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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(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.
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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
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