$m
ASSETS
Non-current assets
Intangible exploration and evaluation assets
10
1,933.4
2,025.8
Property, plant and equipment
11
5,254.7
5,362.9
Investments 12
1.0
1.0
Other non-current assets
13
789.8
175.7
Derivative financial instruments
20
0.8
15.8
Deferred tax assets
23
724.5
758.9
8,704.2
8,340.1
Extractive
industries
3229
GROUP CASH FLOW STATEMENT [extract]
YEAR ENDED 31 DECEMBER 2017
2017
2016
Notes
$m
$m
Cash flows from investing activities
Proceeds from disposals
9
8.0
62.8
Purchase of intangible exploration and evaluation assets
31
(189.7)
(275.2)
Purchase of property, plant and equipment
31
(117.8)
(756.0)
Interest received
3.1
1.2
Net cash used in investing activities
(296.4) (967.2)
ACCOUNTING POLICIES [extract]
YEAR ENDED 31 DECEMBER 2017
(k)
Exploration, evaluation and production assets
The Group adopts the successful efforts method of accounting for exploration and evaluation costs. Pre-licence costs
are expensed in the period in which they are incurred. All licence acquisition, exploration and evaluation costs and
directly attributable administration costs are initially capitalised in cost centres by well, field or exploration area, as appropriate. Interest payable is capitalised insofar as it relates to specific development activities.
These costs are then written off as exploration costs in the income statement unless commercial reserves have been
established or the determination process has not been completed and there are no indications of impairment.
All field development costs are capitalised as property, plant and equipment. Property, plant and equipment related to
production activities is amortised in accordance with the Group’s depletion and amortisation accounting policy.
Cash consideration received on farm-down of exploration and evaluation assets is credited against the carrying value
of the asset.
NOTES TO GROUP FINANCIAL STATEMENTS [extract]
YEAR ENDED 31 DECEMBER 2017
Note 10.
Intangible exploration and evaluation assets [extract]
2017
2016
Notes
$m
$m
At 1 January
2,025.8
3,400.0
Additions 1
319.0
291.4
Disposals
9
(40.0)
–
Amounts written-off
(143.4)
(723.0)
Write-off associated with Norway-contingent consideration provision
–
(36.5)
Transfer to property, plant, and equipment
11
(188.7)
–
Net transfer to assets held for sale
17
(43.4)
(912.3)
Currency translation adjustments
4.1
6.2
At 31 December
1,933.4
2,025.8
An entity should treat E&E assets as a separate class of assets and make the disclosures
required by IAS 16 and IAS 38 for tangible E&E assets and intangible E&E assets,
respectively. [IFRS 6.25, BC53].
3.6.1
Statement of cash flows
IAS 7 – Statement of Cash Flows – states that only expenditures that result in a
recognised asset in the statement of financial position are eligible for classification as
investing activities. [IAS 7.16]. The IASB specifically notes that ‘the exemption in IFRS 6
3230 Chapter 39
applies only to recognition and measurement of exploration and evaluation assets, not
to the classification of related expenditures in the statement of cash flows’. [IFRS 6.BC23B].
This means that an entity that expenses E&E expenditure will not be able to classify the
associated cash flows as arising from investing activities.
4 UNIT
OF
ACCOUNT
One of the key issues in the development of accounting standards and in the selection
of accounting policies by preparers, is deciding the level at which an entity should
separately account for assets, i.e. what is the ‘unit of account’? The definition of the
unit of account has significant accounting consequences, as can be seen in the
example below.
Example 39.2: Unit of account – dry well
An oil and gas company concludes, based on a number of exploration wells, that oil and gas reserves are
present. However, it needs to drill a number of delineation wells to determine the amount of reserves present
in the field. The first delineation well that is drilled is a dry hole, i.e. no reserves are found.
There are two ways of looking at the cost of drilling the dry hole:
• the dry hole provides important information about the extent of the oil and gas reserves present in the
oil field and should therefore be capitalised as part of the larger oil field; or
• the dry hole will not produce oil in the future and in the absence of future economic benefits the costs
should be expensed immediately.
This example suggests that assets or actions that have no value or meaning at one level
may actually be valuable and necessary at another level.
The unit of account plays a significant role in:
(1) recognition and derecognition of assets;
(2) determining the rate of depreciation or amortisation;
(3) deciding whether or not certain costs should be capitalised;
(4) undertaking impairment testing;
(5) determining the substance of transactions;
(6) application of the measurement model subsequent to recognition of the asset; and
(7) determining the level of detail of the disclosures required.
The decisions about the unit of account will consider, inter alia, cost/benefits and
materiality, whether the items are capable of being used separately, their useful
economic lives, whether the economic benefits that the entity will derive are separable
and the substance of the transaction. To some degree the choice of the unit of account
will depend on industry practice, as discussed below.
Extractive
industries
3231
In Example 39.2 above, an individual dry hole might not be considered a separate asset
because individual wells are typically not capable of being used separately, their
economic benefits are inseparable, the wells are similar in nature and the substance of
the matter can only be understood at the level of the project as a whole. However, in
concluding on whether to capitalise or expense the cost of the individual dry hole as set
out in Example 39.2 above, an entity will consider its specific accounting policy and its
definition of the unit of account. This is discussed further at 4.1 below.
4.1
Unit of account in the extractive industries
In the extractive industries the definition of the unit of account is particularly important
in deciding whether or not certain costs may be capitalised, determining the rate of
depreciation and in impairment testing. Historically entities in the extractive industries
have accounted for preproduction costs using methods such as:
• successful efforts method;
• full cost method; and
• area-of-interest method.
These are discussed further at 3.2.3 to 3.2.5 above. A key issue under each of these
methods is determining the appropriate unit of account, which is referred to in the
industry as the ‘cost centre’ or ‘pool’. In practice, entities would define their cost centres
along geographical, political or legal boundaries or align them to the operating units in
their organisation. The IASC’s Issues Paper listed the following, commonly used, cost
centres that have been used pre-IFRS:83
(a) the
world;
(b) each country or group of countries in which the entity operates;
(c) each contractual or legal mineral acquisition unit, such as a lease or production
sharing contract;
(d) each area of interest (geological feature, such as a mine or field, that lends itself to
a unified exploration and development effort);
(e) geological units other than areas of interest (such as a basin or a geologic province); or
(f) the entity’s organisational units.
IFRS does not provide industry specific guidance on determining appropriate units of
account for the extractive industries. Nevertheless, we believe that in determining the
unit of account an entity should take the legal rights (see (c) above) as its starting point
and apply the criteria discussed above to assess whether the unit of account should be
larger or smaller. The other cost centres listed above might result in a unit of account
that is unjustifiably large when viewed in the light of the factors influenced by the unit
of account as set out at 4 above.
3232 Chapter 39
The definition of ‘unit of account’ was considered in the Extractive Activities DP (see 1.3
above). While the DP would not need to be considered in the context of the IAS 8
hierarchy, it did draw attention to the fact that the selection of an appropriate unit of
account might need to take into account the stage of the underlying activities. In
particular, the DP proposed that ‘...the geographical boundary of the unit of account
would be defined initially on the basis of the exploration rights held. As exploration,
evaluation and development activities take place, the unit of account would contract
progressively until it becomes no greater than a single area, or group of contiguous areas,
for which the legal rights are held and which is managed separately and would be
expected to generate largely independent cash flows’. The DP’s view was that the
components approach in IAS 16 would apply to determine the items that should be
accounted for as a single asset. However, the DP suggested that an entity may decide to
account for its assets using a smaller unit of account.
The thinking underlying the above proposal in the DP would be relevant in the
following types of situations:
• Certain transactions in the extractive industries (e.g. carried interests
arrangements) result in the creation of new legal rights out of existing legal rights.
Whenever this is the case, an entity needs to assess whether such transactions give
rise to new units of account. If so, the accounting policies should be applied to
those new units of account rather than the previous unit/s of account.
• When an entity acquires a business that owns reserves and resources, it needs to
consider whether it should define the unit of account at the level of the licence or
separate ore zones or reservoirs within the licence.
Determining the unit of account is an area that requires a significant amount of
judgement, which may need to be disclosed under IAS 1 – Presentation of Financial
Statements – together with other judgements that management has made in the process
of applying the entity’s accounting policies and that have the most significant effect on
the amounts recognised in the financial statements. [IAS 1.122].
As the prevalence of unconventional oil and gas projects increases, the determination
of the unit of account is becoming an increasingly common topic. With unconventional
programs, the objectives of individual wells or drilling campaigns may differ to those for
a conventional drilling program. It may be that the drilling of each well provides
important information about the extent of the oil and gas reserves present in the oil and
gas field, but multiple wells need to be drilled before a decision can be made regarding
success. So unlike conventional oil and gas projects, concluding whether a well cost
should be capitalised may not be possible on an individual well basis immediately after
each well is drilled. In these circumstances, an entity may determine that the costs of an
individual well should be carried forward pending further analysis.
Extractive
industries
3233
5
LEGAL RIGHTS TO EXPLORE FOR, DEVELOP AND
PRODUCE MINERAL PROPERTIES
An entity can acquire legal rights to explore for, develop and produce wasting resources
on a mineral property by:84
(a) purchasing of minerals (i.e. outright ownership);
(b) obtaining a lease or concession (see 5.2 below);
(c) entering into a production-sharing contract or production-sharing agreement
(see 5.3 below);
(d) entering into a pure-service contract (see 5.4 below);
(e) entering into a service contract (also called a service agreement or risk service
contract) (see 5.5.1 below);
(f) entering into a joint operating agreement (see 5.6 below); and
(g) retaining an overriding royalty or other royalty interest subsequent to sale of an
interest (see 5.7 below).
Although many of these are more commonly encountered in the oil and gas sector, which
is reflected in many of the examples and illustrations below, they are not restricted to this
sector and mining companies can and do enter into similar arrangements.
The IASC Issues Paper noted that ‘in the mining sector, rights to explore for, develop, and
produce minerals are often acquired by purchase of either the mineral rights alone (which
does not include ownership of the land surface) or by purchase of both mineral rights and
surface rights. In other cases, they are acquired through a right to mine contract, which
grants the enterprise the rights to develop and mine the property and may call for a
payment at the time the contract becomes effective and subsequent periodic payments.
In the mining sector, rights to explore, develop, and produce minerals may also be
acquired by mineral leases from private owners or from the government’.85
In the oil and gas sector entities usually obtain the rights to explore for, develop, and
produce oil and gas through mineral leases, concession agreements, production-sharing
contracts, or service contracts.86 Arrangements similar to production sharing contracts
are also becoming more common in the mining sector. The type of legal arrangement
used depends to a large extent on the legal framework of the country and market
practice. The main features of each of these legal rights to access mineral reserves and
resources, except for the outright ownership of minerals, are discussed below.
The extract below from the financial statements of TOTAL illustrates the different types
of legal arrangements that an oil and gas company may enter into to secure access to
mineral reserves and resources.
3234 Chapter 39
Extract 39.7: TOTAL S.A. (2017)
2 BUSINESS OVERVIEW FOR FISCAL YEAR 2017 [extract]
2.1 Exploration & Production segment [extract]
2.1.6 Contractual framework of activities [extract]
Licenses, permits and contracts governing the Group entities’ ownership of oil and gas interests have terms that vary
from country to country and are generally granted by or entered into with a government entity or a state-owned
company and are sometimes entered into with private owners. These agreements usually take the form of concessions
or production sharing contracts.
In the framework of oil concession agreements, the oil company owns the assets and the facilities and is entitled to
the entire production. In exchange, the operating risks, costs and investments are the oil company’s responsibility and
it agrees to remit to the relevant host country, usually the owner of the subsoil resources, a production-based royalty,
income tax, and possibly other taxes that may apply under local tax legislation.
The production sharing contract (“PSC”) involves a more complex legal framework than the concession agreement:
it defines the terms and conditions of production sharing and sets the rules governing the cooperation between the
company or consortium in possession of the license and the host country, which is generally represented by a state-
owned company. The latter can thus be involved in operating decisions, cost accounting and production allocation.
The consortium agrees to undertake and finance all exploration, development and production activities at its own risk.
International GAAP® 2019: Generally Accepted Accounting Practice under International Financial Reporting Standards Page 639
