International GAAP® 2019: Generally Accepted Accounting Practice under International Financial Reporting Standards

by International GAAP 2019 (pdf)

  of equipment, tools, and personnel used to perform the service. In most cases, the

  service contractor’s reimbursement is fixed by the terms of the contract with little

  exposure to either project performance or market factors. Payment for services is

  normally based on daily or hourly rates, a fixed turnkey rate, or some other specified

  amount. Payments may be made at specified intervals or at the completion of the

  service. Payments, in some cases, may be tied to the field performance, operating cost

  reductions, or other important metrics.

  The risks of the service company under this type of contract are usually limited to non-

  recoverable cost overruns, losses owing to client breach of contract, default, or

  contractual dispute. Such a contract is generally considered to be a services contract

  that gives rise to revenue from the rendering of services and not income from the

  production of mineral. Therefore, the minerals produced are not included in the normal

  reserve disclosures of the contractor,92 and the contractor bears no risk if reserves are

  not found. It is worth noting that such contracts do need to be assessed for embedded

  leases in accordance with the requirements of IFRIC 4. See 17.1 below for more

  information. As noted above with respect to PSCs, the type and nature of contracts

  continue to evolve. These new contracts also have some attributes of services contracts,

  but do differ from pure-service contracts. We discuss these in more detail at 5.5 below.

  5.5 Evolving

  contractual

  arrangements

  The type and nature of contracts emerging continues to evolve. New contracts have

  some attributes of PSCs, but do differ from the traditional PSC. As these contractual

  arrangements evolve, determining the accounting implications of these contracts is

  becoming increasingly complex. This not only has an impact on the accounting for

  such contracts but also on whether, and the extent to which, the contractor entity is

  able to recognise reserves in relation to its interests in mineral volumes arising from

  these contracts.

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  Each contractual arrangement needs to be analysed carefully to determine whether

  reserves recognition in relation to these contractual interests in mineral volumes is

  appropriate. Such an analysis would include, at a minimum:

  • the extent of risk to which the contractor party is exposed, including exploration

  and/or development risk;

  • the structure of the contractor’s reimbursement arrangements and whether it is

  subject to performance/reservoir risk or price risk; and

  • the ability for the contractor to take product in-kind, rather than a cash

  reimbursement only.

  Other facts and circumstances may also be relevant in reaching the final assessment.

  Given the varying terms and conditions that exist within these contracts and the fact

  that they are continuing to change/evolve, each contract will need to be individually

  analysed and assessed in detail.

  5.5.1 Risk

  service

  contracts

  An example of a contractual arrangement that has continued to evolve is a risk service

  contract (RSC). Unlike pure-service contracts, under a RSC (also called risked service

  agreement or at-risk service contract), a fee is not certain: an entity (contractor) agrees

  to explore for, develop, and produce minerals on behalf of a host government, but the

  contractor is at risk for the amount spent on exploration and development costs. That

  is, if no minerals are found in commercial quantities, no fee is paid.93 Although a RSC

  does not result in the contractor’s ownership of the minerals in place, the contractor

  may be at risk for the costs of exploration and may have economic interest in those

  minerals. The IASC Issues Paper noted that in the case of RSCs:94

  • the fee may be payable in cash or in minerals produced;

  • the contract may call for the contractor to bear all or part of the costs of exploration

  that are usually recoverable, in whole or in part, from production. If there is no

  production, there is no recovery; and

  • the contract may also give the contractor the right to purchase part of the

  minerals produced.

  As noted in Extract 39.7 above from TOTAL’s financial statements, RSCs are similar to

  PSCs in a number of respects. Although the precise form and content of a RSC may

  vary, the following features are common:

  (a) the repayment of expenses and the compensation for services are established on a

  monetary basis;

  (b) a RSC is for a limited period, after which the government or national oil company

  will take over operations;

  (c) under an RSC the contractor does not obtain ownership of the mineral reserves

  or production;

  (d) the contractor is normally required to carry out a minimum amount of work in

  providing the contracted services;

  (e) the fee that is payable to the contractor covers its capital expenditure, operating

  costs and an agreed-upon profit margin; and

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  industries

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  (f) ownership of the assets used under the contract passes to the government when

  the contractor has been reimbursed for its costs.

  The SPE’s Guidelines for the Evaluation of Petroleum Reserves and Resources notes in

  connection with RSCs that ‘under the existing regulations, it may be more difficult for

  the contractor to justify reserves recognition, and special care must be taken in drafting

  the agreement. If regulations are satisfied, reserves equivalent to the value of the cost-

  recovery-plus-revenue-profit split are normally reported by the contractor’.95

  The nature and terms and conditions of these RSCs continue to change over time. Therefore

  each contract will need to be analysed in detail to determine how it should be accounted for.

  5.6

  Joint operating agreements

  When several entities are jointly involved in an arrangement (e.g. joint ownership of a

  property, production sharing contract or concession) they will need to enter into some form

  of joint operating agreement (JOA). A JOA is a contract between two or more parties to a

  joint arrangement that sets out the rights and obligations to operate the property. Typically,

  a JOA designates one of the working interest owners as the operator and it governs the

  operations and sharing of costs between parties. A JOA does not override, but instead builds

  upon, the contracts that are already in place (such as production sharing contracts). In fact,

  many production sharing contracts require the execution of a JOA between the parties.

  A JOA may give rise to a joint arrangement under IFRS 11 – Joint Arrangements – if

  certain criteria are met. This is discussed in more detail at 7.1 below.

  5.7

  Different types of royalty interests

  Mining companies and oil and gas companies frequently enter into royalty arrangements

  with owners of mineral rights (e.g. governments or private land owners). These royalties are

  often payable upon the extraction and/or sale of minerals. The royalty payments may be

  based on a specified rate per unit of the commodity (e.g. tonne or barrel) or the entity may

  be obliged to dispose of all of the relevant producti
on and pay over a specified proportion

  of the aggregate proceeds of sale, often after deduction of certain extraction costs.

  There are also other types of arrangements, which may be referred to as royalty

  payments/arrangements, but may potentially represent a different type of arrangement.

  Under these arrangements the royalty holder may have retained (or obtained) a more

  direct interest in the underlying production and may undertake mineral extraction and

  sale arrangements independently. We discuss these further below.

  5.7.1

  Working interest and basic royalties

  As discussed at 5.1 above, under a mineral lease the owner/lessor of the mineral rights

  retains a basic royalty interest (or non-operating interest), which entitles it to a specified

  percentage of the mineral produced, while the lessee obtains a working interest (or

  operating interest) under the mineral lease, which entitles it to explore for, develop, and

  produce minerals from the property.

  If the owner of a working interest cannot fund or does not wish to bear the risk of

  exploration, development or production from the property, it may be able to – if this is

  permitted by the underlying lease – sell the working interest or to create new types of

  interest out of its existing working interest. By creating new types of non-operating

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  interests, the working interest owner is able to raise financing and spread the risk of the

  development. The original working interest holder may either:

  • retain the new non-operating interest and transfer the working interest (i.e. the

  rights and obligations for exploring, developing and operating the property); or

  • carve out and transfer a new non-operating interest to another party, while

  retaining the working interest.

  The following non-operating interests are commonly created in practice:96

  • overriding royalties (see 5.7.2 below);

  • production payment royalties (see 5.7.3 below); and

  • net profits interests (see 5.7.4 below).

  5.7.2 Overriding

  royalties

  An overriding royalty is very similar to a basic royalty, except that the former is created

  out of the operating interest and if the operating interest expires, the overriding royalty

  also expires.97 An overriding royalty owner bears only its share of production taxes and

  sometimes of the costs incurred to get the product into a saleable condition.

  5.7.3

  Production payment royalties

  A production payment royalty is the right to recover a specified amount of cash or a specified

  quantity of minerals, out of the working interest’s share of gross production. For example,

  the working interest holder may assign a production payment royalty to another party for

  USD 12 million, in exchange for a repayment of USD 15 million plus 12% interest out of the

  first 65% of the working interest holder’s share of production. Production payments that are

  specified as a quantity of minerals are often called volumetric production payments or VPPs.

  5.7.4

  Net profits interests

  A net profits interest is similar to an overriding royalty. However, the amount to be

  received by the royalty owner is a share of the net proceeds from production (as defined

  in the contract) that is paid solely from the working interest owner’s share. The owner

  of a net profits interest is not liable for any expenses.

  5.7.5

  Revenue and royalties: gross or net?

  Many mineral leases, concession agreements and production sharing contracts require the

  payment of a royalty to the original owner of the mineral reserves or the government. The

  accounting treatment for government and other royalties payable has historically been

  diverse, as it has not been entirely clear whether revenue should be presented net of royalty

  payments or not. Historically, many companies have presented revenue net of those royalties

  that are paid in kind. This was on the basis that the entity had no legal right to the royalty

  product and, hence, never received any inflow of economic benefits from those volumes.

  However, when the entity is required to sell the physical product in the market and remit the

  net proceeds (after deduction of certain costs incurred) to the royalty holder, it may have

  been considered to have control of those volumes to such an extent that it was appropriate

  to present revenue on a gross basis and include the royalty payment within cost of sales or

  taxes (depending on how the royalty is calculated). See 12.11.2 below for further discussion.

  Extracts 39.8 and 39.9 below, from the financial statements of Premier Oil and BHP

  respectively, illustrate typical accounting policies for royalties under IFRS.

  Extractive

  industries

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  Extract 39.8: Premier Oil plc (2017)

  Accounting Policies [extract]

  For the year ended 31 December 2017

  Royalties

  Royalties are charged as production costs to the income statement in the year in which the related production is

  recognised as income.

  Extract 39.9: BHP Billiton plc (2017)

  5 Income tax expense [extract]

  Recognition and measurement [extract]

  Royalty-related taxation [extract]

  Royalties and resource rent taxes are treated as taxation arrangements (impacting income tax expense/(benefit)) when

  they are imposed under government authority and the amount payable is calculated by reference to revenue derived

  (net of any allowable deductions) after adjustment for temporary differences. Obligations arising from royalty

  arrangements that do not satisfy these criteria are recognised as current provisions and included in expenses.

  Extract 39.10 below, from the financial statements of Statoil, illustrates some of the

  complications that may arise in determining revenue when an entity sells product on

  behalf of the government.

  Extract 39.10: Statoil ASA (2017)

  Notes to the Consolidated financial statements [extract]

  2 Significant accounting policies [extract]

  Transactions with the Norwegian State [extract]

  Statoil markets and sells the Norwegian State’s share of oil and gas production from the Norwegian continental shelf (NCS).

  The Norwegian State’s participation in petroleum activities is organised through the SDFI. All purchases and sales of the SDFI’s oil production are classified as purchases [net of inventory variation] and revenues, respectively. Statoil sells, in its own name, but for the Norwegian State’s account and risk, the State’s production of natural gas. These sales and related

  expenditures refunded by the Norwegian State are presented net in the Consolidated financial statements.

  Critical accounting judgements and key sources of estimation uncertainty [extract]

  Revenue recognition – gross versus net presentation of traded SDFI volumes of oil and gas production

  As described under Transactions with the Norwegian State above, Statoil markets and sells the Norwegian State’s

  share of oil and gas production from the NCS. Statoil includes the costs of purchase and proceeds from the sale of the

  SDFI oil production in purchases [net of inventory variation] and revenues, respectively. In making the judgement,

  Statoil considered the detailed criteria for the recognition of revenue from the sale of goods and, in particular,

  concluded that the risk an
d reward of the ownership of the oil had been transferred from the SDFI to Statoil.

  Statoil sells, in its own name, but for the Norwegian State’s account and risk, the State’s production of natural gas.

  These gas sales, and related expenditures refunded by the State, are shown net in Statoil’s Consolidated financial

  statements. In making the judgement, Statoil considered the same criteria as for the oil production and concluded that

  the risk and reward of the ownership of the gas had not been transferred from the SDFI to Statoil.

  The SPE-PRMS (see 2.2 above) notes that ‘royalty volumes should be deducted from

  the lessee’s entitlement to resources. In some agreements, royalties owned by the host

  government are actually treated as taxes to be paid in cash. In such cases, the equivalent

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  royalty volumes are controlled by the contractor who may (subject to regulatory

  guidance) elect to report these volumes as reserves and/or contingent resources with

  appropriate offsets (increase in operating expense) to recognize the financial liability of

  the royalty obligation’.98

  6 RISK-SHARING

  ARRANGEMENTS

  As discussed at 1.1 above, the high costs and high risks in the extractive industries often

  lead entities to enter into risk-sharing arrangements. The following types of risk-sharing

  arrangements are discussed in this chapter:

  • carried interests (see 6.1 below);

  • farm-ins and farm-outs (see 6.2 below);

  • asset swaps (see 6.3 below);

  • unitisations (see 15.4 below);

  • investments in subsidiaries, joint arrangements and associates (see 7 below);

  • production sharing contracts (see 5.3 above), which result in a degree of risk

  sharing with local governments; and

  • risk service contracts (see 5.5.1 above).

  6.1 Carried

  interests

  Carried interests often arise when a party in an arrangement is either unable or

  unwilling to bear the risk of exploration or is unable or unwilling to fund its share of

  the cost of exploration or development. A carried interest is an agreement under

  which one party (the carrying party) agrees to pay for a portion or all of the pre-

  production costs of another party (the carried party) on a licence in which both own

  a portion of the working interest.99 In effect, commercially, the carried party is trading