17.3.6
Identifying lease payments included in the measurement of the lease
liability
Some lease agreements include payments that are described as variable or may appear
to contain variability but are in-substance fixed payments because the contract terms
require the payment of a fixed amount that is unavoidable. Such payments are lease
payments included in the measurement of the lease liability and right-of-use assets at
the commencement date.
For example, consideration paid for the use of equipment, such as drilling rigs, is
typically expressed as a rate paid for each operating day, hour or fraction of an hour.
The types of rates a lessee may be charged include:
• full operating rate – a rate charged when the rig is operating at full capacity with a
full crew (in which case there could be a non-lease component of crew services);
• standby rate or cold-stack rate – a rate charged when the lessee unilaterally puts
the rig on standby;
• major maintenance rate – a minimal rate, or in some cases a ‘zero rate’ charged
when the lessor determines that maintenance needs to be performed and the rig is
not available for use by the lessee; or
• inclement weather rate – a minimal rate, or in some cases a ‘zero rate’ charged
when weather makes it dangerous to operate the rig and, therefore, it is not
available for use by the lessee.
There will likely be variability in the pricing of a drilling contract, however typically
there will be a minimum rate in these types of contracts. This amount would likely be
the lowest rate that the lessee would pay while the asset is available for use by the lessee.
Depending on the contract, this rate may be referred to using terms such as a standby
or cold-stack rate. When identifying lease payments in an arrangement, mining
companies and oil and gas companies should only consider rates that apply when the
asset is available for use.
Example 39.17: Identifying lease payments – inclement weather
Upstream Entity A enters into a 3-year contract with Rig Owner for the right to use Drilling Rig 1 over a
three year period. The contract is considered to contain a lease. The contract specifies the rates a lessee may
be charged and these include:
• full operating rate of 100,000 CU per day – charged when the rig is operating at full capacity with a full crew;
• standby rate of 40,000 CU per day – charged when the lessee unilaterally puts the rig on standby; and
• inclement weather rate of zero CU per day – charged when weather makes it dangerous to operate the
rig and, therefore, it is not available for use by the lessee.
Analysis
In calculating the lease liability, the standby rate of 40,000 CU per day for 3 years would be used. The
inclement weather rate is not applicable in calculating the minimum lease payments as the rate only applies
when the asset is not available for use.
Example 39.18: Identifying lease payments – major maintenance
Mining entity Z enters into an arrangement with Equipment Supplier T for the lease of a piece of processing
equipment to be utilised at the mine site. The contract requires payment of 10,000 CU per day for the
equipment, but stipulates Supplier T perform10 days per annum of major maintenance that is required on the
equipment. The day rate for those 10 major maintenance days is zero CU per day.
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Analysis
In calculating the lease liability, the rate of 10,000 CU per day would be used. However, the rate would only
be applied for 355 days each year on the basis that the contractual arrangement clearly sets out that there are
10 days per annum where the equipment will not be available for use to allow for major maintenance to be
undertaken, and that a zero day rate will apply on those days. Accordingly, contractually, the minimum lease
payments are in fact lower, as the equipment will only be available for 355 days per annum.
This differs from the zero day rate that applies for inclement weather in example 39.17 above because the
period of time when the inclement weather rate will apply, is outside of the control of both parties.
See Chapter 24 at 4.5.1 for further discussion.
17.3.7
Allocating contract consideration
Lessees allocate the consideration in the contract to the lease and non-lease components
on a relative stand-alone price basis. However, IFRS 16 provides a practical expedient that
permits lessees to make an accounting policy election, by class of underlying asset, to
account for each separate lease component of a contract and any associated non-lease
components as a single lease component. Lessors are required to apply IFRS 15 to allocate
the consideration in a contract between the lease and non-lease components, generally, on
a relative stand-alone selling price basis. See Chapter 24 at 3.2.3.B for further information.
17.3.8
Interaction of leases with asset retirement obligations
When undertaking remediation and rehabilitation activities, it may be possible that a
mining company or oil and gas company enters into an arrangement with a supplier that
is, or contains, a lease that is considered to be an operating lease under IAS 17. The costs
associated with these activities form a significant component of the costs which make
up the asset retirement obligation (ARO) that was recognised by the mining company or
oil and gas company at commencement of the mine or field.
Upon adoption of IFRS 16, assuming this lease is not a short-term lease and does not
relate to the lease of a low-value asset, a right-of-use asset and lease liability will need
to be recognised. One of the issues that has arisen as a result of IFRS 16, is whether the
mining company or oil and gas company’s recognition of the lease liability results in the
derecognition of the ARO liability recognised on the balance sheet. Given that prior to
the commencement of any ARO-related activities, the mining company or oil and gas
company still has an obligation to rehabilitate under IAS 37, it cannot derecognise the
ARO liability. Instead, it now has a separate lease liability for the financing of the lease
of the asset. Accordingly, acquiring the right-of-use asset does not result in the
derecognition of the ARO liability, rather, it would be the activity undertaken or output
of the asset which would ultimately settle the ARO liability. This approach would be
consistent with a scenario where an asset, e.g. the leased asset, had been purchased,
using bank finance, and the finance liability relating to the bank debt used to purchase
the asset, is separately recognised on the balance sheet.
As such, at the point prior to any ARO activity (assuming this occurs at end of mine/field
life), the mining company or oil and gas company has:
• no ARO asset (fully amortised);
• an ARO liability for the full ARO estimate;
• a right-of-use asset; and
• a lease liability.
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See Chapter 24 at 5.2 for discussion on measurement of the right-of-use asset and
lease liability.
The impacts of this will include:
• amortisation of the right-of-use asset across the period of use;
• in
terest expense on the lease liability;
• interest expense arising from the unwinding on the discount on the ARO liability,
assuming interest continues to unwind over the remediation and rehabilitation
activity period; and
• the use (reduction) of the ARO liability (as the leased asset is used to settle
the obligation).
Consideration should be given to the requirements of IAS 37, [IAS 37.61-62], which sets out
that a provision shall be used only for expenditures for which the provision was
originally recognised, i.e. that expenditures that relate to the original provision are set
against it. See Chapter 27 at 4.9.
18 TOLLING
ARRANGEMENTS
In the mining sector it is common for entities to provide raw material to a smelter
or refiner for further processing. If the raw material is sold to the smelter or refiner
and the relevant criteria are satisfied, the mining company recognises revenue in
accordance with IFRS 15. However, under a ‘tolling’ arrangement a mining
company generally supplies, without transferring ownership, raw material to a
smelter or refiner which processes it for a fee and then returns the finished product
to the customer. Alternatively, the mining company may sell the raw material to the
smelter or refiner, but is required to repurchase the finished product. In the latter
two situations, no revenue should be recognised when the raw material is shipped
to the smelter or refiner as there has not been a transfer of the risks and rewards.
An entity should carefully assess the terms and conditions of its tolling
arrangements to determine:
• when it is appropriate to recognise revenue;
• whether those arrangements contain embedded leases that require separation
under IFRIC 4 (see 17.1 above);
• whether the tolling arrangement is part of a series of transactions with a joint
arrangement; and
• whether the toll processing entity is a structured entity that requires consolidation
under IFRS 10 (see Chapter 6 at 4.4.1 for more information).
Extract 39.44 below describes a tolling arrangement between Norsk Hydro and one of
its joint arrangements.
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Extract 39.44: Norsk Hydro ASA (2013)
Notes to the consolidated financial statements [extract]
Note 26 – Investments in jointly controlled entities [extract]
Aluminium Norf GmbH (Alunorf) located in Germany is the world’s largest rolling mill and is owned by Hydro and
Hindalco Industries (50 percent each). Alunorf produces flat rolled products from raw material from the partners based
on a tolling arrangement. Sales from Alunorf to Hydro amounted to NOK 1,499 million in 2013 and NOK 1,423 million
in 2012. Hydro’s capital and financing commitments are regulated in the Joint Venture agreement. Alunorf has
investment commitments amounting to NOK 444 million as of December 31, 2013. Hydro’s financing commitment
based on its interest is NOK 189 million as of December 31, 2013. Alunorf is part of Rolled Products.
For a discussion on the impacts of IFRS 15 on repurchase agreements, see 12.14 above.
19 TAXATION
As mentioned at 1.1 above, one of the characteristics of the extractive industries is the
intense government involvement in their activities, which ranges from ‘outright
governmental ownership of some (especially petroleum) or all minerals to unusual tax
benefits or penalties, price controls, restrictions on imports and exports, restrictions on
production and distribution, environmental and health and safety regulations, and others’.147
Mining companies and oil and gas companies typically need to make payments to
governments in their capacity as:
• owner of the mineral resources;
• co-owner or joint arrangement partner in the projects;
• regulator of, among other things, environmental matters and health and safety
matters; and
• tax authority.
The total payment to a government is often described as the ‘government take’. This includes
fixed payments or variable payments that are based on production, revenue, or a net profit
figure; and which may take the form of fees, bonuses, royalties or taxes. Determining whether
a payment to government meets the definition of income tax is not straightforward.
IAS 12 should be applied in accounting for income taxes, defined as including:
(a) all domestic and foreign taxes which are based on taxable profits; and
(b) taxes, such as withholding taxes, which are payable by a subsidiary, associate or
joint arrangements on distributions to the reporting entity. [IAS 12.1-2].
As discussed in Chapter 29 at 4.1, it is not altogether clear what an income tax actually is.
In the extractive industries the main problem with the definition in IAS 12 occurs when:
(a) a government raises ‘taxes’ on sub-components of net profit (e.g. net profit before
financing costs or revenue minus allowed costs); or
(b) there is a mandatory government participation in certain projects that entitle the
government to a share of profits as defined in a joint operating agreement.
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A considerable amount of judgement is required to determine whether a particular
arrangement falls within the definition of ‘income tax’ under IAS 12 or whether it is
another form of government take. From a commercial perspective the overall share of
the economic benefits that the government takes is much more important than the
distinction between its different forms. In practice, most governments receive benefits
from extractive activities in several different ways, as discussed below. Governments
can choose any of these methods to increase or decrease their share of the benefits.
However, the distinction is crucial given the considerable differences in the accounting
treatments and disclosures that apply to income taxes, other taxes, fees and government
participations. For example, it will affect where these amounts are presented in the profit
or loss, e.g. in operating costs or income tax expense; and it will determine whether
deferred tax balances are required to be recognised and the related disclosures provided.
19.1 Excise duties, production taxes and severance taxes
Excise duties, production taxes and severance taxes result in payments that are due on
production (or severance) of minerals from the earth. Depending on the jurisdiction and
the type of mineral involved, they are calculated:
(a) as a fixed amount per unit produced;
(b) as a percentage of the value of the minerals produced; or
(c) based on revenue minus certain allowable costs.
19.1.1 Production-based
taxation
If the tax is based on a fixed amount per unit produced or as a percentage of the value
of the minerals produced, then it will not meet the definition of an income tax under
IAS 12. In these cases the normal principles of liability recognition under IAS 37 apply
in recognising the tax charge.
Another issue that arises is whether these taxes are, in effect, collected by the entity
from customers on behalf of the taxing authority, as an agent. In other cases, the
taxpayer’s role is more in the nature of principal than agent. The regulations differ
significantly from one country to another. The practical accounting issue that arises
concerns the interpretation of the requirements of IFRS 15 which states that the
‘transaction price is the amount of consideration to which an entity expects to be
entitled in exchange for transferring promised goods or services to a customer,
excluding amounts collected on behalf of third parties (for example, some sales taxes)’.
[IFRS 15.47]. Specifically, should excise duties, production taxes and severance taxes be
deducted from revenue (net presentation) or included in the production costs and,
therefore, revenue (gross presentation)? See 12.11.2 above for further discussion on the
impact of IFRS 15 on the presentation of royalty payments.
The appropriate accounting treatment will depend on the particular circumstances. In
determining whether gross or net presentation is appropriate, the entity needs to
consider whether it is acting in a manner similar to that of an agent or principal. For
further discussion of principal versus agent under IFRS 15 see 12.11 above and
Chapter 28 at 5.4 and presentation of royalties at 5.7.5 above.
Given that excise duties, production taxes and severance taxes are aimed at taxing the
production of minerals rather than the sale of minerals, they are considered to be a tax
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on extractive activities rather than a tax collected by a mining company or oil and gas
company on behalf of the government. Based on this, the tax should be presented as a
production cost.
However, it may be considered that when the excise duty, production tax or severance
tax is payable in kind, that the mining company or oil and gas company never receives
any of the benefits associated with the production of the associated minerals. Hence, it
would be more appropriate to present revenue net of the production or severance tax
as it is in substance the same as a royalty payment.
19.1.2
Petroleum revenue tax (or resource rent tax)
Determining whether a petroleum revenue tax (or resource rent tax) is a production- or
profit-based tax is often not straightforward. Example 39.19 below describes the
petroleum revenue tax in the United Kingdom.
Example 39.19: Petroleum revenue tax148
Petroleum revenue tax (PRT) is a special tax that seeks to tax a high proportion of the economic rent (super-
International GAAP® 2019: Generally Accepted Accounting Practice under International Financial Reporting Standards Page 670