1.1.1 Definition of key terms

The most important terms and abbreviations used are defined in this chapter when discussed or in the glossary at 23 below. However, alternative or more detailed definitions of financial reporting terms, and of mining and oil and gas technical terms and abbreviations, can be found in the following publications:

• Issues Paper Extractive Industries, IASC, November 2000;
• Petroleum Resources Management System, Society of Petroleum Engineers, 2007;
• The Australasian Code for Reporting of Exploration Results, Mineral Resources and Ore Reserves (the JORC Code), Australasian Joint Ore Reserves Committee (the JORC Committee); and
• The former UK Oil Industry Accounting Committee Statement of Recommended Practice (OIAC SORP) (see 1.4 below).

1.3.1 Definitions of reserves and resources

The DP explored a number of alternatives for defining reserves and resources. The definition used is ‘reserves and resources are either the most significant assets or amongst the most significant assets for most entities engaged in extractive activities. Assessing the financial position and performance of an entity engaged in extractive activities in order to make economic decisions therefore requires an understanding of the entity's minerals or oil and gas reserves and resources, which are the source of future cash flows’.⁷

This chapter considers the definitions of reserves and resources that should be used in financial reporting. See 2 below for further discussion.

1.3.2 Asset recognition

The DP proposed that legal rights (i.e. exploration rights and extraction rights) should form the basis of a mineral asset or oil and gas asset. An asset should be recognised when the legal rights are acquired. Associated with these legal rights is information about the (possible) existence of minerals or oil and gas, the extent and characteristics of the deposit, and the economics of their extraction. The project team believed that rights and information associated with minerals or oil and gas properties satisfy the asset recognition criteria. While such information does not represent a separate asset, the project team proposed that information obtained from subsequent exploration and evaluation activities and development works would be treated as enhancements of the asset represented by the legal rights.

When considering the appropriate unit of account (see 4 below), 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 took place, the unit of account would contract progressively until it became no greater than a single area, or group of contiguous areas, for which the legal rights were held and which are managed separately and would be expected to generate largely independent cash flows.

1.3.3 Asset measurement

The DP considered both current value (e.g. fair value) and historical cost as potential measurement bases for minerals and oil and gas assets. Based on their findings, and taking the views of users and preparers into account, the project team concluded that minerals and oil and gas assets should be measured at historical cost and that detailed disclosures should be provided to enhance the relevance of the financial statements. The project team acknowledged that its choice of historical cost as the measurement basis was based to a large extent on doing the ‘least harm’.

In relation to impairment, it was considered that the IAS 36 impairment testing model was not feasible for exploration properties given the early stage of such properties. Therefore, the DP concluded that exploration properties should only be tested for impairment whenever, in management's judgement, there is evidence that suggests that there is a high likelihood that the carrying amount of an exploration asset will not be recovered in full. This would require management to apply a separate set of indicators to such properties in order to assess whether their continued recognition as assets would be justified. In addition, further disclosures would be required in respect of the impairment of exploration properties due to the fact that management may take different views on the exploration properties. These would include separate presentation of exploration properties, the factors that led to an impairment being recognised, and management's view as to why the remaining value of the asset or the other exploration assets is not impaired. This impairment assessment would need to be conducted separately for each exploration property.

1.3.4 Disclosure

The DP proposed extensive disclosures aimed at ensuring users of financial reports could evaluate:

• the value attributable to an entity's minerals or oil and gas assets;
• the contribution of those assets to current period financial performance; and
• the nature and extent of risks and uncertainties associated with those assets.

The DP proposed detailed disclosures about the quantities of reserves and resources, and production revenues and costs. If the assets are measured at historical cost then detailed information should be disclosed about their current value and how it was determined. If, instead, the assets are measured at fair value then detailed information should be disclosed about that fair value and how it was determined.

It is noted that a number of the proposed disclosures differ from US GAAP. These include disclosures of:

• key reserve estimate assumptions and sensitivity analysis (not required by US GAAP); and
• proved and probable reserves (US GAAP only requires proved reserves, with an option to disclose probable reserves).

1.3.5 Publish What You Pay proposals

A coalition of non-governmental organisations has promoted, and continues to promote, a campaign called Publish What You Pay (PWYP), proposing that entities undertaking extractive activities should be required to disclose, in their financial reports, the payments they make to each host government. Furthermore, PWYP recommended that its disclosure proposals should be incorporated into an eventual IFRS for extractive activities. Given this, a section in the DP was dedicated to the PWYP proposals. The DP acknowledged that the disclosure of payments made to governments provides information that would be of use to capital providers in making their investment and lending decisions, but noted that providing this information might be difficult and costly for some entities.

These proposals were partially in response to a perception that in certain countries some mining companies and oil and gas companies are not paying their ‘fair share’ in exchange for extracting scarce natural resources. In addition, there has been and continues to be increasing political pressure to expand the disclosure of payments to governments by entities within extractive industries as a means of reducing corruption by shining a light on these payments. As well as the proposals made in the DP, there are also increasing calls for transparency in the reporting of taxes and other payments to governments. This has led to a variety of transparency or publish what you pay types of initiatives being introduced in different jurisdictions around the world (e.g. US, Europe, UK, Canada, Australia, to name just a few), however these are outside the scope of IFRS and are governed by specific legislation.

1.3.6 Status of Extractive Activities project

After the 2011 Agenda Consultation, the Board adopted a more evidence-based approach to setting IFRS Standards, in that the Board would not start a standard-setting project before carrying out research to gather sufficient evidence that an accounting problem exists, that the problem is sufficiently important that standard-setting is required and that a feasible solution can be found.

Before the IASB's 2015 agenda consultation process, the IASB's research programme included a project on intangible assets, research and development and extractive activities. It was acknowledged that extractive activities are important globally and are particularly significant in some jurisdictions. IFRS 6 was originally intended to be a temporary Standard and provides a number of exemptions from other IFRS Standards that would otherwise apply. It was noted that a permanent solution would be required for reporting these activities.

After considering the feedback from the 2015 agenda consultation process, the Board created a pipeline of future research projects which included Extractive Activities. With respect to the latter, the IASB decided to narrow the scope to remove any reference to intangibles and research and development. The reason for this was primarily based on the amount of resources a combined project would require and a view that the Board could work more effectively and more efficiently on extractive activities if it did not try to address intangible assets and research and development at the same time.

The Board decided in February 2018 to start work on Extractive Activities by asking those national standard-setters whose staff contributed to the 2010 Discussion Paper Extractive Activities to make the Board aware of any developments since then.

At the March 2019 IASB meeting, the Board discussed feedback from National Standard-setters on changes in the extractives industry since the publication of the 2010 Extractive Activities Discussion Paper. The Board was not asked to make any decisions.

Overall, most National Standard-setters consulted identified that:

1. the markets for minerals and oil and gas have become more volatile than they were in 2010;
2. the risk profile of entities operating in the extractives industry has changed;
3. entities operating in the extractives industry are engaging in new and more complex transactions whereby the current accounting requirements may not be clear;
4. increasingly, entities operating in the extractives industry are engaging in unconventional extractives activities;
5. the reporting of other information, such as payments to governments and sustainability reporting, is being mandated at a jurisdictional level; and
6. there have been minor amendments to the relevant reserves and resource definitions within each jurisdiction.

Overall, the staff believe that the Discussion Paper and the feedback received on the Discussion Paper remain a valid starting point for the Board as it starts its new research project on Extractive Activities. However, the changes highlighted by the National Standard-setters summarised in this paper, in combination with the Discussion Paper, should also be considered by the Board.

Based on the analysis, staff propose further research into the effects of the following topics on the Discussion Paper and project proposals:

1. 2018 Conceptual Framework for Financial Reporting;
2. new standards and amendments, including other Board publications;
3. changes to reserves and resources classifications and definitions; and
4. changes to transparency and sustainability reporting, for example, payments to governments.

Staff analysis on each topic will be brought back at a future meeting to help the Board determine the scope of the Extractive Activities project.

Given this, it is unlikely that there will be any significant developments on this project in the near term.

1.6.1 Phases in upstream activities

Although there is not a universally accepted classification of upstream activities in the extractive industries, the IASC Issues Paper identified the following eight phases which other authors also commonly identify:¹⁰

1. Prospecting – Prospecting involves activities undertaken to search for an area of interest, a geologic anomaly or structure that may warrant detailed exploration.¹¹ Prospecting is undertaken typically before mineral rights in the area have been acquired, and if the prospecting results are negative the area of prospecting generally will be abandoned and no mineral rights acquired.¹² However, sometimes it will be necessary to acquire a prospecting permit as the prospecting activities require access to the land to carry out geological and geophysical tests.¹³
2. Acquisition of mineral rights – The acquisition phase involves the activities related to obtaining legal rights to explore for, develop, and/or produce wasting resources on a mineral property.¹⁴ Legal rights may be acquired in a number of ways as discussed at 5 below.
3. Exploration – Exploration is the detailed examination of a geographical area of interest that has shown sufficient mineral-producing potential to merit further exploration, often using techniques that are similar to those used in the prospecting phase.¹⁵ In the mining sector, exploration usually involves taking cores for analysis, sinking exploratory shafts, geological mapping, geochemical analysis, cutting drifts and crosscuts, opening shallow pits, and removing overburden in some areas.¹⁶ In the oil and gas sector, exploration involves techniques such as shooting seismic, core drilling, and ultimately the drilling of an exploratory well to determine whether oil and gas reserves do exist.¹⁷
4. Appraisal or evaluation – This involves determining the technical feasibility and commercial viability of mineral deposits that have been found through exploration.¹⁸ This phase typically includes:¹⁹
   1. detailed engineering studies and drilling of additional wells by oil and gas companies to determine how the reservoir can best be developed to obtain maximum recovery;
   2. determination by mining companies of the volume and grade of deposits through drilling of core samples, trenching, and sampling activities in an area known to contain mineral resources;
   3. examination and testing by mining companies of extraction methods and metallurgical or treatment processes;
   4. surveying transportation and infrastructure requirements;
   5. conducting market and finance studies; and
   6. making detailed economic evaluations to determine whether development of the reserves is commercially justified.
5. Development – Development is the establishment of access to the mineral reserve and other preparations for commercial production. In the mining sector, development includes sinking shafts and underground drifts, making permanent excavations, developing passageways and rooms or galleries, building roads and tunnels, and advance removal of overburden and waste rock.²⁰ In the oil and gas sector the development phase involves gaining access to, and preparing, well locations for drilling, constructing platforms or preparing drill sites, drilling wells, and installing equipment and facilities.²¹
6. Construction – Construction involves installing facilities, such as buildings, machinery and equipment to extract, treat, and transport minerals.²²
7. Production – The production phase involves the extraction of the natural resources from the earth and the related processes necessary to make the produced resource marketable or transportable.²³
8. Closure and decommissioning – Closure means ceasing production, removing equipment and facilities, restoring the production site to appropriate conditions after operations have ceased and abandoning the site.²⁴

The above phases are not necessarily discrete sequential steps. Instead, the phases often overlap or take place simultaneously. Nevertheless, they provide a useful framework for developing accounting policies in the extractive industries. Accounting for expenditures depends very much on the phase during which they are incurred; for example, as discussed further below, costs incurred in the prospecting phase cannot be recognised as assets, whereas most costs incurred in the construction phase should be capitalised.

2.2.1 Basic principles and definitions

The following graphically presents the SPE-PRMS resources classification system:³⁰

The horizontal axis reflects the range of uncertainty of estimated quantities potentially recoverable from an accumulation by a project, while the vertical axis represents the chance of commerciality, which is the chance that a project will be committed for development and reach commercial producing status.³¹

The SPE-PRMS defines proved, probable and possible reserves as follows:

• ‘Reserves are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. Reserves must further satisfy four criteria: discovered, recoverable, commercial, and remaining (as of the evaluation's effective date) based on the development project(s) applied. Reserves are further categorized in accordance with the range of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by development and production status.’³²
• ‘Proved Reserves are those quantities of petroleum, that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable from known reservoirs and under defined technical and commercial conditions. If deterministic methods are used, the term “reasonable certainty” is intended to express a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate.’³³
• ‘Probable Reserves are those additional Reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than Proved Reserves but more certain to be recovered than Possible Reserves. It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated Proved plus Probable Reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the 2P estimate.’³⁴
• ‘Possible Reserves are those additional reserves which analysis of geoscience and engineering data suggest are less likely to be recoverable than Probable Reserves. The total quantities ultimately recovered from the project have a low probability to exceed the sum of Proved plus Probable plus Possible (3P) Reserves, which is equivalent to the high estimate scenario. When probabilistic methods are used, there should be at least a 10% probability that the actual quantities recovered will equal or exceed the 3P estimate.’³⁵

The SPE‑PRMS distinguishes between Contingent and Prospective Resources:

• The term Resources as used herein is intended to encompass all quantities of petroleum naturally occurring on or within the Earth's crust, both discovered and undiscovered (whether recoverable or unrecoverable), plus those quantities already produced. Further, it includes all types of petroleum whether currently considered ‘conventional’ or ‘unconventional’ resources.³⁶
• ‘Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations, by the application of development project(s) not currently deemed to be commercial owing to one or more contingencies. Contingent Resources have an associated chance of development. Contingent Resources may include, for example, projects for which there are currently no viable markets, or where commercial recovery is dependent on technology under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality. Contingent Resources are further categorized in accordance with the range of uncertainty associated with the estimates and may be sub-classified based on project maturity and/or economic status.’³⁷
• ‘Prospective Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective Resources have both an associated chance of geologic discovery and a chance of development. Prospective Resources are further categorized in accordance with the range of uncertainty associated with recoverable estimates, assuming discovery and development, and may be sub-classified based on project maturity.’³⁸

Total petroleum initially-in-place (PIIP) is all quantities of petroleum that are estimated to exist in naturally occurring accumulations, discovered and undiscovered, before production. Discovered PIIP is the quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations before production.³⁹ Undiscovered PIIP is that quantity of petroleum estimated, as of a given date, to be contained within accumulations yet to be discovered.⁴⁰

Production is the cumulative quantities of petroleum that has been recovered at a given date.⁴¹ Unrecoverable Resources are that portion of Discovered or Undiscovered PIIP evaluated, as of a given date, to be unrecoverable by the currently defined project(s). A portion of these quantities may become recoverable in the future as commercial circumstances change, technology is developed, or additional data are acquired. The remaining portion may never be recovered because of physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks.⁴²

2.2.2 Classification and categorisation guidelines

The SPE‑PRMS provides guidance on classifying resources depending on the relative maturity of the development projects being applied to yield the recoverable quantity estimates.⁴³

As Figure 43.2,⁴⁴ above illustrates, development projects and associated recoverable quantities may be sub-classified according to project maturity levels and the associated actions (i.e. business decisions) required to move a project forward to commercial production.⁴⁵

The SPE‑PRMS also provides guidance on categorising resources, depending on the associated degrees of uncertainty, into the following cumulative categories:⁴⁶

• proved, probable and possible (1P, 2P and 3P) for reserves;
• low, best and high (1C, 2C and 3C) for contingent resources; and
• low estimate, best estimate and high estimate for prospective resources.

Additionally, guidance is provided on categorisation of reserves and resources related to incremental projects, such as workovers, infill drilling and improved recovery.⁴⁷

To promote consistency in project evaluations and reporting, the SPE‑PRMS provides guidelines on the economic assumptions that are to be used, measurement of production, and resources entitlement and recognition,⁴⁸ and also provides guidance on the analytical procedures, and on the deterministic and probabilistic methods to be used.

2.3.1 CRIRSCO International Reporting Template (November 2013)

Set out below are the main requirements of the CRIRSCO International Reporting Template (CRIRSCO Template) to the extent that they are relevant to financial reporting by mining companies.

2.3.1.B Reporting terminology

The general relationship between Exploration Results, Mineral Resources and Mineral Reserves can be summarised in the following diagram:⁵⁷

The terms in the above diagram are defined as follows:

Exploration Results include data and information generated by mineral exploration programmes that might be of use to investors but which do not form part of a declaration of Mineral Resources or Mineral Reserves.⁵⁸ The CRIRSCO Template specifically requires that any information relating to Exploration Results be expressed in such a way that it does not unreasonably imply that potentially economic mineralisation has been discovered.⁵⁹

A Mineral Resource is a concentration or occurrence of solid material of economic interest in or on the Earth's crust in such form, grade, quality and quantity that there are reasonable prospects for eventual economic extraction. The location, quantity, grade, continuity and other geological characteristics of a Mineral Resource are known, estimated or interpreted from specific geological evidence and knowledge, including sampling. Mineral Resources are sub-divided, in order of increasing geological confidence, into Inferred, Indicated and Measured categories:⁶⁰

• ‘An Inferred Mineral Resource is that part of a Mineral Resource for which quantity and grade or quality are estimated on the basis of limited geological evidence and sampling. Geological evidence is sufficient to imply but not verify geological and grade or quality continuity. An Inferred Resource has a lower level of confidence than that applying to an Indicated Mineral Resource and must not be converted to a Mineral Reserve. It is reasonably expected that the majority of Inferred Mineral Resources could be upgraded to Indicated Mineral Resources with continued exploration.’⁶¹
• ‘An Indicated Mineral Resource is that part of a Mineral Resource for which quantity, grade or quality, densities, shape and physical characteristics are estimated with sufficient confidence to allow the application of Modifying Factors in sufficient detail to support mine planning and evaluation of the economic viability of the deposit. Geological evidence is derived from adequately detailed and reliable exploration, sampling and testing and is sufficient to assume geological and grade or quality continuity between points of observation. An Indicated Mineral Resource has a lower level of confidence than that applying to a Measured Mineral Resource and may only be converted to a Probable Mineral Reserve.’⁶²
• ‘A Measured Mineral Resource is that part of a Mineral Resource for which quantity, grade or quality, densities, shape and physical characteristics are estimated with confidence to allow the application of Modifying Factors to support detailed mine planning and final evaluation of the economic viability of the deposit. Geological evidence is derived from detailed and reliable exploration, sampling and testing and is sufficient to confirm geological and grade or quality continuity between points of observation. A Measured Mineral Resource has a higher level of confidence than that applying to either an Indicated Mineral Resource or an Inferred Mineral Resource. It may be converted to a Proved Mineral Reserve or to a Probable Mineral Reserve.’⁶³
• ‘Modifying factors are considerations used to convert Mineral Resources to Mineral Reserves. These include, but are not restricted to, mining, processing, metallurgical, infrastructure, economic, marketing, legal, environmental, social and governmental factors.’⁶⁴
• ‘A Mineral Reserve is the economically mineable part of a Measured and/or Indicated Mineral Resource. It includes diluting materials and allowances for losses, which may occur when the material is mined or extracted and is defined by studies at Pre-Feasibility or Feasibility level as appropriate that include application of Modifying Factors. Such studies demonstrate that, at the time of reporting, extraction could reasonably be justified.’⁶⁵
• ‘A Probable Mineral Reserve is the economically mineable part of an Indicated, and in some circumstances, a Measured Mineral Resource. The confidence in the Modifying Factors applying to a Probable Mineral Reserve is lower than that applying to a Proved Mineral Reserve. A Probable Mineral Reserve has a lower level of confidence than a Proved Mineral Reserve but is of sufficient quality to serve as the basis for a decision on the development of the deposit.’⁶⁶
• ‘A Proved Mineral Reserve is the economically mineable part of a Measured Mineral Resource. A Proved Mineral Reserve implies a high degree of confidence in the Modifying Factors. A Proved Mineral Reserve represents the highest confidence category of reserve estimate.’⁶⁷

The CRIRSCO Template contains more detailed guidance on how a competent person should decide on mineral resource and mineral reserve classification and contains a checklist and guideline for the preparation of public reports.

2.4.1 Oil and gas sector

Many oil and gas companies are required to disclose information about reserve quantities in accordance with the rules and requirements of the stock exchange on which they are listed. However, those oil and gas companies that are not subject to the specific disclosure requirements of a stock exchange or other local regulator should consider the need to disclose reserves and resources information to provide users with the information they need to understand the entity's financial position and performance.

Companies may continue to consider disclosing the information previously required under the former OIAC SORP or the US ASC 932‑235‑50 – Disclosure of Standardised Measure of Oil and Gas (US ASC 932‑235‑50) or could look to the example disclosures contained in the 2010 DP at 1.3.4 above.

2.4.2 Mining sector

Many mining companies are required to disclose information about reserve quantities in accordance with the rules and requirements of the stock exchange on which they are listed. However, those mining companies that are not subject to the specific disclosure requirements of a stock exchange or other local regulator may wish to consider disclosing the information required under SEC Industry Guide 7.

Mining companies that are subject to the SEC rules and regulations need to understand not only the content of Industry Guide 7, but also the current interpretation of this content by the SEC's staff. While many of the definitions may seem familiar, the SEC staff's interpretations may differ considerably from those of regulators in other countries.⁶⁹ Refer to SEC Industry Guide 7 sections I-III for details.

2.4.3 Disclosure of the value of reserves

As part of its work on the Extractive Activities DP (see 1.3.4 above) the IASB staff considered whether a disclosure-focused approach might be appropriate in an extractive industries financial reporting standard. It is in this context that the DP noted that, given the near unanimity of the feedback from users on the lack of relevance of either historical cost or current value accounting for reserves and resources, a disclosure-focused approach needed to be considered as one alternative in the discussion paper.⁷⁰

One of the key issues to consider before developing a disclosure-focused approach is whether or not disclosure of the value of mineral reserves should be a requirement. A secondary issue is whether the mineral reserves should be disclosed at their fair value or at a standardised measure of value, similar to the requirement under ASC 932‑235‑50 which is based on discounted net cash flows.

This disclosure requirement is not uncontroversial, as the ‘standardized measure of oil and gas’ (often abbreviated to SMOG) does not represent the market value of an entity's proved reserves. However, the standardised measure of the value of oil and gas reserves greatly reduces the impact of management's opinion about future development on the value calculated, e.g. the method prescribes the discount rate and commodity price to be used. While this may not take into account relevant insights that management may have, the advantage is that comparability of the disclosures between entities is increased. As illustrated in Extract 43.1, some companies caution against over-reliance on these disclosures.

It is clear that reaching agreement as to what constitutes useful and relevant disclosures about the value of mineral reserves is not straightforward and will be controversial. Still, in September 2008, the Board indicated support for the Extractive Activities DP to propose the disclosure of ‘a current value measurement, such as a standardised measure of discounted cash flows, and the key assumptions necessary for a user to make use of that measurement’. This would not be disclosed if the minerals or oil and gas assets are measured on the balance sheet at fair value or some other current value measurement. In that case, an entity would provide disclosures similar to those required in the US (by ASC 820‑10‑50‑1, 2, 3 – Fair Value Measurements and Disclosures).⁷¹ Accordingly, the DP concluded that:

• if the assets are measured at historical cost then detailed information should be disclosed about their current value (either fair value or standardised measure) and how it was determined; or
• if, instead, the assets are measured at fair value then detailed information should be disclosed about that fair value and how it was determined.

3.1.1 Scope exclusions in other standards relating to the extractive industries

In the Basis for Conclusions on IFRS 6 the IASB confirmed that ‘even though no IFRS has addressed extractive activities directly, all IFRSs (including International Accounting Standards and Interpretations) are applicable to entities engaged in the exploration for and evaluation of mineral resources that make an unreserved statement of compliance with IFRSs in accordance with IAS 1’. [IFRS 6.BC6]. However, certain aspects of activities that occur in the extractive industries that fall outside the scope of IFRS 6 are excluded from the scope of other standards.

Various standards exclude ‘minerals’ from their scope, but the exact wording of the scope exclusions differs from standard to standard. Therefore, it would be incorrect to conclude that the same aspects of the extractive industries’ activities are excluded from the scope of these standards:

• IAS 2 – does not apply to the measurement of minerals and mineral products, ‘to the extent that they are measured at net realisable value in accordance with well-established practices in those industries’. [IAS 2.3(a), 4]. The practice of measuring minerals and mineral products inventories at net realisable value is, in reality, relatively rare in many areas of the extractive industries.
• IAS 16 – does not apply to ‘mineral rights and mineral reserves such as oil, natural gas and similar non-regenerative resources’. [IAS 16.3(d)]. In addition, the standard does not apply to ‘the recognition and measurement of exploration and evaluation assets’. [IAS 16.3(c)]. Equipment used in extracting reserves is within the scope of IAS 16.
• IFRS 16 – does not apply to ‘leases to explore for or use minerals, oil, natural gas and similar non-regenerative resources’. [IFRS 16.3(a)]. However, leases including leases of right-of-use assets in a sublease of assets used for exploration or evaluation activities are in the scope of IFRS 16.
• IAS 38 – does not apply to ‘expenditure on the exploration for, or development and extraction of, minerals, oil, natural gas and similar non-regenerative resources’ or to the recognition and measurement of E&E assets. [IAS 38.2(c)-(d)].
• IAS 40 – does not apply to ‘mineral rights and mineral reserves such as oil, natural gas and similar non-regenerative resources’. [IAS 40.4(b)].

3.2.1 Developing an accounting policy under IFRS 6

When developing its accounting policy for E&E expenditures, IFRS 6 requires an entity recognising E&E assets to apply paragraph 10 of IAS 8. [IFRS 6.6, BC19]. Hence management should use its judgement in developing and applying an accounting policy that results in information that is relevant and reliable. [IAS 8.10]. However, IFRS 6 does provide an exemption from paragraphs 11 and 12 of IAS 8, [IFRS 6.7, BC17], which ‘specify sources of authoritative requirements and guidance that management is required to consider in developing an accounting policy for an item if no IFRS applies specifically to that item’ (the so-called ‘GAAP hierarchy’, see Chapter 3 at 4.3). In developing such a policy, IFRS 6 imposes a number of significant constraints on an entity's choice of accounting policy because:

• an entity needs to specify which expenditures are recognised as E&E assets and apply that accounting policy consistently (see 3.3.1 below); [IFRS 6.9]
• expenditures related to the development of mineral resources should not be recognised as E&E assets (see 3.3.1 below); [IFRS 6.10] and
• the requirement to apply IAS 16, IAS 38 and IAS 36 after the E&E phase affects the choice of accounting policies during the E&E phase. In January 2006 the IFRIC clarified that ‘it was clear that the scope of IFRS 6 consistently limited the relief from the hierarchy to policies applied to E&E activities and that there was no basis for interpreting IFRS 6 as granting any additional relief in areas outside its scope’.⁷² For example, an entity may be able to apply the full cost method of accounting (see 3.2.4 below) during the E&E phase, but it will not be able to apply that policy after the E&E phase.

The IASB believed that waiving these requirements in IFRS 6 would ‘detract from the relevance and reliability of an entity's financial statements to an unacceptable degree’. [IFRS 6.BC23].

3.2.2 Options for an exploration and evaluation policy

Entities active in the extractive industries have followed, and continue to follow, a large variety of accounting practices for E&E expenditure, which range ‘from deferring on the balance sheet nearly all exploration and evaluation expenditure to recognising all such expenditure in profit or loss as incurred’. [IFRS 6.BC17]. As mentioned earlier, IFRS 6 provides an exemption from paragraphs 11 and 12 of IAS 8. The inference from this is that the standard ‘grandfathers’ all existing practices by not requiring these to have any authoritative basis. The Basis for Conclusions states that ‘the Board decided that an entity could continue to follow the accounting policies that it was using when it first applied the IFRS's requirements, provided they satisfy the requirements of paragraph 10 of IAS 8 … with some exceptions …’. [IFRS 6.BC22]. These exceptions in IFRS 6, described above, have a rather more profound impact than may be obvious at first sight and, in fact, instead of allowing previous national GAAP accounting policies, IFRS 6 effectively prohibits many of them.

There are several methods adopted by oil and gas companies (and modified by some mining companies) to account for E&E costs. These include successful efforts, full cost and area of interest accounting. These methods have evolved through the use of previous GAAPs and industry practice. While these terms and methods (or similar methods) are commonly used in the sector, none of these is specifically referred to in IFRS.

We explore below each of these methods and consider to what extent they are compliant with the requirements of IFRS.

3.2.3 Successful efforts method

The successful efforts methods that have been developed by different accounting standard-setters are generally based on the successful efforts concept as set out in US GAAP, under which generally only those costs that lead directly to the discovery, acquisition, or development of specific, discrete mineral resources and reserves are capitalised and become part of the capitalised costs of the cost centre. Costs that when incurred fail to meet this criterion are generally charged to expense in the period they are incurred. Some interpretations of the successful efforts concept allow entities to capitalise the cost of unsuccessful development wells.⁷³

Under the successful efforts method an entity will generally consider each individual mineral lease, concession, or production sharing contract as a cost centre.

When an entity applies the successful efforts method under IFRS, it will need to account for prospecting costs incurred before the E&E phase under IAS 16 or IAS 38. As economic benefits are highly uncertain at this stage of a project, prospecting costs will typically be expensed as incurred. Costs incurred to acquire undeveloped mineral rights, however, should be capitalised under IFRS if an entity expects an inflow of future economic benefits.

To the extent that costs are incurred within the E&E phase of a project, IFRS 6 does not prescribe any recognition and measurement rules. Therefore, it would be acceptable for such costs to be recorded as assets and written off when it is determined that the costs will not lead to economic benefits or to be expensed as incurred if the outcome is uncertain. Deferred costs of an undeveloped mineral right may be depreciated over some determinable period, subject to an impairment test each period with the amount of impairment charged to expense, or an entity may choose to carry forward the deferred costs of the undeveloped mineral right until the entity determines whether the property contains mineral reserves.⁷⁴ However, E&E assets should no longer be classified as such when the technical feasibility and commercial viability of extracting mineral resources are demonstrable. [IFRS 6.17]. At that time the asset should be tested for impairment under IAS 36, reclassified in the statement of financial position and accounted for under IAS 16 or IAS 38. If it is determined that no commercial reserves are present, then the costs capitalised should be expensed. Costs incurred after the E&E phase should be accounted for in accordance with the applicable IFRSs (i.e. IAS 16 and IAS 38).

It is worth noting that with the emergence of unconventional resource E&E projects, such as shale, coal seam and tight oil or gas, the potential timeframe to determine the technical feasibility and commercial viability of a resource can be considerably longer than that of a conventional resource. This is primarily due to the scale of work required to determine the technical feasibility and commercial viability of these more complex and/or less accessible resources in a higher cost environment. Such feasibility determinations may include the drilling and analysing of a significant number of wells over an extended period of time. As such, the overall success of a drilling campaign targeting unconventional resources may not be determined until completion of the campaign – as opposed to the more common well by well basis that is often the case for conventional projects.

Therefore, the costs incurred on unconventional projects over an extended E&E campaign, may be carried forward under existing policies adopted, including capitalisation under a successful efforts policy that permits such treatment, until such time as the broader resource body is deemed to be either successful or unsuccessful.

The essence of most successful efforts approaches is that costs are capitalised pending evaluation, and this would be acceptable under IFRS.

The following extract from the financial statements of Premier Oil illustrates a typical successful efforts method accounting policy applied under IFRS.

3.2.4 Full cost method

The full cost method under most national GAAPs required all costs incurred in prospecting, acquiring mineral interests, exploration, appraisal, development, and construction to be accumulated in large cost centres, e.g. individual countries, groups of countries, or the entire world.⁷⁵ However, although an entity is permitted by IFRS 6 to develop an accounting policy without reference to other IFRSs or to the hierarchy, as described at 3.2.1 above, IFRS 6 cannot be extrapolated or applied by analogy to permit application of the full cost method outside the E&E phase. This was confirmed by the Interpretations Committee in January 2006.⁷⁶

There are several other areas in which application of the full cost method under IFRS is restricted because:

• IFRS 6 requires E&E assets to be classified as tangible or intangible assets according to the nature of the assets. [IFRS 6.15]. In other words, even when an entity accounts for E&E costs in relatively large pools, it will still need to distinguish between tangible and intangible assets.
• While the full cost method under most national GAAPs requires the application of some form of ‘ceiling test’, IFRS 6 requires – when impairment indicators are present – an impairment test to be performed in accordance with IAS 36 (although in accordance with IFRS 6, E&E assets can be allocated to CGUs or groups of CGUs (which may include producing CGUs), provided certain criteria are met – see 3.5.2 below for further information).
• Once the technical feasibility and commercial viability of extracting mineral resources are demonstrable, IFRS 6 requires that E&E assets shall no longer be classified as such and need to be tested for impairment under IAS 36 and reclassified in the statement of financial position and accounted for under IAS 16 or IAS 38. [IFRS 6.17]. This means that it is not possible to account for successful and unsuccessful projects within one cost centre or pool.

For these reasons it is not possible to apply the full cost method of accounting under IFRS without making very significant modifications in the application of the method. An entity might want to use the full cost method as its starting point in developing its accounting policy for E&E assets under IFRS. However, it will rarely be appropriate to describe the resulting accounting policy as a ‘full cost method’ because key elements of the full cost method are not permitted under IFRS.

In July 2009, the IASB published an amendment to IFRS 1 – Additional Exemptions for First-time Adopters (Amendments to IFRS 1), which introduced a first-time adoption exemption for first-time adopters that accounted under their previous GAAP for ‘exploration and development costs for oil and gas properties in the development or production phases … in cost centres that include all properties in a large geographical area’ (i.e. the full cost method).⁷⁷ Under the exemption, a first-time adopter may elect to measure oil and gas assets at the date of transition to IFRSs on a deemed cost basis (see Chapter 5 at 5.5.3), but does not permit continued application of the previous GAAP accounting policy.

3.2.5 Area-of-interest method

The area-of-interest method is an accounting concept by which ‘costs incurred for individual geological or geographical areas that have characteristics conducive to containing a mineral reserve are deferred as assets pending determination of whether commercial reserves are found. If the area of interest is found to contain commercial reserves, the accumulated costs are capitalised. If the area is found to contain no commercial reserves, the accumulated costs are charged to expense’.⁷⁸

Some consider the area-of-interest method to be a version of the successful efforts method that uses an area-of-interest, rather than an individual licence, as its unit of account. Others believe that the area-of-interest method is more akin to the full cost method applied on an area-of-interest basis.⁷⁹ ‘Under the area-of-interest concept, all costs identified with an area of interest would be deferred and capitalised if commercial reserves are later determined to exist in the area. However, costs incurred up to the point that an area of interest is identified (prospecting costs) are often charged to expense by those who consider that they are applying the area-of-interest concept. Costs of individual unsuccessful activities incurred on a specific area of interest, such as drilling an exploratory well that finds no reserves, are accumulated as part of the total cost of the area of interest.’⁸⁰

While IFRS 6 will often not permit all aspects of an area-of-interest method defined by a national GAAP, an entity that uses relatively small areas of interest may be able to implement the method in a meaningful way under IFRS. The area-of-interest method is more common in the mining sector than in the oil and gas sector. Still, there are some entities that apply the method to oil and gas activities.

3.2.6 Changes in accounting policies

The standard permits a change in an entity's accounting policies for E&E expenditures only if ‘the change makes the financial statements more relevant to the economic decision-making needs of users and no less reliable, or more reliable and no less relevant to those needs’. [IFRS 6.13, BC49]. In making such a change, an entity should judge the relevance and reliability using the criteria in IAS 8. The entity should justify the change by demonstrating that the change ‘brings its financial statements closer to meeting the criteria in IAS 8, but the change need not achieve full compliance with those criteria’. [IFRS 6.14].

3.3.1 Types of expenditure in the exploration and evaluation phase

The standard requires an entity to determine an accounting policy specifying which expenditures are recognised as E&E assets and apply the policy consistently. Such an accounting policy should take into account the degree to which the expenditure can be associated with finding specific mineral resources. Types of expenditure include:

1. acquisition of rights to explore;
2. topographical, geological, geochemical and geophysical studies;
3. exploratory drilling;
4. trenching;
5. sampling; and
6. activities in relation to evaluating the technical feasibility and commercial viability of extracting a mineral resource. [IFRS 6.9].

This list is not intended to be exhaustive.

In permitting geological and geophysical costs (G&G costs) to be included in the initial measurement of E&E assets, IFRS differs from US GAAP – ASC 932 – Extractive Activities – Oil and Gas, which does not permit capitalisation of G&G costs,⁸¹ and may differ from the requirements under other national standards.

IFRS 6 allows an accounting policy choice as to how to treat expenditures on administration and other general overhead costs; however, the chosen policy should be consistent with one of the treatments available under other IFRSs, i.e. expense or capitalise. [IFRS 6.BC28]. This is because there are inconsistencies between IAS 16 (which does not allow such costs to be capitalised), IAS 2 (which requires capitalisation of production overheads but not general administration) and IAS 38 (which only allows capitalisation if directly attributable to bringing the asset into use, otherwise capitalisation is prohibited).

Expenditures related to the development of mineral resources should not be recognised as E&E assets. Instead, the IASB's Conceptual Framework and IAS 38 should be applied in developing guidance on accounting for such assets. [IFRS 6.10]. IFRS does not define ‘development of mineral resources’, but notes that ‘development of a mineral resource once the technical feasibility and commercial viability of extracting the mineral resource had been determined was an example of the development phase of an internal project’. [IFRS 6.BC27]. While this is not a full definition, in practice this means that until a feasibility study is complete and a development is approved, accumulated costs are considered E&E assets and are accounted for under IFRS 6. The timing of transferring expenditure from the exploration phase to the development phase is discussed in further detail at 3.4.1 below.

The standard specifically requires the application of IAS 37 – Provisions, Contingent Liabilities and Contingent Assets – to any obligations for removal and restoration that are incurred during a particular period as a consequence of having undertaken the exploration for and evaluation of mineral resources. [IFRS 6.11]. Although IFRS 6 did not make a corresponding amendment to the scope of IFRIC 1 – Changes in Existing Decommissioning, Restoration and Similar Liabilities – which applies to such liabilities when they are recognised in property, plant and equipment under IAS 16, we believe that the interpretation should also be applied in relation to E&E assets. However, if the E&E costs were originally expensed, then the future costs of any related removal and restoration obligations should also be expensed.

The extract below from Glencore illustrates a typical accounting policy for E&E assets for a mining company.

The extract below from BP illustrates an accounting policy for E&E assets for an oil and gas company.

3.3.2 Capitalisation of borrowing costs in the exploration and evaluation phase

IAS 23 – Borrowing Costs – requires capitalisation of borrowing costs that are directly attributable to the acquisition, construction or production of a ‘qualifying asset’ as part of the cost of that asset. [IAS 23.8]. An E&E asset will generally meet the definition of a qualifying asset as it ‘necessarily takes a substantial period of time to get ready for its intended use or sale’. [IAS 23.5]. However, IAS 23 requires capitalisation of borrowing costs only when it is probable that they will result in future economic benefits to the entity and the costs can be measured reliably. [IAS 23.9]. Unlike IAS 23, IFRS 6 permits capitalisation of E&E assets even when it is not probable that they will result in future economic benefits. Unless an entity's E&E project has resulted in the classification of mineral resources as proven or probable, it is unlikely that future economic benefits from that project can be considered probable. In these circumstances, it is consistent with the requirements of IFRS 6 and IAS 23 to capitalise an E&E asset but not capitalise borrowing costs in respect of it.

3.4.1 Reclassification of E&E assets

E&E assets should no longer be classified as such when ‘technical feasibility and commercial viability of extracting a mineral resource are demonstrable’.

Determining when technical feasibility and commercial viability have been demonstrated may involve significant judgement, particularly in relation to complex assets or projects where feasibility assessment may be ongoing over an extended period of time: for example Liquefied Natural Gas (LNG) projects, unconventional assets, large scale, technically challenging projects, or where significant upfront investment in long lead items is required.

A final investment decision being approved is often a common signal that technical feasibility and commercial viability have been determined. However, absent this, other factors may also need to be considered, such as the booking of significant quantities of commercial reserves, approval of budgeted expenditure to commence commercial development activities or the actual commencement of expenditure on development activities. It should be noted that both technical feasibility and commercial viability must be demonstrated before an asset can be transferred out of E&E. Activities that occur prior to this point which are aimed at assessing the viability of a resource, may still be regarded as E&E in nature and must be accounted for accordingly.

Before reclassification, E&E assets should be assessed for impairment individually or as part of a cash-generating unit and any impairment loss should be recognised. [IFRS 6.17].

3.5.1 Impairment testing ‘triggers’

E&E assets should be assessed for impairment when facts and circumstances suggest that the carrying amount of an E&E asset may exceed its recoverable amount. [IFRS 6.18]. Under IFRS 6 one or more of the following facts and circumstances could indicate that an impairment test is required. The list is not intended to be exhaustive:

1. the period for which the entity has the right to explore in the specific area has expired during the period or will expire in the near future, and is not expected to be renewed;
2. substantive expenditure on further exploration for and evaluation of mineral resources in the specific area is neither budgeted nor planned;
3. exploration for and evaluation of mineral resources in the specific area have not led to the discovery of commercially viable quantities of mineral resources and the entity has decided to discontinue such activities in the specific area; and
4. sufficient data exist to indicate that, although a development in the specific area is likely to proceed, the carrying amount of the E&E asset is unlikely to be recovered in full from successful development or by sale. [IFRS 6.20].

Finding that an exploratory or development well does not contain oil or gas in commercial quantities (i.e. finding a ‘dry hole’) is not listed in IFRS 6 as an impairment indicator. If finding a dry hole marks the end of budgeted or planned exploration activity, indicator (b) above would require impairment testing under IAS 36. Similarly, if the dry hole led to a decision that activities in the area would be discontinued, indicator (c) would require that an impairment test be performed, and indicator (d) requires an entity to do an impairment test if it is unlikely that it will recover the E&E costs from successful development or sale. However, absent one of these indicators being met, in isolation, drilling a dry hole would not necessarily trigger an impairment test. For example, if the first well in a three well campaign is a dry hole, but the entity still intends to drill the remaining two wells, an impairment trigger may not exist.

3.5.2 Specifying the level at which E&E assets are assessed for impairment

When deciding the level at which E&E assets should be assessed, rather than introduce a special CGU for E&E assets, IFRS 6 allows CGUs to be aggregated in a way consistent with the approach applied to goodwill in IAS 36. [IFRS 6.BC40‑BC47]. Therefore, an entity should determine an accounting policy for allocating E&E assets to CGUs or to CGU groups for the purpose of assessing them for impairment. [IFRS 6.21]. Each CGU or group of CGUs to which an E&E asset is allocated should not be larger than an operating segment (which is smaller than a reportable segment) determined in accordance with IFRS 8 – Operating Segments. [IFRS 6.21]. See also Chapter 20 at 8.1.4.

Hence, the level identified by an entity for the purposes of testing E&E assets for impairment may be comprised of one or more CGUs. [IFRS 6.22].

3.5.3 Cash-generating units comprising successful and unsuccessful E&E projects

IFRS 6 does not specifically address whether successful and unsuccessful E&E projects can be combined in a single CGU (which will occur under full cost accounting and may occur under area of interest accounting). There are some issues to consider before doing this:

• Regardless of whether there is an impairment trigger (see 3.5.1 above), IFRS 6 requires E&E assets to be tested for impairment before reclassification when the technical feasibility and commercial viability of extracting a mineral resource are demonstrable. [IFRS 6.17]. That means that the successful conclusion of a small E&E project and its reclassification out of E&E would result in an impairment test of a much larger CGU and possible recognition of an impairment loss on that larger CGU.
• Successful E&E projects should be reclassified as tangible or intangible assets under IAS 16 and IAS 38, respectively. [IFRS 6.15]. Therefore, a CGU comprising both successful and unsuccessful E&E projects would be subject to the impairment triggers in both IFRS 6 and IAS 36. This would significantly increase the frequency of impairment testing. [IFRS 6.20, IAS 36.8‑17].
• An entity should carefully consider the consequences of including several E&E projects in a CGU, because the unsuccessful conclusion of one project would usually trigger an impairment test of the entire CGU. [IFRS 6.20].

3.5.4 Order of impairment testing

CGUs often contain other assets as well as E&E assets. When developing IFRS 6, Exposure Draft ED 6 – Exploration for and Evaluation of Mineral Resources specifically stated that such other assets should be tested for impairment first, in accordance with IAS 36, before testing the CGU inclusive of the E&E assets.⁸² However, IFRS 6 does not specifically address this topic. Despite this, we believe that as the impairment test is completed in accordance with IAS 36, and a similar approach is adopted as that applied to goodwill, the order of the impairment testing as set out in IAS 36 would apply. That is, an entity would test the underlying assets/CGU without the E&E assets first, recognise any write down (if applicable) and then test the CGU/CGU group with the E&E assets allocated.

3.5.5 Additional considerations if E&E assets are impaired

In some circumstances an entity that recognises an impairment of an E&E asset must also decide whether or not to derecognise the asset because no future economic benefits are expected, as illustrated in Example 43.1 below.

If an entity concludes that production is not technically feasible or commercially viable, that provides evidence that the related E&E asset needs to be tested for impairment. It is also possible that such evidence may indicate that no future economic benefits are expected from such assets and therefore any remaining assets should be derecognised. When considering the two examples above, in Entity A's situation, no oil and/or gas resources were discovered and based on current plans, no future economic benefits were expected from the related E&E assets so they were derecognised. Whereas in Entity B's situation, while oil and/or gas resources were discovered, extraction was not commercially viable at this stage. So while an impairment was recognised, the remaining assets were not derecognised as management did expect future economic benefits to flow from such assets.

Although IFRS 6 does not specifically deal with derecognition of E&E assets, the entity should derecognise the E&E asset because the asset is no longer in the exploration and evaluation phase and hence outside the scope of IFRS 6 and other asset standards such as IAS 16 and IAS 38 would require derecognition under those circumstances. Once derecognised, the costs of an E&E asset that have been written off cannot be re-recognised as part of a new E&E asset, so unlike an impairment, the write off is permanent.

3.5.6 Income statement treatment of E&E write downs – impairment or exploration expense

In some circumstances, it may be unclear whether an E&E asset is impaired, or whether a write off of unsuccessful exploration is required. In an unconventional project, or in circumstances where costs have been carried forward for some time pending determination of technical feasibility and commercial viability, judgement will be required in concluding on the most appropriate income statement presentation. Key considerations may include whether the objectives of drilling or other expenditure programs have been met, whether the indicative impairment triggers in IFRS 6 have been met, and management's future intentions for the asset.

3.5.7 Reversal of impairment losses

Any impairment loss on an E&E asset recognised in accordance with IFRS 6 needs to be reversed if there is evidence that the loss no longer exists or has decreased. The entity must apply the requirements specified in IAS 36 for reversing an impairment loss (see Chapter 20 at 11). [IFRS 6.BC48, IAS 36.109‑123].

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 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.

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 43.7 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:

1. the repayment of expenses and the compensation for services are established on a monetary basis;
2. a RSC is for a limited period, after which the government or national oil company will take over operations;
3. under an RSC the contractor does not obtain ownership of the mineral reserves or production;
4. the contractor is normally required to carry out a minimum amount of work in providing the contracted services;
5. the fee that is payable to the contractor covers its capital expenditure, operating costs and an agreed-upon profit margin; and
6. 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.

5.7.1 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 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 43.8 and 43.9 below, from the financial statements of Premier Oil and BHP respectively, illustrate typical accounting policies for royalties under IFRS.

Extract 43.10 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.

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 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

6.1.1 Types of carried interest arrangements

Carried interest arrangements tend to fall into one of the following two categories:

• financing-type arrangements – the carrying party provides funding to the carried party and receives a lender's return on the funds provided, while the right to additional production acts as a security that underpins the arrangement; or
• purchase/sale-type arrangement – the carried party effectively sells an interest or a partial interest in a project to the carrying party. The carrying party will be required to fund the project in exchange for an increased share of any proceeds if the project succeeds, while the carried party retains a reduced share of any proceeds.

In practice, however, it is not always easy to determine in which category a particular carried interest arrangement falls, as is illustrated in the example below.

When entering into a carried interest arrangement, an entity must assess whether the arrangement is a financing-type arrangement or purchase/sale-type arrangement. Some of the indicators that a carried interest arrangement should be accounted for as a financing-type arrangement are that:

• the carried party is unable to fund its share of the project;
• the risks associated with the development are not significant, i.e. financing-type arrangements will be more common in the development stage; and
• the carrying party receives a return that is comparable to a lender's rate of return.

Indicators that a carried interest arrangement should be treated as a purchase/sale-type arrangement include:

• the carrying party and carried party have genuinely different opinions about the chances of success of the project, and the carried party could fund its share of the project if it wanted to;
• there are significant uncertainties about the outcome of the project. Purchase/ sale-type arrangements are therefore more common in the E&E phase;
• the arrangement gives the carrying party voting rights in the project;
• there are significant uncertainties about the costs of the project, perhaps because it involves use of a new technology or approach;
• the carrying party could lose all of its investment or possibly earn a return significantly in excess of a lender's rate of return; and
• the carrying party can only recover its investment from the project that is subject to the arrangement and there is no recourse to other assets or interests of the carried party.

In Example 43.4 above, scenario 1 has the characteristics of a financing-type arrangement, while scenario 2 has those of a purchase/sale-type arrangement. However, when an arrangement (such as scenario 3) has financing-type and purchase/sale-type characteristics (e.g. as a result of the relative bargaining strength of the parties), an entity will need to analyse the arrangement carefully and exercise judgement in developing an appropriate accounting policy.

The following types of carried interest arrangements are discussed below:

• carried interest arrangements in the E&E phase (see 6.1.2 below);
• financing-type carried interest arrangements in the development phase (see 6.1.3 below); and
• purchase/sale-type carried interest arrangements in the development phase (see 6.1.4 below).

6.1.2 Carried interest arrangements in the E&E phase

While IFRS 6 should be applied to accounting for E&E expenditures, the standard does not address other aspects of accounting by entities engaged in the exploration for and evaluation of mineral resources. [IFRS 6.4]. That leaves unanswered the question of whether carried interest arrangements can ever fall within the scope of IFRS 6. In the case of a purchase/sale-type carried interest arrangement the transaction, at least in economic terms, leads to the acquisition of an E&E asset by the carrying party and a disposal by the carried party. Therefore, we believe that purchase/sale-type carried interest arrangements in the E&E phase would fall within the scope of IFRS 6. Hence an entity has two options: either to develop an accounting policy under IAS 8 as discussed at 6.1.4 below, or, on transition to IFRS or first application under IFRS, to develop an accounting policy under IFRS 6 that is based on a previous national GAAP that contains such guidance. In practice this usually means that:

• the carrying party accounts for its expenditures under a carried interest arrangement in the same way as directly incurred E&E expenditure (see 3.2 and 3.3 above); and
• the carried party would not record expenditure incurred by the carrying party on its behalf subsequent to the arrangement commencing. However, the carried party may need to recognise a loss when the terms of the transaction indicate that the existing carrying value of the asset is impaired. Alternatively, to the extent that an arrangement is favourable, the carried party would – depending on its accounting policy – recognise the gain either in profit or loss or as a reduction in the carrying amount of the E&E asset.

On the other hand, a finance-type carried interest arrangement (which is generally not as common in the E&E phase) that has no significant impact on the risks and rewards that an entity derives from the underlying E&E working interest, may be more akin to a funding arrangement. As IFRS 6 deals only with accounting for E&E expenditures and assets, it is a matter of judgement whether or not the accounting for finance-type carried interest arrangements is considered to be outside the scope of IFRS 6. If an arrangement is considered to be outside the scope of IFRS 6, it might be appropriate to account for it in the same way as finance-type carried interest arrangements that relate to projects that are not in the E&E phase (see 6.1.3 below).

6.1.3 Financing-type carried interest arrangements in the development phase

As financing-type carried interest arrangements do not result in the transfer of the economic risks and rewards of the underlying working interest between parties, such arrangements are not accounted for as a sale (purchase) by the carried party (carrying party). Instead these arrangements are in effect secured borrowings in which the underlying asset is used as collateral that provides an identifiable stream of cash flows.

These arrangements are most appropriately accounted for as giving rise to a financial asset for the carrying party and a financial liability for the carried party.

The carried party will continue to recognise the expenditure incurred in relation to its full share of the working interest prior to the execution of the carried interest arrangement, and a corresponding financial liability for the amount that it is expected to reimburse to the carrying party as the pre-production costs being met by the carrying party are incurred, irrespective of whether it is a non-recourse arrangement or not. Under IFRS 9 – Financial Instruments – any financial liability would likely be measured at amortised cost unless it meets the definition of a derivative or is designated at fair value through profit or loss. See Chapter 48 at 3 for more information. As a financial liability measured at amortised cost, under IFRS 9 the carried party should accrete interest on the liability and reduce the loan to the extent the carrying party recovers its costs. It should be noted, however, that the application of the effective interest rate method under IFRS 9 requires adjustment of the carrying amount when the entity revises its estimates of the payments to be made. [IFRS 9.B5.4.6].

Conversely the carrying party should recognise a financial asset for the amount that it expects to recover as a reimbursement as the pre-production costs (which are being met by the carrying party) are incurred. Under IFRS 9 an entity would need to determine the classification of the financial asset based on an assessment of the entity's business model for managing financial assets and the contractual cash flow characteristics of the financial asset. See Chapter 48 at 2 for more information. Where the entity expects to recover all of its investment (so it is considered a debt instrument and not an equity instrument), the terms are solely payments of principal and interest and its business model is to hold the investment in order to collect contractual cash flows, the financial asset will be carried at amortised cost. This may be the case in financing-type carried interest arrangements. Where there is exposure to other factors, e.g. uncertainty about recovery and the exposure is through something other than principal and interest, the financial asset may have to be carried at fair value through profit or loss.

This approach to accounting for carried interest arrangements might not be appropriate if there were more than an insignificant transfer of risk (without necessarily resulting in a purchase/sale-type carried interest arrangement). The transfer of risk would suggest that:

• the carried party should recognise a provision under IAS 37 rather than a liability under IFRS 9; and
• the carrying party should account for its right to receive reimbursement as a financial asset at fair value through profit or loss under IFRS 9 or a reimbursement right under IAS 37.

Any financial liability would likely be measured at amortised cost unless it meets the definition of a derivative or was designated at fair value through profit or loss. See Chapter 48 at 3 for more information.

6.1.4 Purchase/sale-type carried interest arrangements in the development phase

The accounting suggested in this section for the carried party is the same as that set out in paragraph 155 of the former OIAC SORP, which stated that the disposal should be accounted for in accordance with the entity's normal accounting policy.

Historically, some entities have accounted for these types of transactions on a cash basis, i.e. the carried party does nothing and the carrying party accounts for its actual cash outlays. It is hard to see how this can be justified under IFRS.

In purchase/sale-type carried interest arrangements, the carried party effectively sells part of its interest in a project to the carrying party. For example, the carried party may sell part of its interest in the mineral reserves to the carrying party which, in exchange, is obliged to fund the remaining costs of developing the field. Consequently, the arrangement has two elements, the purchase/sale of mineral reserves and the funding of developments costs, which should be accounted for in accordance with their substance. Therefore, the carried party should:

• derecognise the part of the asset that it has sold to the carrying party, consistent with the derecognition principles of IAS 16 or IAS 38. [IAS 16.67, IAS 38.112]. Determining the amount to be derecognised may require a considerable amount of judgement depending on how the interest sold is defined;
• recognise the consideration received or receivable from the carrying party;
• recognise a gain or loss on the transaction for the difference between the net disposal proceeds and the carrying amount of the asset disposed of. Recognition of a gain would be appropriate only when the value of the consideration can be determined reliably. If not, then the carried party should account for the consideration received as a reduction in the carrying amount of the underlying assets. See 12.6.1.A below and Chapters 27 to 30 for discussion of how IFRS 15 – Revenue from Contracts with Customers – may impact such calculations; and
• test the retained interest for impairment if the terms of the arrangement indicate that the retained interest may be impaired.

In accounting for its purchase the carrying party should:

• recognise an asset that represents the underlying (partially) undeveloped interest acquired at cost in accordance with the principles of IAS 16 or IAS 38. [IAS 16.15, IAS 38.21]. Cost is defined in these standards as ‘the amount of cash or cash equivalents paid or the fair value of the other consideration given to acquire an asset at the time of its acquisition or construction or, where applicable, the amount attributed to that asset when initially recognised in accordance with the specific requirements of other IFRSs’; [IAS 16.6, IAS 38.8] and
• recognise a liability for the obligation to make defined payments on behalf of the carried party, which relate to the carried party's share of future investments.

The application of this approach is illustrated in Example 43.5 below.

The receivable recognised by the carried party and the corresponding liability recognised by the carrying party are reduced over the course of the construction of the assets to which they relate. The carrying party reduces the liability as it funds the carried party's share of the investment and the carried party recognises its share of the assets being constructed while reducing the balance of the receivable.

6.2.1 Farm‑in arrangements in the E&E phase

IFRS 6 deals only with accounting for E&E expenditures and does not address other aspects of accounting by entities engaged in the exploration for and evaluation of mineral resources. [IFRS 6.4]. That leaves open the question of whether farm‑in arrangements can ever fall within the scope of IFRS 6. However, as a farm‑in arrangement leads to the acquisition of an E&E asset by the farmee and a disposal by the farmor, we believe that a farm‑in arrangement would fall within the scope of IFRS 6. Hence an entity has two options: either to develop an accounting policy under IAS 8 as discussed at 6.2.2 below; or to develop an accounting policy under IFRS 6. In practice many entities use the second option and apply an accounting policy to farm‑in arrangements that is based on a previous national GAAP.

Accounting policies for farm‑in arrangements in the E&E phase that are based on an entity's previous national GAAP will often require that:

• the farmee recognises its expenditure under the arrangement in respect of its own interest and that retained by the farmor, as and when the costs are incurred. The farmee accounts for its expenditures under a farm‑in arrangement in the same way as directly incurred E&E expenditure; and
• the farmor accounts for the farm-out arrangement as follows:
  • the farmor does not record any expenditure made by the farmee on its behalf;
  • the farmor does not recognise a gain or loss on the farm‑out arrangement, but rather redesignates any costs previously capitalised in relation to the whole interest as relating to the partial interest retained; and
  • any cash consideration received is credited against costs previously capitalised in relation to the whole interest with any excess accounted for by the farmor as a gain on disposal.

If an entity applies its previous GAAP accounting policy in respect of farm‑in arrangements, we would expect the entity also to make the farm‑in disclosures required by its previous GAAP.

6.2.2 Farm‑in arrangements outside the E&E phase: accounting by the farmee

A farm‑in represents the complete acquisition of a proportion of a property. The accounting for such an arrangement will depend on whether the entity is farming into an asset or into an arrangement that is considered a business (and which is a joint operation), or whether the farm-in results in the arrangement becoming a joint operation.

6.2.3 Farm‑in arrangements outside the E&E phase: accounting by the farmor

In accounting for a farm-in arrangement the farmor should:

• derecognise the proportion of the asset that it has sold to the farmee, consistent with the principles of IAS 16 or IAS 38; [IAS 16.67, IAS 38.112]
• recognise the consideration received or receivable from the farmee, which represents the farmee's obligation to fund the capital expenditure in relation to the interest retained by the farmor;
• recognise a gain or loss on the transaction for the difference between the net disposal proceeds and the carrying amount of the asset disposed of. [IAS 16.71, IAS 38.113]. Recognition of a gain would be appropriate only when the value of the consideration can be determined reliably. If not, then the carried party should account for the consideration received as a reduction in the carrying amount of the underlying assets; and
• test the retained interest for impairment if the terms of the arrangement indicate that the retained interest may be impaired.

Under IAS 16, IAS 38 and IFRS 15, the amount of consideration to be included in the gain/loss arising from the derecognition of an item of property, plant and equipment or an intangible asset, and hence the receivable that is recognised, is determined in accordance with the requirements for determining the transaction price under IFRS 15. Subsequent changes to the estimated amount of the consideration included in the gain or loss calculation shall be accounted for in accordance with the requirements for changes in the transaction price in IFRS 15. [IAS 16.72, IAS 38.116]. See Chapter 27 at 4.3 and Chapter 29 at 2 for more information.

Any part of the consideration that is receivable in the form of cash will meet the definition of a financial asset under IAS 32, [IAS 32.11], and should be accounted for in accordance with IFRS 9, either at amortised cost or fair value depending on the nature of the receivable or how the farmor designates the receivable. See Chapter 48 at 2 for more information on classifying a financial asset under IFRS 9.

The extract below describes the farm‑in transactions of Harmony Gold.

6.3.1 E&E assets

Accounting for E&E assets, and therefore also accounting for swaps involving only E&E assets, falls within the scope of IFRS 6. [IFRS 6.3]. As that standard does not directly address accounting for asset swaps, it is necessary to consider its hierarchy of guidance in the selection of an accounting policy. IFRS 6 does not require an entity to look at other standards and interpretations that deal with similar issues, or the guidance in the IASB's Conceptual Framework. [IFRS 6.7]. Instead, it allows entities to develop their own accounting policies, or use the guidance issued by other standard-setters, thereby effectively allowing entities to continue using accounting policies that they applied under their previous national GAAP. Therefore, many entities, especially those which consider that they can never determine the fair value of E&E assets reliably, have selected an accounting policy under which they account for E&E assets obtained in a swap transaction at the carrying amount of the asset given up. An alternative approach, which is also permitted under IFRS 6, would be to apply an accounting policy that is based on the guidance in other standards as discussed below.

6.3.2 PP&E, intangible assets and investment property

Three separate international accounting standards contain virtually identical guidance on accounting for exchanges of assets: IAS 16, IAS 38 and IAS 40. These standards require the acquisition of PP&E, intangible assets or investment property, as the case may be, in exchange for non-monetary assets (or a combination of monetary and non-monetary assets) to be measured at fair value. The cost of the acquired asset is measured at fair value unless:

1. the exchange transaction lacks ‘commercial substance’; or
2. the fair value of neither the asset received nor the asset given up is reliably measurable. [IAS 16.24, IAS 38.45, IAS 40.27].

For more information, see Chapter 18 at 4.4 (PP&E), Chapter 17 at 4.7 (intangible assets) and Chapter 19 at 4.6 (investment properties).

6.3.3 Exchanges of E&E assets for other types of assets

An entity that exchanges E&E assets for PP&E, intangible assets or investment property needs to apply an accounting treatment that meets the requirements of IFRS 6 and those of IAS 16, IAS 38 or IAS 40. As discussed above, exchanges involving PP&E, intangible assets and investment property that have commercial substance should be accounted for at fair value. Since this treatment is also allowed under IFRS 6, an entity that exchanges E&E assets for assets within the scope of IAS 16, IAS 38 or IAS 40 should apply an accounting policy that complies with the guidance in those standards.

7.1.1 Assessing joint control

Joint control is defined as ‘the contractually agreed sharing of control of an arrangement which exists only when the decisions about the relevant activities require the unanimous consent of the parties sharing control’. [IFRS 11.7, Appendix A]. IFRS 11 describes the key aspects of joint control as follows:

• Contractually agreed – contractual arrangements are usually, but not always, written, and set out the terms of the arrangements. [IFRS 11.5(a), B2].
• Control and relevant activities – IFRS 10 describes how to assess whether a party has control, and how to identify the relevant activities, which are described in more detail in Chapter 6 at 3 and 4.1. Some of the aspects of ‘relevant activities’ and ‘control’ that are most relevant to extractives arrangements are discussed at 7.1.1.A and 7.1.2 below, respectively. [IFRS 11.8, B5].
• Unanimous consent – means that any party (with joint control) can prevent any of the other parties, or a group of the parties, from making unilateral decisions about the relevant activities without its consent. [IFRS 11.B9]. Joint control requires sharing of control or collective control by two or more parties. Some of the aspects of ‘unanimous consent’ for extractives arrangements are discussed at 7.1.1.B below.

For more information on assessing joint control see Chapter 12 at 4.

7.1.2 Determination of whether a manager/lead operator of a joint arrangement has control

It is common in the extractive industries for one of the parties to be appointed as the operator or manager of the joint arrangement. The manager is frequently referred to as the operator, but as IFRS 11 uses the terms ‘joint operation’ and ‘joint operator’ with specific meanings, to avoid confusion we refer to such a party as the manager/lead operator. The other parties to the arrangement may delegate some of the decision‑making rights to this manager/lead operator. In many instances, it is considered that the manager/lead operator does not control the joint arrangement, but simply carries out the decisions of the parties under the joint venture (or operating) agreement (JOA), i.e. the manager/lead operator acts as an agent. This view is based on the way in which these roles are generally established and referred to, or perceived, in the industries. Under IFRS 11, consideration is given to whether the manager/lead operator actually controls the arrangement. This is because when decision-making rights have been delegated, IFRS 10 describes how to assess whether the decision-maker is acting as a principal or an agent, and therefore, which party (if any) has control.

Careful consideration of the following will be required:

• scope of the manager's/lead operator's decision-making authority;
• rights held by others (e.g. protective rights and removal rights);
• exposure to variability in returns through the remuneration of the manager/lead operator; and
• variable returns held through other interests (e.g. direct investments by the manager/lead operator in the joint arrangement).

Of these factors, rights held by others and variable returns held through other interests will be particularly relevant for mining companies and oil and gas companies. Each of the above is discussed in Chapter 6 at 6 in more detail.

It is important to note that assessing whether an entity is a principal or an agent will require consideration of all factors collectively. See Chapter 6 at 6.1 for more details regarding the principal versus agent requirements.

Where it is determined that a manager is acting as a principal and therefore controls an arrangement, the impact of this will depend upon the rights and obligations conveyed by the arrangement (see 7.1.2.A and 7.1.2.B below for further discussion on this issue). Where it is determined that the manager/lead operator is acting as an agent, the manager/lead operator would only recognise its own interests in the joint arrangement (the accounting for which will depend upon whether it is a joint operation or joint venture) and its operator/management fee.

7.1.3 Parties to a joint arrangement without joint control or control

The accounting treatment of an interest in a contractual arrangement that does not give rise to joint control or control depends on the rights and obligations of the party.

7.1.4 Managers/lead operators of joint arrangements

It is clear that a participant in a joint operation is required to recognise its rights to the assets, and its obligations for the liabilities (or share thereof), of the joint arrangement. Therefore, it is important that an entity fully understands what these rights and obligations are and how these may differ between the parties.

See 7.1.2 above for a discussion of the principal versus agent assessment that needs to be considered when an entity is appointed as manager/lead operator of a joint arrangement and what impact that assessment might have on the manager's/lead operator's accounting.

7.1.5 Non-operators of joint arrangements

For expenses and liabilities incurred by the manager/lead operator directly in its own name which it recharges to the non-operators, the non-operator entities would be required to recognise an amount payable to the operator for such amounts. Depending on the nature of these arrangements, these may need to be recognised as a financial instrument under IAS 32 and IFRS 9, as a lease (where a sublease exists between the lead operator and the joint arrangement), or potentially a provision under IAS 37, and not under the standard which relates to the type of cost being reimbursed. For example, the non-operator's share of employee entitlements relating to the manager's employees who work on the joint project would not be recognised as an employee benefit under IAS 19 – Employee Benefits. In addition, the related disclosure requirements of IAS 19 would not apply, instead the disclosure requirements of other standards, e.g. IFRS 7 – Financial Instruments: Disclosures – would apply.

Expenses and liabilities incurred by the manager/lead operator jointly on behalf of all of the parties to the arrangement would have to be recognised by each of the non-operator parties in proportion to their respective interests in the arrangement. Such amounts would be recognised for the costs incurred on an accruals basis for production costs, operating expenses etc. and associated ‘joint venture payables’ would be recognised. With respect to longer term arrangements, such as leases entered into by the lead operator on behalf of the joint arrangement, the non-operator parties would consider the broader contractual arrangements to determine whether or not there was a lease by the joint operation. This is discussed further at 18.1.5 below.

8.1.1 Differences between asset purchase transactions and business combinations

The reason it is important to distinguish between an asset acquisition and a business combination is because the accounting consequences are significantly different. The main differences between accounting for an asset acquisition and a business combination can be summarised as follows:

• goodwill or a bargain purchase (also sometimes referred to as negative goodwill) only arise in business combinations;
• assets and liabilities are accounted for at fair value in a business combination, while they are assigned a carrying amount based on their relative fair values in an asset acquisition (see 8.4 below);
• transaction costs should be recognised as an expense under IFRS 3, but can be capitalised on an asset acquisition; and
• in an asset acquisition no deferred tax will arise in relation to acquired assets and assumed liabilities as the initial recognition exception for deferred tax under IAS 12 – Income Taxes – applies. See Chapter 33 at 7.2 for further details.

8.1.2 Definition of a business

IFRS 3 defines a business as ‘an integrated set of activities and assets that is capable of being conducted and managed for the purpose of providing goods or services to customers, generating investment income (such as dividends or interest) or generating other income from ordinary activities’. [IFRS 3 Appendix A]. See Chapter 9 at 3.2.1 and 3.2.2 to 3.2.6 for further discussion on the definition of a business.

In October 2018, the IASB issued amendments to the definition of a business in IFRS 3 that are effective for annual reporting periods beginning on or after 1 January 2020 (with early adoption permitted) and apply prospectively. Major changes introduced by the amendments are:

• clarification on the minimum requirements for a business;
• removal of the assessment of whether market participants are capable of replacing any missing elements;
• narrowing of the definitions of a business and outputs;
• introduction of an optional fair value concentration test; and
• guidance added to help entities assess whether an acquired process is substantive.

For more detail on the changes see Chapter 9 at 3.2.8.

Determining whether a particular set of integrated activities and assets is a business will often require a significant amount of judgement, particularly for oil and gas companies and mining companies depending on the stage of the asset in the asset life cycle. Examples are set out in Chapter 9 at 3.2.

8.2.1 Goodwill in business combinations

Prior to the adoption of IFRS, many mining companies and oil and gas companies assumed that the entire consideration paid for upstream assets should be allocated to the identifiable net assets acquired. That is, any excess of the consideration transferred over the fair value of the identifiable net assets (excluding mineral reserves and resources) acquired would then have been included within mineral reserves and resources acquired and goodwill would not generally be recognised. However, goodwill could arise as a result of synergies, overpayment by the acquirer, or when IFRS requires that acquired assets and/or liabilities are measured at an amount that is not fair value (e.g. deferred taxation). Therefore, it is unlikely to be appropriate for mining companies or oil and gas companies to simply assume that goodwill would never arise in a business combination and that any differential automatically goes to mineral reserves and resources. Mineral reserves and resources and any exploration potential (if relevant) acquired should be valued separately and any excess of the consideration transferred over and above the supportable fair value of the identifiable net assets (which include mineral reserves, resources and acquired exploration potential), should be allocated to goodwill.

By virtue of the way IFRS 3 operates, if an entity were simply to take any excess of the consideration transferred over the fair value of the identifiable net assets acquired to mineral reserves and resources, they may end up having to allocate significantly larger values to minerals reserves and resources than expected. This is because, under IFRS 3, an entity is required to provide for deferred taxation on the temporary differences relating to all identifiable net assets acquired (including mineral reserves and resources), but not on temporary differences related to goodwill. Therefore, if any excess was simply allocated to mineral reserves and resources, to the extent that this created a difference between the carrying amount and the tax base of the mineral reserves and resources, IAS 12 would give rise to a deferred tax liability on the temporary difference, which would create a further excess. This would then result in an iterative calculation in which the deferred tax liability recognised would increase the amount attributed to mineral reserves and resources, which would in turn give rise to an increase in the deferred tax liability (see Chapter 33 at 7.2.2). Given the very high marginal tax rates to which extractive activities are often subject (i.e. tax rates of 60 to 80% are not uncommon) the mineral reserves and resources might end up being grossed up by a factor of 2.5 to 5 (i.e. 1/(1 – 60%) = 2.5). Such an approach would only be acceptable if the final amount allocated to mineral reserves and resources remained in the range of fair values determined for those mineral reserves and resources. If not, such an approach would lead to excessive amounts being allocated to mineral reserves and resources which could not be supported by appropriate valuations.

The extract below from Glencore financial statements illustrates a typical accounting policy for business combinations in which excess consideration transferred is treated as goodwill.

8.2.2 Impairment of assets and goodwill recognised on acquisition

There are a number of circumstances in which the carrying amount of assets and goodwill acquired as part of a business combination and as recorded in the consolidated accounts, may be measured at a higher amount through recognition of notional tax benefits, also known as tax amortisation benefits (i.e. the value has been grossed up on the assumption that its carrying value is deductible for tax) or deferred tax (which can increase goodwill as described above). Application of IAS 36 to goodwill which arises upon recognition of deferred tax liabilities in a business combination is discussed in Chapter 20 at 8.3.1.

8.2.3 Value beyond proven and probable reserves (VBPP)

In the mining sector specifically, the ‘value beyond proven and probable reserves’ (VBPP) is defined as the economic value of the estimated cash flows of a mining asset beyond that asset's proven and probable reserves.

While this term is specifically relevant to the mining sector by virtue of specific guidance in US GAAP, the concept may be equally relevant to the oil and gas sector, i.e. the economic value of an oil and gas licence/area beyond the proven and probable reserves.

For mining companies, there are various situations in which mineralisation and mineral resources might not be classified as proven or probable:

• prior to the quantification of a resource, a mining company may identify mineralisation following exploration activities. However, it may be too early to assess if the geology and grade is sufficiently expansive to meet the definition of a resource;
• Acquired Exploration Potential (AEP) represents the legal right to explore for minerals in a particular property, occurring in the same geological area of interest;
• carrying out the required assessments and studies to obtain classification of mineral reserves can be very costly. Consequently, these activities are often deferred until they become necessary for the planning of future operations. Significant mineral resources are often awaiting the initiation of this process; and
• if an entity acquires a mining company at a time when commodity prices are particularly low, the mineral resources owned by the acquiree may not meet the definition of proven or probable reserves because extraction might not be commercially viable.

While the above types of mineralisation and mineral resources cannot be classified as proven or probable, they will often be valuable because of the future potential that they represent (i.e. reserves may be proven in the future and commodity price increases may make extraction commercially feasible).

IFRS 3 requires that an acquirer recognises the identifiable assets acquired and liabilities assumed that meet the definitions of assets and liabilities at the acquisition date. [IFRS 3.11].

While the legal or contractual rights that allow an entity to extract minerals are not themselves tangible assets, the mineral reserves concerned clearly are. The legal or contractual rights – that allow an entity to extract mineral reserves and resources – acquired in business combinations should be recognised, without exception, at fair value.

An entity that acquires mineral reserves and resources that cannot be classified as proven or probable, should account for the VBPP as part of the value allocated to mining assets, to the extent that a market participant would include VBPP in determining the fair value of the asset, rather than as goodwill.¹⁰³ In practice, the majority of mining companies treat mining assets, the related mineral reserves and resources and licences as tangible assets on the basis that they relate to minerals in the ground, which are themselves tangible assets. However, some entities present the value associated with E&E assets as intangible assets.

AEP would often be indistinguishable from the value of the mineral licence to which it relates. Therefore, the classification of AEP may vary depending on how an entity presents its mining assets and licences. If an entity presents them as tangible assets, they may be likely to treat AEP (or its equivalent), where applicable, as forming part of mineral properties, and hence AEP would be classified as a tangible asset. For an entity that classifies some of its mineral assets as intangible assets, e.g. E&E assets, then they may classify AEP as an intangible also.

Determining the fair value of VBPP requires a considerable amount of expertise. An entity should not only take account of commodity spot prices but also consider the effects of anticipated fluctuations in the future price of minerals, in a manner that is consistent with the expectations of a market participant. An entity should consider all available information including current prices, historical averages, and forward pricing curves and maximise the use of observable inputs. Those market participant assumptions typically are consistent with the acquiring entity's operating plans for developing and producing minerals. However entities need to undertake steps to demonstrate this is true (to ensure compliance with the requirements of IFRS 13 – Fair Value Measurement). The potential upside associated with mineral resources that are not classified as reserves can be much larger than the downward risk. A valuation model that only takes account of a single factor, such as the spot price, historical average or a single long-term price, without considering other information that a market participant would consider, would generally not be able to reflect the upward potential that determines much of the value of VBPP. Consequently, an entity may need to apply option valuation techniques in measuring VBPP.

There are commonly considered to be three categories of VBPP, including:

• mineral resources not yet tested for economic viability;
• early mineralisation; and
• acquired exploration potential.

The CRIRSCO reporting standards consider the geological definition of mineral resources that have not yet been tested for economic viability, which is the first category of VBPP. Valuation techniques used for this category include:

• probability weighted discounted-cash flows;
• resource reserve conversion adjustment;
• comparable transactions; and
• option valuation.

In relation to early mineralisation, the second category of VBPP, while it may represent a discovery, its true value will be determined by further appraisal/evaluation activities to confirm whether a resource exists. This category of VBPP is often grouped with the next (and final) category, being AEP, even though it has a higher intrinsic value, and is valued using:

• cost based methods;
• budgeted expenditure methods;
• comparable sales;
• farm-in/out values; or
• sophisticated option pricing.

In relation to AEP, the basis for its valuation varies from studying historic cost to the use of sophisticated option valuation techniques.

As VBPP does not provide current economic benefits, there is no need to allocate its cost against current revenue and hence no need for amortisation or depreciation. However, as part of the process of completing the acquisition accounting, an entity should form a view about how that value will ultimately be ascribed to future discoveries and converted into proven and probable reserves and then ultimately depreciated. Such methodologies might include a per unit (e.g. tonnes/ounces) basis or possibly an area (e.g. acreage) basis. VBPP would need to be tested for impairment under IAS 36 if, depending on the classification of VBPP, there is an indicator of impairment under that standard or IFRS 6. The VBPP may ultimately be impaired because it may never be converted into proven or probable reserves, but impairment may not be confirmed until the entity is satisfied that the project will not continue.

An impairment of VBPP should be recognised if its book value exceeds the higher of fair value less costs of disposal and value in use. In practice, there may not be a convenient method to determine the value in use. Hence, impairment testing will often need to rely on an approach based on fair value less costs of disposal.

Extract 43.14 below illustrates that AngloGold Ashanti does not subsume the ‘value beyond proven and probable reserves’ in goodwill but instead recognises it as part of the value ascribed to mineral resources.

8.4.1 Asset acquisitions and conditional purchase consideration

When an asset or a group of assets/net assets that do not constitute a business are acquired, they are required to be accounted for at cost. There are various standards in which ‘cost’ is defined, with those of most relevance to the acquisition of an asset being IAS 16, IAS 38 and IAS 40. Cost is defined in those standards as ‘the amount of cash or cash equivalents paid or the fair value of the other consideration given to acquire an asset at the time of its acquisition or construction or, where applicable, the amount attributed to that asset when initially recognised in accordance with the specific requirements of other IFRSs, e.g. IFRS 2 – Share-based Payment’. [IAS 16.6, IAS 38.8, IAS 40.5]. Amounts capitalised under IFRS 6 are also required to be measured initially at cost. [IFRS 6.8].

These requirements sometimes give rise to issues in situations where the purchase price is conditional upon certain events or facts. These issues can best be illustrated by an example.

In scenario 1, we believe Entity A would be required to account for the fair value of the consideration transferred as determined at the date of acquisition. In contrast to the treatment under IFRS 3, there is no purchase price allocation or measurement period under IAS 16. However, suppose that three weeks after the initial accounting the surveyor reports that at the date of acquisition a number of assets listed in the contract were not present or were of inferior quality, the purchase price is therefore adjusted downwards to $14.5 million. Rather than recognising a profit arising from this adjustment, the entity should adjust the cost of the asset as the surveyor's report provides evidence of conditions that existed at the date of acquisition. [IAS 10.3(a)].

In scenario 2 above, Entity C pays an additional $12 million in exchange for additional rights to extract minerals in excess of 20 million barrels (or tonnes) agreed upon in the initial transaction. At the date that Entity C purchases the additional rights it accounts for this as an additional asset acquisition. In more complicated scenarios, however, it might be necessary to assess whether the first and second acquisition should be accounted for together.

It is clear from the above two scenarios that changes in the facts and circumstances can have a significant effect on the accounting for conditional purchase consideration.

When considering asset acquisitions with contingent consideration, several issues need to be addressed. These include:

• how and when the contingent element should be accounted for, i.e. when a liability should be recognised and how it should be measured;
• whether the initial cost of the asset acquired includes an amount relating to the contingent element; and
• how the remeasurement (if any) of any liability recognised in relation to the contingent element should be accounted for. Should it be recognised as an adjustment to the cost of the asset acquired, or should it be recognised in profit or loss?

IAS 32 is clear that the purchase of goods on credit gives rise to a financial liability when the goods are delivered (see Chapter 45 at 2.2.6) and that a contingent obligation to deliver cash meets the definition of a financial liability (see Chapter 45 at 2.2.3). Consequently, it would seem that given the current requirements of IFRS, a financial liability arises on the outright purchase of an item of property, plant and equipment or an intangible asset if the purchase contract requires the subsequent payment of contingent consideration, for example amounts based on the performance of the asset. Further, because there is currently no exemption from applying IFRS 9 to such contracts, one might expect that such a liability would be accounted for in accordance with IFRS 9, i.e. any measurement changes to that liability would flow through profit or loss. This would be consistent with the accounting treatment for contingent consideration arising from a business combination under IFRS 3 (see Chapter 45 at 3.7.1.A). However, this is not necessarily clear and for this reason the issue of how to account for contingent consideration in the acquisition of an item of PP&E was taken to the Interpretations Committee. See below for further discussion of this issue.

The current definition of cost in IAS 16 and IAS 38 requires the cost of an asset on the date of purchase to include the fair value of the consideration given (if a reliable estimate can be made), such as an obligation to pay a contingent price. Based on our experience and the level of diversity of views identified as part of the Interpretations Committee's considerations of this, not all would agree that all contingent payments are for the original asset and, indeed, the circumstances of a particular contract might support this. In addition to this issue, there is the issue of how to account for the remeasurement of the liability and whether changes should be recognised in profit or loss, or included as an adjustment to the cost of the asset.

In practice, contracts can be more complex than suggested above and often give rise to situations where the purchaser can influence or control the crystallisation of the contingent payments, e.g. where the contingent payments are dependent on the purchaser's future actions – such as those that take the form of production-based royalties. These complexities can raise broader questions about the nature of the obligations and, as in the case of royalty-based contingent payments, the appropriate accounting standard to apply initially, as well as how to account for subsequent adjustments to any liability that may have been recognised. To date, these complexities and lack of clarity as to the appropriate accounting have led to various treatments, including:

• the cost of the asset does not initially include any amount relating to the contingent element. Any subsequent payments made in relation to the contingent element are either adjusted against the cost of the asset (once paid) or recognised in profit or loss as incurred;
• the cost of the asset includes an estimate of the contingent consideration at the date of purchase. Subsequent changes in the liability relating to the contingent consideration are then recognised in profit or loss; or
• the cost of the asset includes an estimate of the contingent consideration at the date of purchase. Subsequent changes in the liability relating to the contingent consideration that do not reflect the passage of time are adjusted against the cost of the asset.

The first approach (which is relatively common in the extractive industries) considers that the applicable standard is IAS 37, and applies the concepts of obligating events, probability, contingencies and not providing for future operations. This means that nothing relating to the contingent payment is recognised at the date of purchase. The second approach applies the methodology in IFRS 3, while the third is based on the principles of IFRIC 1.¹⁰⁴

Given this divergence in practice, this issue was referred to the Interpretations Committee in January 2011. The Committee and the IASB have discussed this issue for a number of years since this date. They had been attempting to clarify how the initial recognition and subsequent changes in relation to such contingent consideration should be recognised but did not conclude.

In March 2016, the Interpretations Committee determined that this issue was too broad for it to address within the confines of existing IFRSs. The Interpretations Committee decided not to add this issue to its agenda and concluded that the IASB should address the accounting for variable payments comprehensively.

In February 2018, the IASB decided that the IASB staff should carry out work on ‘Variable and Contingent Consideration’ to determine how broad the research project should be.¹⁰⁵ At the time of writing, this is not listed as an active research project on the IASB's work plan.¹⁰⁶

Until this matter is resolved, an entity should develop an accounting policy for variable consideration relating to the purchase of PP&E in accordance with the hierarchy in IAS 8. In practice, there are different approaches for treating the estimated future variable payments. Some entities do not capitalise these amounts upon initial recognition of the asset and then either expense or capitalise any payments as they are incurred. Other entities include an estimate of future amounts payable on initial recognition with a corresponding liability being recorded. Under this approach, subsequent changes in the liability are either capitalised or expensed. An entity should exercise judgement in developing and consistently applying an accounting policy that results in information that is relevant and reliable in its particular circumstances. [IAS 8.10]. The accounting policy must be applied consistently.

For further information on this issue see Chapter 17 at 4.5, Chapter 18 at 4.1.9 and Chapter 45 at 3.8.

8.4.2 Accounting for land acquisitions

Obtaining the legal rights to explore for, develop and produce minerals can be achieved in a number of ways, as outlined at 5 above. One of these ways is through the outright purchase of the minerals and the land on, or under, which the minerals are located. In undertaking such a transaction, it is not uncommon for an entity to pay an amount in excess of the intrinsic value of the land itself. In such a situation, an entity needs to ensure it appropriately allocates the purchase price between the fair value of the land and the fair value of the mineral or surface mining rights acquired. The amount allocated to land will be capitalised and not depreciated, whereas the amount allocated to the minerals or surface mining rights will form part of the total cost of mining assets and will ultimately be depreciated on a units of production basis over the economically recoverable reserves to which it relates.

10.1.1 Initial recognition

Initial recognition of a decommissioning or restoration provision only on commencement of commercial production is generally not appropriate under IFRS, because the obligation to remove facilities and to restore the environment typically arises during the development/construction of the facilities, with some further obligations arising during the production phase. Therefore, a decommissioning or restoration provision should be recognised during the development or construction phase (see 1.6.1 above) of the project, i.e. before any production takes place, and should form part of the cost of the assets acquired or constructed. It may also be necessary to recognise a further decommissioning or restoration provision during the production phase (see 10.1.3 below).

While the damage caused in the exploration phase may generally be immaterial, an entity should recognise a decommissioning or restoration provision where the damage is material and the entity will be required to carry out remediation. The accounting for such a provision will depend on how the related E&E costs have been accounted for. If the E&E costs are capitalised, the associated decommissioning costs should also be capitalised. However, if the E&E costs are expensed, any associated decommissioning or restoration costs should also be expensed.

Finally, even if decommissioning and restoration were not planned to take place in the foreseeable future (for example because the related assets are continually renewed and replaced), IAS 37 would still require a decommissioning or restoration provision to be recognised. However, in these cases the discounted value of the obligation may be comparatively insignificant.

10.1.2 Measurement of the liability

Measurement of a decommissioning or restoration provision requires a significant amount of judgement because:

• the amount of remedial work required will depend on the scale of the operations. In the extractives industries the environmental damage may vary considerably depending on the type and development of the project;
• the amount of remedial work further depends on environmental standards imposed by local regulators, which may vary over time;
• detailed decommissioning and remedial work plans will often not be developed until fairly shortly before closure of the operations;
• it may not always be clear which costs are directly attributable to decommissioning or restoration (e.g. security costs, maintenance cost, ongoing environmental monitoring and employee termination costs);
• the timing of the decommissioning or restoration depends on when the fields or mines cease to produce at economically viable rates, which depends upon future commodity prices and reserves; and
• the actual decommissioning or restoration work will often be carried out by specialised contractors, the cost of which will depend on future market prices for the necessary remedial work.

Many of the uncertainties above can only be finally resolved towards the end of the production phase, shortly before decommissioning and restoration are to take place. A significant increase in the decommissioning or restoration provision resulting from revised estimates would result in recognition of an additional asset. However, as IFRIC 1 specifically states that any addition to an asset as a result of an increase in a decommissioning or restoration provision is considered to be a trigger for impairment testing, a significant increase in a decommissioning or restoration provision close to the end of the production phase may lead to an immediate impairment of that additional asset. Conversely, a decrease in the decommissioning or restoration provision could exceed the carrying amount of the related asset, in which case the excess should be recognised as a gain in profit or loss.

10.1.3 Decommissioning or restoration costs incurred in the production phase

IAS 16 considers the initial estimate of the costs of dismantling and removing the item and restoring the site on which it is located to be part of the cost of an item of property, plant and equipment. [IAS 16.16(c)]. However, an entity should apply IAS 2 to the costs of obligations for dismantling, removing and restoring the site on which an item is located that are incurred during a particular period as a consequence of having used the item to produce inventories during that period. [IAS 16.18]. That means that such additional decommissioning or restoration costs resulting from production activities should be included in the cost of inventories, [IAS 2.10], while decommissioning costs resulting from the construction of assets during the production phase should be accounted for as discussed above.

An entity that incurs abnormal amounts of costs (e.g. costs of remediation of soil contamination from oil spills or overflowing of a tailings pond) should not treat these as part of the cost of inventories under IAS 2, but expense them immediately. [IAS 2.16].

11.2.1 Markets for intermediate products

In vertically integrated operations, the successive stages of the extraction and production process are often considered to be one CGU as it is not possible to allocate net cash inflows to individual stages of the process. This is common in some mining operations. However, if there is an active market for intermediate commodities (e.g. bauxite, alumina and aluminium) then a vertically integrated mining company needs to consider whether its smelting and refining operations are part of the same CGU as its mining operations. If there is an active market for the output produced by an asset or group of assets, the assets concerned are identified as a separate CGU, even if some or all of the output is used internally. If extraction and smelting or refining are separate CGUs and the cash inflows generated by the asset or each CGU are based on internal transfer pricing, the best estimate of an external arm's length transaction price should be used in estimating the future cash flows to determine the asset's or CGU's VIU. [IAS 36.70]. See Chapter 20 at 3.

11.2.2 External users of processing assets

When an entity is able to derive cash inflows from its processing assets (e.g. smelting or refining facilities) under tolling arrangements (see 20 below), the question arises as to whether or not those processing assets are a separate CGU. If an entity's processing assets generate significant cash inflows from arrangements with third parties then those assets are likely to be a separate CGU.

11.2.3 Shared infrastructure

When several fields or mines share infrastructure (e.g. pipelines to transport gas or oil onshore, railways, ports or refining and smelting and other processing facilities) the question arises as to whether the fields or mines and the shared infrastructure should be treated as a single CGU. Treating the fields or mines and the shared infrastructure as part of the same CGU is not appropriate under the following circumstances:

1. if the shared infrastructure is relatively insignificant;
2. if the fields or mines are capable of selling their product without making use of the shared infrastructure;
3. if the shared infrastructure generates substantial cash inflows from third parties as well as the entity's own fields or mines; or
4. if the shared infrastructure is classified as a corporate asset, which is defined under IAS 36 as ‘assets other than goodwill that contribute to the future cash flows of both the cash-generating unit under review and other cash-generating units’. [IAS 36.6]. In that case, the entity should apply the requirements in IAS 36 regarding corporate assets, which are discussed in Chapter 20 at 4.2.

However, if none of the conditions under (a) to (d) above apply then it may be appropriate to treat the fields or mines and the shared infrastructure as one CGU.

Any shared infrastructure that does not belong to a single CGU but relates to more than one CGU still need to be considered for impairment purposes. It is considered that there are two ways to do this and an entity should use the method most appropriate. Shared infrastructure can be allocated to individual CGUs or the CGUs can be grouped together to test the shared assets (similar to the way corporate assets are tested – see commentary above).

Under the first approach, the shared assets should be allocated to each individual CGU or group of CGUs on a reasonable and consistent basis. The cash flows associated with the shared assets, such as fees from other users and expenditure, should be allocated similarly and should form part of the cash flows of the individual CGU. Under the second approach, the group of CGUs that benefit from the shared assets are grouped together with the shared assets to test the shared assets for impairment.

11.2.4 Fields or mines operated on a portfolio basis

Mining companies and oil and gas companies sometimes operate a ‘portfolio’ of similar mines or fields, which are completely independent from an operational point of view. However, IAS 36 includes the following illustrative example. [IAS 36 IE Example 1C].

The same rationale could also be applied by a mining company that, for example, operates two coal mines on a portfolio basis, or an oil and gas company that, for example, operates two fields within the one PSC and the entitlement to revenue is dependent on production of, the revenue earned and costs incurred across the PSC, not on a field by field basis. However, judgement needs to be exercised before concluding that it is appropriate to treat separate fields or mines as one CGU, particularly when the production costs of the output of fields or mines differ considerably. This is because there may be a desire to combine them into one CGU, so that the higher cost fields or mines are protected by the headroom of the lower cost fields or mine, thereby avoiding a recognition of an impairment charge. Therefore, to be able to combine on a portfolio basis, a mining company or oil and gas company would have to be able to demonstrate that the future cash inflows for the individual mines or fields cannot be determined individually and therefore, the combined group represents the smallest identifiable group of assets that generates cash inflows that are largely independent.

11.4.1 Consistency in cash flows and book values attributed to the CGU

An essential requirement of impairment testing under IAS 36 is that the recoverable amount of a CGU must be determined in the same way as for an individual asset and its carrying amount must be determined on a basis that is consistent with the way in which its recoverable amount is determined. [IAS 36.74, 75].

The carrying amount of a CGU includes only those assets that can be attributed directly, or allocated on a reasonable and consistent basis. These must be the assets that will generate the future cash inflows used in determining the CGU's VIU. It does not include the carrying amount of any recognised liability, unless the recoverable amount of the cash-generating unit cannot be determined without taking it into account.

For practical reasons the entity may determine the recoverable amount of a CGU after taking into account assets and liabilities such as receivables or other financial assets, trade payables, pensions and other provisions that are outside the scope of IAS 36 and not part of the CGU. [IAS 36.79]. If the cash flows of a CGU are determined taking into account these sorts of items, then it is essential that cash flows and assets and liabilities within CGUs are prepared on a consistent basis.

Specific issues mining companies and oil and gas companies will need to consider are:

• environmental provisions and similar provisions and liabilities (see 11.4.1.A below); and
• working capital such as trade debtors, trade payables and inventories (see Chapter 20 at 4.1 and 4.1.3 for further discussion).

11.4.2 Projections of cash flows

IAS 36 requires that in calculating VIU an entity base its cash flow projection on the most recent financial budgets/forecasts approved by management, excluding any estimated future cash inflows or outflows expected to arise from future restructurings or from improving or enhancing the asset's performance. The assumptions used to prepare the cash flows should be reasonable and supportable, which can best be achieved by benchmarking against market data or performance against previous budgets. These projections cannot cover a period in excess of five years, unless a longer period can be justified. [IAS 36.33(b)]. Entities are permitted to use a longer period if they are confident that their projections are reliable, based on past experience. [IAS 36.35].

In practice, most production or mining/field plans will cover a period of more than five years and hence management will typically make financial forecasts for a corresponding period. The use of such longer term forecasts may be appropriate where it is based on proved and probable reserves and expected annual production rates. Assumptions as to the level of reserves expected to be extracted should be consistent with the latest estimates prepared by reserve engineers; annual production rates should be consistent with those for a certain specified preceding period, e.g. five years; and price and cost assumptions should be consistent with the final period of specific assumptions.

11.4.3 Commodity price assumptions

Forecasting commodity prices is never straightforward, because it is not usually possible to know whether recent changes in commodity prices are a temporary aberration or the beginning of a longer-term trend. Management usually takes a longer term approach to estimates of commodity prices for internal management purposes but these are not always consistent with the VIU requirements. Given the long life of most mines and oil fields, an entity should not consider price levels only for the past three or four years. Instead, it should consider historical price levels for longer periods and assess how these prices are influenced by changes in underlying supply and demand levels.

For actively traded commodities, there are typically forward price curves available and in such situations, these provide a reference point for forecast price assumptions.

The commodity assumptions need to match the profile of the life of the mine or oil field. Spot prices and forward curve prices (where they are available as at the impairment testing date) are more relevant for shorter life mines and oil fields, while long-term price assumptions are more relevant for longer life mines and oil fields. Forecast prices (where available) should be used for the future periods covered by the VIU calculation. Where the forward price curve does not extend far enough into the future, the price at the end of the forward curve is generally held steady, or is often dropped to a longer term average price (in real terms), where appropriate.

The future cash flows relating to the purchase or sale of commodities might be known from forward purchase or sales contracts. Use of these contracted prices in place of the spot price or forward curve price for the contracted volumes will generally be acceptable. However, it is possible that some of these forward contracts might be accounted for as derivatives contracts at fair value in accordance with IFRS 9, and therefore the related assets or liabilities will be recognised in the statement of financial position. Such balances would be excluded from the IAS 36 impairment test. Given this, the cash flow projections prepared for the purposes of the IAS 36 impairment test should exclude the pricing terms associated with these forward contracts.

The commodity price is a key assumption in calculating the VIU of any mine or oil field. Only in the context of impairment testing of goodwill and indefinite life intangible assets does IAS 36 specifically require disclosure of:

1. a description of each key assumption on which management has based its cash flow projections for the period covered by the most recent budgets/forecasts. Key assumptions are those to which the unit's (group of units’) recoverable amount is most sensitive; and
2. a description of management's approach to determining the value(s) assigned to each key assumption, whether those value(s) reflect past experience or, if appropriate, are consistent with external sources of information, and, if not, how and why they differ from past experience or external sources of information. [IAS 36.134(d)(i)‑(ii), 134(e)(i)‑(ii)].

In practice, considerable differences may exist between entities in their estimates of future commodity prices. Therefore, we recommend disclosure of the actual commodity prices used in calculating the VIU of any mine or oil field that does not have any goodwill or indefinite life intangibles allocated to it, even though this is not specifically required by IAS 36 as these would generally be considered a significant judgement or estimate and hence would require disclosure under IAS 1. [IAS 1.122, 125]. A possible approach to such disclosures is illustrated in the following extract from the financial statements of BP.

The extract below illustrates a similar type of disclosure by Newcrest Mining from its 30 June 2017 financial statements, in this case as part of the key assumption disclosures within its impairment disclosures.

11.4.4 Future capital expenditure

When determining VIU, although the standard permits an entity to take account of cash outflows required to make an asset ready for use, i.e. those relating to assets under construction, [IAS 36.42], it does not allow inclusion of cash outflows relating to future enhancements of an asset's performance or capacity to which an entity is not committed. [IAS 36.44]. This may have a significant impact on relatively new assets and on fields or mines that will be developed over time. Note that while enhancement capital expenditure may not be recognised, routine or replacement capital expenditure necessary to maintain the function or current performance of the asset or assets in the CGU has to be included. Entities must therefore distinguish between maintenance and enhancement expenditure. This distinction may not be easy to draw in practice but, for example, an anticipated increase in mineral reserves as a consequence of incurring future capital expenditure may be an indicator that the expenditure is enhancement expenditure.

11.4.5 Foreign currency cash flows

An entity in the extractive industries will often sell its product in a currency that is different from the one in which it incurs its production costs (e.g. silver production may be sold in US dollars while production costs may be incurred in pesos). In such situations, impairment testing and calculating VIU under IAS 36 require that the foreign currency cash flows should first be estimated in the currency in which they will be generated and then discounted using a discount rate appropriate for that currency. An entity should translate the present value calculated in the foreign currency using the spot exchange rate at the date of the VIU calculation. [IAS 36.54]. This is to avoid the problems inherent in using forward exchange rates, which are based on differential interest rates. Using such forward rates would result in double-counting the time value of money, first in the discount rate and then in the forward rate. [IAS 36.BCZ49].

This requirement, however, is more complex than it may initially appear. Effectively, this method requires an entity to perform separate impairment tests for cash flows generated in different currencies, but make them consistent with one another so that the combined effect is meaningful. This can be a difficult exercise to undertake. Many different factors need to be considered, including relative inflation rates and relative interest rates, as well as appropriate discount rates for the currencies in question. Because of this, the possibility for error is significant, given this, it is important for entities to seek input from experienced valuers who will be able to assist them in dealing with these challenges.

11.5.1 Projections of cash flows

As required by IFRS 13, the assumptions and other inputs used in a FVLCD DCF model are required to maximise the use of observable market inputs. These should be both realistic and consistent with what a typical market participant would assume.

11.5.2 Commodity price assumptions

Similar to a VIU calculation, commodity price is a key assumption in calculating the FVLCD of any mine or oil field when using a DCF model, and therefore similar issues as those discussed for a VIU calculation (see 11.4.3 above) apply. On the same basis, while the specific disclosure requirements relating to price assumptions in IAS 36 technically only apply in the context of impairment testing of CGUs to which goodwill and indefinite life intangible assets are allocated, because there can be considerable differences between entities in their estimates of future commodity prices, we recommend additional disclosures be provided. Regardless of the specific requirements of IAS 36, an entity is also required to consider the disclosure requirements relating to significant judgements or estimates and hence the requirements of IAS 1. [IAS 1.122, 125]. For example, an entity may wish to disclose the actual commodity prices used in calculating the FVLCD of any mine or oil field, as these would generally be considered a significant judgement or estimate and hence would require disclosure under IAS 1. [IAS 1.122, 125].

11.5.3 Future capital expenditure

There are no restrictions similar to those applicable to a VIU calculation when determining FVLCD provided that it can be demonstrated that a market participant would be willing to attribute some value to the future enhancement and that the requirements of IFRS 13 have been complied with. IFRS 13 is discussed in more detail in Chapter 14.

The treatment of future capital expenditure in an impairment test is discussed in more detail in Chapter 20 at 7.1.2.

11.5.4 Foreign currency cash flows

For FVLCD calculations, the requirements relating to foreign currency cash flows are not specified other than they must reflect what a market participant would use when valuing the asset or CGU. In practice, entities that use a DCF analysis when calculating FVLCD will incorporate a forecast for exchange rates into their calculations rather than using the spot rate. A key issue in any forecast is the assumed timeframe over which the exchange rate may return to lower levels. This assumption is generally best analysed in conjunction with commodity prices in order to ensure consistency in the parameters used, i.e. a rise in prices will usually be accompanied by a rise in currency.

12.1.1 Incidental revenue

During the construction of an asset, an entity may enter into incidental operations that are not, in themselves, necessary to bring the asset itself into the location and condition necessary for it to be capable of operating in the manner intended by management. The standard gives the example of income earned by using a building site as a car park prior to starting construction. An extractives example may be income earned from leasing out the land surrounding the mine site or an onshore gas field to a local farmer to run his sheep on. Because incidental operations such as these are not necessary to bring an item to the location and condition necessary for it to be capable of operating in the manner intended by management, the income and related expenses of incidental operations are recognised in profit or loss and included in their respective classifications of income and expense. [IAS 16.21]. Such incidental income is not offset against the cost of the asset.

12.1.2 Integral to development

The directly attributable costs of an item of property, plant and equipment include the costs of testing whether the asset is functioning properly, after deducting the net proceeds from selling any items produced while bringing the asset to that location and condition. [IAS 16.17(e)]. The standard gives the example of samples produced when testing equipment.

There are other situations in which income may be generated wholly and necessarily as a result of the process of bringing the asset to the location and condition for its intended use. The extractive industries are highly capital intensive and there are many instances where income may be generated prior to the commencement of production.

Some mining examples include:

• During the evaluation phase, i.e. when the technical feasibility and commercial viability are being determined, an entity may ‘trial mine’, to determine which development method would be the most profitable and efficient in the circumstances, and which metallurgical process is the most efficient. Ore mined through trial mining may be processed and sold during the evaluation phase.
• As part of the process of constructing a deep underground mine, the mining operation may extract some saleable ‘product’ during the construction of the mine e.g. sinking shafts to the depth where the main ore-bearing rock is located.
• At the other end of the spectrum, income may be earned from the sale of product from ‘ramping up’ the mine to production at commercial levels.

Some oil and gas examples include:

• Onshore wells are frequently placed on long-term production test as part of the process of appraisal and formulation of a field development plan. Test production may be sold during this time.

Some interpret IAS 16's requirement quite narrowly as only applying to income earned from actually ‘testing’ the asset, while others interpret it more broadly to include other types of pre-commissioning or production testing revenue.

We have noted in practice that some income may be generated wholly and necessarily as a result of activities that are part of the process of bringing the asset into the location and condition for its intended use, i.e. the activities are integral to the construction or development of the mine or field. Some consider that as IAS 16 makes it clear that income generated from incidental operations is to be taken to revenue, [IAS 16.21], but does not explicitly specify the treatment of integral revenue, it could be interpreted that income earned from activities that are integral to the development of the mine or field should be credited to the cost of the mine or field. This is because the main purpose of the activities is the development of the mine or field, not the production of ore or hydrocarbons. The income earned from production is an unintended benefit.

In our experience, practice in accounting for pre-commissioning or test production revenue varies. These various treatments have evolved as a result of the way in which the relatively limited guidance in IFRS has been interpreted and applied. In some instances, this has also been influenced by approaches that originated in previous and other GAAPs, where guidance was/is somewhat clearer.

The key challenge with this issue is usually not how to measure the revenue but how entities view this revenue and, more significantly, how to distinguish those costs that are directly attributable to developing the operating capability of the mine or field from those that represent the cost of producing saleable material. It can be extremely difficult to apportion these costs. Consequently, there is a risk of misstatement of gross profits if these amounts are recorded as revenue and the amount of costs included in profit or loss as cost of goods sold is too low or too high.

Other GAAPs have either previously provided or continue to provide further guidance that has influenced some of the approaches adopted under IFRS. For example, the now superseded Australian GAAP (AGAAP) standard on extractive industries¹⁰⁸ and the former OIAC SORP¹⁰⁹ provided more specific guidance. The former clearly required, and the latter recommended, that any proceeds earned from the sale of product obtained during the exploration, evaluation or development phases should be treated in the same manner as the proceeds from the sale of product in the production phase, i.e. recognised in profit or loss as part of income.

AGAAP required the estimated cost of producing the quantities concerned to be deducted from the accumulated costs of such activities and included as part of costs of goods sold.¹¹⁰ By contrast, the former OIAC SORP was more specific and stated that an amount equivalent to the revenues should be both charged to cost of sales and credited against appraisal costs to record a zero net margin on such production.¹¹¹

The various practices that are currently adopted and accepted include:

• all pre-commissioning/test production revenue is considered integral to the development of the mine or field and is therefore credited to the asset in its entirety;
• only revenue genuinely earned from the testing of assets, e.g. product processed as a result of testing the processing plant and associated facilities, is credited to the associated asset, with all other revenue being recognised in profit or loss; or
• all pre-commissioning or test production revenue is recognised in profit or loss.

For entities that recognise pre-commissioning or test production revenue in profit or loss, various approaches have been observed in practice to determine the amount to be included in cost of goods sold and include:

• an amount equivalent to the revenues is charged to cost of sales and credited against the asset to record a zero net margin on such production (similar to the guidance in the former OIAC SORP);
• a standard or expected cost of production is ascribed to the volumes produced, e.g. weighted average cost per tonne/barrel based on actual results over a historical period, e.g. the last two or three years; or for new mines or fields, the expected cost per tonne/bbl as set out in the business, mine or field plan, producing a standard margin;
• recognising only the incremental cost of processing the product; or
• recognising nothing in cost of goods sold.

The net effect of all of these approaches is that any excess of the total cost incurred over the amount recognised in profit or loss as cost of goods sold, is effectively capitalised as part of the asset. Note that the first approach, where cost of goods sold is recognised at the same amount as the revenue, produces the same net balance sheet and profit or loss result as if the revenue had been credited to the asset in its entirety.

While diverse treatments may have been adopted and accepted in practice to date, it is unlikely the third and fourth cost of goods sold approaches would be appropriate because they would not provide a fair reflection of the cost to produce the saleable product.

There is a significant degree of divergence as to how entities account for pre-commissioning revenue. Significant judgement will also be required to determine when the asset is in the location and condition to be capable of operating as intended by management, i.e. when it is ready for its intended use. In the absence of specific guidance this divergence will continue. However, capitalisation (including recognising income as a credit to the cost of the asset) is to cease when the asset is ready for its intended use, regardless of whether or not it is achieving its targeted levels of production or profitability, or even operating at all.

12.4.1 Accounting for imbalances in revenue under IFRS 15

Revenue from contracts with customers that falls within the scope of IFRS 15 should be treated according to the requirements of IFRS 15. Sales of product by a participant in a joint operation to external customers are within the scope of IFRS 15 and should be recognised when the sales actually occur i.e. when the entity satisfies its performance obligation by transferring a promised good or service (i.e. an asset) to a customer. An asset is transferred when (or as) the customer obtains control of that asset. [IFRS 15.31].

Transactions with other joint operation participants are unlikely to fall within the scope of IFRS 15 and, hence, may not form part of revenue from contracts with customers. [IFRS 15.5(d), 6]. This is consistent with paragraphs BC52-BC56 of IFRS 15, the March 2015 IFRIC agenda decision on IFRS 11 (‘Recognition of revenue by a joint venture’), and IFRS 11 which states that ‘A joint operator shall account for the assets, liabilities, revenues and expenses relating to its interest in a joint operation in accordance with the IFRSs applicable to the particular assets, liabilities, revenues and expenses’. [IFRS 11.21, IFRS 15.BC52-BC56].

This was confirmed in the IFRIC agenda decision issued in March 2019 (‘Sale of Output to an Operator’). The Committee concluded that ‘in the fact pattern described in the request, the joint operator recognises revenue that depicts only the transfer of output to its customers in each reporting period, i.e. revenue recognised applying IFRS 15. This means, for example, the joint operator does not recognise revenue for the output to which it is entitled but which it has not received from the joint operation and sold. The Committee concluded that the principles and requirements in IFRS Standards provide an adequate basis for a joint operator to determine its revenue from the sale of its share of output arising from a joint operation as described in the request. Consequently, the Committee decided not to add this matter to its standard-setting agenda’.¹¹⁴

Accordingly, where a participant in a joint operation has contractual arrangements with customers which do fall within the scope of IFRS 15, it should record revenue from those contracts under IFRS 15, that is, based on its actual sales to customers in that period. No adjustments should be recorded in revenue to account for any variance between the actual share of production volumes sold to date and the share of production which the party has been entitled to sell to date.

Revenue from contracts with customers recognised in accordance with IFRS 15 is a subset of total revenue recognised by an entity, and should be presented separately as required by IFRS 15. [IFRS 15.113(a)]. However, recording adjustments through other revenue in order to align total revenue earned (i.e. revenue from contracts with customers under IFRS 15 plus other revenue) with the share of production the joint operation participant is entitled to in the period, would not be appropriate. Recording the amounts earned in one period in other revenue and, subsequently, recording them as revenue under IFRS 15 in a future period (or vice versa), would result in recycling of revenue earned between two line items in profit or loss. Furthermore, in periods where the adjustment being recorded through other revenue is to reduce total revenue recognised in the period, this would result in a debit entry or ‘negative revenue’ being disclosed in other revenue, which is not appropriate.

12.4.2 Consideration of cost of goods sold where revenue is recognised in accordance with IFRS 15

If revenue is recognised based on actual sales to customers in the period, and costs are based on invoiced costs to the participants in a joint operation in proportion to their equity interest, there will be a mismatch between the proportion of revenue lifted and sold and the proportion of costs borne.

Entities may determine that is it appropriate to adjust production costs to align volumes for which production costs are recognised with volumes sold (for which revenue has been recognised in accordance with IFRS 15). The accounting for the adjustments to cost of goods sold will depend on whether the imbalances are settled between/among joint operation participants in cash or by physical settlement, as well as whether the joint operation is in an overlift or underlift position.

In the case of physical settlement, an overlift participant would recognise a liability for future expenses by way of future production costs that are not matched by corresponding future revenues. This overlift liability meets the definition of a provision under IAS 37, as the timing and amount of the settlement are uncertain. In applying IAS 37, the amount recognised as a provision should be ‘the best estimate of the expenditure required to settle the present obligation at the end of the reporting period’, [IAS 37.36], which is ‘the amount that an entity would rationally pay to settle the obligation at the end of the reporting period or to transfer it to a third party at that time’. [IAS 37.37].

The overlift liability is recorded at the market value or cost of the production imbalance, depending on whether the overlift liability is considered to represent: i) a provision for production costs attributable to the volumes sold in excess of currency entitlement (which would likely be recorded at cost); or, ii) an obligation for physical delivery of petroleum product (taken out of the entity's future entitlements) for which fair value measurement may be more appropriate.

Conversely, an underlift participant may recognise an underlift asset depending on whether the underlift participant considers they have: i) a right equivalent to a prepaid commodity purchase; or ii) a right to additional physical inventory, and therefore, applies IAS 2 by analogy. Consistent with IAS 2, an underlift asset would be measured at the lower of cost or net realisable value, [IAS 2.9], or otherwise at net realisable value, if there is a well-established industry practice. [IAS 2.3(a)].

If an overlift or underlift adjustment is recorded in cost of goods sold at fair value, this will result in the joint operator's gross margin reflecting the gross margin that would be earned based on its entitlement interest. If an adjustment were recorded through cost of goods sold at cost, the gross margin shown would reflect the gross margin attributed to the volumes actually sold to customers.

In some instances, not accounting for the effects of imbalances has been justified on the grounds that operating costs for the period should be expensed as incurred because they relate to the period's production activity and not to the revenues recognised.¹¹⁵

In the case of cash balancing, the underlift asset or overlift liability meets the definition of a financial asset or financial liability respectively, in accordance with IAS 32 and therefore, should be accounted for in accordance with IFRS 9. The initial recognition of that financial asset or financial liability would be at fair value. Depending on the designation of the financial asset or financial liability, subsequent measurement would be either at amortised cost or fair value.

Extract 43.21 below sets out BP's disclosure of its accounting for revenues relating to oil and natural gas properties in which the group has an interest with joint operation partners.

12.4.3 Facility imbalances

Imbalances that are similar to overlifts and underlifts can also arise on facilities such as pipelines when a venturer delivers more or less product into a pipeline than it takes out in the same period. The resulting accounting issues arising are similar to those concerning overlifts and underlifts.

12.6.1 Accounting by the producer

Generally, the accounting for these arrangements by the producer could be one of the following:

• a financial liability (i.e. debt) in accordance with IFRS 9. A key factor in determining whether the contract is a financial liability is whether the contract establishes an unavoidable contractual obligation for the producer to make payments in cash or another financial asset, [IAS 32.11, IAS 32.16(a)], that is, whether the arrangement has more of the characteristics of debt;
• a sale of a mineral interest (under IAS 16 or IAS 38) and a contract to provide services such as extraction, refining, etc., in accordance with IFRS 15. This would occur when the arrangement effectively transfers control over a portion of the mine from the producer to the investor and there is an obligation to provide future extraction services; or
• a commodity contract, which is outside the scope of IFRS 9 and in the scope of IFRS 15. This would only occur when the arrangement is an executory contract to deliver an expected amount of the commodity in the future to the investor from the producer's own operation (i.e. it meets the ‘own-use’ exemption). If the commodity contract does not meet the own-use exemption, the arrangement will be in scope of IFRS 9.

Whether the arrangement constitutes debt, a sale of mineral interest and a contract to provide services or a forward sale of a commodity, is subject to significant judgement.

In each classification, the producer must assess and determine whether the arrangement contains separable embedded derivatives. That is, the producer would need to determine whether the arrangement contains a component or terms which had the effect that some of the cash flows of the combined instrument (being the arrangement) vary in a similar way to a stand-alone derivative (i.e. an embedded derivative).

For both the producer and the investor, each arrangement will have very specific facts and circumstances that will need to be understood and assessed, as different accounting treatments may apply in different circumstances. Understanding the economic motivations and outcomes for both the producer and the investor and the substance of the arrangement are necessary to ensure a robust and balanced accounting conclusion can be reached. In many cases, the route to determining the classification will be a non-linear and iterative process.

The potential implications of IFRS 15 need to be considered for transactions which are considered to be either a sale of a mineral interest with a contract to provide services or a commodity contract.

12.6.2 Accounting by the investor

From the investor's perspective, where the accounting becomes more complex is where the investor has acquired a right to receive cash, some quantity or value of a particular commodity, or the option to choose one or the other, or some combination of both. From the investor's perspective, there are generally four common accounting outcomes that are frequently observed:

• acquisition of a mineral interest (under the principles of IAS 16 or IAS 38) and potentially a prepayment in relation to future services such as extraction, refining, etc., – this would occur when the arrangement effectively transfers control over a portion of the mine/field from the producer to the investor and there is a right to receive future extraction services;
• commodity contract, which is outside the scope of IFRS 9 and in the scope of IAS 38 – this would only occur when the arrangement is an executory contract to receive an expected amount of the commodity in the future from the producer and its meets the ‘own-use’ exemption for the investor. If the commodity contract does not meet the own-use exemption, the arrangement will be in scope of IFRS 9;
• a financial asset (i.e. a receivable or some sort of other financial asset) in accordance with IFRS 9 – this would occur when the arrangement establishes a contractual right to receive cash or another financial asset in the future; or
• a mix of all three.

The accounting implications of each for the investor, from a profit or loss perspective, can be significantly different.

12.8.1 Provisionally priced sales contracts

Sales contracts for certain commodities (e.g. copper and oil) often provide for provisional pricing at the time of shipment. The final sales price is often based on the average quoted market prices during a subsequent period (the ‘quotational period’ or ‘QP’), the price on a fixed date after delivery or the amount subsequently realised by another party (e.g. the smelter or refiner, net of tolling charges).

As discussed at 13.2.2 below these QP pricing exposures may meet the definition of an embedded derivative under IFRS 9. The treatment of embedded derivatives in commodity contracts is discussed in more detail at 12.8 above.

From a revenue recognition perspective, under IFRS 15, revenue will be recognised when control passes to the customer and will be measured at the amount to which the entity expects to be entitled, being the estimate of the price expected to be received at the end of the QP, i.e. the forward price. [IFRS 15.47].

If shipping is considered to be a separate performance obligation, some of the revenue may need to be allocated between the commodity and shipping services. See 12.12 below for further discussion.

With respect to the presentation of any fair value movements in the receivable from the date of sale, entities have often presented the QP movements as part of revenue. IFRS 15 does not address the presentation of fair value movements in receivables. Likewise, IFRS 9 does not specify where such movements should be presented in profit or loss.

IFRS 15 only addresses a subset of total revenue (i.e. revenue from contracts with customers). That is, transactions outside the scope of IFRS 15 might result in the recognition of revenue. However, while IFRS 15 does not specifically prohibit fair value movements of a receivable from being described as revenue, it does specifically require an entity to disclose revenue from contracts with customers separately from its other sources of revenue, either in the statement of comprehensive income or in the notes. [IFRS 15.113]. Therefore, entities will need to track these separately.

The extracts below set out the accounting policy for provisionally priced sales for Rio Tinto and Anglo American under IFRS 15.

12.9.1 Royalty arrangements with collaborative partners

As discussed at 12.5 above, IFRS 15 only addresses contracts with customers for goods or services provided in the ordinary course of an entity's business, it does not apply to arrangements between collaborative partners. [IFRS 15.6]. Where royalties are received by an entity as part of such an arrangement, they will generally not be in the scope of IFRS 15, unless the collaborator or partner meets the definition of a customer for some, or all, aspects of the arrangement. See 12.9.2 below.

12.9.2 Royalty arrangements with customers

IFRS 15 does not scope out revenue from the extraction of minerals. Therefore, regardless of the type of product being sold, if the counterparty to the contract is determined to be a customer, then the contract will be in scope of IFRS 15.

If a royalty arrangement is considered to be a supplier-customer relationship (and, hence, is in scope), mining companies and oil and gas companies may face a number of challenges in applying IFRS 15 to these arrangements. These may include identifying the performance obligations, determining the transaction price (e.g. if consideration is variable and dependent upon actions by the customer, which would be the case for the future extraction of minerals), applying the constraint on variable consideration, and reallocating the transaction price when and if there is a change in the transaction price. See Chapter 29 for more details on these requirements.

When considering the accounting for such royalties, IFRS 15 contains specific requirements that apply to licences of intellectual property, which may appear similar to some types of royalty arrangements in extractives industries. However, it is important to note that the IFRS 15 requirements only apply to licences of intellectual property and not all sales-based or usage-based royalties. So, the general requirements applicable to variable consideration, including those relating to the constraint, will need to be considered (see Chapter 29 at 2.2 for further discussion).

12.9.3 Royalty arrangements and the sale of non-financial items

If the royalty arrangement is not considered to relate to a contract with a customer nor to a collaborative arrangement, but instead, relates to the sale of a non-financial asset (e.g. an interest in a mining project or oil and gas project), IFRS 15 may still impact these arrangements. This is because the requirements for the recognition and measurement of a gain or loss on the transfer of some non-financial assets that are not the output of an entity's ordinary operations (e.g. property, plant and equipment in the scope of IAS 16), refer to the requirements of IFRS 15 (see Chapter 27 at 4.3 for more detail).

Specifically, an entity needs to:

• determine the date of disposal and, therefore, the date of derecognition (i.e. the date control transfers to the acquirer) (see Chapter 30 for more detail);
• measure the consideration to be included in the calculation of the gain or loss arising from disposal including any variable consideration requirements (see Chapter 29 at 2 for more detail); and
• recognise any subsequent changes to the estimated amount of consideration (see Chapter 29 at 2 for more detail).

Mineral rights and mineral reserves (and, hence, the associated capitalised costs) are outside the scope of both IAS 16 and IAS 38. However, in selecting an accounting policy for the disposal of these assets, in practice, most entities look to the principles of these two standards. Therefore, these requirements are likely to be applied by analogy to arrangements in which an entity sells all (or part) of its mining properties or oil and gas properties and some of the consideration comprises a royalty-based component.

There is also a lack of clarity as to how to apply the requirements of IFRS 15 to such arrangements where, by virtue of the royalty rights, the vendor is considered to have retained an interest in the mineral property. This may impact what is recognised or derecognised from the balance sheet in terms of mineral assets and/or financial assets, and also the gain/loss that is recognised in profit or loss.

There is more specific guidance on when the royalty receivable represents contingent consideration in the sale of a business (see Chapter 45 at 3.7.1.B).

12.11.1 Relationships with joint arrangement partners

It is not uncommon for valid vendor-customer relationships to exist alongside joint arrangement/collaborator contracts such as joint operating agreements or production sharing contracts. The manager/lead operator of a joint arrangement may have a vendor-customer contract to purchase volumes produced by the non-operating parties. The manager/lead operator would then on sell the product to third parties, and depending on the specific contract terms, could be acting as the principal in the onward sale, or as agent that is selling on behalf of the other joint arrangement partners.

Similarly, an entity with a gathering station or processing plant could purchase commodities from other parties with tenements or fields in the same region at the point of entry into the plant. Both the seller and purchaser would have to consider whether the purchaser is a principal or an agent in the onward sale to the third-party customer and account for the revenue accordingly.

12.11.2 Royalty payments

As discussed at 5.7.5 above, mining companies and oil and gas companies frequently enter into a range of different royalty arrangements with owners of mineral rights (e.g. governments or private land owners) and at times, the treatment is diverse. It is unclear whether, and how, such arrangements should be accounted for under IFRS 15.

In situations where the royalty holder retains or obtains a direct interest in the underlying production, it may be that the relationship between the mining company or oil and gas company and the royalty holder is more like a collaborative arrangement (and, hence, is not within the scope of IFRS 15). See 12.5 above for further discussion.

If these royalty payments are in scope, the requirements relating to principal versus agent in IFRS 15 will be helpful in assessing how these royalty payments should be presented. Specifically, an entity will need to determine whether it obtains control of all of the underlying minerals once extracted, sells the product to its customers and then remits the proceeds to the royalty holder. If so, the mining company or oil and gas company will be considered to be acting as the principal and, hence, would recognise the full amount as revenue with any payments to the royalty holder being recognised as part of cost of goods sold (or possibly as an income tax, depending on the nature of the royalty payment – see 21 below for further discussion on determining when an arrangement is an income tax). Where the entity does not obtain control over those volumes, it may be acting as the royalty holder's agent and extracting the minerals on its behalf.

The principal versus agent assessment under IFRS 15 is discussed in more detail in Chapter 28 at 3.4 and the issue of how sales (and other similar) taxes should be accounted for are discussed in Chapter 29 at 2.1.

12.12.1 Identification of performance obligations

Subsequent to the issuance of IFRS 15, there was some debate as to whether shipping represented a separate performance obligation. The issue was raised with the joint Transition Resources Group (TRG) and was also considered by the IASB and US FASB. The US FASB amended their standard to allow US GAAP entities to elect to account for shipping and handling activities performed after the control of a good has been transferred to the customer as a fulfilment cost (i.e. an expense). Without such an accounting policy choice, a US GAAP entity that has shipping arrangements after the customer has obtained control may determine that the act of shipping is a performance obligation under the standard. The IASB did not permit a similar policy choice under IFRS 15.

Given this, when assessing customer contracts, mining companies and oil and gas companies need to consider the requirements of IFRS 15 to determine whether shipping is a separate performance obligation. It is likely that any shipping services provided to a customer after the customer obtains control over a good will represent a separate performance obligation. If this is the case, the transaction price for that contract will need to be allocated to the various performance obligations including shipping. Revenue will then be recognised when the goods are delivered and when the shipping services have been provided, either at a point in time or over time.

The extracts below illustrate how Rio Tinto and Anglo American have identified shipping services in certain types of arrangements to be separate performance obligations.

12.12.2 Satisfaction of performance obligations – control assessment

Under IFRS 15, an entity recognises revenue only when it satisfies a performance obligation by transferring control of a promised good or service to the customer and control may be transferred over time or at a point in time. See Chapter 30 for more information.

When assessing contracts with customers, mining companies and oil and gas companies need to carefully examine the terms of their contracts, including shipping terms, in light of the indicators of control, to assess how shipping should be accounted for.

It is also worth noting that there may be some shipping arrangements where title to the goods must pass to the carrier during transportation, but the related contract includes a clause that requires the carrier to sell the goods back to the mining company or oil and gas company at the same or another specified price. The impact of repurchase clauses is discussed at 12.14 below.

The extract below illustrates how Anglo American recognises revenue from shipping services over time.

12.15.1 Identify the contract

Judgement will need to be applied when identifying the contract for these long-term arrangements. A contract is an agreement between two or more parties that creates enforceable rights and obligations. [IFRS 15 Appendix A]. Entities will need to determine what the enforceable part of the contract is. For example, whether there is a specified minimum the customer must buy (e.g. in take-or-pay contracts – see 12.16 below), whether it is the overall agreement, sometimes referred to as the master services agreement, or whether it is each purchase order. See Chapter 28 at 2 and 2.1 for more details.

12.15.2 Identify the performance obligations

The next step is to identify all the promised goods or services within the contract to determine which will be treated as separate performance obligations. Chapter 28 at 3 explores in detail the requirements for determining whether a good or service is distinct, whether the transfer of a good or service represents a separate performance obligation and/or whether (and when) they need to be bundled.

During the development of IFRS 15, some respondents thought it was unclear whether a three-year service or supply contract would be accounted for as a single performance obligation or a number of performance obligations covering smaller time periods (e.g. yearly, quarterly, monthly, daily) or individual units such as ounces, tonnes or barrels.

IFRS 15 clarifies that even if a good or service is determined to be distinct, if that good or service is part of a series of goods and services that are substantially the same and have the same pattern of transfer, that series of goods or services is treated as a single performance obligation. However, before such a treatment can be applied, specific criteria must be met. See Chapter 28 at 3.2 for further discussion and guidance.

Given the nature of these multi-period commodity-based sales arrangements, each unit (e.g. each metric tonne (mt) of coal or each barrel of oil), would likely be a distinct good and therefore, each unit would represent a separate performance obligation that is satisfied at a point in time. Because such goods are satisfied at a point in time, they would not meet the criteria to be considered a series of distinct goods that would have to be treated as a single performance obligation.

In addition, any option for additional goods or services will need to be evaluated to determine if those goods or services should be considered a separate performance obligation. See Chapter 28 at 3.6 for further discussion.

The extract below illustrates Rio Tinto's policy for identifying performance obligations in commodity sales contracts.

The extract below illustrates Equinor's policy for identifying performance obligations, and, whether they are recognised at a point in time or over time.

12.15.3 Determine the transaction price

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 (e.g. some sales taxes). When determining the transaction price, an entity should consider the effects of all of the following:

• variable consideration (including any related constraint);
• a significant financing component (i.e. the time value of money);
• non-cash consideration; and
• consideration payable to a customer.

In many cases, the transaction price is readily determinable because the entity will receive payment at or near the same time as it transfers the promised good or service and the price is fixed for the minimum committed purchases. However, determining the transaction price may be more challenging when it is variable in amount, when payment is received at a time that is different from when the entity provides the goods or services and the effect of the time value of money is significant to the contract, or when payment is in a form other than cash. See Chapter 29 at 2 for more information.

For a fixed price contract, this step will be relatively straightforward. For variable price contracts, determining the transaction price may appear to be significantly more complex than for a fixed price contract. Many commodity sales contracts contain market-based or index-based pricing terms that create variable consideration. After separating out any parts of the transaction price that are within the scope of another standard (e.g. IFRS 9 – see 12.8 above), an entity will need determine whether it should partially or fully constrain the portion of the variable transaction price. Chapter 29 at 2.2 discusses variable consideration and, in particular, the requirements relating to the constraint.

12.15.4 Allocate the transaction price

The next step is to allocate the transaction price to the performance obligations, generally in proportion to their stand-alone selling prices (i.e. on a relative stand-alone selling price basis), with two exceptions relating to the allocation of variable consideration and discounts. See Chapter 29 at 3 for detail. With commodity-based sales contracts, there are a number of things to consider depending on whether the transaction price is variable (or contains a variable component), fixed and/or whether there is a discount. Some factors to consider with variable and fixed consideration are discussed below, while the allocation of a discount is discussed in Chapter 29 at 3.4.

12.15.5 Recognise revenue

Finally, an entity will recognise revenue once each performance obligation is satisfied which will occur when control of the good transfers to the customer. As discussed earlier, for long-term commodity-based sales arrangement, the performance obligations are likely to be satisfied at a point in time. See Chapter 30 for more information on how to determine when a performance obligation is satisfied. The precise timing of when control transfers to a customer may be impacted by the shipping terms associated with each contract. See 12.12 above and Chapter 30 at 4 for further discussion on shipping.

The extract below illustrates Rio Tinto's policy for determining when control of its commodity sales passes.

12.16.1 Volumes paid for, but not taken

A feature unique to take-or-pay contracts is the terms relating to payments made for volumes not taken, as explained further at 19.2.1 below. The requirements of IFRS 15 may result in different accounting considerations and possibly different conclusions depending on the specific facts and circumstances of each arrangement.

12.16.2 Breakage (customers’ unexercised rights)

The standard requires that when an entity receives consideration that is attributable to a customer's unexercised rights, the entity is to recognise a contract liability equal to the amount prepaid by the customer (because the entity has not yet satisfied the performance obligations to which the payment relates). However, IFRS 15 discusses the situation where, in certain industries, customers may pay for goods or services in advance, but may not ultimately exercise all of their rights to these goods or services – either because they choose not to or are unable to. IFRS 15 refers to these unexercised rights as ‘breakage’. [IFRS 15.B44‑47].

IFRS 15 states that when an entity expects to be entitled to a breakage amount, the expected breakage will be recognised as revenue in proportion to the pattern of rights exercised by the customer. Otherwise, breakage amounts will only be recognised when the likelihood of the customer exercising its right becomes remote. See Chapter 30 at 11 for more information.

This may apply to take-or-pay contracts, for which payments are received in relation to make-up volumes and the customer's rights remain unexercised. Such breakage provisions may be applicable if:

• a customer is unable to use the make-up volumes in other areas of its own operations;
• a customer is unable to store the make-up volumes and use them after the take-or-pay contract has expired;
• a customer is unable to take delivery of the make-up volumes and sell them into the market; or
• there are limitations (physical or contractual) that prevent the customer from taking all of the make-up volumes.

For take-or-pay contracts, this may mean that an entity may be able to recognise revenue in relation to breakage amounts in an earlier period, provided it can demonstrate it is not required to constrain its estimate of breakage. This could potentially occur in the following ways:

• At contract inception, the mining entity or oil and gas entity may be able to reliably estimate the amount of breakage and would include that amount in the transaction price and allocate that to expected actual usage.
• If the entity cannot estimate an amount of breakage, it will recognise the revenue associated with those unexercised rights when it becomes remote that they will be exercised. This could occur during a make-up period after the initial term of the contract or when the deficiency make-up period expires outright (which would be consistent with current accounting).

It is also possible that, given the nature of these arrangements and the inherent uncertainty in being able to predict a customer's behaviour, it may be difficult to satisfy the requirements relating to constraint because the entity's experience may not be predictive of the outcome at this level of certainty (i.e. highly probable).

13.2.1 Foreign currency embedded derivatives

The most common embedded derivatives in the extractive industries are probably foreign currency embedded derivatives which arise when a producer of minerals sells these in a currency that is not the functional currency of any substantial party to the contract, the currency in which the price of the related commodity is routinely denominated in commercial transactions around the world or a currency that is commonly used in contracts to purchase or sell non-financial items in the economic environment in which the transaction takes place. [IFRS 9.B4.3.8(d)]. A more detailed analysis of these requirements can be found in Chapter 46 at 5.2.1.

13.2.2 Provisionally priced sales contracts

As discussed above at 12.8.1, sales contracts for certain commodities (e.g. copper and oil) often provide for provisional pricing at the time of shipment, with final pricing based on the average market price for a particular future period, i.e. the ‘quotational period’.

If the contract is cancellable without penalty before delivery, the price adjustment feature does not meet the definition of a derivative because there is no contractual obligation until delivery takes place.

If the contract is non-cancellable, the price adjustment feature is considered to be an embedded derivative. The non-financial contract for the sale or purchase of the product, e.g. copper or oil, at a future date would be treated as the host contract.

For non–cancellable contracts, there will be a contractual obligation, but until control passes to the customer, the embedded derivative would be considered to be closely related to the non-financial host commodity contract and does not need to be recorded separately.

As discussed at 12.8.1 above, revenue is recognised when control passes to the customer. At this point, the non-financial host commodity contract is considered to be satisfied and a corresponding receivable is recognised. However, the receivable is still exposed to the price adjustment feature. As discussed at 12.8 above, under IFRS 9, embedded derivatives are not separated from financial assets, i.e. from the receivable. Instead, the receivable will need to be measured at fair value through profit or loss in its entirety. See Chapter 48 at 2 for more information on the classification of financial assets.

13.2.3 Long-term supply contracts

Long-term supply contracts sometimes contain embedded derivatives because of a desire to shift certain risks between contracting parties or as a consequence of existing market practices. The fair value of embedded derivatives in long-term supply contracts can be highly material to the entities involved. For example, in the mining sector electricity purchase contracts sometimes contain price conditions based on the commodity that is being sold, which provides an economic hedge for the mining company. While the electricity price component (if fixed) would meet the definition of an embedded derivative, it would be considered closely related to the host contract and hence would not have to be separated. However, the linkage to the commodity price would be unlikely to be considered closely related and would likely have to be separately accounted for as an embedded derivative. In the oil and gas sector the sales price of gas is at times based on that of electricity, which provides an economic hedge for the utility company that purchases the gas, and would also likely represent an embedded derivative that has to be separately accounted for. See Chapter 46 at 5.2.2 for further discussion.

As can be seen in the following extract from BHP Billiton's 2007 financial statements, the pricing terms of embedded derivatives in purchase (sales) contracts often match those of the product that the entity sells (purchases). (Note that while this disclosure is historical, it remains valid under IFRS 9).

13.2.4 Development of gas markets

Where there is no active local market in gas, market participants often enter into long-term contracts that are priced on the basis of a basket of underlying factors, such as oil prices, electricity prices and inflation indices. In the absence of an active market in gas, such price clauses are not considered to give rise to embedded derivatives because there is no accepted benchmark price for gas that could have been used instead.

An entity that applies IFRS 9 is required to assess whether an embedded derivative is required to be separated from the host contract (provided that host contract is not a financial asset (see 12.8 above for more information)) and accounted for as a derivative when the entity first becomes a party to the contract. [IFRS 9.B4.3.11]. Subsequent reassessment of embedded derivatives under IFRS 9 is generally prohibited. [IFRS 9.B4.3.11]. See Chapter 46 at 7 for more information. Therefore, in the case of gas, when an active market subsequently develops, an entity is not permitted to separate embedded derivatives from existing gas contracts, unless there is a change in the terms of the contract that significantly modifies the cash flows that otherwise would be required under the contract. However, if the entity enters into a new gas contract with exactly the same terms and conditions, it would be required to separate embedded derivatives from the new gas contract.

Judgement is required in determining whether there is an active market in a particular geographic region and the relevant geographic market for any type of commodity. Where no active market exists consideration should be given to the industry practice for pricing such commodity-based contracts. A pricing methodology that is consistent with industry practice would generally not be considered to contain embedded derivatives.

The extract below from BP shows the company's previous approach to embedded derivatives before and after the development of an active gas trading market in the UK, and demonstrates that the fair value of embedded derivatives in long-term gas contracts can be quite significant. (Note also that while this disclosure is historical, it remains valid under IFRS 9).

14.2.1 By-products

A by-product is a secondary product obtained during the course of production or processing, having relatively small importance when compared with the principal product or products.

IAS 2 prescribes the following accounting for by-products:

• ‘…When the costs of conversion of each product are not separately identifiable, they are allocated between the products on a rational and consistent basis. The allocation may be based, for example, on the relative sales value of each product either at the stage in the production process when the products become separately identifiable, or at the completion of production. Most by-products, by their nature, are immaterial. When this is the case, they are often measured at net realisable value and this value is deducted from the cost of the main product. As a result, the carrying amount of the main product is not materially different from its cost.’ [IAS 2.14].

By-products that are significant in value should be accounted for as joint products as discussed at 14.2.2 below. However, there are some entities that treat such by-product sales as a negative cost, i.e. by crediting these against cost of goods sold of the main product. This treatment would likely only be acceptable on the basis of materiality. It is important to note that the negative cost approach discussed in IAS 2, [IAS 2.14], only relates to the allocation of the costs of conversion between the main product and by-product and does not allow the revenue from a sale of by-products as a reduction of cost of goods sold (even if the sales are not significant).

If an entity determines the sale of by-products or scrap materials is in the course of its ordinary activities (even if they are not significant), the entity would recognise those sales as revenue from contracts with customers under IFRS 15. If an entity determines that such sales are not in its ordinary course of business, the entity would recognise those sales as either other income or other revenues (i.e. separate from revenue from contracts with customers) because they represent sales to non-customers.

Extracts 43.37 and 43.38 below illustrates how Rio Tinto and Anglo American respectively account for their by-product revenue under IFRS 15.

Although IAS 2 does not require extensive disclosures in respect of by-products, if amounts are material, disclosure of the following information, which many extractives companies provide on a voluntary basis, will greatly assist users:

• accounting policies applied to by-products;
• line items in the primary financial statements in which revenues and carried amounts have been disclosed;
• quantities of by-products sold; and
• average prices of by-products sold.

14.2.2 Joint products

Joint products are two or more products produced simultaneously from a common raw material source, with each product having a significant relative sales value. One joint product cannot be produced without the other and the products cannot be identified separately until a certain production stage, often called the ‘split-off point’, is reached. Joint products are very common in both the oil and gas sector (e.g. crude oil when run through a refinery produces a variety of products) and the mining sector.

Joint products, by definition, are all significant in value and require that an entity allocate on a rational and consistent basis the costs of conversion that are not separately identifiable for each product. The IASC Issues Paper outlined two approaches that have found acceptance in practice:¹¹⁸

1. allocation on the basis of physical characteristics – In the oil and gas sector, entities often combine quantities of oil and gas based on their relative energy content (i.e. 6,000 cubic feet of gas is roughly equal in energy to one barrel of oil). This method, however, does not take account of the fact that, for example, gas is cheaper per unit of energy than oil because the latter is more difficult to transport; and
2. allocation on the basis of relative values – This approach is more common in the mining sector where often it is not possible to identify a relevant physical characteristic that can be used to combine quantities of different products. The drawback of this method is that it results in very similar profit margins for each of the joint products, which may not be reflective of the underlying economic reality (i.e. one of the joint products, if mined in isolation, might have a completely different profit margin).

Although it should be kept in mind that neither method is perfect, both approaches are currently permitted under IFRS. It is true also that whichever method is selected, it is unlikely to have a material effect on reported profit overall. The extract below illustrates the application of approach (b) by Anglo American.

15.4.1 Unitisations

A unitisation arrangement is ‘an agreement between two parties each of which owns an interest in one or more mineral properties in an area to cross-assign to one another a share of the interest in the mineral properties that each owns in the area; from that point forward they share, as agreed, in further costs and revenues related to the properties’.¹²⁰ The parties pool their individual interests in return for an interest in the overall unit, which is then operated jointly to increase efficiency.¹²¹ Once an area is subject to an unitisation arrangement, the parties share costs and production in accordance with their percentages established under the unitisation agreement. The unitisation agreement does not affect costs and production associated with non-unitised areas within the original licences, which continue to fall to the original licensees.¹²²

IFRS does not specifically address accounting for a unitisation arrangement. Therefore, the accounting for such an arrangement depends on the type of asset that is subject to the arrangement. If the assets subject to the arrangement were E&E assets, then the transaction would fall within the scope of IFRS 6, which provides a temporary exemption from IAS 8 (see 3.2.1 above). An entity would be permitted to develop an accounting policy for unitisation arrangements involving E&E assets that is not based on IFRS. However, unitisations are unlikely to occur in the E&E phase when technical feasibility and commercial viability of extracting a mineral resource are not yet demonstrable.

For unitisations that occur outside the E&E phase, as there is no specific guidance in IFRS, an entity will need to develop an accounting policy in accordance with the IAS 8 hierarchy. The first step in developing an accounting policy for unitisations is setting criteria for determining which assets are included within the transaction. Particularly important is the assessment as to whether the unitisation includes the mineral reserves themselves or not. The main reason for not including the mineral reserves derives from the fact that they are subject to redetermination (see 15.4.2 below).

The example below, which is taken from the IASC's Issues Paper, illustrates how a unitisation transaction might work in practice.

Although the reserves are unitised in the physical sense (i.e. each party will end up selling oil or gas that physically came out of the reserves of the other party), in volume terms the parties remain entitled to a quantity of reserves that is equal to that which they contributed. However, the timing of production and the costs to produce the reserves may be impacted by the unitisation agreement. The example below explains this in more detail.

To the extent that the unitisation of the mineral reserves themselves lacks commercial substance (see 6.3.2 above), it may be appropriate to exclude the mineral reserves in accounting for an unitisation. Where the unitisation significantly affects the risk and timing of the cash flows or the type of product (e.g. an unitisation could lead to an exchange of, say, gas reserves for oil reserves) there is likely to be substance to the unitisation of the reserves.

If the assets subject to the unitisation arrangement are not E&E assets, or not only E&E assets, then it is necessary to develop an accounting policy in accordance with the requirements of IAS 8. Unitisation arrangements generally give rise to joint control over the underlying assets or entities:

1. if the unitisation arrangement results in joint control over a joint venture then the parties should apply IFRS 11 (see Chapter 12) and IAS 28 (see Chapter 11) and provide the relevant disclosures in accordance with the requirements contained in IFRS 12 (see Chapter 13); or
2. if the unitisation arrangement gives rise to a joint operation or results in a swap of assets that are not jointly controlled, then each of the parties should account for the arrangement as an asset swap (see 6.3 above).

Under both (a) and (b) above, a party to an unitisation agreement would report a gain (or loss) depending on whether the fair value of the interest received is higher (or lower) than the carrying amount of the interest given up.

15.4.2 Redeterminations

The percentage interests in an unitisation arrangement are based on estimates of the relative quantities of reserves contributed by each of the parties. As field life progresses and production experience is gained, many unitisation agreements require the reserves to be redetermined, which often leads the parties to conclude that the recoverable reserves in one or perhaps both of the original properties are not as previously estimated. Unitisation agreements typically require one or more ‘redeterminations’ of percentage interests once better reservoir information becomes available. In most cases, the revised percentage interests are deemed to be effective from the date of the original unitisation agreement, which means that adjustments are required between the parties in respect of their relative entitlements to cumulative production and their shares of cumulative costs.¹²⁴

Unitisation agreements normally set out when redeterminations need to take place and the way in which adjustments to the percentage interests should be effected. The former OIAC SORP described the process as follows:

1. ‘(a) Adjustments in respect of cumulative “capital” costs are usually made immediately following the redetermination by means of a lump sum reimbursement, sometimes including an “interest” or uplift element to reflect related financing costs.
2. (b) Adjustments to shares of cumulative production are generally effected prospectively. Participants with an increased share are entitled to additional “make-up” production until the cumulative liftings are rebalanced. During this period adjusted percentage interests are applied to both production entitlement and operating costs. Once equity is achieved the effective percentage interests revert to those established by the redetermination.’¹²⁵

An adjustment to an entity's percentage interest due to a redetermination is not a prior period error under IFRS. [IAS 8.5]. Instead, the redetermination results from new information or new developments and therefore should be treated as a change in an accounting estimate. Accordingly, a redetermination should not result in a fully retrospective adjustment.

Redeterminations give rise to some further accounting issues which are discussed below.

15.5.1 Scope of IFRIC 20

Generally, those costs incurred in the development phase of a mine would be capitalised as part of the depreciable cost of building, developing and constructing the mine, under the principles of IAS 16. Ultimately, these capitalised costs are depreciated or amortised on a systematic basis, usually by using the units of production method, once production commences. The stripping costs incurred in the development phase of a mine are not considered by IFRIC 20.

Instead, the interpretation applies to all waste removal (stripping) costs incurred during the production phase of a surface mine (production stripping costs). [IFRIC 20.2]. It does not apply to oil and natural gas extraction and underground mining activities. Also, it does not address the question of whether oil sands extraction is considered to be a surface mining activity and therefore whether it is in scope or not. [IFRIC 20.BC4].

Despite the importance of the term ‘production phase’, this is not defined in the Interpretation, or elsewhere in IFRS. The determination of the commencement of the production phase not only affects stripping costs, but also affects many other accounting issues in the extractive industries, described in more detail below. These include the cessation of the capitalisation of other costs, including borrowing costs, the commencement of depreciation or amortisation (see 16 below), and the treatment of certain pre-production revenues (see 12.1 above).

Stripping activity undertaken during the production phase may create two benefits (1) the extraction of ore (inventory) in the current period and (2) improved access to the ore body to be mined in a future period. Where the benefits are realised in the form of inventory produced, the production stripping costs are to be accounted for in accordance with IAS 2. Where the benefits are improved access to ore to be mined in the future, these costs are to be recognised as a non-current asset, if the required criteria are met (see 15.5.2 below). The Interpretation refers to this non-current asset as the ‘stripping activity asset’. [IFRIC 20.8].

15.5.2 Recognition criteria – stripping activity asset

IFRIC 20 states that an entity must recognise a stripping activity asset if, and only if, all of the following criteria are satisfied:

1. it is probable that the future economic benefit (improved access to the ore body) associated with the stripping activity will flow to the entity;
2. the entity can identify the component of the ore body for which access has been improved; and
3. the costs relating to the stripping activity associated with that component can be measured reliably. [IFRIC 20.9].

Instead of being a separate asset, the stripping activity asset is to be accounted for as an addition to, or as an enhancement of, an existing asset. This means that the stripping activity asset will be accounted for as part of an existing asset. [IFRIC 20.10]. IFRIC 20 does not specify whether the stripping activity asset is a tangible or intangible asset. Instead, it simply states that it should be classified as tangible or intangible according to the nature of the existing asset of which it is part – so it will depend upon whether an entity classifies its mine assets as tangible or intangible.

The Interpretation considers that the stripping activity asset might add to or improve a variety of existing assets, such as, the mine property (land), the mineral deposit itself, an intangible right to extract the ore or an asset that originated in the mine development phase. [IFRIC 20.BC10]. In most instances, entities classify their producing mine assets as tangible assets; therefore, it is likely that the stripping activity assets will also be classified as tangible assets.

15.5.3 Initial recognition

The stripping activity asset is to be initially measured at cost. This will be the accumulation of costs directly incurred to perform the stripping activity that benefits the identified component of ore, plus an allocation of directly attributable overhead costs. [IFRIC 20.12]. Examples of the types of costs expected to be included as directly attributable overhead costs are items such as salary costs of the mine supervisor overseeing that component of the mine, and an allocation of rental costs of any equipment hired specifically to perform the stripping activity. [IFRIC 20.BC12].

Some incidental operations may take place at the same time as the production stripping activity that are not necessary for the production stripping activity to continue as planned. The costs associated with these incidental operations are not to be included in the cost of the stripping activity asset. [IFRIC 20.12]. An example provided in the Interpretation is the building of an access ramp in the area in which the production stripping activity is taking place. These ancillary costs must be recognised as assets or expensed in accordance with other IFRSs.

15.5.4 Subsequent measurement

After initial recognition, the stripping activity asset must be carried at its cost or revalued amount less depreciation or amortisation and less impairment losses, in the same way as the existing asset of which it is a part. [IFRIC 20.14]. The stripping activity asset is to be depreciated or amortised on a systematic basis, over the expected useful life of the identified component of the ore body that becomes more accessible as a result of the stripping activity. [IFRIC 20.15].

The units of production method is effectively required to be applied unless another method is more appropriate. [IFRIC 20.15]. The expected useful life of the identified component that is used to depreciate or amortise the stripping activity asset will differ from the expected useful life that is used to depreciate or amortise the mine itself and the related life-of-mine assets, unless the stripping activity provides improved access to the whole of the ore body (this is expected to be rare). [IFRIC 20.16].

Consistent with the units of production method used for other mining assets, the calculation of the units of production rate will be completed when a stripping activity asset is first recognised. It will then need to be reviewed (and if necessary, updated) at the end of each reporting period, or when the mine plan changes. The new units of production rate will be applied prospectively.

Given the depreciation or amortisation of the stripping activity asset represents the consumption of the benefits associated with the stripping activity asset, and those benefits are realised by the extraction of the ore to which the stripping activity asset relates (i.e. the ore for which access was improved by the removal of this waste in prior periods), this depreciation or amortisation effectively represents part of the cost of extracting that ore in future periods. In accordance with IAS 2, such costs should be included in the cost of that subsequent ore. This effectively means that the depreciation or amortisation of the stripping activity asset should be recapitalised as part of the cost of the inventory produced in those subsequent periods. Once the inventory is sold, those costs will be recognised in profit or loss as part of cost of goods sold.

15.5.5 Disclosures

IFRIC 20 has no specific disclosure requirements. However, the general disclosure requirements of IAS 1 are relevant, e.g. the requirements to disclose significant accounting policies, [IAS 1.117], and significant judgements, estimates and assumptions. [IAS 1.125]. For many entities, it is likely that the accounting policy for stripping costs would be considered a significant accounting policy which would therefore warrant disclosure, as would the judgements, estimates and assumptions they make when applying this policy.

The extract below from Rio Tinto illustrates an IFRIC 20 accounting policy disclosure.

16.1.1 Mineral reserves

In the absence of a standard or an interpretation specifically applicable to mineral reserves and their related expenditures, which are technically outside the scope of IAS 16 and IAS 38, management needs to develop an accounting policy for the depreciation or amortisation of mineral reserves in accordance with the hierarchy in IAS 8, taking into account the requirements and guidance in Standards and Interpretations dealing with similar and related issues and the definitions, recognition criteria and measurement concepts for assets, liabilities, income and expenses in the Conceptual Framework. [IAS 8.11]. In practice, an entity will generally develop an accounting policy that is based on the depreciation and amortisation principles in IAS 16 and IAS 38, which deal with similar and related issues.

16.1.2 Assets depreciated using the straight-line method

The straight-line method of depreciation is generally preferred in accounting for the depreciation of property, plant and equipment. The main practical advantages of the straight-line method are considered to be its simplicity and the fact that its results are often not materially different from the units of production method if annual production is relatively constant.¹²⁶ In general, the straight-line method is considered to be preferable for:

• assets whose loss in value is more closely linked to the passage of time than to the quantities of minerals produced (e.g. front-end loaders that are used in stripping overburden and production of minerals);
• assets that are unrelated to production and that are separable from the field or mine (e.g. office buildings);
• assets with a useful life that is either much longer (e.g. offshore platforms) or much shorter (e.g. drill jumbos) than that of the field or mine in which they are used;
• assets used in fields or mines whose annual production is relatively constant. However, if assets are used in fields or mines that are expected to suffer extended outages, due to weather conditions or periodic repairs and maintenance, then the straight-line method may be less appropriate; and
• assets that are used in more than one field or mine (e.g. service trucks).

If the production of a field or mine drops significantly towards the end of its productive life, then the straight-line method may result in a relatively high depreciation charge per unit of production in these latter years. In those cases, an entity may need to perform an impairment test on the assets involved.

The extract below indicates the assets to which BHP applies the straight-line method.

16.1.3 Assets depreciated using the units of production method

When it comes to assets relating to mineral reserves, the units of production method is the most common method applied. ‘The underlying principle of the units of production method is that capitalised costs associated with a cost centre are incurred to find and develop the commercially producible reserves in that cost centre, so that each unit produced from the centre is assigned an equal amount of cost.’¹²⁷ The units of production method thereby effectively allocates an equal amount of depreciation to each unit produced, rather than an equal amount to each year as under the straight-line method.

When the level of production varies considerably over the life of a project (e.g. the production of oil fields is much higher in the periods just after the start of production than in the final periods of production), depreciation based on a units of production method will produce a more equal cost per unit from year to year than straight-line methods. Under the straight-line method the depreciation charge per unit in the early years of production could be much less than the depreciation per unit in later years. ‘That factor, coupled with the fact that typically production costs per unit increase in later years, means that the profitability of operations would be distorted if the straight-line method is used, showing larger profits in early years and lower profits in later years of the mineral resource's life. The higher cost per unit in later years is, in part, due to fewer units being produced while many production costs remain fixed and, in part, a result of many variable costs per unit increasing over time because reserves may be harder to extract, there may be greater equipment repairs, and similar other factors.’¹²⁸ Nevertheless, even under the units of production method, profitability often drops significantly towards the end of the productive life of a field or mine. When this happens an entity will need to carry out an impairment test and may need to recognise an impairment charge (see 11 above).

In general, the units of production method is considered to be preferable for:

• assets used in fields or mines whose annual production may vary considerably over their useful economic life;
• assets whose loss in value is more closely linked to the quantities of minerals produced than to the passage of time (e.g. draglines used in the extraction of mineral ore);
• assets that are used in production or that are inseparable from the field or mine (e.g. wells and well heads);
• assets with a useful life that is the same as that of the field or mine in which they are used; and
• assets that are used in only one field or mine (e.g. overland conveyor belts).

Extract 43.49 above and Extract 43.50 below indicate the classes of asset to which BHP and Lonmin, respectively, apply the units of production method.

The practical application of the units of production method gives rise to the following issues that require entities to exercise a considerable degree of judgement in determining the:

1. units of production formula (see 16.1.3.A below);
2. reserves base (see 16.1.3.B below);
3. unit of measure (see 16.1.3.C below); and
4. joint and by-products (see 16.1.3.D below).

As discussed at 16.1.3.B below, the asset base that is subject to depreciation should be consistent with the reserves base that is used, which may require an entity to exclude certain costs from (or include future investments in) the depreciation pool.

16.1.3.A Units of production formula

There are a number of different ways in which an entity could calculate a depreciation charge under the units of production method. The most obvious of these is probably the following formula:

The reserves estimate used in the above formula is the best estimate of the reserves at the beginning of the period, but by the end of the period a revised and more accurate estimate is often available. Therefore, it may be considered that in order to take into account the most recent information, the opening reserves should be calculated by adding the ‘closing reserves estimated at the end of the period’ to the ‘current period's production’. However, reserves estimates might change for a number of reasons:

1. more detailed knowledge about existing reserves (e.g. detailed engineering studies or drilling of additional wells which occurred after the commencement of the period);
2. new events that affect the physical quantity of reserves (e.g. major fire in a mine); and
3. changes in economic assumptions (e.g. higher commodity prices).

It is generally not appropriate to take account of these events retrospectively. For example, changes in reserves estimates that result from events that took place after the end of the reporting period (such as those under (b) and (c)) are non-adjusting events that should be accounted for prospectively in accordance with IFRS. [IAS 8.32‑38, IAS 10.3]. Changes in reserves estimates that result from new information or new developments which do not offer greater clarity concerning the conditions that existed at the end of the reporting period (such as those under (a)) are not considered to be corrections of errors; instead they are changes in accounting estimates that should be accounted for prospectively under IFRS. [IAS 8.5, 32‑38].

Determining whether actual changes in reserves estimates should be treated as adjusting or non-adjusting events will depend upon the specific facts and circumstances and may require significant judgement.

Usually, an entity will continue to invest during the year in assets in the depreciation pool (see 16.1.3.B below for a discussion of ‘depreciation pools’) that are used to extract minerals. This raises the question as to whether or not assets that were used for only part of the production during the period should be depreciated on a different basis. Under the straight-line method, an entity will generally calculate the depreciation of asset additions during the period based on the assumption that they were added (1) at the beginning of the period, (2) in the middle of the period or (3) at the end of the period. While method (2) is often the best approximation, methods (1) and (3) are generally not materially different when the accounting period is rather short (e.g. monthly or quarterly reporting) or when the level of asset additions is relatively low compared to the asset base.

The above considerations explain why the units of production formula that is commonly used in the extractive industries is slightly more complicated than the formula given above:

This units of production formula is widely used in the oil and gas sector by entities that apply US GAAP or did apply the former OIAC SORP. In the mining sector, however, both the first and the second units of production formulae are used in practice.

17.1.1 Mineral rights

Leases to explore for or use minerals, oil, natural gas and similar non-regenerative resources are excluded from the scope of IFRS 16, [IFRS 16.3], (amongst other types of arrangements – see Chapter 23 at 2.2 for the full list of scope exclusions).

IFRS 16 does not specify whether the scope exclusion for leases to explore for or use minerals, oil, natural gas and similar non-regenerative resources applies broadly to other leases that relate to, or are part of, the process of exploring for, or using, those resources. For example, in some jurisdictions, the minerals are owned by the government, but the land within which the minerals are located is privately owned. In these jurisdictions, a mining and metals entity needs to enter into a mineral lease with the government as well as a surface lease (i.e. the right to use the land) with the private landowner. IFRS 16's Basis for Conclusions states that IFRS 6 specifies the accounting for rights to explore for, and evaluate, mineral resources. [IFRS 16.BC68(a)].

The US GAAP leases standard (ASC 842 – Leases), includes more specific guidance on how this scope exclusion should be applied. It states that leases of minerals, oil, natural gas and similar non-regenerative resources, including the intangible rights to explore for those resources and the rights to use the land in which those natural resources are contained (unless those rights of use include more than the right to explore for natural resources) are outside the scope of ASC 842. However, equipment used to explore for the natural resources is within the scope of ASC 842.2.

Entities will need to apply judgement to determine how broadly to interpret and apply this scope exclusion under IFRS 16.

IFRS 16 is not specific as to whether the scope exclusion only applies to mineral rights in the E&E phase or whether it also applies to other rights (e.g. exploitation and/or extraction rights that arise in connection with development and production phases). The wording of the exclusion specifies that it applies to ‘leases to explore for or use minerals’ (emphasis added), which suggests that it applies more broadly (i.e. to the E&E, development and production phases). However, the reference to IFRS 6 in the Basis for Conclusions of IFRS 16 [IFRS 16.BC68(a)] may infer that the exclusion is limited to rights in the E&E phase.

Most mining companies and oil and gas companies generally apply the scope exclusion to the mineral rights in the E&E, development and production phases. We would expect that given the wording in the main body of the standard, the scope exclusion would apply to mineral rights in all phases. We would also expect that consistent with ASC 842, in the event that rights extend to more than the right to explore for or use natural resources, the scope exclusion would not apply. For example, in the event that there is also a corporate head office building on part of the land, an apportionment would be applied, and the scope exclusion would not apply to the portion of the land upon which the head office is built. Furthermore, we would not expect the scope exclusion to extend to equipment used to explore, develop or produce mineral rights.

17.1.2 Land easements or rights of way

Land easements or rights of way are rights to use, access or cross another entity's land for a specified purpose. For example, a land easement might be obtained for the right to construct and operate a pipeline or other assets (e.g. a railway line) over, under or through an existing area of land or body of water while allowing the landowner continued use of the land for other purposes (e.g. farming), as long as the landowner does not interfere with the rights conveyed in the land easement.

When determining whether a contract for a land easement or right of way is a lease, mining companies and oil and gas companies will need to assess whether there is an identified asset and whether the customer obtains substantially all of the economic benefits of the identified asset and has the right to direct the use of that asset(s) throughout the period of use.

This will require careful consideration of the rights and obligations in each arrangement and conclusions may vary given that the nature of these contracts can also vary by jurisdictions. The issue of accounting for land easements is discussed in Chapter 23 at 3.1.2.

17.1.3 Subsurface rights

In June 2019, the Interpretations Committee discussed a contract for subsurface rights.¹⁴¹ In the contract described, a pipeline operator obtains the right to place an oil pipeline in underground space for 20 years in exchange for consideration. The contract specifies the exact location and dimensions (path, width and depth) of the underground space within which the pipeline will be placed. The landowner retains the right to use the surface of the land above the pipeline, but it has no right to access or otherwise change the use of the specified underground space throughout the 20-year period of use. The customer has the right to perform inspection, repairs and maintenance work (including replacing damaged sections of the pipeline when necessary).

During the discussion, the Interpretations Committee noted the following:

• Paragraph 3 of IFRS 16 requires an entity to apply IFRS 16 to all leases, with limited exceptions. In the contract described in the request, none of the exceptions in paragraphs 3 and 4 of IFRS 16 apply. In particular, the Interpretations Committee noted that the underground space is tangible. Accordingly, if the contract contains a lease, IFRS 16 applies to that lease. If the contract does not contain a lease, the entity would then consider which other IFRS standard applies.
• Applying paragraph B9 of IFRS 16, to meet the definition of a lease the customer must have both:
  • the right to obtain substantially all the economic benefits from use of an identified asset throughout the period of use; and
  • the right to direct the use of the identified asset throughout the period of use.
• The specified underground space is physically distinct from the remainder of the land. The contract's specifications include the path, width and depth of the pipeline, thereby defining a physically distinct underground space. The space being underground does not in itself affect whether it is an identified asset – the specified underground space is physically distinct in the same way that a specified area of space on the land's surface would be physically distinct. As the landowner does not have the right to substitute the underground space throughout the period of use, the Committee concluded that the specified underground space is an identified asset as described in paragraphs B13–B20.
• The customer has the right to obtain substantially all the economic benefits from use of the specified underground space throughout the 20-year period of use. The customer has exclusive use of the specified underground space throughout that period of use.
• The customer has the right to direct the use of the specified underground space throughout the 20-year period of use because the customer has the right to operate the asset throughout the period of use without the supplier having the right to change those operating instructions. How and for what purpose the specified underground space will be used (i.e. to locate the pipeline with specified dimensions through which oil will be transported) is predetermined in the contract. The customer has the right to operate the specified underground space by having the right to perform inspection, repairs and maintenance work. The customer makes all the decisions about the use of the specified underground space that can be made during the 20-year period of use.

Consequently, the Interpretations Committee concluded that the contract described in the request contains a lease as defined in IFRS 16. The customer would therefore apply IFRS 16 in accounting for that lease.

18.3.1 Assessing the contractual arrangements between the lead operator and the non-operator parties to the JO

18.3.2 Determining if there is a sublease

Once it has been established there is a customer-supplier relationship between the lead operator and the JO, the next step is to determine whether there is a lease.

IFRS 16 states that a contract is, or contains, a lease if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. [IFRS 16.9]. In assessing whether a contract conveys the right to control the use of an identified asset for a period of time, an entity assesses whether, throughout the period of use, the customer has both:

• the right to obtain substantially all of the economic benefits from use of the identified asset; and
• the right to direct the use of the identified asset.

The key factor to determine whether there is a sublease is whether it is the lead operator (as the supplier) or the JO (as the customer) that has the right to control the use of the identified asset.

18.3.3 Determining if there is an identified asset

18.3.4 Determining if the customer has the right to control the use of an identified asset

As discussed above at 18.2 above, when applying the requirements of IFRS 16 (as outlined below) and specifically when considering the concept of the customer, it is the JO that is the customer. The JO (as the customer) has the right to control the use of an identified asset if it has both the right to obtain substantially all of the economic benefits from use and the right to direct the use of the asset. It would be inappropriate to conclude that a contract does not contain a lease on the grounds that each of the parties to the JO either obtains only a portion of the economic benefits from use of the underlying asset or does not unilaterally direct the use of the underlying asset. [IFRS 16.BC126].

18.4.1 JOA and/or related contractual arrangements are, or contain, a sublease

18.4.2 JOA and/or related contractual arrangements are not, do not contain, a sublease

When the contractual arrangements between the lead operator and the JO do not contain a sublease, the lead operator continues to recognise the right-of-use asset and related lease liability in relation to the lease with the third party supplier at lease commencement and will recognise amortisation of the right-of-use asset and interest on the lease liability across the term of the lease.

The arrangement with the JO will then likely represent an executory contract and the accounting by the lead operator for amounts receivable from the non-operator parties will depend on the nature of this arrangement. Some of the potential accounting considerations may include the matters listed below. When undertaking these assessments, as discussed at Section 18.2 above, it is important to note that the determination of the customer for the purposes of applying IFRS 16 does not necessarily impact the determination of a customer for the purposes of other standards. For example, a customer, for the purposes of IFRS 15, is determined by applying the specific requirements and guidance of IFRS 15.

• Provision of JO management services whereby the JO is considered to be a customer: the arrangement will be in the scope, and the lead operator will apply the provisions, of IFRS 15. Revenue will be recognised at the amount the lead operator expects to be entitled to in exchange for providing the JO management services to the JO as the relevant performance obligations are satisfied. See Chapters 27 to 31 for more information on factors to consider when applying IFRS 15.
• JO does not represent a customer: where the lead operator does not consider it is providing JO management services to the non-operator parties within the scope of IFRS 15, the lead operator will need to apply other relevant IFRS standards, or when no specific IFRS standards are applicable, use judgement to determine the appropriate accounting treatment for the arrangement. The lead operator will need to apply IAS 8 to determine the nature of the relationship and whether and when it should recognise amounts receivable from the non-operator parties. Specifically, the lead operator will need to assess whether the provisions of IFRS 9 relating to financial assets apply or whether the reimbursement requirements of IAS 37 apply. The lead operator will also need to assess whether these amounts represent a form of income or a direct reimbursement of expenditure.

18.4.3 Other issues to consider

In addition to the above, there are a number of other potential issues that a lead operator may need to consider when evaluating the overall accounting implications, which include but are not limited to:

• Capitalisation of costs: where the activities of the JO are being undertaken in relation to a project that is in the exploration and evaluation (E&E) phase or the development phase, depending on the lead operator's accounting policies, it may need to consider whether some of the costs incurred, e.g. a portion of the amortisation of the right-of-use asset and/or interest expense on the lease liability, should be capitalised. The lead operator will need to assess whether such costs meet the requirements for capitalisation under the relevant standards (including IAS 23 which explicitly scopes in interest in respect of leases under IFRS 16), and if so, determine the amount that should be capitalised versus the amount that should be expensed.
• Mismatch between the lead operator's costs and the amounts receivable from the non-operator parties: in each period, the lead operator's accounting for the expenses relating to the lease with a third party which are to effectively be reimbursed by the non-operator parties, will not necessarily be equivalent to the amounts receivable from the non-operator parties. This is because the IFRS 16 accounting for the lease with the third party supplier will generally be more front ended and will comprise amortisation of the right-of-use asset and interest on the lease liability. This will differ from the income a lead operator will recognise under sublease operating accounting or executory contract accounting. This will lead to timing mismatches for the lead operator in its profit or loss.
• Presentation of amounts receivable from the non-operator parties (where the arrangement is not a ‘sublease which is a finance lease’, i.e. it is either an operating lease or not a sublease): in this situation, a question that may be asked is whether any amounts receivable from the non-operator parties can be offset against the amounts recognised by the lead operator. This question is generally raised because from an economic perspective, the non-operator parties are effectively paying their respective share of the cash costs incurred by the lead operator on the lease with the third party supplier. Hence, some lead operators may prefer to present the effects of this on a net basis, if / where possible.

  When assessing this offsetting issue, the following needs to be considered:

  • Ability to offset: IAS 1, [IFRS 1.32], and the Conceptual Framework, [CF 7.10], provide the requirements and guidance with respect to offsetting of assets and liabilities and income and expenses. IAS 1 states offsetting is not allowed unless required/permitted by another standard and the Conceptual Framework notes it is generally not permitted as offsetting classifies dissimilar items together. Given this, it is expected the ability to achieve offsetting will be rare.
  • Lead operator capitalises its costs as part of an E&E or development asset: in such a situation, the lead operator would only be able to capitalise the portion of the costs incurred on the head lease relating to its ownership in the JO assets. This is on the basis that it would not receive the future economic benefits associated with the costs attributable to the non-operator parties. These costs would therefore need to be recognised in profit or loss (P&L). See below for further discussion on the issues this would present.
  • Lead operator recognises its costs in P&L: in this situation, the question is whether the lead operator can offset the amounts receivable from non-operator parties directly against the line items within P&L in which it has recognised the costs relating to the lease with the third party supplier. The challenges here may include:
    • mismatches in amounts (as discussed above);
    • whether such amounts received can be offset and if so, upon what basis; and
    • if a valid argument could be mounted to support offsetting, which is considered difficult to achieve, given the lead operator will be recognising amortisation and interest, it is unclear how the amounts received would be allocated between the two line items.

18.5.1 JOA and/or related contractual arrangements contain a sublease

When the JO is the sublessee, under IFRS 16, there is no longer any differentiation between operating or finance leases. As a result, there will be a right-of-use asset and lease liability in relation to the lease with the lead operator, for which each participant in the JO will, in accordance with IFRS 11, need to:

• recognise its proportionate share of the right-of-use asset and lease liability based on its respective interest in the JO; and
• during the term of the sublease:
  • recognise amortisation of its share of the right-of-use asset; and
  • recognise interest expense in relation to its share of the lease liability.

18.5.2 JOA and/or related contractual arrangements do not contain a sublease

Where the JOA and/or related contractual arrangements do not contain a sublease, IFRS 16 does not apply to the JO. Therefore, the non-operator parties will likely continue to recognise amounts payable to the lead operator consistently based on their existing accounting policies.

18.5.3 Other factors to consider when evaluating the overall accounting

In addition to the above, there are a number of other potential factors which non-operator parties will need to consider when evaluating the overall accounting, which include but are not limited to:

• Capitalisation of costs: where the activities of the JO are being undertaken in relation to a project that is in the E&E phase or the development phase, depending on the non-operator's accounting policies, it may need to consider whether the costs incurred, e.g. amortisation of the right-of-use asset and/or interest expense on the lease liability, should be capitalised. Each non-operator party will need to assess whether such costs meet the eligibility requirements for capitalisation in accordance with the relevant standard (including IAS 23), their own policies and appropriate industry practice. If so, the amount that will need to be capitalised versus the amount that will be expensed will need to be identified.
• Cash flow impact: the profile over which right-of-use amortisation and interest expense will be recognised will vary depending on the nature of the particular asset and could vary significantly from the pattern in which cash costs are incurred. This is because it is expected that most lead operators will seek to align cost recovery with the pattern in which their cash costs are incurred. This is likely to lead to timing and potentially overall measurement differences between amounts incurred and cash outflows recognised.

18.6.1 Access to information

If the contractual arrangement between the lead operator and the JO are concluded to contain a sublease, or the JO itself is considered to have entered into a lease directly with a third party supplier, the parties to the JO will need to recognise their respective share of the lease liability, right-of-use asset, amortisation expense, interest expense and variable lease payments, if any. To do this, the lead operator will need to provide non-operator parties with the required information. Therefore, parties to the JO will need to discuss and agree what information is required, who will prepare and provide such information and when such information will be made available.

Where lead operators agree to prepare, or are required to prepare, such information on behalf of the non-operator parties, the non-operator parties will need to consider whether there are any material differences in accounting policies which need to be adjusted for before recognising such amounts in their own financial statements. Also, on transition to IFRS 16, it will be necessary to consider the impact of different transition options taken by each of the parties. For example, if the JO exists at transition date and the lead operator prepares this information on a full retrospective basis, but one of the non-operator parties adopts IFRS 16 using the modified retrospective approach, adjustments will be required to align to their transition approach (if material).

18.6.2 Impact on systems and processes

Where leases are concluded to exist, this may require significant alterations to systems and processes. Lead operators will be required to consider the ability of existing systems and processes to execute joint interest billing going forward in light of these changes. Non-operator parties will need to consider whether their systems and processes are capable of accounting for leases.

Entities are encouraged to liaise closely with parties to each of their JOs, sharing sufficient information so that each member of the JO is able to determine their appropriate accounting.

19.2.1 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 a contract liability, i.e. 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.¹⁵²

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. unearned 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.¹⁵³ For a discussion of the IFRS 15 considerations for these types of arrangements, see 12.16 above.

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.

21.1.1 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 3.4 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 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.

21.1.2 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 43.28 below describes the petroleum revenue tax in the United Kingdom.

The UK PRT is similar to an income tax in that the tax is a percentage of revenue minus certain costs. However, there are also a number of other features that are not commonly found in income taxes or in some other resource rent taxes:

• the oil allowance is a physical quantity of oil that is PRT exempt in each field, subject to a cumulative maximum over the life of the field; and
• the tax is levied on individual oil fields rather than the entity owning the oil field as a whole.

There are many different types of petroleum revenue taxes (or resource rent taxes) around the world, some of which are clearly not income taxes, while others have some of the characteristics of an income tax. In determining whether a particular production tax meets the definition of an income tax under IAS 12, an entity will need to assess whether or not the tax is based on (or closely enough linked to) net profit for the period. If it does not meet the definition of an income tax, an entity should develop an accounting policy under the hierarchy in IAS 8.

Practice is mixed, which means that while some entities may treat a particular petroleum revenue tax (or resource rent tax) as an income tax under IAS 12 and hence provide for current and deferred taxes (see Extract 43.58 below), others may consider the same tax to be outside the scope of IAS 12.

As illustrated in Extract 43.59 below, BHP assesses resource rent taxes and royalties individually to determine whether they meet the definition of an income tax or not.