusion of costs of other participants

Step 4

Regulation 29 sets out Step 4 of the RPM, which is to exclude from the RPM calculation all personal costs incurred by another participant. Exclusion of personal costs does not mean they are disregarded completely. Instead, each participant includes their own personal costs in calculating their RPM price, but excludes the personal costs of others. This ensures that information which is not usually shared between participants of an operation (namely individual selling and marketing costs) can maintain its confidential status.

Regulation 30 - Included costs

Regulation 30 defines an 'included cost' for a participant as all identified costs other than those excluded under regulation 27 or 29. Included costs are all those costs taken into account in the netback and cost-plus formulas that are used to determine the RPM price for each participant.

Regulation 31 - Capital and operating costs

Step 5

Regulation 31 sets out Step 5 of the RPM, which is to classify included costs into capital and operating costs for the purposes of the netback and cost-plus formulas. This step is necessary as it is only capital costs that are allocated across the life of the integrated GTL operation, and if relevant, augmented or reduced.

Under subregulation 31(1), a cost is a capital cost if it is not a personal cost and is either:

a cost incurred before the production date; or
a cost relating to a depreciating asset for the purposes of section 40-30 of the Income Tax Assessment Act 1997.

The effect of subregulation 31(1) is that costs incurred before the production date and that would otherwise be operating costs, are classified as capital costs and are allocated between years of tax under Regulation 36 rather than being given effect only in price calculations for the first production year (see subregulation 36(7)).

Under subregulation 31(2), all other included costs that are not capital costs or personal costs are operating costs. These costs are not allocated between years of tax and only effect the RPM calculation in the production year in which they are incurred.

Under subregulation 31(3), a capital cost that does not relate to a unit of property (ie, an operating cost incurred prior to production) is taken to have been incurred on 1 January of the year of tax in which it was incurred. Using a common date, simplifies, inter alia, the calculation of capital allocations.

Step 6

Step 6 of the RPM is set out in the method statement under Regulation 25. In the method statement, the participant is directed to identify the amounts of the relevant included costs. This entails identifying:

included operating costs incurred in the assessment year; and
included capital costs incurred up to and including the assessment year.

Regulation 32 - Phase costs and upstream and downstream costs

Step 7

Regulation 32 sets out Step 7 of the RPM and operates to attribute a participant's included costs in a year of tax to the various phases of the integrated GTL operation. Attributing costs to phases is essential for removing costs associated with multiple use. Only direct costs are attributed in this way. The concepts of upstream costs (the basis of the cost-plus formula) and downstream costs (netback formula) are also defined.

Subregulation 32(1) states that the participant's included direct and indirect costs are attributed to the various phases of the integrated GTL operation in accordance with this Regulation.

Subregulation 32(2) defines a phase cost for the phase as each direct cost that can be wholly attributed to a phase of the integrated GTL operation. Subregulation 32(3) deals with those direct costs that cannot be wholly attributed to the activities of a single phase. In this case, the cost is apportioned to the appropriate phase on a reasonable basis.

Under subregulation 32(4), each indirect cost is divided equally between the upstream and downstream stages of the operation. The effect of this subregulation is to recognise that indirect costs are invariably related to the integrated GTL operation as a whole and thus should be equally accounted for in both netback and cost-plus calculations. As such, the energy coefficient (as determined under Regulation 37) is not applied to indirect costs.

Subregulations 32(5) and (6) define the concepts of upstream costs and downstream costs respectively for the purposes of the netback and cost-plus calculations. Upstream costs are those costs that belong to the phases in the upstream stage of the integrated GTL operation together with the indirect costs allocated to the upstream by subregulation 32(4). Downstream costs are those costs that belong to the phases in the downstream stage of the integrated GTL operation together with the indirect costs allocated to the downstream by subregulation 32 (4).

Division 5.3: Allocating capital costs to years of tax

For the purposes of the cost-plus and netback calculations, capital costs are spread across the life of the project so that they can be taken into account on a yearly basis. Division 5.3 sets out the rules on how these capital costs are to be captured and annually allocated. Regulations 33 to 35 give effect to Steps 8 and 9 of the RPM by making certain adjustments (where relevant) to the value of capital costs entering the cost-plus and netback calculations.

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

Step 8

Regulation 33 provides for the augmentation of capital costs associated with a unit of property that is constructed over a period of time and completed after the production year. These costs are augmented for the number of calendar years between the start date for the capital cost and 1 January of the final cost year. This ensures that a return on capital consistent with augmentation under regulations 34 and 35 is provided for the unit of property while its costs are still being incurred and it is not used. Figure 4 illustrates the augmentation period under regulation 33.

Under subregulation 33(3), the augmented capital cost is taken to be incurred in the final cost year. This means that the amount of the capital cost at the end of the augmentation period for Regulation 33 becomes the amount to be augmented under Regulation 34 or 35. Subregulations 34(2) and 35(2) ensure that this is the case. Also, the final cost year as defined in Regulation 33 is the start year of the capital cost in Regulations 34 and 35. This ensures that these costs will not be augmented twice over the same period.

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

Step 9

Where a depreciating asset is completed and all its costs have been incurred, but its use in an integrated GTL operation has not commenced, capital costs are augmented by regulation 34 so as to provide a return to capital for costs incurred prior to the commencement of the operational use. Capital costs are augmented by applying a capital allowance, which allows for capital costs to be uplifted at a rate compounded by the number of calendar years between the start date for the capital cost and the production date.

Regulation 34 provides for the augmentation of included capital costs for a participant in an integrated GTL operation where project sales gas is the first petroleum product produced.

Subregulation 34(1) states that regulation 34 applies to a capital cost where:

the cost is incurred before the production year; and
no MPC is produced before the year when project sales gas is first produced (ie the production year).

Subregulation 34(2) states that the capital cost to be augmented is taken to be the amount calculated under regulation 33 and is taken to have been incurred at the end of the final cost year. These are then the start date and capital cost for the calculation under regulation 34.

Under subregulation 34(3), the capital cost is augmented for the number of calendar years between when the capital cost would otherwise have been taken to be incurred and the start of production use. That is, the start date for the capital cost and the production date. Figure 5 illustrates the augmentation period:

Under subregulation 34(4), the augmented capital cost is taken to be incurred in the production year. This augmented amount is then allocated between years of tax using the capital allocation formula contained in regulation 36.

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

Step 9

Capital costs are augmented to account for the time between when they are incurred and when they begin to be used in an integrated GTL operation. Capital costs may also be reduced (depreciated) to account for their use in the production of MPCs other than project sales gas. For example, a platform may be used to extract liquid petroleum for a number of years prior to project natural gas being produced. In such circumstances, the capital cost of the platform is reduced for the number of calendar years between the date the capital cost is incurred (the start date) and the production date for the integrated GTL operation.

Subregulation 35(1) states that regulation 35 applies to a capital cost of a participant in an integrated GTL operation where:

the cost is incurred before the production year; and
an MPC, other than project sales gas, is produced in the integrated GTL operation; and
the first MPC production year is before the first production year for the integrated GTL operation.

Subregulation 35(2) states that the capital cost to be augmented is taken to be the amount calculated under regulation 33 and is taken to have been incurred at the end of the final cost year. These are then the start date and capital cost for the calculation under regulation 35.

Subregulation 35(3) deals with capital costs incurred for a unit of property that is used solely for the project natural gas, project sales gas and project liquid sequence. In this case, the cost is augmented for the number of calendar years between when the capital cost would otherwise have been taken to be incurred and the start of production use. That is, the start date for the capital cost and the production date. The augmentation period is the same as shown in Figure 5.

Subregulation 35(4) provides that if a capital cost is incurred before the MPC production year and the unit of property is used to any extent in the course of producing an MPC, the capital cost is:

augmented for the number of calendar years between the start date for the capital cost when the capital cost would otherwise have been taken to be incurred and the start of MPC production use (ie, 31 December of the MPC production year); and
reduced for the number of calendar years between 31 December of the MPC production year and the production date (see Regulation 12).

Figure 6 illustrates the augmentation and reduction period under subregulation 35 (4).

Subregulation 35(5) provides that if subregulation 35(3) does not apply and the capital cost is incurred in or after the MPC production year but before the production year for project liquid, the capital cost is reduced for the number of calendar years between the start date for the capital cost (when the capital cost would otherwise have been taken to be incurred) and the production date. Figure 7 illustrates the reduction period under subregulation 35(5).

Subregulation 35(6) provides that an augmented or reduced capital cost under this Regulation is taken to be incurred in the production year. This augmented or reduced amount is the capital cost that is allocated to years of tax using the capital allocation formula contained in regulation 36.

Regulation 36 - Allocating capital costs to a year of tax

Step 10

Step 10 of the RPM allocates included capital costs to each year of tax from the production year onwards.

Subregulation 36(1) states that this Regulation applies to included capital costs of a participant in a year of tax in relation to a unit of property. These capital costs include upstream and downstream current year capital costs and, if appropriate, capital costs that have been augmented and/or reduced under Regulation 34 or 35.

Subregulation 36(2) provides that the annualised capital cost is allocated to the year of tax in which it was incurred (defined as the cost year) and to each subsequent year of tax for the remainder of the expected operating life of the unit of property.

Subregulation 36(3) provides that if the expected operating life of the unit of property is no more than 15 years, the formula for determining the annual allocation is based on the following annuity calculation:

where:

capital allowance is the capital allowance for the year of tax in which the capital cost is incurred (see regulation 13); and
N is the number of calendar years in the expected operating life of the unit of property.

Subregulation 36(4) provides that if the expected operating life of the unit of property is more than 15 years, the formula for the annual allocation is based on the following calculation:

where:

capital allowance is the capital allowance for the year of tax in which the capital cost is incurred (see regulation 13).

Subregulation 36(5) allows for the recalculation of the capital allocation if the expected operating life of the unit of property changes. This may occur either as a result of the unit of property's expected operating life changing, or as a result of a change in the expected operating life of the integrated GTL operation. For the assessment year, and each subsequent year of tax, capital costs are allocated using the new expected operating life of the unit of property. The allocation of capital costs for the RPM prices of previous years is unaffected.

The capital allocation is required to be recalculated to ensure that costs associated with those capital items utilised by the integrated GTL operation in the production and processing of project sales gas are included in the determination of the RPM price. Similarly, the costs associated with capital items that are no longer utilised by the integrated operation should not be included in the determination of the RPM price.

For example, assume that a unit of property has an expected operating life of 7 years. The capital costs associated with this unit of property are allocated, using the annuity formula under subregulation 36(3), over the 7-year life of the unit. Four years into its use by the operation, it is decided that the unit of property will be used for 10 years rather than 7 years. At that point, the annual capital allocation is redetermined based on the remaining available capital cost (ie, the capital cost at the production date less the amount of capital allocated over the previous years of tax) and the remaining 6-years expected life of the unit of property. This capital allocation is then used for each subsequent year of tax. No adjustment is necessary for past years of tax.

The expected operating life of a unit of property is defined in relation to its use and absorbed into the operation and so treated as if it cannot be any longer than the expected life of the integrated GTL operation. As such, subregulation 36(6) defines the expected operating life of a unit of property as the number of calendar years between:

the start date for the capital cost; and
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.

Subregulation 36(7) provides that a capital cost that does not relate to a unit of property, but is a capital cost by virtue of subparagraph 31(1)(b)(i), is allocated in the same manner as if it was incurred in relation to a unit of property that has an expected operating life equal to the operating life of the operation. This means that those operating costs incurred prior to the production date are treated as capital costs and allocated over the expected operating life of the project.

Division 5.4: Accounting for multiple use of a phase

This Division comprises Step 12 of the RPM and adjusts costs of the integrated GTL operation for multiple use of facilities according to the ratio of project product to total product being processed.

Regulation 37 - Applying the energy coefficients to costs of each phase

Step 12

Step 12 deals with the apportionment of costs where there is multiple use of facilities in any particular phase of an integrated GTL operation, so that only those costs associated with the passage of project sales gas through the integrated GTL operation are included in the RPM calculation.

A valid gas transfer price when a project either produces multiple products, or has multiple uses, should only include expenditures and outputs so far as they are related to the integrated GTL operation. Where a phase is involved in the processing of more than one product, or has more than one use, the phase costs are apportioned. This is done by applying an energy coefficient to the capital cost allocation and the operating costs for each phase in the year of tax.

Under regulation 37, the amount of each phase cost in 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; and
total phase energy is the energy content of all the petroleum product (not just project product) attributable to the participants that enters the phase in the year of tax.

Where project product leaves the integrated GTL operation, or the facilities of a phase are used to process MPCs other than project product, then the energy coefficient to be applied to the phase costs is less than 1.

The formula caters for changes in project energy not only from year to year but also through the year. For example, a reduction halfway through the year in the project energy content entering the phase from a full capacity level to a half capacity level results in three quarters of costs being included for the year. The reference to energy is a reference to energy content of the petroleum product measured in gigajoules. The energy content for the volume of petroleum product must be measured according to a common measurement system, including at common standard conditions. Under the International System of Units, this would be measurement in gigajoules at fifteen degrees Celsius and one atmosphere (101.325 kilopascals). A gigajoule is equivalent to 109 joules, where a joule is defined in Australian Standard ISO 1000-1998 'The International System of Units (SI) and its Application'.

Step 13

Step 13 of the RPM is set out in the RPM method statement under regulation 25. It directs the participant to calculate for the year of tax their cost-plus price, as stipulated under regulation 22, and netback price, as stipulated under regulation 23.

Step 14

Step 14 of the RPM is set out in the RPM method statement under Regulation 25. It directs the participant to obtain their RPM price for the year of tax, according to the formula set out in regulation 20. It is this price that is then used by the participant to determine their assessable petroleum receipts for the year of tax as set out in Part 3 of the Regulations.

Part 6: Notional tax amount - sales gas

Division 2 of Part VIII of the PRRTA Act contains rules for the collection of PRRT by instalments. Section 96 of the Act specifies the amount that is payable by a taxpayer as an instalment of tax in relation to an instalment period. That amount is referred to as a 'notional tax amount' and is ascertained under section 97 of the Act. Each instalment period is the period from the beginning of the year of tax up to the end of the quarter for which a notional tax amount is being calculated.

Under section 97, the previous period liability is subtracted from the current period liability to arrive at the notional tax amount payable for the instalment period. The current period liability is an amount equal to the tax that is payable by the taxpayer for the instalment period worked out in accordance with the rules set out in subsection 97(1A) - principally, as if the instalment period were the year of tax. The previous period liability is the notional tax amount, or the sum of the notional tax amounts, for any prior instalment period or periods in the year of tax. This means that each instalment not only covers an additional period compared to each previous instalment, but also corrects any calculations for earlier instalments.

Subsection 97(1AA) applies so that for an integrated GTL operation where the amount of assessable petroleum receipts that is taken into account in working out the current period liability is determined in accordance with subparagraph 24(1)(d)(i) or paragraph 24(1)(e) of the Act, then, for the purposes of calculating a current period liability, the amount of assessable petroleum receipts is to be worked out in accordance with the Regulations.

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

For paragraph 97(1AA)(b) of the PRRTA Act, regulation 38 provides that if the amounts to be used to calculate a taxpayer's assessable petroleum receipts under Regulation 14 or 15 are either:

a comparable uncontrolled price;
the consideration received or receivable, less any expenses payable, by the taxpayer in relation to the sale; or
an advance pricing arrangement.

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

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

Regulation 39 applies where a participant of an integrated GTL operation uses an RPM price to determine their assessable petroleum receipts under regulation 14 or 15 and they had an RPM price for the previous year of tax.

Subregulation 39(2) sets out that, for paragraph 97(1AA)(b) of the PRRTA Act, the amount that is to be used to calculate the current period liability under subsection 97(1A) is:

where:

PLVal is the project liquid value for the participant's share of project liquid in the instalment period;
RPMPREV is the RPM price for the participant for the previous year of tax;
VPGPREV is the volume of project sales gas to which the participant was entitled to receive in the downstream stage in the previous year of tax, including the participant's share of that project sales gas used in producing and processing project liquid; and
PLValPREV is the project liquid value for the participant's share of project liquid in the previous year of tax.

This formula factors in movements in the market value for project liquid from the previous year to the current instalment period, as well as taking account of changes in production levels, without requiring full reassessment of the RPM.

Under subregulation 39(3), the project liquid value for the participant in a period is the total market value of the project liquid to which the participant is entitled in the period.

Under subregulation 39(4), if the participant sells a quantity of project liquid from the operation for the current period, and the sale is an arm's length transaction, the market value of that liquid (and so to that extent the project liquid value) is taken to be the amount received for the sale.

Under subregulation 39(5), if there is a quantity of the project liquid for which there is no sale or a non-arm's length sale, the market value of that quantity is the market value at the point at the end of the downstream stage.

Under subregulation 39(6), if the Commissioner is not satisfied that sufficient information is available to determine a market value for project liquid under subregulation 39(5), then the market value is the amount determined by the Commissioner as fair and reasonable. This determination by the Commissioner is subject to objection and review according to Part IVC to the Taxation Administration Act 1953.

Regulation 40 - Notional tax amount when no previous RPM price

Regulation 40 applies where a participant of an integrated GTL operation uses the RPM price to determine their assessable petroleum receipts under regulation 14 or 15, but they do not have an RPM price for the previous year of tax. This is likely to occur when a new participant enters into the integrated GTL operation.

Subregulation 40(2) provides that (if the taxpayer did not transfer into the project or did not elect to apply subregulation 40(3)), then the amount that is to be included in calculating the current period liability under subsection 97(1A) of the Act is:

where:

VPG is the total volume of project sales gas that was processed into project liquid that the previous participants were entitled to receive in the downstream stage, including the participant's share of that project sales gas used in producing and processing project liquid; and
RPM price is the RPM price calculated as if the instalment period were the assessment year (including under regulation 21 if applicable).

Subregulation 40(3) sets out that if the participant had transferred into the operation in the assessment year, then they may elect to apply the formula set out in subregulation 39(2) replacing the factors in that equation with the following:

RPMPREV is the average RPM price for the previous participants for the previous year of tax, weighted according to the project liquid value for each of the previous participants in the previous year of tax;
VPGPREV is the total volume of project sales gas that was, in the previous year of tax, processed into project liquid that the previous participants were entitled to receive in the downstream stage, including the participant's share of that project sales gas used in producing and processing project liquid; and
PLValPREV is the total project liquid value for the previous participants in the previous year of tax.

This allows the taxpayer to elect to use the previous year's RPM calculation rather than having to carry out a fresh calculation before working out each instalment.

The term previous participants refers to those who were participants in the integrated operation in the assessment year prior to the year the new participant transferred into the project.

Part 7: Miscellaneous

Regulation 41 - Review of decisions - prescribed decisions

Section 106A of the Act provides that certain decisions made under the Act, or these Regulations, are reviewable under Part IVC to the Taxation Administration Act 1953. A reviewable decision is one that relates to the taxpayer and against which the taxpayer may object. It is subject to review by the Commissioner and the Administrative Appeals Tribunal, and to appeal to the Federal Court. Regulation 41 specifies those decisions under the Act or Regulations that are reviewable under section 106A of the Act. These decisions are set out in Table 5.

Table 5
Commissioner's determination Act/ regulation reference
Whether a transaction is a non-arm's length transaction. Subsection 24(2) of the Act
Whether to substitute an estimate of N or VNG Subregulation 9(5)
The RPM amount where no agreement can be reached between the participants and the Commissioner. Regulation 21
The market value of project liquid Subregulation 23(4) or 39(6)

Attachment 2

Example 1: Calculation of RPM price - no phases except for upstream and downstream stages

Ausgas Pty Ltd is developing an integrated GTL operation. It owns the upstream stage, where the project natural gas is sourced, and processed to the point where it becomes project sales gas. It also owns the downstream stage of the project, where the project sales gas is processed into liquefied product.

Because Ausgas Pty Ltd has 100 per cent ownership of the upstream and downstream stages of the integrated GTL operation and does not intend to use the facilities other than for the production/processing of project product as defined in subregulation 4(5), it is not required to notify the Commissioner under subregulation 6(3) of any phase points additional to the point where the upstream stage ends and the downstream stage begins.

Ausgas Pty Ltd has not entered into an APA with the Commissioner and there is no CUP for the sales gas. Consequently, an RPM price is needed to determine Ausgas Pty Ltd's petroleum resource rent tax liability for the upstream production of project sales gas. Subregulation 17(3) applies and an RPM price is to be used to determine a taxpayer's assessable petroleum receipts.

This example sets out how an RPM price is calculated for the first 6 years of project production. Figures in the table may not add due to rounding.

The project

The project is expected to operate for 25 years and process 5 billion units of sales gas over that time. Some project sales gas will be used or lost during the downstream processing of project sales gas into project liquid. The gas used or lost during processing continues to be included in the volume of project sales gas for the purposes of the RPM calculation (subregulations 4(2) and 4(3)). Ausgas Pty Ltd expect that this gas will account for around 10 per cent of project sales gas crossing the PRRT ringfence. Table 1 shows the production data for the project over the first 6 years of production.

Table 1: Project production data

Project construction takes 2 years for the upstream stage and 3 years for the downstream stage. Pre-production capital costs are set out in Table 2 and operating costs for the first 6 years of production are set out in Table 3. It is assumed that no capital costs are incurred in these 6 production years.

The classification and identification of capital and operating expenditures to the upstream and downstream stages take the example up to Step 7 in the method statement contained in Regulation 25. In this example, the classification and identification of costs is set out in the Tables 1 and 2. This in effect accounts for Steps 1 to 7 of the RPM.

Table 2: Capital expenditure of project

Table 3: Operating expenditure

Step 8 - Augmentation of capital costs incurred before the production year

It is assumed that project sales gas is first processed into project liquid in September 2007. The production year determined in accordance with subregulation 4(6) for the operation is therefore 2007-08. The production date determined in accordance with subregulation 4(7) is 31 December 2007.

Upstream capital costs

Under Regulation 34, capital costs incurred before production commences are augmented for the number of calendar years between the start date and the production date (see Regulations 3 and 4 for definitions of these terms). If some expenditures are incurred over several years, so that Regulation 33 is applicable, the expenditures are augmented each year up to the final cost year. The included costs so augmented are taken to be incurred in the final cost year and Regulations 34 and 35 apply.

By reference to Table 2, the start date for expenditures incurred in 2005-06 and 2006-07 are 1 January 2006 and 1 January 2007 respectively.

Under Regulation 11, the formula used to determine the augmented capital cost is:

The capital allowance is the capital allowance for the production year and is determined under Regulation 13. The capital allowance for the production year is assumed to be 13 per cent (based on a long-term bond rate of 6 per cent).

The number of calendar years between the start date and the production date (N) for capital costs incurred in 2005-06 and 2006-07 is 2 and 1 respectively.

To illustrate, the upstream capital costs incurred in 2005-06 are therefore augmented as follows:

Table 4 shows the effect of augmentation on the nominal upstream capital costs for this project.

Table 4: Effect of augmentation of nominal upstream capital costs

Downstream capital costs

The number of calendar years between the start date and the production date (N) for costs incurred in 2004-05, 2005-06 and 2006-07 are 3, 2 and 1 respectively.

The downstream capital costs incurred in 2004-05 are augmented as follows:

Table 5 shows the effect of augmentation on the nominal downstream capital costs.

Table 5: Effect of augmentation of nominal downstream capital costs

Step 9 - Augment and reduce early capital costs

Where an MPC other than project sales gas is produced before the production year of the integrated GTL operation, all capital costs incurred in relation to this production must be augmented for the number of calendar years between the start date for the capital costs and the 31 December of the MPC production year (paragraph 35(4)(a)). This augmented capital amount is then reduced for the number of calendar years between the 31 December of the MPC production year and the production date (paragraph 35(4)(b)). This process is undertaken to fully account for the use of project capital in the production of product other than project sales gas.

In this example, Regulation 35 is not applicable as the integrated GTL operation will only produce project sales gas.

Step 10 - Annualise capital costs

An annual capital allocation is determined for both the upstream and downstream capital costs.

As stated above, Ausgas Pty Ltd expects the operating life of the operation to be 25 years. Therefore, the capital allocation for the upstream and downstream components is determined under subregulation 36(4) as:

where:

Capital allowance is the capital allowance for the year of tax in which the capital cost is incurred. This is assumed to be 13 per cent.

Upstream capital allocation

The capital allowance of 13 per cent is applied to the augmented base capital amount (from Table 4) of $4.814 billion to give the annual allocation for the upstream:

Downstream capital allocation

The capital allowance of 13 per cent is applied to the augmented base capital amount (from Table 5) of $3.850 billion to give the annual allocation for the upstream:

Step 11 - Identify costs for the assessment year

The allocation of capital costs for the assessment years is set out in Table 6.

The relevant operating costs are set out in Table 3.

Step 12 - Apply the energy coefficients to the costs

Project product is the only product produced/processed in the upstream and downstream stages. Therefore, the energy coefficient for each of the production years is one, so the allocated capital amounts remain unchanged (Regulation 37).

Table 6: Annual Capital allocation

Step 13 - Obtain the cost-plus and netback prices

Adjustment of capital allocation for utilised capacity

To ensure that the upstream and downstream capital costs included in the netback and cost-plus formulas reflect the appropriate quantum of capital utilised in a year of tax, a volume coefficient is applied to the upstream and downstream capital allocations.

As set out in Regulation 10, the volume coefficient (VC) is the actual volume of project natural gas produced for the current year (VA) divided by the benchmark annual volume of natural gas (VB). Project sales gas used or lost in processing project sales gas into project liquid within the integrated GTL operation continues to be included in the volume coefficient calculations.

Table 7 shows yearly production of project liquid and actual volume of project natural gas for the first 6 years of the project.

Table 7: Yearly production and market value variables

In the year of tax before the production year, Ausgas Pty Ltd provides the Commissioner with an estimate of the variables required to determine the estimated average annual volume of project natural gas. The Commissioner accepts the estimates and this provides the estimated average volume of project natural gas of 200 million units (Regulation 9).

This estimated average annual volume of project natural gas is taken to be the benchmark volume (VB), until the actual volume (VA) exceeds the estimated volume for the first time. When VA exceeds the estimated volume for the first time, VB equals VA for that year. In subsequent years, VB is the average of production volumes for the years following, and including, the year where VA is greater than the estimate. Thus, based on the production profile shown in Table 7, the following volume coefficients apply to each year:

As VA exceeds the estimated average annual volume of project natural gas (200 million units) for the first time, VB becomes 225 million units in this year (subregulation 10(2)(b)).

After this point, VB becomes the average of VA after (and including) year 4 (subregulation 10(2)(c)).

Table 8 summarises the calculation of the volume coefficients.

Table 8: Volume coefficient

The volume coefficient is then applied to the annual capital allocations (both upstream and downstream) in the cost-plus and netback formulae.

Cost-plus price

The cost-plus price is the project's upstream costs per unit of production (including any project sales gas used in integrated GTL operation) in the year of tax. The cost-plus formula is set out in Regulation 22. For the 2007-08 year of tax the cost-plus calculation for Ausgas Pty Ltd is as follows:

Table 9 shows the cost-plus formula variables and price for the subsequent years.

Table 9: Cost-plus calculation

Netback price

The netback price is determined by subtracting the downstream personal costs per unit of the participant's entitlement of project liquid from the revenue (net of downstream costs) per unit of project liquid produced in the year of tax. The netback formula is set out in Regulation 23. The volume of project sales gas (the denominator in the netback formula) includes the volume of project sales gas used in integrated GTL operation. Personal costs are not relevant to this example. For the 2007-08 year of tax the netback calculation for Ausgas Pty Ltd is as follows:

Table 10 shows the netback variables and price for the subsequent years.

Table 10: Netback calculation

Step 14 - Obtain the RPM price for the assessment year

The RPM price is the average of the cost-plus price and the netback price (Regulation 20). Table 11 shows the residual price calculation.

Table 11: RPM price calculation

Assessable petroleum receipts

For each of the years modelled, Ausgas Pty Ltd now has a gas transfer price it can apply to determine its PRRT liable revenue. Example 4 provides a detailed example of the calculation of notional receipts for instalment purposes.

Attachment 3

Example 2: Calculation of RPM price - Joint venture with two partners and one upstream and one downstream phase

Ausgas Pty Ltd and Offshore Pty Ltd are joint venture participants in an integrated GTL operation. Ausgas and Offshore are each entitled to a share of project liquid. The entitlement of Ausgas is 60 per cent and of Offshore is 40 per cent. These entitlements are fixed throughout the life of the project.

Neither of the individual participants have entered into an APA with the Commissioner and there is no CUP for the sales gas. Consequently, an RPM price is needed to determine each participant's PRRT liability for the upstream production of project gas (subregulation 17(3) applies and an RPM price is to be used to determine a taxpayer's assessable petroleum receipts).

This example sets out how an RPM price is calculated for the first 6 years of production by the project. Figures in the tables may not add due to rounding.

The project

The expected operating life of the project (referred to as NE in Regulation 9) is 25 years and the project processes 8 billion units of natural gas over that time. Project construction takes 2 years for the upstream stage and 3 years for the downstream stage. Pre-production capital costs are set out in Table 1 and operating costs for the first 6 years of production are set out in Table 2. It is assumed that no capital costs are incurred in these 6 years.

The capital contribution of each company to the development of the project is shown in Table 1, and it is assumed that there are no ongoing capital costs over the period used in this example. Table 2 shows the profile of project operating costs for each of the participants. These capital and operating costs are included costs as prescribed by Regulation 30.

Table 1: Participant project capital costs

Table 2: Participant project operating cost

Each participant also incurs individual costs in selling and marketing of their entitlement of project liquid from the project. These expenditures are wholly attributable to the downstream phase of the project and are only taken into account by the participant who incurs them because of Regulation 29. These personal expenditures are shown in Table 3.

Table 3: Participant personal costs

The identification of capital and operating expenditures and their classification to the upstream and downstream stages take the example up to Step 7 in the method statement contained in Regulation 25. Personal costs are set aside until Step 13 of this methodology.

Step 8: - Augmentation of capital costs incurred before the production year

It is assumed that project sales gas is first processed into project liquid in September 2007. The production year determined in accordance with subregulation 4(6) for the operation is therefore 2007-08. The production date determined in accordance with subregulation 4(7) is 31 December 2007.

Augmentation of project capital costs

Under Regulation 34, all included capital costs incurred before production commences are augmented for the number of calendar years between the start date and the production date.

The start date for expenditures incurred in 2004-05, 2005-06 and 2006-07 are 1 January 2005, 1 January 2006 and 1 January 2007 respectively.

The capital allowance rate for the production year is in this example is 13 per cent (based on a long-term bond rate of 6 per cent). This capital allowance rate is determined for the production year under Regulation 13.

Under Regulation 11 the formula used to determine the augmented capital cost is:

The calculation of augmented capital costs is carried out on the pooled project cost. That is, the combined included expenditures of Ausgas and Offshore. In this example, the project's upstream capital costs incurred in 2005-06 are augmented for the 2 years from expenditure to the production year as follows:

Table 4 shows the effect of augmentation on the nominal capital costs for this project.

Table 4: Augmented project capital expenditure

The total augmented capital cost in the upstream is $7.786 billion and downstream is $7.904 billion.

Step 9 - Augment and reduce early capital costs

If an MPC other than sales gas is produced before the production year of the integrated GTL operation, all capital costs incurred in relation to it must be augmented for the number of calendar years between the start date for the capital costs and the 31 December of the MPC production year (paragraph 35(4)(a)). This augmented capital amount is then reduced for the number of calendar years between the 31 December of the MPC production year and the production date (paragraph 35(4)(b)). This process is undertaken to fully account for the use of project capital in the production of product other than project sales gas.

In this example, Regulation 35 is not applicable as the integrated GTL operation will only produce sales gas.

Step 10 - Annualise capital costs

In order to appropriately reflect the use of project capital, an annual capital allocation is determined for both the upstream and downstream capital costs. The capital allocation for the upstream and downstream components is based on the total of the augmented capital costs calculated in Step 8. As the project life is greater than 15 years, the capital costs are allocated in the following way (as set out in subregulation 36(4)):

The capital allowance of 13 per cent is applied to the augmented base capital amount of $7.8 billion to give the annual allocation for the upstream:

Similarly, the downstream annual capital allocation is:

Step 11: - Identify costs for the assessment year

The relevant capital costs for the assessment year are those calculated in Step 10. The relevant operating costs are those set out in Table 2 above.

Step 12 - Apply the energy coefficients to the costs

Project product is the only product produced or processed in the upstream and downstream stages. Therefore, the energy coefficient for each of the production years is one, so the allocated capital amounts remain unchanged as shown in Table 5 (Regulation 37).

Table 5: Annual capital allocation

Step 13: - Obtain the cost-plus and netback prices for each participant

To ensure that the upstream and downstream capital costs included in the netback and cost-plus formulas reflect the appropriate quantum of capital utilised in a year of tax, a volume coefficient is applied to the upstream and downstream capital allocations.

As set out in Regulation 10, the volume coefficient (VC) is the actual volume of project natural gas produced for the current year (VA) divided by the benchmark volume of gas (VB).

Table 6 shows yearly production of project liquid and actual volume of project natural gas for the first 6 years of the project.

Table 6: Production volumes

Over the 25 year operating life of the project, it is expected that 8 billion units of natural gas will be extracted. Therefore, the estimated average annual volume of gas is 320 million units. In the year of tax before the production year, the joint venture participants provide the Commissioner with an estimate of the variable required to determine the estimated average annual volume of natural gas (Regulation 9). This estimated average annual volume of natural gas capacity is taken to be the benchmark volume (VB), until the actual volume (VA) exceeds the estimated volume for the first time. When VA exceeds the estimated volume for the first time, VB equals VA for that year. In subsequent years, VB is the average of production volumes for the years following, and including, the year where VA is greater than the estimate.

A fully worked example of this calculation is provided in Example 1. Based on the production profile shown in Table 6, the volume coefficient for each year of production is shown in Table 7.

Table 7: Project benchmark volume and volume coefficient

The volume coefficient is then applied to the annual capital allocations (both upstream and downstream) in the cost-plus and netback formulas.

Cost-plus price

The cost-plus price is equal to the project's upstream costs per unit of production in the year of tax and is the same for all participants. The cost-plus formula is set out in Regulation 22. For example, in the 2007-08 year of tax the cost-plus calculation is as follows:

Table 8 shows the source data and the cost-plus price for Ausgas Pty Ltd and Offshore Pty Ltd.

Table 8: Cost-plus price calculation

Netback price

The netback price is determined by subtracting the downstream personal costs per unit of the participant's project liquid entitlement from the revenue (net of downstream costs) per unit of project liquid produced in the year of tax. The netback formula is set out in Regulation 23. For example, in the 2007-08 year of tax the netback calculation for Ausgas Pty Ltd is as follows:

Tables 9 and 10 show the relevant data and netback prices for Ausgas Pty Ltd and Offshore Pty Ltd respectively.

Table 9: Ausgas Pty Ltd netback price calculation

Table 10: Offshore Pty Ltd netback price calculation

Step 14 - Obtain the RPM price for the assessment year

The RPM price for each participant is the average of its cost-plus and netback price (Regulation 20). Tables 11 and 12 show the residual price calculations for each participant.

Table 11: Ausgas Pty Ltd RPM price

Table 12: Offshore Pty Ltd RPM price

Assessable petroleum receipts

For each of the years modelled, Ausgas and Offshore now have prices they can apply to determine their PRRT liable revenue. Example 4 provides a detailed example of the calculation of notional receipts for instalment purposes.

Attachment 4

Example 3: Calculation of RPM price - multiple phases in the upstream and multiple use in two phases (one upstream and one downstream)

Ausgas Pty Ltd is developing an integrated GTL operation which sources natural gas from 2 gas fields. It wholly owns Gas Field 1 and the upstream and downstream stages of the integrated GTL operation. Gas Field 2 is not owned by Ausgas Pty Ltd. Ausgas will process Gas Field 2 gas into liquid on a 'tolling' basis, receiving assessable receipts for this service (while the Gas Field 1 production licence continues). Its PRRT will be worked out by claiming its deductible expenditures in full against the combined total of its receipts from the sale of project liquid and its tolling operations. The downstream stage processes sales gas from both gas fields.

In order to comply with subregulation 6(3), Ausgas Pty Ltd is required to notify the Commissioner that the upstream stage is divided into 2 phases:

Phase 1 of the upstream stage includes the facilities to extract and transport natural gas from the Gas Field 1 (the gas field for which the RPM price in this example is being calculated) up to the phase point.
Phase 2 commences at the phase point where natural gas from Gas Field 2 (a petroleum project not owned by Ausgas Pty Ltd) enters the integrated GTL operation and is transported and processed into sales gas for processing in the downstream stage. The facilities in phase 2 are also used to process gas from Gas Field 1 (project sales gas).

The downstream stage is treated as one phase. The downstream facilities are used to process sales gas from Gas Field 1 and Gas Field 2.

Ausgas Pty Ltd has not entered into an APA with the Commissioner and there is no CUP for the sales gas. Consequently, an RPM price is used to determine Ausgas Pty Ltd's PRRT liability for the upstream production of project sales gas. Subregulation 17(3) applies and an RPM price is to be used to determine the taxpayer's assessable petroleum receipts.

This example sets out how an RPM price is calculated for the first 6 years of project production. Figures in the tables may not add due to rounding.

Details of the project

The Gas Field 1 project is expected to operate for 25 years and process 5 billion units of project sales gas over that time. The project is constructed over a 2 year period commencing in the 2005-06 financial year. Pre-production year capital costs are set out in Table 1 and operating costs for the first 6 years of production are set out in Table 2. It is assumed that no capital costs are incurred in these 6 production years.

The classification and identification of capital and operating expenditures to the upstream and downstream stages take the example up to Step 7 in the method statement contained in Regulation 25. In this example, the classification and identification of costs is set out in the Tables 1 and 2.

Table 1: Capital expenditure of project

Table 2: Operating expenditure

The production data for the gas processed by the project is outlined in Table 3. This table includes data relating to project liquid production and the selling price over the first 6 years of production. It also provides the volume of natural gas from Gas Field 2 (non-project natural gas) processed by the project.

Table 3: Production data

Step 8 - Augmentation of capital costs incurred before the production year

It is assumed that project sales gas is first processed into project liquid in March 2008. Therefore, the production year determined in accordance with subregulation 4(6) for the operation is 2007-08. The production date determined in accordance with subregulation 4(7) is 31 December 2007.

Augmentation of capital costs of Phase 1

Under Regulation 34, capital costs incurred before production commences are augmented for the number of calendar years between the start date and the production date (see Regulation 3 for definitions of these terms). By reference to Table 1, the start date for phase 1 capital expenditures incurred in 2006-07 is 1 January 2007.

Under Regulation 11, the formula used to determine the augmented capital cost is:

The capital allowance is the capital allowance for the production year and is determined under Regulation 13. In this example, the capital allowance for the production year is assumed to be 13 per cent (based on a long-term bond rate of 6 per cent).

For example, the number of calendar years between the start date and the production date (N) for capital costs incurred in relation to phase 1 in 2006-07 is 1.

The phase 1 capital costs incurred in 2006-07 are augmented as follows:

Table 4 shows the effect of augmentation on the nominal capital costs for this project.

Table 4: Augmented capital costs

Step 9 - Augment and reduce early capital costs

Where an MPC other than sales gas is produced before the production year of the integrated GTL operation, all capital costs incurred in relation to this production must be augmented for the number of calendar years between the start date for the capital costs and the 31 December of the MPC production year (paragraph 35(4)(a)). This augmented capital amount is then reduced for the number of calendar years between the 31 December of the MPC production year and the production date (paragraph 35(4)(b)). This process is undertaken to fully account for the use of project capital in the production of MPCs other than project sales gas.

In this example Regulation 35 does not apply as there is no production prior to the production year for project sales gas.

Step 10 - Annualise capital costs

An annual capital allocation is determined for each phase of the project.

As stated above, Ausgas Pty Ltd expects the operating life of the operation to be 25 years. Therefore, the capital allocation for the upstream and downstream components is determined under subregulation 36(4) as:

where:

Capital cost is the total capital costs of each phase after augmentation and reduction; and
Capital allowance is the capital allowance for the cost year (the year of tax in which the capital cost is taken to be incurred - this is assumed to be 13 per cent).

Phase 1 capital allocation

The total capital available in phase 1 is $848 million (see Table 4). The capital allowance of 13 per cent is applied to this augmented capital amount to give the annual allocation for the phase 1:

Phase 2 capital allocation

The total capital available in phase 2 is $835 million (see Table 4). The capital allowance of 13 per cent is applied to this augmented and reduced capital amount to give the annual allocation for the phase 2:

Downstream capital allocation

The capital allowance of 13 per cent is applied to the augmented base capital amount of $2.972 billion (see Table 4) to give the annual allocation for the downstream:

Step 11 - Identify costs for the assessment year

The allocation of capital costs for the assessment year is as determined in Step 10. The relevant operating costs are set out in Table 2.

Step 12 - Apply the energy coefficients to the costs

This project is processing product other than project product. Accordingly, the annual costs determined (including capital costs determined in Step 10) are adjusted according to the proportion (by energy content) of project product being processed in that phase (Regulation 37). Project product is the only product produced and processed in phase 1. Therefore, the phase 1 energy coefficient for each of the production years is one and the costs for phase 1 remain unchanged.

For phase 2 and the downstream stage, which both process a combination of non-project and project product, the costs are to be adjusted by the proportion of project product being processed in each year. For example, in the 2007-08 year the energy coefficient is first calculated as follows (based on the production data in Table 3 and assuming the energy content of project product is the same as that of non-project product):

The energy coefficient is then multiplied by the capital allocation for 2007-08 to arrive at the energy content adjusted capital allocation for phase 2 in that year:

This calculation is repeated to determine the energy content adjusted capital and operating cost allocations for phase 2 and the downstream stage for each year of tax. The adjusted operating cost allocations for phases 1 and 2 are summed to give the total upstream operating costs of the project. The adjusted capital cost allocations for phases 1 and 2 are summed to give the total upstream capital costs of the project. These costs are used in the cost-plus calculation in Step 13 of the RPM. Similarly, the adjusted downstream operating and capital costs are used in the netback calculation in Step 13. Table 5 shows the adjusted capital allocations for each phase and the total capital amounts for the upstream and downstream stages. Table 6 shows the adjusted operating costs for each phase and the total operating costs for the upstream and downstream stages.

Table 5: Energy content adjusted annual capital allocation

Table 6: Energy content adjusted operating costs

From this point, the cost and production data relating to Gas Field 2 are no longer relevant to the calculations.

Step 13 - Obtain the cost-plus and netback prices

Adjustment of capital allocation for utilised capacity

To ensure that the upstream and downstream capital costs included in the netback and cost-plus formulas reflect the appropriate quantum of capital utilised in a year of tax, a volume coefficient is applied to the upstream and downstream capital allocations.

As set out in Regulation 10, the volume coefficient (VC) is the actual volume of project natural gas produced for the current year (VA) divided by the benchmark annual volume of gas (VB).

In the year of tax before the production year, Ausgas Pty Ltd provides the Commissioner with an estimate of the variables required to determine the estimated average annual volume of project natural gas. The Commissioner accepts the estimates and this provides the estimated average volume of project natural gas of 200 million units (Regulation 9).

This estimated estimated average annual volume of project natural gas is taken to be the benchmark volume (VB), until the actual volume (VA) exceeds the estimated volume for the first time. When VA exceeds the estimated volume for the first time, VB equals VA for that year. In subsequent years, VB is the average of production volumes for the years following, and including, the year where VA is greater than the estimate. Example 1 provides a detailed calculation of volume coefficients over a number of years of production.

Based on the production profile for project natural gas shown in Table 3, the volume coefficients for the first 6 years are shown in Table 7 below. The volume coefficient is then applied to the annual capital allocations in the cost-plus and netback formulae.

Table 7: Volume coefficient

Cost-plus price

The cost-plus price is sum of the project's upstream costs per unit of production and the participant's personal upstream costs per unit of project sales gas that participant is entitled to at the end of the upstream stage of production in the year of tax. The cost-plus formula is set out in Regulation 22. For example, for the 2007-08 year of tax the cost-plus calculation for Ausgas Pty Ltd is as follows:

Table 8 shows the cost-plus formula variables and price for the subsequent years.

Table 8: Cost-plus calculation

Netback price

The netback price is determined by subtracting the downstream costs unit cost attributable to the project from the revenue from the sale of a unit of project liquid produced in the year of tax. The netback formula is set out in Regulation 23. Personal costs are not relevant to this example. For the 2007-08 year of tax the netback calculation for Ausgas Pty Ltd is as follows:

Table 11 shows the netback variables and price for the subsequent years.

Table 11: Netback calculation

Step 14 - Obtain the RPM price for the assessment year

The RPM price is the average of the cost-plus price and the netback price (Regulation 20). Table 12 shows the residual price calculation.

Table 12: RPM price calculation

Assessable petroleum receipts

For each of the years modelled, Ausgas Pty Ltd now has a price it can apply to determine its PRRT liable revenue. Example 4 provides a detailed example of the calculation of notional receipts for instalment purposes.

Attachment 5

Example 4: Calculation of current period liability

This example outlines the calculation of a project's notional assessable receipts for determining a project's current period PRRT liability for instalment purposes.

In the first year of production, the notional assessable receipts for instalment purposes are determined by multiplying the volume (VPG) by an RPM price ascertained as if the instalment period were the assessable year. Subregulation 40 (3) does not apply in this example. In subsequent years, the procedure shown in this example is used to determine the notional assessable receipts of the project (Regulation 39). This is done by multiplying the year-to-date project liquid value by the ratio of the previous year's assessable receipts to the previous year's project liquid value. Under the Act, the instalment period is the period from the start of the year of tax to the end of the quarter for which assessable receipts and current period liability is being determined. The calculation of the instalment due for that period gives credit for any previous instalments of the year of tax. The Regulations are consistent with this approach.

This example assumes that no other product is produced by the project during the production year. Table 1 shows the production data for the 2007-08 tax year.

Table 1: 2007-08 year-to-date project production data

(a) Project sales gas not converted into project liquid is included in the VPG variable when calculating assessable receipts of the integrated GTL operation.

Under Regulation 39 the market value of a participant's entitlement to liquefied product for the current instalment period is adjusted for the purpose of calculating the current period liability under subsection 97 (1A) of the Act. The adjusted amount factors in movements in the market value for product liquid from the previous year to the current instalment period. The adjusted amount will be used to determine the current period liability for that period. The formula for the adjustment is:

where:

PLVal is the project liquid value for the participant in the instalment period.

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

In this example, RPMPREV is equal to $3.75.

VPGPREV is the volume of project gas processed to produce project liquid to which the participant was entitled in the previous year of tax (including any project sales gas used in the production process of the integrated GTL operation).

In this example, VPGPREV is equal to 365 million units.

PLValPREV is the project liquid value for the participant in the previous year of tax.

In this example, PLValPREV is equal to $2.555 billion.

For the first instalment period (September quarter) in the 2007-08 year of tax, the formula is applied as follows to give the current period PRRT assessable receipts:

This calculation is repeated for each of the two following instalment periods. These amounts are shown in Table 3.

Table 2: Notional PRRT assessable receipts for the instalment periods

The assessable receipts calculated above are then used as the basis for the calculation of the project's relevant PRRT current period liabilities in accordance with section 97 of the Act.

The project's full year assessable receipts are determined by applying the RPM price for the 2007-08 tax year to the volume of project sales gas produced in that year. In this example, the RPM price for 2007-08 is $3.90 and the volume of project sales gas produced in that year (from Table 1) is 407 million units. Therefore, the total assessable receipts of the project for the year of tax are:

This amount is the assessable receipts for the year of tax to be used in the final assessment.

Attachment 6

List of acronyms and symbols
Acronym Description Regulation
APA Advanced pricing arrangement 18
CUP Comparable uncontrolled price 19
GTL Gas to liquids 4(1)
LTBR Long term bond rate The Act
MPC Marketable petroleum commodity The Act
N Operating life of the operation 4(8)
NE The estimate of N 9(7)
PLVal Value of project liquid 23(1), 39(2) and 40(3)
PRRT Petroleum resource rent tax na
RPM Residual pricing method 25
The Act Petroleum Resource Rent Tax Assessment Act 1987 The Act
VA The actual volume of natural gas for the current year. 10(2)
VB Benchmark volume of natural gas produced upstream for use in the downstream process during the year of tax. 10(2)
VNG The total volume of project natural gas to be recovered during the life of the operation 9(1)(b)
VNGE. The estimate of VNG 9(3)
VPSG Volume of project sales gas 22 and 23(1)