always been a matter requiring considerable judgement for mining entities. See 4 above
3374 Chapter 39
for further discussion. This issue is particularly relevant when assessing how to account
for new mining techniques. For example, block cave mining is one such mining technique
that is being increasingly proposed or used for a number of deposits worldwide.
Block cave mining is a mass mining method that allows for the bulk mining of large,
relatively lower grade, ore bodies for which the grade is consistently distributed
throughout. The word ‘block’ refers to the layout of the mine – which effectively divides
the ore body into large sections, with areas that can be several thousand square metres in
size. This approach adopts a mine design and process which involves the creation of an
undercut by fracturing the rock section underneath the block through the use of blasting.
This blasting destroys the rock’s ability to support the block above. Caving of the rock
mass then occurs under the natural forces of gravity (which can be in the order of millions
of tonnes), when a sufficient amount of rock has been removed underneath the block.
The broken ore is then removed from the base of the block. This mine activity occurs
without the need for drilling and blasting, as the ore above continues to fall while the
broken ore beneath is removed. Broken ore is removed from the area at the extraction
level through the use of a grid of draw points. These effectively funnel the broken ore
down to a particular point so that it can be collected and removed for further processing.
Block caving has been applied to large scale extraction of various metals and minerals,
sometimes in thick beds of ore but more usually in steep to vertical masses. Examples
of block caving operations include Northparkes (Australia), Palabora (South Africa),
Questa Mine (New Mexico) and Freeport (Indonesia).143
Block cave mining does require substantial upfront development costs, as initial
underground access followed by large excavations (undercutting), must be completed
to gain access and initially ‘undermine’ the block that is to cave. In addition, large
underground and above ground haulage and milling infrastructure must be constructed
to extract and then process the ore that a successful cave will generate.
One of the key issues to be addressed is how these substantial upfront development
costs, in addition to the ongoing development costs associated with each block (i.e. to
extend the undercutting beneath each new block and construct the draw points for each
block) should be treated for depreciation or amortisation.
Generally these costs are depreciated or amortised on a units of production basis –
therefore in determining useful life, it is necessary to determine what the appropriate
reserves base should be for each of these different types of costs. For example, in relation
to the costs associated with initially going underground and constructing the main haulage
tunnel which will be used to access and extract the reserves from the entire ore body, the
useful life associated with such assets may be the reserves of the entire ore body.
In relation to the costs associated in constructing the milling infrastructure, it is possible
that such assets may be used to process ore from multiple ore bodies. Therefore, the
useful life of such assets may be the reserves of multiple ore bodies. However, this will
depend upon the specific facts and circumstances of the particular development.
For those costs associated with each individual block, e.g. the undercutting costs directly
attributable to each block and the costs associated in constructing the draw points for that
block, the appropriate reserves base may potentially only be those to be extracted from
that particular block, which may only be a component of the entire ore body.
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The approach adopted by each entity will be determined by the specific facts and
circumstances of each mine development, such as the nature of the block cave mining
technique employed and how the associated assets will be used. Such an assessment
will require entities to exercise considerable judgement. Appropriate disclosures are
recommended where significant judgements and estimates are considered material.
17
LONG-TERM CONTRACTS AND LEASES
Given the nature of the extractive industries, mining companies and oil and gas
companies regularly enter into a wide range of long-term contracts. These may relate
to the provision of services or the sale of goods. There are a number of potential issues
to be addressed when considering the accounting for these arrangements, these are
discussed below. In 17.1 and 17.2 below we consider the current accounting
requirements under IFRIC 4 and IAS 17. For a discussion of the impact of the new leases
standard (IFRS 16) on mining companies and oil and gas companies see 17.3 below. This
should be read in conjunction with the general discussion set out in Chapter 24.
17.1 Embedded
leases
IFRIC 4 notes that there are arrangements that do not take the legal form of a lease but
that convey rights to use items for agreed periods of time in return for a payment or
series of payments. [IFRIC 4.1].
The Interpretation focuses on the accounting implications of the following, all of which
are forms of arrangements found in the extractive industries and in all of which an entity
(the supplier) conveys a right to use an asset to another entity (the purchaser), together
with related services or outputs:
• outsourcing arrangements;
• arrangements where suppliers of network capacity enter into contracts to provide
purchasers with rights to capacity; and
• take-or-pay and similar contracts, in which purchasers must make specified
payments regardless of whether they take delivery of the contracted products or
services (e.g. where purchasers are committed to acquiring substantially all of the
output of a supplier’s power generator). [IFRIC 4.1]. See 17.2 below.
Other types of agreements common in the extractive industries and which would need
to be assessed for the existence of embedded leases include:
• service arrangements – such as contract mining services arrangements or oilfield
services arrangements;
• throughput arrangements (which may take the form of a take-or-pay arrangement);
• tolling contracts (see 18 below);
• contractor facilities located on the mining company’s or oil and gas company’s property;
• storage facility arrangements;
• energy-related or utility contracts, e.g. gas, electricity, telecommunications, water; or
• transportation/freight/shipping/handling services contracts.
3376 Chapter 39
IFRIC 4 specifies that one of these types of arrangements (or part thereof) could be
within the scope of IAS 17 if it meets the definition of a lease, e.g. if it conveys to the
lessee the right to use an asset for an agreed period of time in return for a payment or
series of payments. [IFRIC 4.BC2]. IAS 17 applies to the lease element of the arrangement
notwithstanding the related services or outputs because IAS 17 applies to ‘agreements
that transfer
the right to use assets even though substantial services by the lessor may
be called for in connection with the operation or maintenance of such assets’. [IAS 17.3].
This is regardless of the fact that the arrangement is not described as a lease and is likely
to grant rights that are significantly different from those in a formal lease agreement.
The detailed requirements of IFRIC 4 are discussed in Chapter 23 at 2.1.
See 17.3 below for a discussion of the impact of the new leases standard (IFRS 16) on
mining companies and oil and gas companies and Chapter 24 for a general discussion.
ENGIE SA has an accounting policy addressing IFRIC 4.
Extract 39.42: ENGIE SA (2017)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS [extract]
NOTE 1 ACCOUNTING STANDARDS AND METHODS [extract]
1.4 Accounting methods [extract]
1.4.9 Leases [extract]
1.4.9.3 Accounting for arrangements that contain a lease
IFRIC 4 deals with the identification of services and take-or-pay sales or purchasing contracts that do not take the
legal form of a lease but convey rights to customers/suppliers to use an asset or a group of assets in return for a
payment or a series of fixed payments. Contracts meeting these criteria should be identified as either operating leases
or finance leases. In the latter case, a finance receivable should be recognized to reflect the financing deemed to be
granted by the Group where it is considered as acting as lessor and its customers as lessees.
The Group is concerned by this interpretation mainly with respect to:
• some energy purchase and sale contracts, particularly where the contract conveys to the purchaser
of the energy an exclusive right to use a production asset;
• certain contracts with industrial customers relating to assets held by the Group.
17.2 Take-or-pay
contracts
A ‘take-or-pay’ contract is a specific type of long-term commodity-based sales agreement
between a customer and a supplier in which the pricing terms are set for a specified minimum
quantity of a particular good or service. The customer must pay the minimum amount as per
the contract, even if it does not take the volumes. There may also be options for additional
volumes in excess of the minimum. Take-or-pay contracts for the supply of gas are
particularly common, because entities developing gas fields need to make very significant
investments in infrastructure such as pipelines, liquefaction plants and shipping terminals, to
make transport of gas to the end-consumer economically viable. In order to raise the funds
to finance such investments, it is crucial to know that there is a profitable market for the gas,
as it cannot easily be diverted and sold in an alternative market or to an alternative customer.
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While take-or-pay contracts perhaps most commonly involve the supply of gas, they
can also include other arrangements such as contracts for pipeline capacity or LNG
regasification facilities. Take-or-pay contracts also are used in the mining sector, e.g.
with some coal contracts, though less frequently than in the oil and gas sector. Often
take-or-pay contracts permit the purchaser to recover payments for quantities not
taken, by allowing the purchaser to take more than the minimum in later years and to
apply the previously paid-for undertake amount towards the cost of product taken in
the later years.144
The following issues need to be considered in accounting for take-or-pay contracts:
• Structured entities – If a take-or-pay contract transfers the majority of the risks
and rewards from the development of a mine or gas field to the customer, it is
necessary to consider whether the entity developing the gas field has, in effect,
become a structured entity of that customer and therefore, the customer needs to
consider the level of influence it has over that mining entity or oil and gas entity
(see Chapter 6 at 4.4.1).
• Embedded leases – Take-or-pay contracts are often for a very significant portion
of the output of the gas field that it relates to. Therefore, as illustrated in
Extract 39.48 above, the operator and customer need to consider whether the
take-or-pay contract contains a lease of the related assets (see 17.1 above for
current requirements under IAS 17 and IFRIC 4 and 17.3 below for potential
implications under IFRS 16).
• Embedded derivatives – As illustrated in Extract 39.43 below, the price of gas sold
under take-or-pay contracts is often based on a ‘basket’ of fuel prices and/or
inflation price indices. If there is an active market for gas then this often means
that an embedded derivative needs to be separated from the underlying host take-
or-pay contract (see 13.2 above).
• Guarantees – Lenders are often willing to provide funding for the development of
a gas field only if the operator can present a solid business case, which includes a
‘guaranteed’ stream of revenue from a reputable customer. In such cases, the take-
or-pay contract acts as a form of credit enhancement or possibly as a guarantee.
The operator and customer may need to consider whether the take-or-pay
arrangement includes a guarantee that should be accounted for such under IFRS 9
(see Chapter 41 at 3.4).
• Make-up product and undertake – A customer that fails to take the specified
volume during the period specified must nevertheless pay for the agreed-
volume. However, a take-or-pay contract sometimes permits the customer to
take an equivalent amount of production (makeup product) at a later date after
the payment for the guaranteed amount has been made (see 12.16 above and
17.2.1 below).
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Extract 39.43 below from the financial statements of ENGIE SA gives an overview of
some of these important terms and conditions that exist in take-or-pay contracts.
Extract 39.43: ENGIE SA (2017)
2017 Registration Document
2 Risk factors [extract]
2.3 Operational risks[extract]
2.3.1 Purchases and sales [extract]
2.3.1.1 Purchase and sale of natural gas
The Group has established a procurement portfolio composed in part of long-term contracts, including some with a take-
or-pay clause which, under certain conditions, stipulates that minimum quantities will be taken during a period.
In case of major gas supply interruption (for example, due to an interruption of Russian deliveries or an interruption of transit in Ukraine) or an interruption of LNG supply (for example, from Yemen or Egypt), or difficulty in renewing
certain contracts under favorable economic conditions, the replacement cost for gas, including transportation, could be
higher and affect the Group’s margins. To mitigate this risk, the Group has a number of tools for flexibility and
modulation (flexibility in long-term contracts, storage and regasification capacity, and purchasing in the marketplaces)
as well as a diversified portfolio.
Prices of long-term purchase contracts (partially indexed to the price indices of oil products) may be decorrelated from
selling prices or prices in the gas markets. This spread might have a significant impact on the Group’s results. Long-term contracts include price adjustment clauses, so that the economic balance between producer and buyer can be altered. The
Group’s buy/sell margin may therefore change according to price adjustments in LNG or gaseous gas contracts and the
state of the gas market in general.
Negotiations in recent years have led to the integration of market indices in long-term contracts and/or to the reduction of the difference between the contract price and market price. They have also led to increased frequency of price revisions.
17.2.1
Make-up product and undertake
Under some take-or-pay arrangements, a customer who is required to pay for the
product not taken will often have no right of future recovery. The customer should
recognise an expense equal to the payment made, while the operator recognises the
same amount as revenue. However, if the substance of the relationship between the
operator and customer is such that a renegotiation of the arrangement is probable then
it may be more appropriate for the operator to recognise the penalty payment as
deferred revenue. The customer, however, should still recognise an expense in this case
as it does not have a legal right to receive reimbursement or makeup product.145
The accounting is different when a customer that is required to pay for product not
taken has a right to take makeup product in the future.
In this case, the operator would recognise a contract liability, i.e. deferred revenue, in
relation to the ‘undertake’ measured in accordance with IFRS 15, as it represents an
obligation for the operator to have to provide the product in the future. The operator only
recognises revenue in accordance with IFRS 15 once the make-up product has been taken
by the customer, i.e. the performance obligation is satisfied. Only once the make-up
period has expired or it is clear that the purchaser has become unable to take the product,
would the liability be eliminated and revenue recognised.146 For a discussion of the
IFRS 15 considerations for these types of arrangements, see 12.16 above.
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From the customer’s perspective, it would normally recognise a prepaid amount
representing the make-up product that it is entitled to receive in the future. However,
if the customer is entitled to more make-up product than it can sell, it may need to
recognise an impairment charge.
International GAAP® 2019: Generally Accepted Accounting Practice under International Financial Reporting Standards Page 668
