IFRS OIL AND GAS3

Energy, Utilities & Mining

Financial reporting in theoil and gas industry*International Financial Reporting Standards

April 2008

*connectedthinking

08PwC0290_IFRS O&G final edit 10.04.2008 12:01 Uhr Seite 1


The move to International Financial ReportingStandards (IFRS) is advancing the transparencyand comparability of financial statements aroundthe world. Many countries now requirecompanies to prepare their financial statementsin accordance with IFRS. National standards inother countries are being converged with IFRS.The global trend towards IFRS has gainedsignificant further momentum with the USSecurities and Exchange Commission’s (SEC)commitment to the standards, beginning with itsdecision to drop the requirement for foreign-listed companies in the US to reconcile to USGAAP.

The development of IFRS offers considerable long-term advantages for global companies but,along the way, it brings considerable challenges.The oil & gas industry is one of the world’s mostglobal industries, characterised by the need forbig upfront investment, often with greatuncertainty about outcomes over a long-termtime horizon. Its geopolitical, environmental,energy and natural resource supply and tradingchallenges, combined with often complexstakeholder and business relationships, hasmeant that the transition to IFRS has requiredsome complex judgements about how toimplement the new standards.

This edition of ‘Financial reporting in the oil & gas industry’ describes the financial reportingimplications of IFRS across a number of areasselected for their particular relevance to oil & gascompanies. It provides insights into howcompanies are responding to the variouschallenges and includes examples of accountingpolicies and other disclosures from publishedfinancial statements. It examines keydevelopments in the evolution of IFRS in theindustry. The International Accounting StandardsBoard (IASB), for example, has formed anExtractive Activities working group. However,formal guidance on many issues facingcompanies is unlikely to be available for someyears. Another key development, of course, isconvergence with US GAAP and the implicationsof the latest signals from the SEC for the oil &gas industry.

This publication does not describe all IFRSs applicable to oil & gas entities. The ever-changinglandscape means that management shouldconduct further research and seek specificadvice before acting on any of the more complexmatters raised. PricewaterhouseCoopers has adeep level of insight into and commitment tohelping companies in the sector reporteffectively. For more information or assistance,please do not hesitate to contact your local officeor one of our specialist oil & gas partners.

Richard PatersonGlobal Energy, Utilities and Mining Leader

Foreword

Foreword

1Financial reporting in the oil and gas industry


Contents

Introduction 5

1 Oil & Gas Value Chain & Significant Accounting Issues 7

1.1 Exploration & development 9

1.1.1 Exploration & evaluation 9

1.1.2 Borrowing costs 11

1.1.3 Development expenditures 11

1.2 Production & sales 11

1.2.1 Reserves & resources 11

1.2.2 Depreciation of production and downstream assets 12

1.2.3 Product valuation issues 14

1.2.4 Impairment of production and downstream assets 14

1.2.5 Disclosure of resources 16

1.2.6 Decommissioning obligation 17

1.2.7 Financial instruments and embedded derivatives 18

1.2.8 Revenue recognition issues 21

1.2.9 Royalty and income taxes 22

1.2.10 Emission Trading Schemes 24

1.3 Company-wide issues 25

1.3.1 Production sharing agreements and concessions 25

1.3.2 Joint ventures 26

1.3.3 Business combinations 29

1.3.4 Functional currency 30

2 Developments from the IASB 33

2.1 Extractive activities research project 34

2.2 Borrowing costs 34

2.3 Emissions Trading Schemes 34

2.4 ED 9 Joint Arrangements 35


Contents


2.5 IFRS 3, Business combinations (revised) and IAS 27, Consolidated and separate financial statements (revised) 36

3 IFRS/US GAAP Differences 39

3.1 Exploration & evaluation 40

3.2 Reserves & resources 41

3.3 Depreciation of production and downstream assets 41

3.4 Inventory valuation issues 41

3.5 Impairment of production and downstream assets 42

3.6 Disclosure of resources 42

3.7 Decommissioning obligations 43

3.8 Financial instruments and embedded derivatives 44

3.9 Revenue recognition 46

3.10 Joint ventures 46

3.11 Business Combinations 48

4 Financial disclosure examples 51

4.1 Exploration & evaluation 52

4.2 Reserves & resources 53

4.3 Depreciation of production and downstream assets 54

4.4 Impairment 54

4.5 Decommissioning obligation 56

4.6 Financial instruments and embedded derivatives 56

4.7 Revenue recognition issues 57

4.8 Royalty and income taxes 57

4.9 Emission Trading Schemes 58

4.10 Joint ventures 58

4.11 Business combinations 60

4.12 Functional currency 61

Contact us 62



What is the focus of this publication?

This publication considers the major accountingpractices adopted by the oil and gas industryunder International Financial Reporting Standards(IFRS).

The need for this publication has arisen due to:

• the absence of an extractive industries standard under IFRS;

• the adoption of IFRS by oil and gas entities across a number of jurisdictions, with overwhelming acceptance that applying IFRS in this industry will be a continual challenge; and

• ongoing transition projects in a number of other jurisdictions, for which companies can draw on the existing interpretations of the industry.

Who should use this publication?

This publication is intended for:

• executives and financial managers in the oil and gas industry, who are often faced with alternative accounting practices;

• investors and other users of oil and gas industry financial statements, so they can identify some of the accounting practices adopted to reflect unusual features unique to the industry; and

• accounting bodies, standard-setting agencies and governments throughout the world interested in accounting and reporting practices and responsible for establishing financial reporting requirements.

What is included?

Included in this publication are issues that webelieve are of financial reporting interest due to:

• their particular relevance to oil and gas entities; and/or

• historical varying international practice.

The oil and gas industry has not only experienced the transition to IFRS, it has alsoseen:

• significant growth in corporate acquisition activity;

• increased globalisation;

• continued increase in its exposure to sophisticated financial instruments and transactions; and

• an increased focus on environmental and restoration liabilities.

This publication has a number of chapters designed to cover the main issues raised.

PricewaterhouseCoopers’ experience

This publication is based on the experiencegained from the worldwide leadership position ofPricewaterhouseCoopers in the provision ofaccounting services to the oil and gas industry.This leadership position enablesPricewaterhouseCoopers’ Global Oil and GasIndustry Group to make recommendations andlead discussions on international standards andpractice. The IASB has asked a group of nationalstandard-setters to undertake a research projectthat will form the first step towards thedevelopment of an acceptable approach toresolving accounting issues that are unique toupstream extractive activities. The primary focusof the research project is on the financialreporting issues associated with reserves andresources. An advisory panel has beenestablished to provide advice throughout theresearch project. PwC participates in theadvisory panel. We support the IASB’s project toconsider the promulgation of an accountingstandard for the extractive industries; we hopethat this will bring consistency to all areas offinancial reporting in the extractive industries.The oil and gas industry is arguably one of themost global industries, and internationalcomparability would be welcomed.

We hope you find this publication useful.

Introduction

Introduction




1 Oil & Gas Value Chain & Significant Accounting Issues

7Financial reporting in the oil and gas industry1 O

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• Exploration & evaluation

• Borrowing costs

• Development expenditures

• Reserves & Resources (incl. depletion,

depreciation and amortisation)

• Depreciation of production and downstream assets

• Product valuation issues

• Impairment of production and downstream assets

• Disclosure of resources

• Decommissioning obligations

• Financial instruments and embedded derivatives

• Revenue recognition issues

• Royalty and income taxes

• Emission trading schemes

Company-wide Issues:

• Production sharing agreements and concessions

• Joint ventures

• Business combinations

• Functional currency

Exploration & Development Production & Sales

The objective of oil and gas operations is to find,extract, refine and sell oil and gas, refinedproducts and related products. It requiressubstantial capital investment and long leadtimes to find and extract the hydrocarbons inchallenging environmental conditions withuncertain outcomes. Exploration, developmentand production often takes place in joint venturesor joint activities to share the substantial capitalcosts. The outputs often need to be transportedsignificant distances through pipelines, andtankers; gas volumes are increasingly liquefied,transported by special carriers and then re-gasified on arrival at its destination. Gas remainschallenging to transport; thus many producersand utilities look for long-term contracts tosupport the infrastructure required to develop amajor field, particularly off-shore.

The industry is exposed significantly to macro-economic factors such as commodity prices,currency fluctuations, interest-rate risk andpolitical developments. The assessment ofcommercial viability and technical feasibility to

extract the hydrocarbons is complex, and includesa number of significant variables. The industrycan have a significant impact on the environmentconsequential to its operations and is oftenobligated to remediate any resulting damage.Despite all of these challenges, taxation of oiland gas extractive activity and the resultantprofits is a major source of revenue for manygovernments. Governments are also increasinglysophisticated and looking to secure a significantshare of any oil and gas produced on theirsovereign territory.

This publication examines the accounting issues that are most significant for the oil and gasindustry. The issues are addressed following the oil & gas value chain: exploration anddevelopment, production and sales of product,together with issues that are pervasive to theentity.

For published financial disclosure examples, see Section 4 on page 51.

1 Oil & Gas Value Chain & Significant Accounting Issues

8 PricewaterhouseCoopers

Oil & Gas Value Chain and Significant Accounting Issues


1.1 Exploration & development

1.1.1 Exploration & evaluation (E&E)

Exploration costs are incurred to discover hydrocarbon resources. Evaluation costs areincurred to assess the technical feasibility andcommercial viability of the resources found.Exploration, as defined in IFRS 6 Exploration and Evaluation of Mineral Resources, starts whenthe legal rights to explore have been obtained.Expenditure incurred before obtaining the legalright to explore must be expensed.

The accounting treatment of exploration and evaluation expenditures (capitalising orexpensing) can have a significant impact on thefinancial statements and reported financialresults, particularly for entities at the explorationstage with no production activities. This chapterconsiders the available alternatives for thetreatment of such expenditure under IFRS.

Successful Efforts and Full Cost Method

Two broadly acknowledged methods havetraditionally been used under national GAAP to account for E&E and subsequent developmentcosts: successful efforts and full cost. Manydifferent variants exist under national GAAP, butthese are broadly similar. US GAAP has had asignificant influence on the development ofaccounting practice in this area; entities in thosecountries that may not have specific rules oftenfollow US GAAP by analogy, and US GAAP hasinfluenced the accounting rules in othercountries. The successful efforts method hasperhaps been more widely used under nationalGAAP by integrated oil and gas companies, butis also used by many smaller upstream-onlybusinesses. Costs incurred in finding, acquiringand developing reserves are capitalised on afield-by-field basis. Capitalised costs areallocated to commercially viable hydrocarbonreserves. Failure to discover commercially viablereserves means that the expenditure is chargedto expense. Capitalised costs are depleted on afield-by-field basis as production occurs.

However, some upstream companies under national GAAP have historically used the full costmethod. All costs incurred in searching for,acquiring and developing the reserves in a largegeographic cost centre or pool, as opposed to

individual fields, are capitalised. Cost centres are typically grouped on a country by countrybasis, although sometimes countries may begrouped together if the fields have similar orlinked economic or geological characteristics.These larger cost pools are then depleted on acountry basis as production occurs. If explorationefforts in the country or geologic formation arewholly unsuccessful, the costs are expensed. Full cost, generally, results in a larger deferral ofcosts during exploration and development andincreased subsequent depletion charges.

Debate continues within the industry on the conceptual merits of both methods. IFRS 6 wasissued to provide an interim solution for E&Ecosts pending the outcome of the widerextractive industries project by the IASB. Entities transitioning to IFRS can continueapplying their current accounting policy for E&E.IFRS 6 provides an interim solution forexploration and evaluation costs, but does notapply to costs incurred once this phase iscompleted. The period of shelter provided by thestandard is a relatively narrow one, and theimpairment rules make the continuation of fullcost past the E&E phase a challenge.

Policy choice for E&E under IFRS 6

An entity accounts for its E&E expenditure by developing an accounting policy that complies with the IFRS Framework or in accordance withthe exemption permitted by IFRS 6. IFRS 6allows an entity to continue to apply its existingaccounting policy under national GAAP for E&E.The policy need not be in full compliance withthe IFRS Framework.

Changes made to an entity’s accounting policy for E&E can only be made if they result in anaccounting policy that is closer to the principlesof the Framework. The change must result in anew policy that is more relevant and no lessreliable or more reliable and no less relevant thanthe previous policy. The policy, in short, canmove closer to the Framework but not furtheraway. This restriction on changes to theaccounting policy includes changes implementedon adoption of IFRS 6. The shelter of IFRS 6 onlycovers the exploration and evaluation phase, untilthe point at which the reserves’ commercialviability has been established.


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Initial recognition of E&E under the IFRS 6exemption

The exemption in IFRS 6 allows an entity to continue to apply the same accounting policy toexploration and evaluation expenditures as it didbefore the application of IFRS 6. The costscapitalised under this policy might not meet theIFRS Framework definition of an asset, as theprobability of future economic benefits has notyet been demonstrated. IFRS 6 therefore deemsthese costs to be assets. E&E expendituresmight therefore be capitalised earlier than wouldotherwise be the case under the Framework.

Initial recognition of E&E under the Framework

Expenditures incurred in exploration activities should be expensed unless they meet thedefinition of an asset. An entity recognises anasset when it is probable that economic benefitswill flow to the entity as a result of theexpenditure. The economic benefits might beavailable through commercial exploitation ofhydrocarbon reserves or sales of exploration orfurther development rights. It is difficult for anentity to demonstrate at that stage that therecovery of exploration expenditure is probable.As a result, exploration expenditure has to beexpensed. Virtually all entities transitioning toIFRS have chosen to use the IFRS 6 shelterrather than develop a policy under theFramework.

Reclassification out of E&E under IFRS 6

IFRS 6 requires that E&E assets are reclassified when evaluation procedures have beencompleted. E&E assets for which commercially-viable reserves have been identified arereclassified to development assets. E&E assetsare tested for impairment immediately prior toreclassification out of E&E. The impairmenttesting requirements are described below.

Impairment of E&E assets

IFRS 6 introduces an alternative impairment-testing regime for E&E that differs from thegeneral requirements for impairment testing. An entity assesses E&E assets for impairment

only when facts and circumstances suggest thatan impairment exists. Indicators of impairmentinclude, but are not limited to:

• Rights to explore in an area have expired or will expire in the near future without renewal.

• No further exploration or evaluation is planned or budgeted.

• The decision to discontinue exploration and evaluation in an area because of the absence of commercial reserves.

• Sufficient data exists to indicate that the book value will not be fully recovered from future development and production.

The affected E&E assets should be tested for impairment once indicators have been identified.IFRS also introduces a notion of larger cashgenerating units (CGUs) for E&E assets. Entitiesare allowed to group E&E assets with producingassets, as long as the accounting policy is clearas to the grouping and such policy is appliedconsistently. The only limit is that each CGU or group of CGUs cannot be larger than thesegment. The grouping of E&E assets withproducing assets might therefore enable animpairment to be avoided.

Once the decision on commercial viability has been established, E&E assets are reclassified outof the E&E category. They are tested forimpairment under the IFRS 6 policy adopted bythe entity prior to reclassification. However, onceassets have been reclassified out of E&E thenormal impairment testing guidelines of IAS 36Impairment apply. Successful E&E will bereclassified to development. Unsuccessful E&Emust be written down to fair value less costs tosell, because the shelter afforded by groupingthese assets with producing assets in a largerCGU shelter is no longer available.

Assets reclassified out of E&E are subject to the normal IFRS requirements of impairment testingat the CGU level and depreciation on acomponent basis. Impairment testing anddepreciation on a pool basis is not acceptable.



1.1.2 Borrowing costs

The cost of an item of property, plant and equipment may include borrowing costs incurredfor the purpose of acquiring or constructing it.Such borrowing costs may be capitalised if theasset takes a substantial period of time to getready for its intended use. The capitalisation ofborrowing costs under IAS 23 Borrowing Costs(Issued 1993) is an option, but one which mustbe applied consistently to all qualifying assets.However, amendments to IAS 23 that werepublished in 2007 and become effective from 1 January 2009 will require that all applicableborrowing costs be capitalised.

Borrowing costs should be capitalised while acquisition or construction is actively underway.These costs include the costs of specific fundsborrowed for the purpose of financing theconstruction of the asset, and those generalborrowings that would have been avoided if theexpenditure on the qualifying asset had not beenmade. The general borrowing costs attributableto an asset’s construction should be calculatedby reference to the entity’s weighted averagecost of general borrowings.

1.1.3 Development expenditures

Development expenditures are costs incurred to obtain access to proved reserves and to providefacilities for extracting, treating, gathering andstoring the oil and gas.

Development expenditures should generally be capitalised to the extent that they are necessaryto bring the property to commercial production.Expenditures incurred after the point at whichcommercial production has commenced shouldonly be capitalised if the expenditures meet theasset recognition criteria. This will be where theadditional expenditure enhances the productivecapacity of the producing property.

Dry holes

Some of the wells drilled in accordance with the development plan for the field may beunsuccessful (dry), but the results of thedevelopment work as a whole may furthersupport the conclusion that the field hascommercially viable reserves. The relevant unit ofaccount for a field in the development or

production stage is normally larger than theindividual well. It is appropriate therefore toassess the economic benefits of the developmentdry hole in the context of the field as a whole andthe development plan for that field. The informationprovided by a development dry hole is usefulinformation and is applied through developingthe field’s infrastructure more precisely. The costsof a development dry hole should thereforenormally be capitalised.

1.2 Production & sales

1.2.1 Reserves & Resources

The oil and gas natural resources found by an entity are its most important economic asset. The financial strength of the entity depends onthe scale and quality of the resources it has theright to extract and sell. Resources are thesource of future cash inflows from sale ofhydrocarbons, and provide the basis forborrowing and for raising equity finance.

What are reserves?

Natural resources are outside the scope of IAS 16 Property, Plant and Equipment. The IASB isconsidering the accounting treatment for mineralresources and reserves as part of its ExtractiveActivities project. Entities record reserves at thehistorical cost of finding and developing reservesor acquiring them from third parties. The cost offinding and developing reserves is not directlyinfluenced by the quantity of reserves, except to the extent that impairment may be an issue. The cost of reserves acquired in a businesscombination may be more closely associatedwith the fair value of reserves present. However,reserves and resources have a pervasive impacton an oil and gas entity’s financial statements,impacting on a number of significant areas.These include, but are not limited to:

• depletion, depreciation and amortisation;

• impairment and reversal of impairment;

• the recognition of future decommissioning and restoration obligations;

• termination and pension benefit cash flows;

• allocation of purchase price in business combinations.


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Resources versus reserves

Resources are those volumes of oil and gas that are estimated to be present in the ground, whichmay or may not be economically recoverable.

Reserves are those resources that are anticipated to be commercially recovered fromknown accumulations from a specific date. The geological and engineering data available forspecific accumulations will enable an assessmentof the uncertainty/certainty of the reservesestimate. Reserves are classified as proved orunproved according to the degree ofcertainty/uncertainty associated with theirestimated recoverability. These classifications donot arise from any definitions or guidance in theIFRSs. They are commonly and broadly used inthe industry.

Several countries have their own definitions of reserves, for example China, Russia and Norway.Companies that are SEC registrants apply theSEC’s own definition of reserves for financialreporting purposes. There are also definitionsdeveloped by the professional societies, eg, Society of Petroleum Engineers (SPE).

Proved reserves are estimated quantities of reserves that, based on geological andengineering data, appear reasonably certain tobe recoverable in the future from known oil andgas reserves under existing economic andoperating conditions, ie, prices and costs as ofthe date the estimate is made.

Proved reserves are further sub-classified into those described as proved developed andproved undeveloped:

• proved developed reserves are those reserves that can be expected to be recovered through existing wells with existing equipment and operating methods;

• proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled proved acreage, or from existing wells where relatively major expenditure is required before the reserves can be extracted.

Unproved reserves are those reserves that technical or other uncertainties preclude frombeing classified as proved. Unproved reservesmay be further categorised as probable andpossible reserves:

• probable reserves are those additional reserves that are less likely to be recovered than proved reserves but more certain to be recovered than possible reserves;

• possible reserves are those additional reserves that analysis of geoscience and engineering data suggest are less likely to be recoverable than probable reserves.

Estimation of reserves

Reserves estimates are usually made by petroleum reservoir engineers, sometimes bygeologists but, as a rule, not by accountants.

Preparing reserve estimations is a complex process. It requires an analysis of informationabout the geology of the reservoir and thesurrounding rock formations and analysis of thefluids and gases within the reservoir. It alsorequires an assessment of the impact of factorssuch as temperature and pressure on therecoverability of the reserves, taking account ofoperating practices, statutory and regulatoryrequirements, costs and other factors that willaffect the commercial viability of extracting thereserves. As an oil and gas field is developed andproduced, more information about the mix of oil,gas, water, etc, reservoir pressure, and otherrelevant data is obtained and used to update theestimates of recoverable reserves. Estimates ofreserves are therefore revised over the life of thefield.

There are standards for estimating and auditing oil and gas reserves information developed bythe Society of Petroleum Engineers. The SPEStandards are not binding on petroleumengineers but do provide estimation andreporting guidance.

1.2.2 Depreciation of production anddownstream assets

The accumulated costs from E&E, developmentand production phases are amortised overexpected total production using a unit ofproduction (UOP) basis. UOP is the most



appropriate amortisation method because itreflects the pattern of consumption of thereserves’ economic benefits. However,straightline amortisation may be appropriate forsome assets.

Depletion, depreciation and amortisation (DD&A)

The IFRSs do not prescribe what basis should be used for the UOP calculation. Many entities useonly proved developed; others use all proved orboth proved and probable. The basis of the UOPcalculation is an accounting policy choice, andshould be applied consistently.

If proved and proved undeveloped reserves are used, then an adjustment should be consideredwhen calculating the amortisation charge toreflect the future development costs that need tobe incurred to access the undeveloped reserves.

The total production used for DD&A of assets that are subject to a lease or licence should berestricted to the total production expected to beproduced during the licence/lease term.Renewals of the licence/lease are only assumedif there is evidence to support probable renewalwithout significant cost.

Components

IFRS has a specific requirement for ‘component’ depreciation, as described in IAS 16. Eachsignificant part of an item of property, plant andequipment is depreciated separately. Significantparts of an asset that have similar useful livesand pattern of consumption can be groupedtogether. This requirement can createcomplications for oil & gas entities, as there aremany assets that include components with ashorter useful life than the asset as a whole.

Productive assets are often large and complex installations. Assets are expensive to construct,tend to be exposed to harsh environmental oroperating conditions and require periodicreplacement or repair. Large network orinfrastructure assets might comprise a significantnumber of components, many of which will havediffering useful lives. Examples include gastreatment installations, refineries, chemicalplants, distribution networks and offshoreplatforms, including the supporting infrastructureand pipelines.

The significant components of these types of assets must be separately identified, such as thecompressors in a pipeline. It can be a complexprocess, particularly on transition to IFRS, as therecordkeeping may not have been required tocomply with national GAAP.

Some components can be identified by considering the routine shutdown/turnaroundschedules and the replacement and maintenanceroutines associated with these. Considerationshould also be given to those components thatare prone to technological obsolescence,corrosion or wear and tear more severe than thatof the other portions of the larger asset.

Depreciation of components

Those identified components that have a shorter useful life than the remainder of the asset shouldbe depreciated to the recoverable amount overthat shorter useful life. The remaining carryingamount of the component is derecognised onreplacement and the cost of the replacement partis capitalised. A complication can arise whereupstream assets are largely depreciated on aUOP basis but specific assets are consumed in amore straight-line manner. A potential work-around exists if production is stable over time.The production expected during the period canbe estimated and the components depreciatedover that number of units. This method needs tobe periodically assessed to determine that itcontinues to approximate a straight-line method.

The calculation of a depreciation charge cannot be avoided on the basis that a high level ofmaintenance expenditure is incurred that willcontinuously maintain the network’s operatingcapacity. The practice of assuming that themaintenance charge approximates thedepreciation charge and thus avoiding thecalculation of depreciation on an asset orcomponent basis, known as renewalsaccounting, is not acceptable under IFRS.

The costs of performing a turnaround/overhaul are capitalised as a component of the plantprovided this provides access to future economicbenefits, but turnaround/overhaul costs that donot relate to the replacement of components orthe installation of new assets should beexpensed as incurred. Turnaround/overhaul costsshould not be accrued over the period between


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the turnarounds/overhauls because there is nolegal or constructive obligation to perform theturnaround/overhaul – the entity could choose tocease operations at the plant and hence avoidthe turnaround/overhaul costs.

1.2.3 Product valuation issues

Accounting for linefill

Some items of property, plant and equipment, such as pipelines, refineries and gas storage,require a certain minimum level of product to bemaintained in them in order for them to operateefficiently. Such product should be classified aspart of the property, plant and equipmentbecause it is necessary to bring the PPE to itsrequired operating condition. The product willtherefore be recognised as a component of thePPE at cost and subject to depreciation toestimated residual value.

However, product that an entity owns but stores in PPE owned by a third party continues to beclassified as inventory, for example all gas in arented storage facility. It does not represent acomponent of the third party’s PPE nor acomponent of PPE owned by the entity. Suchproduct should therefore be measured at FIFO orweighted average cost.

Determining net realisable value for oilinventories

Oil produced and purchased for use by an entity is valued at the lower of cost and net realisablevalue. Determining net realisable value requiresconsideration of the estimated selling price in theordinary course of business less the estimatedcosts to complete the processing of the inventory(where appropriate) and less the estimated costsnecessary to sell the inventories. An entitydetermines the estimated selling price of theoil/oil product using the market price for oil at thebalance sheet date, or where appropriate, theforward price curve for oil at the balance sheetdate. Movements in the oil price after the balancesheet date typically reflect changes in the marketconditions after that date and therefore shouldnot be reflected in the calculation of netrealisable value.

1.2.4 Impairment of production and downstream assets

The oil and gas industry is distinguished by the significant capital investment required. The heavyinvestment in fixed assets leaves the industryexposed to adverse economic conditions andtherefore impairment charges.

Oil and gas assets should be tested for impairment whenever indicators of impairmentexist. The normal measurement rules forimpairment apply to assets with the exception ofthe grouping of E&E assets with existingproducing cash generating units (CGUs) asdescribed in section 1.1.1.

Impairment indicators

Impairment triggers relevant for the petroleumsector include declining market prices for oil andgas, significant downward reserve revisions,increased regulation or tax changes, deteriorating local conditions such that it maybecome unsafe to continue operations andexpropriation of assets.

Impairment indicators can also be internal in nature. Evidence that an asset or CGU has beendamaged or become obsolete is an impairmentindicator; for example a refinery destroyed by fireis, in accounting terms, an impaired asset. Otherindicators of impairment are a decision to sell orrestructure a CGU or evidence that businessperformance is less than expected.

Management should be alert to indicators on a CGU basis; for example learning of a fire at anindividual petrol station would be an indicator ofimpairment for that station as a separate CGU.However, generally, management is likely toidentify impairment indicators on a regional orarea basis, reflective of how they manage theirbusiness. Once an impairment indicator has beenidentified, the impairment test must be performedat the individual CGU level, even if the indicatorwas identified at a regional level.

Cash generating units

A CGU is the smallest group of assets that generates cash inflows largely independent ofother assets or groups of assets. A CGU in anupstream entity will often be identified as a fieldand its supporting infrastructure assets.



Production, and therefore cash flows, can beassociated with individual wells. However, thefield investment decision is made based onexpected field production, not a single well, andall wells are typically dependent on the fieldinfrastructure.

An entity operating in the downstream businessmay own petrol stations, clustered in geographicareas to benefit from management oversight,supply and logistics. The petrol stations, bycontrast, are not dependent on fixedinfrastructure and generate largely independentcash inflows.

Calculation of recoverable amount

Impairments are recognised if a CGU’s carrying amount exceeds its recoverable amount.Recoverable amount is the higher of fair valueless costs to sell (FVLCTS) and value in use (VIU).

Fair value less costs to sell (FVLCTS)

Fair value less costs to sell is the amount that a market participant would pay for the asset orCGU, less the costs of sale. The use ofdiscounted cash flows for FVLCTS is permittedwhere there is no readily available market pricefor the asset or where there are no recent markettransactions for the fair value to be determinedthrough a comparison between the asset beingtested for impairment and a recent markettransaction. However, where discounted cashflows are used, the inputs must be based onexternal, market-based data.

The projected cash flows for FVLCTS therefore include the assumptions that a potentialpurchaser would include in determining the priceof the asset. Thus industry expectations for thedevelopment of the asset may be taken intoaccount which may not be permitted under VIU.However, the assumptions and resulting valuemust be based on recent market data andtransactions.

Post-tax cash flows are used when calculating FVLCTS using a discounted cash flow model.The discount rate applied in FVLCTS will be apost-tax market rate based on a typical industryparticipant’s cost of capital.

Value in use (VIU)

VIU is the present value of the future cash flows expected to be derived from an asset or CGU inits current condition. Determination of VIU issubject to the explicit requirements of IAS 36.The cash flows are based on the asset that theentity has now and must exclude any plans toenhance the asset or its output in the future butincludes expenditure necessary to maintain thecurrent performance of the asset. The VIU cashflows for assets that are under construction andnot yet complete (eg, an oil or gas field that ispart-developed) should include the cash flowsnecessary for their completion and theassociated additional cash inflows or reducedcash outflows.

Any foreign currency cash flows are projected in the currency in which they will be earned, anddiscounted at a rate appropriate for thatcurrency. The resulting value is translated to theentity’s functional currency using the spot rate atthe date of the impairment test.

The discount rate used for VIU is always pre-tax and applied to pre-tax cash flows. This is oftenthe most difficult element of the impairment test,as pre-tax rates are not available in the marketplace. Grossing up the post tax rate does notgive the correct answer unless no deferred tax isinvolved. Arriving at the correct pre-tax rate is acomplex mathematical exercise.

Contracted cash flows in VIU

The cash flows prepared for a VIU calculation should reflect management’s best estimate of thefuture cash flows expected to be generated fromthe assets concerned. Purchases and sales ofcommodities are included in the VIU at the spotprice at the date of the impairment test, or ifappropriate, prices obtained from the forwardprice curve at the date of the impairment test.

However, management should use the contracted price in its VIU calculation for anycommodities unless the contract is already onthe balance sheet at fair value. A commoditycontract that can be settled net in cash and forwhich the own-use exception cannot be claimed,for example, is recognised separately on thebalance sheet at fair value as a derivative.Including the contracted prices of such a


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contract would double count the effects of thecontract. Impairment of financial instruments that are within the scope of IAS 39 FinancialInstruments: Recognition and Measurement isaddressed by IAS 39 and not IAS 36.

The cash flow effects of hedging instruments such as caps and collars for commoditypurchases and sales are also excluded from theVIU cash flows. These contracts are alsoaccounted for in accordance with IAS 39.

1.2.5 Disclosure of resources

A key indicator for evaluating the performance of oil and gas entities are their existing reserves andthe future production and cash flows expectedfrom them. Some national accounting standardsand securities regulators require supplementaldisclosure of reserve information, most notablythe Statement on Financial Accounting Standards(FAS) 69 and Securities and ExchangeCommission (SEC) regulations. There are alsorecommendations on accounting practicesissued by industry bodies – Statements ofRecommended Practice (SORPs) – which coverAccounting for Oil and Gas Exploration,Development, Production and DecommissioningActivities. However, there are no reservedisclosure requirements under IFRS.

IAS 1 Presentation of Financial Statementsrequires that an entity’s financial statementsshould provide additional information that is notpresented on the face of the financial statementsbut which is necessary for a fair presentation. IAS 1 allows an entity to consider thepronouncements of other standard-settingbodies and accepted industry practices in theabsence of specific IFRS guidance whendeveloping accounting policies. Many entitiesprovide supplemental information with thefinancial statements because of the uniquenature of the oil and gas industry and the cleardesire of investors and other users of thefinancial statements to receive information aboutreserves. The information is usually supplementalto the financial statements, and is not covered bythe independent auditor’s opinion.

Information about quantities of oil and gas reserves and changes therein is essential forusers to understand and compare oil and gascompanies’ financial position and performance.

Entities should consider presenting reservequantities and changes on a reasonablyaggregate basis. Where certain reserves aresubject to particular risks, those risks should be identified and communicated. Reservedisclosures accompanying the financialstatements should be consistent with thosereserves used for financial statement purposes.For example, proven and probable reserves orproved developed and undeveloped reservesmight be used for depreciation, depletion andamortisation calculations.

The categories of reserves used and their definitions should be clearly described. Reportinga ‘value’ for reserves and a common means ofmeasuring that value have long been debated,and there is no consensus among nationalstandard-setters permitting or requiring valuedisclosure. There is, at present, no globallyagreed method to ‘value’ disclosures. However,there are globally accepted engineeringdefinitions of reserves that take into accounteconomic factors. These definitions may be auseful benchmark for disclosing future cash flowinformation about reserves for investors andother users of financial statements to evaluate.

The disclosure of key assumptions concerning the future, and other key sources of estimationuncertainty at the balance sheet date, is requiredby IAS 1. Given that the reserves and resourceshave a pervasive impact, this normally results inentities providing disclosure about hydrocarbonresource and reserve estimates, for example:

• hydrocarbon resource and reserve estimates: • methodology used; and • key assumptions;

• the sensitivity of carrying amounts of assets and liabilities to the hydrocarbon resource and reserve estimates used;

• the range of reasonably possible outcomes within the next financial year in respect of the carrying amounts of the assets and liabilities affected; and

• an explanation of changes made to past hydrocarbon resource and reserve estimates, including changes to underlying key assumptions.

Other information – for example, potential future costs to be incurred to acquire, develop and



produce reserves – may help users of financialstatements to assess the entity’s performance.Supplementary disclosure of such informationwith IFRS financial statements is useful, but itshould be consistently reported, the underlyingbasis clearly disclosed and based on a commonguideline or practice, such as the Society ofPetroleum Engineers definitions.

Companies already presenting supplementary information regarding reserves under theirnational GAAP may want to continue providingsuch information until the IASB publishes acomprehensive standard, setting out thesupplementary information disclosurerequirements under IFRS.

1.2.6 Decommissioning obligations

The oil and gas industry can have a significant impact on the environment. Decommissioning orenvironmental restoration work at the end of theuseful life of a plant or other installation may berequired by law, the terms of operating licencesor an entity’s stated policy and past practice. An entity that promises to remediate damage,even when there is no legal requirement, mayhave created a constructive obligation and thus a liability under IFRS. There may also beenvironmental clean-up obligations forcontamination of land that arises during theoperating life of a refinery or other installation.The associated costs of remediation/restorationcan be significant. The accounting treatment fordecommissioning costs is therefore critical.

Decommissioning provisions

A provision is recognised when an obligation exists to perform the clean-up. The local legalregulations should be taken into account whendetermining the existence and extent of theobligation. Obligations to decommission orremove an asset are created at the time the assetis put in place. An offshore drilling platform, forexample, must be removed at the end of itsuseful life. The obligation to remove it arises from its placement. The obligation does notchange in substance if the platform produces10,000 barrels or 1,000,000. Entities recognisedecommissioning provisions at the present value of the expected future cash flows that willbe required to perform the decommissioning.

The cost of the provision is recognised as part ofthe cost of the asset when it is put in place anddepreciated over the asset’s useful life. The totalcost of the fixed asset, including the cost ofdecommissioning, is depreciated on the basisthat best reflects the consumption of theeconomic benefits of the asset. Provisions fordecommissioning and restoration are recognisedeven if the decommissioning is not expected tobe performed for a long time, for example 80 to100 years. This may prove challenging in thedownstream business, for example refinerieswhen decommissioning is not expected in theshort to medium term.

The effect of the time to expected decommissioning will be reflected in thediscounting of the provision. The discount rateused is the pre-tax rate that reflects currentmarket assessments of the time value of money.Entities also need to reflect the specific risksassociated with the decommissioning liability.Different decommissioning obligations will,naturally, have different inherent risks, forexample different uncertainties associated withthe methods, the costs and the timing ofdecommissioning. The risks specific to the liabilitycan be reflected either in the pre-tax cash flowforecasts prepared or in the discount rate used.

Revisions to decommissioning provisions

Decommissioning provisions are updated at each balance sheet date for changes in the estimatesof the amount or timing of future cash flows andchanges in the discount rate. Changes toprovisions that relate to the removal of an assetare added to or deducted from the carryingamount of the related asset in the current period.The adjustments to the asset are restricted,however. The asset cannot decrease below zeroand cannot increase above its recoverableamount:

• if the decrease of provision exceeds the carrying amount of the asset, the excess is recognised immediately in profit or loss;

• adjustments that result in an addition to the cost of the asset are assessed to determine if the new carrying amount is fully recoverable or not. An impairment test is required if there is an indication that the asset may not be fully recoverable.


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The accretion of the discount on a decommissioning liability is recognised as part offinance expense in the income statement.

1.2.7 Financial instruments and embedded derivatives

The accounting for financial instruments can have a major impact on an oil & gas entity’sfinancial statements. Many use a range ofderivatives to manage the commodity, currencyand interest-rate risks to which they areoperationally exposed. Other, less obvious,sources of financial instruments issues arisethrough both the scope of IAS 39 and the rulesaround accounting for embedded derivatives.Many entities that are solely engaged inproducing, refining and selling commodities, maybe party to commercial contracts that are eitherwholly within the scope of IAS 39 or containembedded derivatives from pricing formulas orcurrency.

Scope of IAS 39

Contracts to buy or sell a non-financial item, such as a commodity, that can be settled net incash or another financial instrument, or byexchanging financial instruments, are within thescope of IAS 39. They are treated as derivativesand are marked to market through the incomestatement. Contracts that are for an entity’s‘own-use’ are exempt from the requirements ofIAS 39 but these ‘own-use’ contracts may includeembedded derivatives that may be required to beseparately accounted for. An ‘own-use’ contractis one that was entered into and continues to beheld for the purpose of the receipt or delivery ofthe non-financial item in accordance with theentity’s expected purchase, sale or usagerequirements. In other words, it will result inphysical delivery of the commodity. The ‘netsettlement’ notion in IAS 39 is quite broad. A contract to buy or sell a non-financial item canbe net settled in any of the following ways:

(a) the terms of the contract permit either party to settle it net in cash or another financial instrument;

(b) the entity has a practice of settling similar contracts net, whether:• with the counterparty; • by entering into offsetting contracts; or • by selling the contract before its exercise or

lapse;

(c) the entity has a practice, for similar items, of taking delivery of the underlying and selling it within a short period after delivery for the purpose of generating a profit from short-term fluctuations in price or dealer’s margin; or

(d) the commodity that is the subject of the contract is readily convertible to cash.

Application of ‘own-use’

Own-use applies to those contracts that were entered into and continue to be held for thepurpose of the receipt or delivery of a non-financial item. The practice of settling similarcontracts net prevents an entire category ofcontracts from qualifying for the own-usetreatment (ie, all similar contracts must then berecognised as derivatives at fair value).

A contract that falls into category (b) or (c) above cannot qualify for own-use treatment. Thesecontracts must be accounted for as derivativesat fair value. Contracts subject to the criteriadescribed in (a) or (d) above are evaluated to seeif they qualify for own-use treatment.

Many contracts for commodities such as oil and gas meet criterion (d) above (ie, readilyconvertible to cash) when there is an activemarket for the commodity. An active marketexists when prices are publicly available on aregular basis and those prices represent regularlyoccurring arm’s length transactions betweenwilling buyers and willing sellers. Consequently,sale and purchase contracts for commodities inlocations where an active market exists must beaccounted for at fair value unless own-usetreatment can be evidenced. An entity’s policies,procedures and internal controls are thereforecritical in determining the appropriate treatmentof its commodity contracts.

Own-use is not an election. A contract that meetsthe own-use criteria cannot be selectively fairvalued unless it otherwise falls into the scope ofIAS 39. If an own-use contract contains one or



more embedded derivatives, an entity maydesignate the entire hybrid contract as a financialasset or financial liability at fair value throughprofit or loss unless:

(a) the embedded derivative(s) does not significantly modify the cash flows of the contract; and

(b) it is clear with little or no analysis that separation of the embedded derivative is prohibited.

However, the IASB has proposed to restrict the ability to designate the entire hybrid instrumentas a financial asset or financial liability at fairvalue through profit or loss. The proposal to beincluded in the IASB’s 2008 AnnualImprovements project will restrict this designationto host contracts that are financial instruments inthe scope of IAS 39.

Further discussion on embedded derivatives is presented in the following section.

Measurement of long-term contracts that do not qualify for ‘own-use’

Long-term commodity contracts are not uncommon, particularly for purchase and sale ofnatural gas. Some of these contracts may bewithin the scope of IAS 39 as they contain netsettlement provisions and do not get own-usetreatment. These contracts are measured at fairvalue using the valuation guidance in IAS 39 withchanges recorded in the income statement.There may not be market prices for the entireperiod of the contract. For example, there maybe prices available for the next three years andthen some prices for specific dates further out.This is described as having illiquid periods in thecontract. These contracts are valued usingvaluation techniques in the absence of an activemarket for the entire contract term.

Valuation is complex and is intended to establish what the transaction price would have been onthe measurement date in an arm’s lengthexchange motivated by normal businessconsiderations. Therefore it:

(a) incorporates all factors that market participants would consider in setting a price, making maximum use of market inputs and relying as little as possible on entity-specific inputs;

(b) is consistent with accepted economic methodologies for pricing financial instruments; and

(c) is tested for validity using prices from anyobservable current market transactions in the same instrument or based on any available observable market data.

The assumptions used to value long-term contracts are updated at each balance sheetdate to reflect changes in market prices, theavailability of additional market data and changes in management’s estimates of prices for any remaining illiquid periods of the contract. Clear disclosure of the policy and approach,including significant assumptions, are crucial toensure that users understand the entity’s financialstatements.

Day-one profits

Commodity contracts that fall within the scope of IAS 39 and fail to qualify for own-use treatmenthave the potential to create day-one gains. A day-one gain is the difference between the fairvalue of the contract at inception as calculatedby a valuation model and the amount paid toenter the contract. The contracts are initiallyrecognised under IAS 39 at fair value. Any suchprofits or losses can only be recognised if the fairvalue of the contract:

(1) is evidenced by other observable markettransactions in the same instrument; or

(2) is based on valuation techniques whosevariables include only data from observable markets.

Thus, the profit must be supported by objective market-based evidence. Observable markettransactions must be in the same instrument (ie,without modification or repackaging and in thesame market where the contract was originated).Prices must be established for transactions withdifferent counterparties for the same commodityand for the same duration at the same deliverypoint.

Any day-one profit or loss that is not recognised at initial recognition is recognised subsequentlyonly to the extent that it arises from a change ina factor (including time) that market participantswould consider in setting a price. Commodity


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contracts include a volume component, and oiland gas entities are likely to recognise thedeferred gain/loss and release it to profit or losson a systematic basis as the volumes aredelivered, or as observable market pricesbecome available for the remaining deliveryperiod. The recognition of the day-onegain/losses may change as the result of the IASBproject on Fair Value Measurements.

Volume flexibility (optionality)

Long-term commodity contracts frequently offer the counterparty flexibility in relation to thequantity of the commodity to be delivered underthe contract. A supplier that gives a purchaservolume flexibility may have created a writtenoption. This will often prevent the supplier fromclaiming the own-use exemption. A writtenoption cannot be entered into for the purpose ofthe receipt or delivery of a non-financial item inaccordance with the entity’s expected purchase,sale or usage requirements. A contractcontaining a written option must be accountedfor in accordance with IAS 39 if it can be settlednet in cash, eg, when the item that is subject ofthe contract is readily convertible into cash.

Contracts may include volume flexibility but not contain a written option if the purchaser did notpay a premium for the optionality. Receipt of apremium to compensate the supplier for the riskthat the purchaser may not take the optionalquantities specified in the contract is one of the distinguishing features of a written option.The premium might be explicit in the contract orimplicit in the pricing. It is necessary to considerwhether a net premium is received either atinception or over the contract’s life in order todetermine the accounting treatment. If nopremium can be identified, other terms of thecontract may need to be examined to determinewhether it contains a written option; in particular,whether the buyer is able to secure economicvalue from the option’s presence.

Embedded derivatives

Long-term commodity purchase and sale contracts frequently contain a pricing clause (ie,indexation) based on a commodity other than the commodity deliverable under the contract.Such contracts contain embedded derivatives

that may have to be separated and accounted for under IAS 39 as a derivative. Examples aregas prices that are linked to the price of oil orother products, or a pricing formula that includesan inflation component.

An embedded derivative is a derivative instrument that is combined with a non-derivativehost contract (the ‘host’ contract) to form a singlehybrid instrument. An embedded derivativecauses some or all of the cash flows of the hostcontract to be modified, based on a specifiedvariable. An embedded derivative can arisethrough market practices or common contractingarrangements.

An embedded derivative is separated from the host contract and accounted for as a derivativeif:

(a) the economic characteristics and risks of the embedded derivative are not closely related to the economic characteristics and risks of the host contract;

(b) a separate instrument with the same terms as the embedded derivative would meet the definition of a derivative; and

(c) the hybrid (combined) instrument is not measured at fair value with changes in fair value recognised in the profit or loss (ie, a derivative that is embedded in a financial asset or financial liability at fair value through profit or loss is not separated).

Embedded derivatives that are not closely related must be separated from the host contract andaccounted for at fair value, with changes in fairvalue recognised in the income statement. It maynot be possible to measure the embeddedderivative. Therefore, the entire combinedcontract must be measured at fair value, withchanges in fair value recognised in the incomestatement.

An embedded derivative that is required to be separated may be designated as a hedginginstrument, in which case the hedge accountingrules are applied.

A contract that contains one or more embedded derivatives can be designated as acontract at fair value through profit or loss atinception, unless:



(a) the embedded derivative(s) does not significantly modify the cash flows of the contract; and

(b) it is clear with little or no analysis that separation of the embedded derivative(s) is prohibited.

Assessing whether embedded derivatives areclosely related

All embedded derivatives must be assessed to determine if they are ‘closely related’ to the host contract at the inception of the contract. A pricing formula that is indexed to somethingother than the commodity delivered under thecontract could introduce a new risk to thecontract. Some common embedded derivativesthat routinely fail the closely-related test areindexation to an unrelated published market priceand denomination in a foreign currency that isnot the functional currency of either party and nota currency in which such contracts are routinelydenominated in transactions around the world.

The assessment of whether an embedded derivative is closely related is both qualitative andquantitative, and requires an understanding ofthe economic characteristics and risks of bothinstruments.

In the absence of an active market price for a particular commodity, management shouldconsider how other contracts for that particularcommodity are normally priced. It is common fora pricing formula to be developed as a proxy formarket prices. When it can be demonstrated thata commodity contract is priced by reference toan identifiable industry ‘norm’ and contracts areregularly priced in that market according to thatnorm, the pricing mechanism does not modifythe cash flows under the contract and is notconsidered an embedded derivative.

Timing of assessment of embedded derivatives

All contracts need to be assessed for embedded derivatives at the date when the entity firstbecomes a party to the contract. Subsequentreassessment of embedded derivatives isprohibited unless there is a significant change inthe terms of the contract, in which casereassessment is required. A significant change inthe terms of the contract has occurred when the

expected future cash flows associated with theembedded derivative, host contract, or hybridcontract have significantly changed relative to thepreviously expected cash flows under the contract.

A first-time adopter assesses whether an embedded derivative is required to be separatedfrom the host contract and accounted for as aderivative on the basis of the conditions thatexisted at the later of the date it first became aparty to the contract and the date areassessment is required.

The same principles apply to an entity that purchases a contract containing an embeddedderivative. The date of purchase is treated as thedate when the entity first becomes party to thecontract.

1.2.8 Revenue recognition issues

Revenue recognition, particularly for upstream activities, can present some significantchallenges. Production often takes place in jointventures or through concessions, and entitiesneed to analyse the facts and circumstances todetermine when and how much revenue torecognise. Crude oil and gas may need to bemoved long distances and need to be of aspecific type to meet refinery requirements.Entities may exchange product to meet logistical,scheduling or other requirements. This sectionlooks at these common issues. Revenuerecognition in production-sharing agreements(PSAs) is discussed in section 1.3.1.

Overlift and underlift

Many joint ventures (JV) share the physical output (for example crude oil) between the jointventure partners. Each JV partner is thenresponsible for either using or selling the oil ittakes.

The physical nature of the taking (lifting) of oil is such that it is often more efficient for each partnerto lift a full tanker-load of oil at a time. A liftingschedule identifies the order and frequency withwhich each partner can lift. At the balance sheetdate the amount of oil lifted by each partner maynot be equal to its equity interest in the field.Some partners will have taken more than theirshare (overlifted) and others will have taken lessthan their share (underlifted).


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Overlift and underlift are in effect a sale of oil at the point of lifting by the underlifter to theoverlifter. The criteria for revenue recognition inIAS 18 Revenue paragraph 14 are considered tohave been met. Overlift is therefore treated as apurchase of oil by the overlifter from theunderlifter.

The sale of oil by the underlifter to the overlifter should be recognised at the market price of oil atthe date of lifting. Similarly the overlifter shouldreflect the purchase of oil at the same value.

The extent of underlift by a partner is reflected as an asset in the balance sheet and the extent ofoverlift is reflected as a liability. An underlift assetis the right to receive additional oil from futureproduction without the obligation to fund theproduction of that additional oil. An overliftliability is the obligation to deliver oil out of theentity’s equity share of future production.

The initial measurement of the overlift liability and underlift asset is at the market price of oil at thedate of lifting, consistent with the measurementof the sale and purchase. Subsequentmeasurement depends on the terms of the JVagreement. JV agreements that allow the netsettlement of overlift and underlift balances incash will fall within the scope of IAS 39 unlessthe own-use exemption applies.

Overlift and underlift balances that fall within the scope of IAS 39 must be remeasured to thecurrent market price of oil at the balance sheetdate. The change arising from thisremeasurement is included in the incomestatement as other income/expense rather thanrevenue or cost of sales.

Overlift and underlift balances that do not fall within the scope of IAS 39 should be measuredat the lower of carrying amount and currentmarket value. Any remeasurement should beincluded in other income/expense rather thanrevenue or cost of sales.

Exchanges

Energy companies exchange crude or refined oil products with other energy companies to achieveoperational objectives. This is often done to saveon transportation costs by exchanging a quantityof product A in location X for a quantity ofproduct A in location Y. Variations on this arise –

sometimes there are variations in the quality ofthe product, sometimes different products areexchanged. Balancing payments are made toreflect differences in the values of the productsexchanged where appropriate.

The nature of the exchange will determine if it is a like-for-like exchange or an exchange ofdissimilar goods. A like-for-like exchange doesn’tgive rise to revenue recognition or gains, but anexchange of dissimilar goods is accounted forgross, giving rise to revenue recognition andgains or losses.

The exchange of crude oil, even where the qualities of the crude differ, is usually treated asan exchange of similar products and accountedfor at book value. Any balancing payment madeor received to reflect minor differences in qualityor location should be adjusted against thecarrying value of the inventory. There may,however, be unusual circumstances where thefacts of the exchange suggest that there aresignificant differences between the crude oilexchanged. The transaction should be accountedfor as a sale of one product and the purchase ofthe other at fair values in these circumstances. A significant cash element in the transaction is anindicator that the transaction may be a sale andpurchase of dissimilar products.

1.2.9 Royalty and income taxes

Petroleum taxes generally fall into two categories – those that are calculated on profits earned(income taxes) and those calculated onproduction or sales (royalty or excise taxes). Thecategorisation is crucial: royalty and excise taxesdo not form part of revenue, while income taxesusually require deferred tax accounting but formpart of revenue.

Petroleum taxes – royalty and excise

Petroleum taxes that are calculated by applying a tax rate to a measure of revenue or volume donot fall within the scope of IAS 12 Income Taxesand are not income taxes. They do not form partof revenue or give rise to deferred tax liabilities.Revenue-based and volume-based taxes arerecognised when the production occurs orrevenue arises. These taxes are most oftendescribed as royalty or excise taxes. They aremeasured in accordance with the relevant tax



legislation and a liability is recorded for amountsdue that have not yet been paid to thegovernment.

Royalty and excise taxes are in effect the government’s share of the natural resourcesexploited and are a share of production free ofcost. They may be paid in cash or in kind. If incash, the entity sells the oil or gas and remits tothe government its share of the proceeds.Royalty payments in cash or in kind are excludedfrom gross revenues and costs.

Petroleum taxes based on profits

Petroleum taxes that are calculated by applying a tax rate to a measure of profit fall within thescope of IAS 12. The profit measure used tocalculate the tax is that required by the taxlegislation and will, accordingly, differ from theIFRS profit measure. Profit in this context isrevenue less costs as defined by the relevant taxlegislation, and thus might include costs that arecapitalised for financial reporting purposes.However it is not, for example, an allocation ofprofit oil in a PSA. Examples of taxes based onprofits include Petroleum Revenue Tax in the UK,Norwegian Petroleum Tax and AustralianResource Rent Tax.

Petroleum taxes on income are often ‘super’ taxes applied in addition to ordinary corporateincome taxes. The tax may apply only to profitsarising from specific geological areas orsometimes on a field-by-field basis within largerareas. The petroleum tax may or may not bedeductible when determining corporate incometax; this does not change its character as a taxon income. The computation of the tax is oftencomplicated. There may be a certain number ofbarrels or bcm that are free of tax, accelerateddepreciation and additional tax credits forinvestment. Often there is a minimum taxcomputation as well. Each complicating factor inthe computation must be separately evaluatedand accounted for in accordance with IAS 12.

Deferred tax must be calculated in respect of all taxes that fall within the scope of IAS 12. Thedeferred tax is calculated separately for each taxby identifying the temporary differences betweenthe IFRS carrying amount and the correspondingtax base for each tax. Petroleum income taxesmay be assessed on a field-specific basis or a

regional basis. An IFRS balance sheet and a taxbalance sheet will be required for each area orfield subject to separate taxation for thecalculation of the deferred tax.

The tax rate applied to the temporary differences will be the statutory rate for the relevant tax. The statutory rate may be adjusted for certainallowances and reliefs (eg, tax free barrels) incertain limited circumstances where the tax iscalculated on a field-specific basis without theopportunity to transfer profits or losses betweenfields.

Taxes in PSAs

Production sharing agreements are discussed in further detail in Chapter 1.3.1. However, a crucialquestion arises about the taxation of PSAs –when are amounts paid to the government asincome tax (and thus form part of revenue) andwhen are amounts a royalty and excluded fromrevenue. Some PSAs include a requirement forthe national oil company or another governmentbody to pay income tax on behalf of the operatorof the PSA. When does tax paid on behalf of anoperator form part of revenue and income taxexpense?

The revenue arrangements and tax arrangements are unique in each country and can vary within acountry, such that each major PSA is usuallyunique. However, there are common features thatwill drive the assessment as income tax, royaltyor government share of production. Among thecommon features that should be considered inmaking this determination are:

• whether a well established income tax regime exists;

• whether the tax is computed on a measure of profits; and

• whether the PSA requires the payment of income taxes, the filing of a tax return and establishes a legal liability for income taxes until such liability is discharged by payment from the entity or a third party.

Tax paid in cash or in kind

Tax is usually paid in cash to the relevant tax authorities. However, some governments allowpayment of tax through the delivery of oil instead


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of cash for income taxes, royalty and excisetaxes and amounts due under licences,production sharing contracts and the like.

The accounting for the tax charge and the settlement through oil should reflect thesubstance of the arrangement. Determining theaccounting is straightforward if it is an incometax (see definition above) and is calculated inmonetary terms. The volume of oil used to settlethe liability is then determined by reference to themarket price of oil. The entity has in effect ‘sold’the oil and used the proceeds to settle its taxliability. These amounts are appropriatelyincluded in gross revenue and tax expense.

Arrangements where the liability is calculated by reference to the volume of oil produced withoutreference to market prices can make it moredifficult to identify the appropriate accounting.These are most often a royalty or volume-basedtax. The accounting should reflect the substanceof the agreement with the government. Somearrangements will be a royalty fee, some will be a traditional profit tax, some will be anappropriation of profits and some will be acombination of these and more. The agreementor legislation under which oil is delivered to agovernment must be reviewed to determine thesubstance and hence the appropriate accounting.Different agreements with the same governmentmust each be reviewed as the substance of thearrangement, and hence the accounting maydiffer from one to another.

Tax ‘paid on behalf’ (POB)

POB arrangements are varied, but generally arise when a government entity will pay the income tax due by a foreign upstream entity to thegovernment on behalf of the foreign upstreamentity. This occurs where the upstream entity isthe operator of fields under a PSA and thegovernment entity is usually the national oilcompany that holds the government’s interest inthe PSA. The crucial issue in accounting for taxPOB arrangements are if they are akin to a taxholiday or if the upstream entity retains anobligation for the income tax.

POB arrangements that represent a tax holiday such that the upstream company has no legal taxobligation are accounted for as a tax holiday. The upstream company presents no tax expense

and does not gross up revenue for the tax paidon its behalf by the government entity. If theupstream company retains an obligation for theincome tax, it would follow the accountingdescribed above under Tax paid in cash or in kind.

1.2.10 Emission trading schemes

The ratification of the Kyoto Protocol by the EU required total emissions of greenhouse gaseswithin the EU member states to fall to 92% oftheir 1990 levels in the period between 2008 and2012. The introduction of the EU EmissionsTrading Scheme (EU ETS) on 1 January 2005represents a significant EU policy response to thechallenge. Under the scheme, EU member stateshave set limits on carbon dioxide emissions fromenergy intensive companies. The scheme workson a ‘cap’ and ‘trade’ basis and each memberstate of the EU is required to set an emissionscap covering all installations covered by thescheme.

The EU cap and trade scheme is expected to serve as a model for other governments seekingto reduce emissions.

There are also several non-Kyoto carbon markets in existence. These include the New South WalesGreenhouse Gas Abatement Scheme, theRegional Greenhouse Gas Initiative and WesternClimate Initiative in the United States and theChicago Climate Exchange in North America.

Accounting for ETS

The emission rights permit an entity to emit pollutants up to a specified level. The emissionrights are either given or sold by the governmentto the emitter for a defined compliance period.

Schemes in which the emission rights are tradable allow an entity to:

• emit fewer pollutants than it has allowances for and sell the excess allowances;

• emit pollutants to the level that it holds allowances for; or

• emit pollutants above the level that it holds allowances for and either purchase additional allowances or pay a fine.



IFRIC 3 Emission Rights was published in December 2004 to provide guidance on how toaccount for cap and trade emission schemes.The interpretation proved controversial and waswithdrawn in June 2005 due to concerns over theconsequences of the required accountingbecause it introduced significant incomestatement volatility. The withdrawal of IFRIC 3means there is no specific comprehensiveaccounting for cap and trade schemes.

The guidance in IFRIC 3 remains valid, but entitiesare free to apply variations provided that therequirements of all relevant IFRS standards aremet. Several approaches have emerged inpractice under IFRS. The scheme can result inthe recognition of assets (allowances), expenseof emissions, a liability (obligation to submitallowances) and potentially a government grant.

The allowances are intangible assets and are recognised at cost if separately acquired.Allowances that are received free of charge fromthe government are recognised either at fair valuewith a corresponding deferred income (liability),or at cost (nil) as allowed by IAS 20 Accountingfor Government Grants and Disclosure ofGovernment Assistance.

The allowances recognised are not amortised provided residual value is at least equal tocarrying value. The cost of allowances isrecognised in the income statement in line withthe profile of the emissions produced.

The government grant (if initial recognition at fair value under IAS 20 is chosen) is amortised to theincome statement on a straight-line basis overthe compliance period. An alternative to thestraight-line basis can be used if it is a betterreflection of the consumption of the economicbenefits of the government grant.

The entity may choose to apply the revaluation model in IAS 38 Intangible Assets for thesubsequent measurement of the emissionsallowances. The revaluation model requires thatthe carrying amount of the allowances is restatedto fair value at each balance sheet date, withchanges to fair value recognised directly in equityexcept for impairment, which is recognised in theincome statement. This is the accounting that isrequired by IFRIC 3 and is seldom used inpractice.

A provision is recognised for the obligation to deliver allowances or pay a fine to the extent thatpollutants have been emitted. The allowancesreduce the provision when they are used tosatisfy the entity’s obligations through delivery tothe government at the end of the scheme year.However, the carrying amount of the allowancescannot reduce the liability balance until theallowances are delivered.

1.3 Company-wide issues

1.3.1 Production sharing agreements and concessions

There are as many forms of production sharing arrangements (PSA) and concessions as thereare combinations of national, regional andmunicipal governments in oil producing areas.

A PSA is the method whereby governments facilitate the exploitation of their country’shydrocarbon resources by taking advantage ofthe expertise of a commercial oil and gas entity.Governments, particularly in emerging or poorernations, try to provide a stable regulatory and taxregime to create sufficient certainty forcommercial entities to invest in an expensive andlong-lived development process. An oil and gasentity will undertake exploration, supply thecapital, develop the resources found, build theinfrastructure and lift the natural resources. The government retains title to the hydrocarbonresources (whatever the quantity that is ultimatelyextracted) and often the legal title to all fixedassets constructed to exploit the resources. The government will take a percentage share ofthe output, which may be delivered in product orpaid in cash under an agreed pricing formula.The operating entity may only be entitled torecover specified costs plus an agreed profitmargin. It may have the right to extract resourcesover a specified period of time.

A concession agreement is much the same, although the entity will retain legal title to itsassets and does not share production with thegovernment. The government will still becompensated based on production quantitiesand prices – this is often described as aconcession rent, royalty or a tax.

PSAs and concessions are not standard even within the same legal jurisdiction. The more


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significant a new field is expected to be, themore likely that the relevant government will write specific legislation or regulations for it. Each must be evaluated and accounted for inaccordance with the substance of thearrangement. The entity’s previous experience of dealing with the relevant government will alsobe important, as it is not uncommon forgovernments to force changes in PSAs orconcessions based on changes in marketconditions or environmental factors. An agreementmay contain a right of renewal with no significantincremental cost. The government may have apolicy or practice with regard to renewal. Theseshould be assessed when estimating theexpected life of the agreement.

Exploration, development and productionassets in PSAs

The legal form of the PSA or concession should not impact on the recognition of exploration andevaluation (E&E) assets or production assets.Costs that meet the criteria of IFRS 6, IAS 38 orIAS 16 should be recognised in accordance withthe usual criteria where the entity is exposed tothe majority of the economic risks and hasaccess to the probable future economic benefitsof the assets. The period of the PSA orconcession should be longer than the expecteduseful life of the majority of the constructedassets. The probable hydrocarbon resources andcurrent prices should provide evidence that E&E,development and fixed asset investment will berecovered during the concession period. Assetsare appropriately recorded on the balance sheetof the entity beyond the E&E phase, if bothconditions are present.

A PSA that is shorter than the expected useful life of the related production assets or is a costplus arrangement can represent an arrangementwhereby the government compensates the entityfor exploration activities and the developmentand construction of fixed assets. The entityshould assess the arrangement to determine towhat extent it is bearing the risks associated withthe exploration, the reserves, etc, and to whatextent it is instead bearing the risks ofcontractual performance under the contract.Under arrangements where the entity is largelybearing the risks of its performance under the

PSA rather than the risks of the exploration andthe reserves, it can continue to capitalise E&Eand development costs, but fixed assets are notcapitalised as such. The entity instead may havea receivable from the government where it isallowed to retain oil extracted to the extent ofcosts incurred plus a profit margin. The accountingapplied in these circumstances is therefore inaccordance with IAS 39 rather than IAS 16.

All assets recognised are then accounted for under the usual policies of the entity forsubsequent measurement, depreciation,amortisation, impairment testing and de-recognition. Assets should be fully depreciated oramortised on a units of production basis by thedate that control passes back to the governmentor the concession ends. A PSA is almost alwaysa separate CGU for impairment testing purposesonce in production.

Revenue and costs of PSAs and concessions

The entity should record only its share of oil under a PSA as revenue. Oil extracted on behalfof a government is not revenue or a productioncost. The entity acts as the government’s agentto extract and deliver the oil or sell the oil andremit the proceeds. Many PSAs specify thatincome taxes owed by the entity are paid indelivered oil rather than cash. ‘Tax oil’ is recordedas revenue and as a reduction of the current taxliability to reflect the substance of thearrangement where the entity delivers oil to thevalue of its current tax liability. Any volume-basedtax is accounted for as royalty or excise taxwithin operating results.

Assets subject to depreciation, depletion or amortisation should be expensed in a mannerthat reflects the consumption of their economicbenefits. The units of production basis is usuallythe appropriate method.

1.3.2 Joint ventures

Joint ventures and other similar arrangements are frequently used by oil & gas companies as a way to share the high risks associated with theindustry or as a way of bringing in specialist skills to a particular project on an equity basis.The legal basis for a joint venture or thedescription of it may take various forms;establishing a joint venture might be achieved



through a formal joint venture contract, oralternatively the governance arrangements setout in a company’s constitution might give thesame result. The feature that distinguishes a jointventure from other forms of cooperation betweenparties is the presence of joint control. Anarrangement without joint control is not a jointventure.

Joint control

Joint control is the contractually-agreed sharing of control. It requires that an identified group ofventurers must unanimously agree on all keyfinancial and operating decisions. Put anotherway – each of those parties that share the jointcontrol have a veto right: they can each blockkey decisions if they do not agree. Not all partiesto the joint venture need to share joint control – itis possible for a small number of key venturers toshare joint control, and for other investors toaccount for their interest either as an investmentin an associate (if they have significant influence)or as an available for sale financial asset inaccordance with IAS 39.

A key test when identifying if joint control exists is to identify how disputes between ventures areresolved. If joint control exists, resolution ofdisputes will usually require eventual agreementbetween the venturers, independent arbitrationor, as a last resort, dissolution of the jointventure.

The nomination of one of the venturers as operator of the joint venture does not preventjoint control. The operator’s powers are usuallylimited to day-to-day operational decisions – allkey strategic financial and operating decisionsremain with the joint venture partners collectively.

Types of joint venture

Joint ventures are analysed into three classes; jointly controlled operations, jointly controlledassets and jointly controlled entities. Jointlycontrolled assets are common in the upstreamindustry and jointly controlled entities in thedownstream sector. Jointly controlled assetsexist when the venturers jointly own and controlthe assets used in the joint venture. Jointlycontrolled entities arise when the venturers jointly control an entity which, in turn holds theassets and liabilities of the joint venture. A jointly

controlled entity is usually, but not necessarily, a legal entity, such as a company. The key toidentifying the presence of an entity is todetermine whether the joint venture can performthe functions associated with an entity, such asentering into contracts in its own name, incurringand settling its own liabilities and holding a bankaccount in its own right.

Accounting for jointly controlled operations

Joint operations are often found where one party controls hydrocarbon rights and has productionfacilities and another party has transport facilitiesand/or processing capacity. The parties to thejoint operation will share the revenue andexpenses of the jointly produced end product.Each will retain title and control of its own assets.

The venturer should recognise 100% of the assets it controls and the liabilities it incurs aswell as its own expenses and its share of incomefrom the sale of goods or services from the JV.

Accounting for jointly controlled assets

A venturer to a jointly controlled assets arrangement recognises:

• its share of the jointly controlled asset, classified according to the nature of the asset;

• any liabilities the venturer has incurred;

• its proportionate share of any liabilities that arise from the jointly controlled assets;

• its share of expenses from the operation of the assets; and

• its share of any income arising from the operation of the assets (for example, ancillary fees from use by third parties).

Jointly controlled assets tend to reflect the sharing of costs and risk rather than the sharingof profits. An example is a joint venture interest inan oil field where each venturer receives its shareof the oil produced.

Accounting for jointly controlled entities

Jointly controlled entities can be accounted for either by proportionate consolidation or usingequity accounting. The choice between thesetwo methods is a policy choice, and must beapplied consistently to all jointly controlled


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entities. A key practical issue will sometimes beensuring that the results of the joint venture areincorporated by the venturer on the same basisas the venturer’s own results – ie, using the sameGAAP (IFRS) and the same accounting policychoices. The growing use of IFRS is helpingreduce the adjustments required but doesn’teliminate them.

Companies should be aware, however, that the IASB is proposing to eliminate the choice ofproportionate consolidation in certaincircumstances. Further details are included insection 2.

Contributions to joint ventures

It is common for venturers to contribute assets to a joint venture when it is created. This may be inthe form of cash or a non-monetary asset.Contributions of assets are a part disposal by thecontributing party, in return receiving a share ofthe assets contributed by the other venturers.Accordingly the contributor should recognise again/loss on the part disposal measured as thedifference between its share of the fair value ofthe assets contributed by the other venturers andthe other venturers’ share of the book value ofthe asset it contributed.

The venturer recognises its share of an asset contributed by other venturers at its share of the fair value of the asset contributed. This isclassified in the balance sheet according to the nature of the asset in the case of jointlycontrolled assets or when proportionateconsolidation is applied to a jointly controlledentity. The equivalent measurement basis isachieved when equity accounting is applied;however, the interest in the asset forms part ofthe equity accounted investment balance.

The same principles apply when one of the other venturers contributes a business to a jointventure; however, in this case one of the assetsrecognised will be goodwill, calculated in thesame way as in a business combination.

Investments with less than joint control

Some co-operative arrangements may appear to be joint ventures but fail on the basis thatunanimous agreement between venturers is notrequired for key strategic decisions. This may

arise when a super majority, for example an 80%majority, is required but where the threshold canbe achieved with a variety of combinations ofshareholders and no venturers are able toindividually veto the decisions of others.Accounting for these arrangements will dependon the way they are structured and the rights thateach venturer has.

When the arrangement is organised in an entity, each investor will account for its investmenteither using equity accounting in accordance withIAS 28 Investments in Associates (if it hassignificant influence) or at fair value as a financialasset in accordance with IAS 39. When theinvestors have an undivided interest in thetangible or intangible assets, they will typicallyhave a right to use a share of the operativecapacity of that asset. An example is when anumber of investors have invested in an oilpipeline and an investor with, say, a 20% interesthas the right to use 20% of the capacity of thepipeline. Industry practice is for an investor torecognise its undivided interest at cost lessaccumulated depreciation and any impairmentcharges.

An undivided interest in an asset is normally accompanied by a requirement to incur aproportionate share of the asset’s operating andmaintenance costs. These costs should berecognised as expenses in the income statementwhen incurred and classified in the same way asequivalent costs for wholly-owned assets.

Accounting within the joint venture

The preceding paragraphs describe the accounting by the investor in a joint venture. The joint venture itself will normally prepare itsown financial statements for reporting to the jointventure partners, for tax compliance or for otherreasons. It is increasingly common for thesefinancial statements to be prepared inaccordance with IFRS. Joint ventures aretypically created by the venturers contributingassets and businesses to the joint venture inexchange for their equity interest in the JV.Assets received by a joint venture in exchangefor issuing shares to a venturer is a transactionwithin the scope of IFRS 2 Share-basedPayment. Such assets are therefore recognisedat fair value. However, the accounting for the



receipt of a business contributed by a venturer isnot described within the IFRS literature. Twopolicies have developed. One is to recognise theassets and liabilities of the business, includinggoodwill, at fair value, similar to the accountingfor an asset contribution and the accounting for abusiness combination. The second is torecognise the assets and liabilities of thebusiness at the same book values as used in thecontributing party’s IFRS financial statements.The policy followed must be disclosed andconsistently applied.

1.3.3 Business combinations

Acquisition of assets and businesses are common in oil and gas. Entities seek to secureaccess to reserves or replace depleting reserves.These may be business combinations oracquisitions of groups of assets. IFRS 3 BusinessCombinations provides guidance on both typesof transactions, and the accounting can differsignificantly.

All business combinations are accounted for by applying the purchase method. The purchasemethod is summarised as follows:

a) identify the acquirer;

b) measure the cost of the combination; and

c) record the fair value of assets acquired and liabilities assumed.

Definition of a business

A business is an integrated set of activities managed together to provide a return toinvestors or other economic benefits. The keyelement of the definition is ‘integration’.Upstream activities in production will typicallyrepresent a business, whereas those at theexploration stage will typically represent acollection of assets. Projects that lie in thedevelopment stage will require consideration ofthe stage of development and other relevantfactors.

The accounting for a business combination and a group of assets can be substantially different. A business combination will usually result in therecognition of goodwill and deferred tax. An assettransaction qualifies for the initial recognitionexemption and therefore there is usually no

deferred tax. The consideration in an assettransaction is allocated to individual assetsacquired and liabilities assumed based onrelative fair values.

Allocation of the cost of the combination to assets and liabilities acquired

IFRS 3 requires all identifiable assets and liabilities (including contingent liabilities) acquiredto be recorded at their fair value. These includeassets and liabilities that may not have beenpreviously recorded by the entity acquired eg,acquired reserves and resources – proved,probable and possible.

IFRS 3 also requires recognition separately of intangible assets if they arise from contractual orlegal rights, or are separable from the business.The standard includes a list of items that arepresumed to satisfy the recognition criteria. The items that should satisfy the recognitioncriteria include trademarks, trade names, serviceand certification marks, Internet domain names,customer lists, customer contracts, use rights(such as drilling, water, hydrocarbon, etc),patented/unpatented technology, etc, many ofwhich may apply to oil and gas companies.

Fair values of assets are often determined using discounted cash flow models. These modelsshould include the tax amortisation benefit (TAB)available to the typical market participant. The TAB represents the value associated with the tax deductibility for an asset. Asset valuesobtained through direct market observationsrather than the use of discounted cash flows(DCFs) already reflect the general tax benefitassociated with the asset. Differences betweenthe general tax benefit of each asset and thespecific tax benefits for the acquirer are includedwithin goodwill because these are entity-specific.

Goodwill

Past practice in upstream transactions accounted for under national GAAP or previousversions of IFRS seldom resulted in therecognition of significant amounts of goodwill.The consideration paid was allocated to proved,probable and possible reserves.

IFRS 3 requires that the fair value of the assets acquired and liabilities assumed are recognised.The difference between consideration and the fair


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value of net assets gives rise to positive ornegative goodwill. This residual approach to thecalculation of goodwill required by IFRS 3 is likelyto result in the goodwill in upstream businesscombinations. Any goodwill is likely to representthe value paid for assets that do not qualify forseparate recognition on the balance sheet (suchas an assembled workforce), synergies paid forby the acquirer and, occasionally, overpayments.

However, IFRS 3 requires certain assets and liabilities acquired in a business combination tobe recognised on a basis other than fair value.Examples include pension liabilities and deferredtax. Deferred tax is calculated after the fair valuesof the other identifiable assets and liabilities havebeen determined by comparing the fair valuerecognised for accounting purposes with the taxbase of each asset and liability. Consequently,the mechanics of the deferred tax calculation andthe goodwill calculation might result in goodwillbeing recognised solely as a result of therecognition of the deferred tax. That is, goodwillmight be recognised when there is no expectationof goodwill because there are no unrecognisedassets, no synergies and no overpayments. This anomaly will persist until the IASB revisesthe deferred tax standard, expected in 2009.

1.3.4 Functional currency

Oil and gas entities commonly undertake transactions in more than one currency, ascommodity prices are often denominated in USdollars and costs are typically denominated inthe local currency. Determination of the functionalcurrency can require significant analysis andjudgement.

An entity’s functional currency is the currency of the primary economic environment in which itoperates. This is the currency in which the entitymeasures its results and financial position. An entity’s presentation currency is the currencyin which it presents its accounts. Reportingentities may select any presentation currency(subject to the restrictions imposed by localregulations or shareholder agreements). However, the functional currency must reflect thesubstance of the entity’s underlying transactions,events and conditions; it is unaffected by thechoice of presentation currency.

Exchange differences can arise for two reasons: when a transaction is undertaken in a currencyother than the entity’s functional currency; orwhen the presentation currency differs from thefunctional currency.

Determining the functional currency

Identifying the functional currency for an oil and gas entity can be complex because there areoften significant cash flows in both the US dollarand local currency.

Determining the functional currency, management should take into account primarilythe currency that dominates the determination ofthe sales prices and that most influencesoperating costs.

The currency in which selling prices are denominated and settled is often the currencythat mainly dominates the determination of salesprices, but this is not necessarily the case. Many sales within the oil and gas industry areconducted either in, or with reference to, the USdollar. However, the US dollar may not alwaysbe the main influence on these transactions. For many of the commodities sold by oil and gasentities, it is difficult to identify a single countrywhose competitive forces and regulations mainlydetermine the selling prices.

If the primary indicators do not provide an obvious answer to what the functional currencyis, the currency in which an entity’s finances aredenominated should be considered ie, thecurrency in which funds from financing activitiesare generated and the currency in which receiptsfrom operating activities are retained.

A typical oil and gas entity in the production stage receives its revenue predominantly in USdollars with most of its costs denominated in thelocal currency and only some in US dollars.Management may conclude that the US dollar isthe functional currency, as the majority of thecash flows are denominated and settled in theUS dollar.

Oil and gas entities at different stages of operation may reach a different view about theirfunctional currency. Functional currency is not afree choice, and an entity’s functional currencydoes not change unless there are changes in itsoperations and transaction flows.



Determining the functional currency of holding companies and treasury companies may present some unique challenges; these havelargely internal sources of cash although theymay pay dividends, make investments, raise debt and provide risk management services. The underlying source of the cash flows to suchcompanies is usually the appropriate basis fordetermining the functional currency.


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2 Developments from the IASB

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2.1 Extractive activities research project

The extractive activities project at the IASB is a comprehensive research project and the first steptowards a standard focused on upstreamextractive activities. Any new standard isexpected to supersede IFRS 6 Exploration forand Evaluation of Mineral Resources.

The project was approved in 2004 and is considering the unique issues associated withaccounting for upstream activities. This involvesresearching:

• financial reporting issues associated with oil & gas reserves and resources (including the exploration for reserves and resources) – in particular whether and how to define, recognise, measure and disclose reserves and resources; and

• considering other issues related to extractive activity accounting as identified in the IASC’s Extractive Industries Issues Paper.

A Discussion Paper is due in late 2008. Despite the scope of the project including ‘other issues’and referring to the previous Issues Paper, it isexpected to focus almost exclusively on thereserves and resources recognition questions.The Issues Paper spanned a wide range ofissues relevant to the industry includingdecommissioning and restoration, revenuerecognition, joint ventures and impairment. TheIASB’s discussions to date have raised thepossibility of recognising and measuring reserveson the balance sheet at fair value. This will likelybe given consideration as one of the possibleaccounting models during the Board’sdeliberations and its public consultations.

2.2 Borrowing costsThe IASB issued amendments to IAS 23 Borrowing Costs in March 2007. IAS 23Rremoves the policy choice of either capitalising orexpensing borrowing costs and requiresmanagement to capitalise borrowing costsattributable to qualifying assets. Qualifying assetsare assets that take a substantial time to getready for their intended use or sale. An exampleis self-constructed assets such as power plant,buildings, machinery.

The changes to the standard were made as part of the IASB’s and FASB’s short-termconvergence project. The elimination of theoption to expense borrowing costs does notachieve full convergence with US GAAP, as sometechnical differences remain (for example,definitions of borrowing costs and qualifyingassets).

The effective date of IAS 23R is 1 January 2009, with earlier adoption permitted. The amendmentsare to be applied prospectively; comparatives willnot need to be restated. The Board has providedadditional relief by allowing management todesignate a particular date on which it can startapplying the amendments. For example,management can decide to designate 1 October2008 as a starting date, because the companystarts a project for which management would liketo capitalise interest when it applies IAS 23R in2009.

2.3 Emissions Trading SchemesThe IASB added the emissions trading topic to its agenda after the withdrawal of IFRIC 3Emission Rights in 2005. The project wastemporarily deferred (due to deferral of theproject relating to government grants) and againactivated in December 2007 with the increasinginternational interest in emission trading schemesand the diversity in practice that has arisen. TheBoard decided to limit the scope of the project tothe issues that arise in accounting for emissionstrading schemes, rather than addressing broadlythe accounting for all government grants (whichwould have involved re-activating the IAS 20project).

The purpose of the project is to comprehensively address the accounting for emissions tradingschemes. It will cover the following issues: • whether the emissions allowances are an asset

(considering different ways of acquiring the asset) and what its nature is;

• recognition and measurement of allowances;• whether liability exists, what its nature is and

how it should be measured.

The project is in the research phase, with the Board gathering information on the characteristicsof various emissions trading schemes. This willbe the basis for preparation of a comprehensivepackage that outlines the alternative models that

2 Developments from the IASB



could be used to account for emissions tradingschemes. The timing of an initial due processdocument and the estimated project completiondate is not yet determined.

2.4 ED 9 Joint ArrangementsThe IASB published in September 2007 the exposure draft ED 9 Joint Arrangements, whichsets out proposals for the recognition anddisclosure of interests in joint arrangements. It isintended to replace IAS 31 Interests in JointVentures and it is another step towards the goalsof the Memorandum of Understanding betweenthe IASB and the FASB on the convergence ofIFRS and US GAAP. The changes proposed areto IFRS only; there are no changes proposed to US GAAP.

ED 9’s core principle is that parties to a joint arrangement recognise their contractual rightsand obligations arising from the arrangement.The ED therefore focuses on the recognition ofassets and liabilities by the party to the jointarrangement.

The scope of the ED is broadly the same as that of IAS 31. That is, unanimous agreement isrequired between the key parties that have thepower to make the financial and operating policydecisions for the joint arrangement.

There are two principal changes proposed by ED 9. The first is the elimination of proportionateconsolidation for a jointly controlled entity. Thesecond change is the introduction of a ‘dualapproach’ to the accounting for jointarrangements.

Elimination of proportionate consolidation

Eliminating proportionate consolidation will have a fundamental impact on the income statementand balance sheet for some entities. Entities thatcurrently use proportionate consolidation toaccount for jointly controlled entities may need toaccount for many of these using the equitymethod. These entities will replace the line-by-line proportionate consolidation of the incomestatement and balance sheet by a single netresult and a single net investment balance.

Switching from proportionate consolidation toequity accounting has the following impacts:

• Revenues are reduced: the venturer cannot present its share of the joint venture’s revenue as part of its own revenue.

• Tangible and intangible assets are reduced: the gross presentation of the venturer’s share of the JV’s tangible assets, intangible assets, other assets and liabilities is replaced by a single net amount, classified as part of its investments.

Although the information about these gross amounts is included in the notes to the financialstatements, removing them from the primarystatements diminishes their prominence. Movingto equity accounting for an E&P joint ventureralso raises the question about the presentation ofreserves. Some regulators require that thereserves presented reflect only those that willresult in revenue when produced. Thisaccounting change would – in thosecircumstances – require a restatement of thereserves reported.

The ‘dual approach’ to joint arrangements

The second change is the introduction of a ‘dual approach’ to the accounting for joint arrangements.ED 9 carries forward with modification from IAS31, the three types of joint arrangement; eachtype having specific accounting requirements.The first two types are Joint Operations and Joint Assets. The description of these types andthe accounting for them is consistent with JointlyControlled Operations and Jointly ControlledAssets in IAS 31. The third type of jointarrangement is a Joint Venture, which isaccounted for using equity accounting. A JointVenture is identified by the party having rightsonly to a share of the outcome of the jointarrangement, for example a share of the profit or loss of the joint arrangement. The key changeis that a single joint arrangement may containmore than one type; for example Joint Assetsand a Joint Venture. The party to such a jointarrangement accounts first for the assets andliabilities of the Joint Assets arrangement andthen uses a residual approach to equityaccounting for the Joint Venture part of the jointarrangement.


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The introduction of the dual approach will require all companies to review each of their joint ventureagreements. They will need to determine whethereach joint arrangement exhibits the propertiesand characteristics of joint assets/jointoperations (typically a direct use ofassets/obligation for liabilities) and/or thecharacteristics of a Joint Venture (an interest inthe outcome of the JV, eg, a share of profitgenerated by the Joint Venture). An interest in theoutcome/net result will more commonly arisewhen the joint arrangement is incorporated;however, unincorporated joint arrangements arecapable, in some circumstances, of returning anet result/profit to the partners, and so shouldalso be analysed.

Other considerations

The results presented in financial statements will reflect the cumulative impact of all relevantfactors. For example, if a company has aninterest in the net result of an E&P joint venture itwill account for its interest in the joint ventureusing equity accounting. However, if it alsopurchases (its share of) oil from the joint ventureand sells it to a third party, it will record revenuefor those third-party sales in addition to equityaccounting for its interest in the joint venture,after appropriate eliminations.

A company that finds itself moving from proportionate consolidation to equity accountingmay also want to consider the impact of itsinternal management reporting. IFRS 8 OperatingSegments requires disclosure of segmentalinformation on the same basis as is provided tothe company’s chief operating decision-maker(CODM). The accounting basis used for providinginformation to the CODM is used to present thesegment information in accordance with IFRS 8.Accordingly, if the CODM is presented withinformation prepared using proportionateconsolidation, then this is the basis that shouldbe presented in the segment information andreconciled to the primary financial statements.

The ED includes a number of illustrative examples, including a farm-in arrangement and aunitisation. These examples describe theexpected accounting for these arrangements in

accordance with the ED proposals. Theaccounting described in the examples mayrequire some entities to modify their accountingpractices in these areas.

Timetable

The IASB expects to publish a new IFRS for joint arrangements in quarter 4 of 2008. Theimplementation date has not been decided yetbut might be as early as 2010. Those companiesthat conduct a significant amount of theirbusiness through joint ventures may want tofollow the development of this standard carefully.

2.5 IFRS 3, Business combinations (revised) and IAS 27, Consolidated and separate financial statements (revised)

The IASB issued two revised standards in January 2008: IFRS 3R Business Combinationsand IAS 27R Consolidated and SeparateFinancial Statements. The revised standards areeffective for annual periods beginning on or after 1 July 2009. The standards result in more fairvalue changes being recorded through theincome statement and cement the ‘economicentity’ view of the reporting entity.

The key differences between IFRS 3R and IAS 27R and the previous standards are as follows:

• Business combinations achieved by contract alone and business combinations involving only mutual entities are accounted for under the revised IFRS 3.

• Minor changes in the definition of a business with more significant changes in the application guidance.

• Transaction costs incurred in connection with the business combination are expensed when incurred and are no longer included in the cost of the acquiree.

• An acquirer recognises contingent consideration at fair value at the acquisition date. Subsequent changes in the fair value of such contingent consideration will often affect the income statement.



• The acquirer recognises either the entire goodwill inherent in the acquiree, independent of whether a 100% interest is acquired (full goodwill method), or only the portion of the total goodwill that corresponds to the proportionate interest acquired (as currently the case under IFRS 3).

• Any previously-held non-controlling interest (as a financial asset or associate, for example) is remeasured to its fair value at the date of obtaining control, and a gain or loss is recognised in the income statement.

• There are new provisions to determine whether a portion of the consideration transferred for the acquiree or the assets acquired and liabilities assumed are part of the business combination or part of another transaction to be accounted for separately under the applicable IFRS.

• There is new guidance on classification and designation of assets, liabilities and equity instruments acquired or assumed in a business combination on the basis of the conditions that exist at the acquisition date, except for leases and insurance contracts. This guidance includes reassessment of embedded derivatives.

• Intangible assets are recognised separately from goodwill if they are identifiable – ie, if they are separable or arise from contractual or other legal rights. The reliably-measurable criterion is presumed to be met.

• Recognition of the acquiree’s deferred tax assets after the initial accounting for the business combination leads to an adjustment of goodwill only if the adjustment is made within the measurement period (not exceeding one year from the acquisition date) and the adjustment results from new information about facts and circumstances that already existed at the acquisition date. Otherwise, it must be reflected in the income statement with no change to goodwill.

• All purchases of equity interests from and sales of equity interests to non-controlling interests are treated as treasury share transactions. Any difference between the amount of consideration received or given and the amount of non-controlling interest is recorded in equity. Entities will no longer be able to report gains on the partial disposal of a subsidiary.

• Additional disclosure requirements.

Several of the requirements may be of interest to oil and gas entities. The slight changes in thedefinition of a business and the relatedapplication guidance may push transactions into business combination accounting sooner inthe development process. The requirement to re-assess all contracts and arrangements forembedded derivatives may also result in moreclassified as derivatives with subsequent incomestatement volatility. Contingent consideration ismore common in mining, with selling shareholdersseeking to profit from previously undiscoveredresources or favourable price movements. Thesearrangements are less common in oil and gas butdo exist. All such arrangements will be capturedby the contingent consideration guidance andrecognised as liabilities of the acquirer whetheror not payment is probable at the date of thetransaction. All subsequent changes are incomestatement items.


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3 IFRS/US GAAP Differences

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There are a number of differences between IFRS and US GAAP. This section provides a summarydescription of those IFRS/US GAAP differences that are particularly relevant to oil & gas entities.These differences relate to: exploration and evaluation, reserves & resources, depreciation, inventoryvaluation, impairment, disclosure of resources, decommissioning obligations, financial instruments,revenue recognition, joint ventures and business combinations.

3.1 Exploration and evaluation

Capitalisation inthe exploration &evaluation phase

Impairment of E&Eassets

No formal capitalisation modelsprescribed. IFRS 6 permitscontinuation of previous accountingpolicy for E&E assets but only untilevaluation is complete. Wide range ofpolicies possible from capitalisationof all E&E expenditures after licenceacquisition to the expense of all suchexpenditures. However, changes tocapitalisation polices are restricted tothose which move the policy closerto compliance with the IFRSFramework.

IFRS 6 provides specific relief forE&E assets. Cash-generating units(CGUs) may be combined up to thelevel of a segment for E&E assets. Impairment testing is requiredimmediately before assets arereclassified from E&E todevelopment.

IFRS 6 also provides guidance in relation to identifying trigger eventsfor an impairment review.

Impairment charges against E&E assets are reversed if recoverableamount subsequently increases.

Evaluation of exploration activity that is completed after the balance sheetdate and that concludes that theexploration has been unsuccessful, isclassified as a non-adjusting (type II)post-balance sheet event.

Two formal models – successfulefforts and full cost, in accordancewith FAS 19 and Regulation S-XRule 4-10. Types of expenditure thatmay be capitalised are defined.

No similar relief for E&E assets. This is unlikely to result in a GAAPdifference when the company usessuccessful efforts under US GAAP. A company applying full cost willprobably be able to shelterunsuccessful exploration costs inlarger pools until these are depletedthrough production.

No reversal of impairment charges is permitted.

Evaluation of exploration activity that is completed after the balance sheetdate and that concludes that theexploration has been unsuccessful,is classified as a type I (adjusting)post-balance sheet event (FIN 36).

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3.3 Depreciation of production and downstream assets

Depletion ofproduction assets

Components ofproperty, plant andequipment

The reserve and resourceclassifications used for the depletioncalculation are not specified. Anentity should develop an appropriateaccounting policy for depletion andapply the policy consistently, eg, unitof production method. Commonlyused categories of reserves includeproved developed, or proveddeveloped and undeveloped orproved and probable.

Significant parts (components) of anitem of PPE are depreciatedseparately if they have different usefullives. Pool-wide depletion ofproduction assets not permitted.

The definitions of reserves used are those adopted by the SEC.Proved reserves are used fordepletion of acquisition costs andproved developed reserves are usedfor depletion of development costs.

Cost categories follow major typesof assets as required by FAS 19 –individual items are not separated.Production assets held in a full costpool depleted on a pool-wide basis.

Issue IFRS US GAAP

3.2 Reserves & resources

Definitions No system of reserve classificationprescribed. No restriction on thecategories used for financial reportingpurposes.

Entities must use the definitions ofreserves and resources approved bythe SEC. Only proved reserves can bedisclosed for financial reportingpurposes. Proved and proveddeveloped are used for depletiondepending on the nature of the costs.

Issue IFRS US GAAP

3.4 Inventory valuation issues

Impact of changesin market pricesafter balance sheetdate

Inventories measured at the lower ofcost and net realisable value. Netrealisable value does not reflectchanges in the market price of theinventory after the balance sheet dateif this reflects events and conditionsthat arose after the balance sheetdate.

Inventories measured at the lower ofcost and market value. When marketvalue is lower than cost at thebalance sheet date, a recovery ofmarket value after the balance sheetdate but before the issuance of thefinancial statements is recognised asa type I (adjusting) post balance sheetevent.

Issue IFRS US GAAP



3.5 Impairment of production and downstream assets

Impairment testtriggers

Level at whichimpairment tested

Measurement of impairment

Reversal ofimpairment charge

Assets or groups of assets (cashgenerating units) are tested forimpairment when indicators ofimpairment are present.

Assets tested for impairment at thecash generating unit (CGU) level.CGU is the smallest identifiable groupof assets that generates cash inflowsthat are largely independent of thecash inflows from other assets orgroups of assets.

Production assets typically tested for impairment at the field level. A pool-wide impairment test is notpermitted.

Impairment is measured as theexcess of the asset’s carryingamount over its recoverable amount.The recoverable amount is the higherof its value in use and fair value lesscosts to sell.

Impairment losses, other than thoserelating to goodwill, are reversedwhen there has been a change in theeconomic conditions or in theexpected use of the asset.

Long-lived assets are tested forimpairment only if indicators arepresent and an undiscounted cashflow test suggests that the carryingamount of an asset will not berecovered from its use and eventualdisposal. Unproved properties areassessed periodically for impairmentbased on results of drilling activity,firm plans, etc.

Similar to IFRS except that thegrouping of assets is based onlargely independent cash flows (inand out) rather than just cashinflows.

Production assets accounted for under the full cost method are testedfor impairment on a pool-wide basis.

Impairment of proved properties ismeasured as the excess of theasset’s carrying amount over its fairvalue. Impairment of unprovedproperties is based on results ofactivities.

Impairment losses are neverreversed.

Issue IFRS US GAAP

3.6 Disclosure of resources

Disclosurerequirements

No specific requirements to disclosereserves and resources; however, IAS1 includes general requirement todisclose additional informationnecessary for a fair presentation.

Detailed disclosures required by FAS69 and SEC Regulation S-X.

Issue IFRS US GAAP


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3.7 Decommissioning obligations

Measurement ofliability

Recognition of decommissioningasset

Liability measured at the bestestimate of the expenditure requiredto settle the obligation.

Risks associated with the liability are reflected in the cash flows or in thediscount rate.

The discount rate is updated at each balance sheet date.

The adjustment to PPE when the decommissioning liability isrecognised forms part of the asset to be decommissioned.

Range of cash flows prepared andrisk weighted to calculate expectedvalues.

Risks associated with the liability are only reflected in the cash flows,except for credit risk, which isreflected in the discount rate.

The discount rate for an existing liability is not updated. Accordingly,downward revisions to undiscountedcash flows are discounted using thecredit adjusted risk-free rate whenthe liability was originally recognised.Upward revisions, however, arediscounted using the current creditadjusted risk-free rate at the time ofthe revision.

Decommissioning liability need not be recognised for assets withindeterminate life.

The asset recognised in respect of adecommissioning obligation is aseparate asset from the asset to bedecommissioned.

This distinction is relevant because of the limits placed on subsequentadjustments to the asset as a result of remeasurement of thedecommissioning liability. Inparticular, the limit that thedecommissioning asset cannot bereduced below zero for US GAAPcompared with the limit that theasset to be decommissioned cannotbe reduced below zero for IFRS.

Issue IFRS US GAAP



Continued on next page

3.8 Financial instruments and embedded derivativesIFRS and US GAAP take broadly consistent approaches to the accounting for financial instruments; however, many detailed differences exist between the two.

IFRS and US GAAP define financial assets and financial liabilities in similar ways. Both require recognition of financial instruments only when the entity becomes a party to the instrument’scontractual provisions. Financial assets, financial liabilities and derivatives are recognised initially atfair value under IFRS and US GAAP. Transaction costs that are directly attributable to the acquisitionor issue of a financial asset or financial liability are added to its fair value on initial recognition unlessthe asset or liability is measured subsequently at fair value with changes in fair value recognised inprofit or loss. Subsequent measurement depends on the classification of the financial asset orfinancial liability. Certain classes of financial asset or financial liability are measured subsequently atamortised cost using the effective interest method and others, including derivative financialinstruments, at fair value through profit or loss. The Available For Sale (AFS) class of financial assets ismeasured subsequently at fair value through equity (other comprehensive income). These generalclasses of financial asset and financial liability are used under both IFRS and US GAAP, but theclassification criteria differ in certain respects.

Selected differences between IFRS and US GAAP are summarised below.

Definition of aderivative

A derivative is a financial instrument:

• whose value changes in response to a specified variable or underlying rate (for example, interest rate);

• that requires no or little net investment; and

• that is settled at a future date.

Sets out similar requirements,except that the terms of thederivative contract should:

• require or permit net settlement; and

• identify a notional amount.

There are therefore some derivatives that may fall within the IFRSdefinition, but not the US GAAPdefinition.

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Separation of embeddedderivatives

Own-use exemption

Derivatives embedded in hybridcontracts are separated when:

• the economic characteristics and risks of the embedded derivatives are not closely related to the economic characteristics and risks of the host contract;

• a separate instrument with the same terms as the embedded derivative would meet the definition of a derivative; and

• the hybrid instrument is not measured at fair value through profit or loss.

Under IFRS, reassessment of whetheran embedded derivative needs to beseparated is permitted only whenthere is a change in the terms of thecontract that significantly modifiesthe cash flows that would otherwisebe required under the contract.

A host contract from which an embedded derivative has beenseparated, qualifies for the own-useexemption if the own-use criteria aremet.

Contracts to buy or sell a non-financial item that can be settled netin cash or another financialinstrument are accounted for asfinancial instruments unless thecontract was entered into andcontinues to be held for the purposeof the physical receipt or delivery ofthe non-financial item in accordancewith the entity’s expected purchase,sale or usage requirements.

Application of the own-use exemption is a requirement – not anelection.

Similar to IFRS except that there are some detailed differences of what ismeant by ‘closely related’.

Under US GAAP, if a hybrid instrument contains an embeddedderivative that is not clearly andclosely related to the host contractat inception, but is not required tobe bifurcated, the embeddedderivative is continuouslyreassessed for bifurcation.

The normal purchases and normal sales exemption cannot be claimedfor a contract that contains aseparable embedded derivative –even if the host contract wouldotherwise qualify for the exemption.

Similar to IFRS, contracts that qualify to be classified as for normalpurchases and normal sales do notneed to be accounted for asfinancial instruments. The conditionsunder which the normal purchaseand normal sales exemption isavailable is similar to IFRS butdetailed differences exist.

Application of the normal purchases and normal sales exemption is anelection.

Issue IFRS US GAAP



3.9 Revenue recognition

Overlift/underlift Revenue is recognised inoverlift/underlift situations on amodified entitlements basis.

US GAAP permits a choice of thesales/liftings method or theentitlements method for revenuerecognition.

Issue IFRS US GAAP

3.10 Joint ventures

Definition

Types of jointventure

A joint venture is a contractualagreement that requires all significantdecisions to be taken unanimously byall parties sharing control.

IFRS distinguishes between threetypes of joint venture:

• jointly controlled entities – the arrangement is carried on through a separate entity (company or partnership);

• jointly controlled operations – each venturer uses its own assets for a specific project; and

• jointly controlled assets – a project carried on with assets that are jointly owned.

A corporate joint venture is acorporation owned and operated bya small group of businesses as aseparate and specific business orproject for the mutual benefit of themembers of the group.

Refers only to jointly controlledentities, where the arrangement iscarried on through a separatecorporate entity.

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Jointly controlled entities

Contributions to ajointly controlledentity

Either the proportionate consolidationmethod or the equity method isallowed. Proportionate consolidationrequires the venturer’s share of theassets, liabilities, income andexpenses to be either combined on aline-by-line basis with similar items inthe venturer’s financial statements, orreported as separate line items in theventurer’s financial statements.

A venturer that contributes non-monetary assets, such as shares ornon-current assets, to a jointlycontrolled entity in exchange for anequity interest in the jointly controlledentity recognises in its consolidatedincome statement the portion of thegain or loss attributable to the equityinterests of the other venturers,except when:

• the significant risks and rewards of the contributed assets have not been transferred to the jointly controlled entity;

• the gain or loss on the assets contributed cannot be measured reliably; or

• the contribution transaction lacks commercial substance.

Prior to determining the accountingmodel, an entity first assesseswhether the joint venture is a VariableInterest Entity (VIE). If the joint ventureis a VIE, the primary beneficiaryshould consolidate. If the joint ventureis not a VIE, venturers assess theaccounting using the voting interestmodel. If control does not exist thentypically the arrangement will meetthe criteria to apply the equity methodto measure the investment in thejointly controlled entity. Proportionateconsolidation is generally notpermitted except for unincorporatedentities operating in certain industries,such as the oil & gas industry.

Common practice is for an investor(venturer) to record contributions toa joint venture at cost (ie, theamount of cash contributed and thebook value of other non-monetaryassets contributed). However,sometimes, appreciated non-cashassets are contributed to a newlyformed joint venture in exchange foran equity interest when others haveinvested cash or other financial-typeassets with a ready market value.Practice and existing literature in thisarea vary. Arguments have been putforth that assert that the investorcontributing appreciated non-cashassets has effectively realised part of the appreciation as a result of its interest in the venture to whichothers have contributed cash.Immediate gain recognition can beappropriate. The specific facts andcircumstances will affect gainrecognition, and require carefulanalysis.

Issue IFRS US GAAP



3.11 Business CombinationsThe following summary reflects differences between the requirements of IFRS 3 (Issued 2004) and FAS 141 (Issued 2001).

Purchase method – fair values onacquisition

Purchase method – contingentconsideration

Purchase method – minority interestsat acquisition

Purchase method – intangible assetswith indefiniteuseful lives andgoodwill

Purchase method – negative goodwill

Assets, liabilities and contingentliabilities of acquired entity arerecognised at fair value where fairvalue can be measured reliably.Goodwill is recognised as theresidual between the considerationpaid and the percentage of the fairvalue of the net assets acquired.

In-process research and development is generally capitalised.

Liabilities for restructuring activities are recognised only when theacquiree has an existing liability atacquisition date. Liabilities for futurelosses or other costs expected to beincurred as a result of the businesscombination cannot be recognised.

Included in cost of combination at acquisition date if adjustment isprobable and can be measuredreliably.

Stated at minority’s share of the fairvalue of acquired identifiable assets,liabilities and contingent liabilities.

Capitalised but not amortised.Goodwill and indefinite-livedintangible assets are tested forimpairment at least annually at eitherthe cash-generating unit (CGU) levelor groups of CGUs, as applicable.

The identification and measurementof acquiree’s identifiable assets,liabilities and contingent liabilities arereassessed. Any excess remainingafter reassessment is recognised inthe income statement immediately.

There are specific differences fromIFRS.

Contingent liabilities of the acquiree are recognised if, by the end of theallocation period:

• their fair value can be determined, or

• they are probable and can be reasonably estimated.

Specific rules exist for acquiredin-process research anddevelopment (generally expensed).

Some restructuring liabilities relating solely to the acquired entity may berecognised if specific criteria aboutrestructuring plans are met.

Generally, not recognised untilcontingency is resolved and theamount is determinable.

Stated at minority’s share of pre-acquisition carrying value of netassets.

Similar to IFRS, although the level ofimpairment testing and theimpairment test itself are different.

Any remaining excess afterreassessment is used to reduceproportionately the fair valuesassigned to non-current assets (withcertain exceptions). Any excess isrecognised in the income statementimmediately as an extraordinarygain.

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The revisions made to FAS 141 in 2007 and to IFRS 3 in 2008 remove some of the differencesbetween IFRS and US GAAP. The following table identifies those aspects of business combinationsaccounting from the table above which will become consistent between IFRS and US GAAP as aresult of the revisions to the standards.

Acquisition method– fair values onacquisition

Acquisition method– contingentconsideration

Acquisition method– negative goodwill

Assets and liabilities of the acquired entity are recognised at fair value. This includes acquired in-process research and development.

Liabilities for restructuring activities are recognised only when the acquiree has an existing liability at the acquisition date.

Contingent consideration recognised at fair value.

The identification and measurement of acquiree’s identifiable assets,liabilities and contingent liabilities are reassessed. Any excess remainingafter reassessment is recognised in the income statement immediately.

Issue IFRS and US GAAP



The following summary reflects differences between the requirements of IFRS 3 (Revised 2008) and FAS 141 (Revised 2007).

Assets andliabilities arisingfrom contingencies

Employee benefitarrangements anddeferred tax

Non-controllinginterest (NCI) –formerly MinorityInterest

Contingentconsideration

Lessor operatinglease assets

Recognise contingent liabilities at fairvalue if fair value can be measuredreliably. If not within the scope of IAS39, measure subsequently at higherof amount initially recognised andbest estimate of amount required tosettle (under IAS 37).

Contingent assets are not recognised.

Measure in accordance with IFRS 2 and IAS 12, not at fair value.

Measure at fair value or at NCI shareof fair value of identifiable net assets.

If not within scope of IAS 39, accountfor subsequently under IAS 37.Measure financial asset or liabilitycontingent consideration at fair value,with changes recognised in earningsor other comprehensive income.

Value of asset includes terms oflease.

Liabilities and assets subject tocontractual contingencies arerecognised at fair value. Recogniseliabilities and assets subject to othercontingencies only if more likely than not that they meet definition ofasset or liability at acquisition date. After recognition, retain initialmeasurement until new informationis received, then measure at thehigher of amount initially recognisedand amount under FAS 5 forliabilities subject to contingencies,and lower of acquisition date fairvalue and the best estimate of afuture settlement amount for assetssubject to contingencies.

Measure in accordance with FAS123 and FAS 109, not at fair value.

Measure at fair value.

Measure subsequently at fair value,with changes recognised in earningsif classified as asset or liability.

Value lease separately from asset.

Issue IFRS US GAAP


4 Financial disclosure examples

51Financial reporting in the oil and gas industry4 Financial d

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4.1 Exploration & evaluationSuccessful Efforts Method

BG Group plcExploration expenditure“BG Group uses the ‘successful efforts’ methodof accounting for exploration expenditure.Exploration expenditure, including licenceacquisition costs, is capitalised as an intangibleasset when incurred and certain expenditure,such as geological and geophysical explorationcosts, is expensed. A review of each licence orfield is carried out, at least annually, to ascertainwhether proved reserves have been discovered.When proved reserves are determined, therelevant expenditure, including licence acquisitioncosts, is transferred to property, plant andequipment and depreciated on a unit ofproduction basis. Expenditure deemed to beunsuccessful is written off to the incomestatement. Exploration expenditure is assessedfor impairment when facts and circumstancessuggest that its carrying amount exceeds itsrecoverable amount. For the purposes ofimpairment testing, exploration and productionassets may be aggregated into appropriate cashgenerating units based on considerationsincluding geographical location, the use ofcommon facilities and marketing arrangements.”

Annual Report and Accounts 2007, BG Group plc, p. 74

Royal Dutch Shell plcExploration costs“Shell follows the successful efforts method ofaccounting for oil and natural gas explorationcosts. Exploration costs are charged to incomewhen incurred, except that exploratory drillingcosts are included in property, plant andequipment, pending determination of provedreserves. Exploration wells that are more than12 months old are expensed unless (a) provedreserves are booked, or (b) (i) they have foundcommercially producible quantities of reserves,and (ii) they are subject to further exploration orappraisal activity in that either drilling ofadditional exploratory wells is under way or firmlyplanned for the near future or other activities arebeing undertaken to sufficiently progress theassessing of reserves and the economic andoperating viability of the project.”

Annual Report and Accounts 2007, Royal Dutch Shell plc, p. 118

Initial recognition and reclassification out of E&E under IFRS6

BP plcLicence and property acquisition costs“Exploration licence and leasehold propertyacquisition costs are capitalized within intangiblefixed assets and amortized on a straight-linebasis over the estimated period of exploration.Each property is reviewed on an annual basis toconfirm that drilling activity is planned and it isnot impaired. If no future activity is planned,the remaining balance of the licence andproperty acquisition costs is written off. Upondetermination of economically recoverablereserves (‘proved reserves’ or ‘commercialreserves’), amortization ceases and the remainingcosts are aggregated with explorationexpenditure and held on a field-by-field basis asproved properties awaiting approval within otherintangible assets. When development isapproved internally, the relevant expenditure istransferred to property, plant and equipment.”

Exploration expenditure“Geological and geophysical exploration costsare charged against income as incurred. Costsdirectly associated with an exploration well arecapitalized as an intangible asset until the drillingof the well is complete and the results havebeen evaluated. These costs include employeeremuneration, materials and fuel used, rig costs,delay rentals and payments made to contractors.If hydrocarbons are not found, the explorationexpenditure is written off as a dry hole. Ifhydrocarbons are found and, subject to furtherappraisal activity, which may include the drillingof further wells (exploration or exploratory-typestratigraphic test wells), are likely to be capableof commercial development, the costs continueto be carried as an asset. All such carried costsare subject to technical, commercial andmanagement review at least once a year toconfirm the continued intent to develop orotherwise extract value from the discovery.When this is no longer the case, the costs arewritten off. When proved reserves of oil andnatural gas are determined and development issanctioned, the relevant expenditure istransferred to property, plant and equipment.”

Annual Report and Accounts 2007, BP plc, p. 102

4 Financial disclosure examples



Dry Holes

Hydro ASAExploration and development costs of oil andgas reserves“Hydro uses the successful efforts method ofaccounting for oil and gas exploration anddevelopment costs, and is in accordance withIFRS 6 Exploration for and Evaluation of MineralResources. Exploratory costs, excluding the costof exploratory wells and acquired explorationrights, are charged to expense as incurred.Drilling costs for exploratory wells are capitalizedpending the determination of the existence ofproved reserves. If reserves are not found, thedrilling costs are charged to operating expense.”

Annual Report and Accounts 2007, Hydro ASA, p. F12

4.2 Reserves & resourcesEstimation of reserves

Royal Dutch Shell plcEstimation of oil and gas reserves“Oil and gas reserves are key elements in Shell’sinvestment decision-making process which isfocussed on generating value. They are also animportant element in testing for impairment.Changes in proved oil and gas reserves will alsoaffect the standardised measure of discountedcash flows and changes in proved oil and gasreserves, particularly proved developed reserves,will affect unit-of-production depreciationcharges to income.

Proved oil and gas reserves are the estimatedquantities of crude oil, natural gas and naturalgas liquids that geological and engineering datademonstrate with reasonable certainty to berecoverable in future years from known reservoirsunder existing economic and operatingconditions, i.e., prices and costs as of the datethe estimate is made. Proved developed reservesare reserves that can be expected to berecovered through existing wells with existingequipment and operating methods. Estimates ofoil and gas reserves are inherently imprecise,require the application of judgement and aresubject to future revision. Accordingly, financialand accounting measures (such as thestandardised measure of discounted cash flows,depreciation, depletion and amortisation charges,

and decommissioning and restoration provisions)that are based on proved reserves are alsosubject to change.

Proved reserves are estimated by reference toavailable reservoir and well information, includingproduction and pressure trends for producingreservoirs and, in some cases, subject todefinitional limits, to similar data from otherproducing reservoirs. Proved reserves estimatesare attributed to future development projects onlywhere there is a significant commitment toproject funding and execution and for whichapplicable governmental and regulatoryapprovals have been secured or are reasonablycertain to be secured. Furthermore, estimates ofproved reserves only include volumes for whichaccess to market is assured with reasonablecertainty. All proved reserves estimates aresubject to revision, either upward or downward,based on new information, such as fromdevelopment drilling and production activities orfrom changes in economic factors, includingproduct prices, contract terms or developmentplans. In general, changes in the technicalmaturity of hydrocarbon reserves resulting fromnew information becoming available fromdevelopment and production activities havetended to be the most significant cause of annualrevisions.

In general, estimates of reserves for undevelopedor partially developed fields are subject to greateruncertainty over their future life than estimatesof reserves for fields that are substantiallydeveloped and depleted. As a field goes intoproduction, the amount of proved reserves willbe subject to future revision once additionalinformation becomes available through, forexample, the drilling of additional wells or theobservation of long-term reservoir performanceunder producing conditions. As those fields arefurther developed, new information may lead torevisions.

Changes to Shell’s estimates of proved reserves,particularly proved developed reserves, alsoaffect the amount of depreciation, depletion andamortisation recorded in the ConsolidatedFinancial Statements for property, plant andequipment related to hydrocarbon productionactivities. These changes can for example be theresult of production and revisions.

4 Financial disclosure exam

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A reduction in proved developed reserves willincrease depreciation, depletion and amortisationcharges (assuming constant production) andreduce income.”


Disclosure of resources

BG Group plc(A) Proved reserves“Proved reserves are the estimated quantities ofgas and oil which geological and engineeringdata demonstrate, with reasonable certainty, tobe recoverable in future years from knownreservoirs under existing economic and operatingconditions. Proved developed reserves are thosereserves which can be expected to be recoveredthrough existing wells with existing equipmentand operating methods. Proved undevelopedreserves are those quantities that are expectedto be recovered from new wells on undrilledacreage or from existing wells where relativelymajor expenditure is required for completion.Proved undeveloped reserves comprise totalproved reserves less total proved developedreserves.”


4.3 Depreciation of production anddownstream assetsDepletion, depreciation and amortisation

BP plc“Oil and natural gas properties, including relatedpipelines, are depreciated using a unit-ofproduction method. The cost of producing wellsis amortized over proved developed reserves.Licence acquisition, field development and futuredecommissioning costs are amortized over totalproved reserves. The unit-of-production rate forthe amortization of field development costs takesinto account expenditures incurred to date,together with approved future developmentexpenditure required to develop reserves. Otherproperty, plant and equipment is depreciated ona straight-line basis over its expected useful life.”


Depreciation of components

Hydro ASA“Hydro depreciates separately any component ofan item of property, plant and equipment whenthat component has a useful life and cost that issignificant in relation to the total PP&E cost andPP&E useful life. At each financial year-endHydro reviews the residual value and useful life ofour assets, with any estimate changes accountedfor prospectively over the remaining useful life ofthe asset.”


4.4 Impairment

BP plcImpairment of intangible assets and property,plant and equipment“The group assesses assets or groups of assetsfor impairment whenever events or changes incircumstances indicate that the carrying value ofan asset may not be recoverable. If any suchindication of impairment exists, the group makesan estimate of its recoverable amount. Individualassets are grouped for impairment assessmentpurposes at the lowest level at which there areidentifiable cashflows that are largelyindependent of the cashflows of other groups ofassets. An asset group’s recoverable amount isthe higher of its fair value less costs to sell andits value in use. Where the carrying amount of anasset group exceeds its recoverable amount, theasset group is considered impaired and is writtendown to its recoverable amount. In assessingvalue in use, the estimated future cash flows areadjusted for the risks specific to the asset groupand are discounted to their present value using apre-tax discount rate that reflects current marketassessments of the time value of money.”




Value in use

BP plc“Given the nature of the group’s activities,information on the fair value of an asset is usuallydifficult to obtain unless negotiations withpotential purchasers are taking place.Consequently, unless indicated otherwise, therecoverable amount used in assessing theimpairment charges described below is value inuse. The group generally estimates value in useusing a discounted cash flow model. The futurecashflows are usually adjusted for risks specificto the asset and discounted using a pre- taxdiscount rate of 11% (2006 10% and 2005 10%).This discount rate is derived from the group’spost-tax weighted average cost of capital. Insome cases the group’s pre-tax discount ratemay be adjusted to account for political risk inthe country where the asset is located.”


Calculation of recoverable amount – Fairvalue less costs to sell

Royal Dutch Shell plc“Other than properties with no proved reserves(where the basis for carrying costs in theConsolidated Balance Sheet is explained under“Exploration costs”), the carrying amounts ofmajor property, plant and equipment arereviewed for possible impairment annually, whileall assets are reviewed whenever events orchanges in circumstances indicate that thecarrying amounts for those assets may not berecoverable. If assets are determined to beimpaired, the carrying amounts of those assetsare written down to their recoverable amount,which is the higher of fair value less costs to selland value in use determined as the amount ofestimated risk adjusted discounted future cashflows. For this purpose, assets are groupedbased on separately identifiable and largelyindependent cash flows. Assets held for sale arerecognised at the lower of the carrying amountand fair value less cost to sell. No furtherprovision for depreciation is charged on suchassets.”


Contracted cash flows in VIU

Royal Dutch Shell plc“Estimates of future cash flows used in theevaluation for impairment of assets related tohydrocarbon production are made using riskassessments on field and reservoir performanceand include outlooks on proved reserves andunproved volumes, which are then riskweightedutilising the results from projections of geological,production, recovery and economic factors.

Estimates of future cash flows are based onmanagement estimates of future commodityprices, market supply and demand, productmargins and, in the case of oil and gasproperties, the expected future productionvolumes. Other factors that can lead to changesin estimates include restructuring plans andvariations in regulatory environments. Expectedfuture production volumes, which include bothproved reserves as well as volumes that areexpected to constitute proved reserves in thefuture, are used for impairment testing becauseShell believes this to be the most appropriateindicator of expected future cash flows, used asa measure of value in use. Estimates of futurecash flows are risk-weighted to reflect expectedcash flows and are consistent with those used insubsidiaries’ business plans. A discount ratebased on Shell’s marginal cost of debt is used inimpairment testing. Expected cash flows are thenrisk-adjusted to reflect specific localcircumstances or risks surrounding the cashflows. Shell reviews the discount rate to beapplied on an annual basis although it has beenstable in recent years.”

Annual Report and Accounts 2007, Royal Dutch Shell plc,p. 118 and 123


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4.5 Decommissioning obligationRevisions to decommissioning provisions

BG Group plcDecommissioning costs“Where a legal or constructive obligation hasbeen incurred, provision is made for the netpresent value of the estimated cost ofdecommissioning at the end of the producinglives of fields.

When this provision gives accessto future economic benefits, an asset isrecognised and then subsequently depreciated inline with the life of the underlying producing field,otherwise the costs are charged to the incomestatement. The unwinding of the discount on theprovision is included in the income statementwithin finance costs. Any changes to estimatedcosts or discount rates are dealt withprospectively.

The estimated cost of decommissioning at theend of the producing lives of fields is reviewed atleast annually and engineering estimates andreports are updated periodically. Provision ismade for the estimated cost of decommissioningat the balance sheet date, to the extent thatcurrent circumstances indicate BG Group willultimately bear this cost. The payment dates oftotal expected future decommissioning costs areuncertain but are currently anticipated to bebetween 2010 and 2047.”

Annual Report and Accounts 2007, BG Group plc, p. 74 and 109

Decommissioning provisions

Hydro ASAAsset retirement obligations and similar liabilities“Hydro accounts for asset retirement obligations,including decommissioning, restoration andsimilar liabilities related to the retirement ofnoncurrent assets under IAS 37 Provisions,Contingent Liabilities and Contingent Assetswhich prescribes the accounting for obligationsassociated with the retirement of non-currentassets, and IAS 16 Property, plant andequipment. The fair value of the asset retirementobligation is recognized as a liability when it isincurred, and added to the carrying amount of

the non-current asset as an element of its cost.The effect of the passage of time on the liabilityis recognized as an accretion expense, includedin Financial expense, and the costs added to thecarrying value of the asset are subsequentlydepreciated over the assets’ useful life.Measurement of an asset retirement obligationrequires us to evaluate legal, technical andeconomic data to determine which activities orsites are subject to asset retirement obligations,as well as the method, cost and timing of suchobligations.”


4.6 Financial instruments and embeddedderivativesScope of IAS 39

BG Group plcCommodity instruments“Within the ordinary course of business theGroup routinely enters into sale and purchasetransactions for commodities. The majority ofthese transactions take the form of contracts thatwere entered into and continue to be held for thepurpose of receipt or delivery of the commodityin accordance with the Group’s expected sale,purchase or usage requirements. Such contractsare not within the scope of IAS 39.

Certain long-term gas sales contracts operatingin the UK gas market have terms within thecontract that constitute written options, andaccordingly they fall within the scope of IAS 39.In addition, commodity instruments are used tomanage certain price exposures in respect ofoptimising the timing and location of its physicalgas and LNG commitments. These contracts arerecognised on the balance sheet at fair valuewith movements in fair value recognised in theincome statement, see Presentation of resultsabove, note 2, page 82, and note 10, page 96.

The Group uses various commodity basedderivative instruments to manage some of therisks arising from fluctuations in commodityprices. Such contracts include physical and netsettled forwards, futures, swaps and options.Where these derivatives have been designated ascash flow hedges of underlying commodity price



exposures, certain gains and losses attributableto these instruments are deferred in equity andrecognised in the income statement when theunderlying hedged transaction crystallises.

All other commodity contracts within the scopeof IAS 39 are measured at fair value with gainsand losses taken to the income statement.

Gas contracts and related derivative instrumentsassociated with the physical purchase and resaleof third-party gas are presented on a netbasis within other operating income.”


Measurement of long-term contracts thatdo not qualify for ‘own use’

BG Group plcValuation“The Group calculates the fair value of interestrate and currency exchange rate derivativeinstruments by using market valuations whereavailable or, where not available, by discountingall future cash flows by the market yield curve atthe balance sheet date.

The fair value of commodity contracts andcommodity related derivatives is based onforward price curves, where available. Whereobservable market valuations are unavailable, thefair value on initial recognition is the transactionprice and is subsequently determined usingquotes from thirdparties or the Group’s forwardplanning assumptions for the price of gas, othercommodities and indices.

One of the assumptions underlying the fair valueof long-term UK gas contracts is that the gasmarket in the UK is liquid for two years.”


Embedded derivatives

BP plc“Derivatives embedded in other financialinstruments or other host contracts are treatedas separate derivatives when their risks and

characteristics are not closely related to those ofthe host contract. Contracts are assessed forembedded derivatives when the group becomesa party to them, including at the date of abusiness combination. Embedded derivatives aremeasured at fair value at each balance sheetdate. Any gains or losses arising from changes infair value are taken directly to profit or loss.”


4.7 Revenue recognition issuesRevenue recognition – Exchanges

BP plc“Revenues associated with the sale of oil, naturalgas, natural gas liquids, liquefied natural gas,petroleum and chemicals products and all otheritems are recognized when the title passes to thecustomer. Physical exchanges are reported net,as are sales and purchases made with acommon counterparty, as part of an arrangementsimilar to a physical exchange. Similarly, wherethe group acts as agent on behalf of a third partyto procure or market energy commodities, anyassociated fee income is recognized but nopurchase or sale is recorded.”


4.8 Royalty and income taxesPetroleum taxes

Centrica plcPetroleum revenue tax (PRT)“The definitions of an income tax in IAS 12,Income Taxes, have led management to judgethat PRT should be treated consistently withother income taxes. The charge for the year ispresented within taxation on profit fromcontinuing operations in the Income Statement.Deferred amounts are included within deferredtax assets and liabilities in the Balance Sheet.”

Annual Report and Accounts 2007, Centrica plc, p. 68


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4.9 Emission Trading SchemesAccounting for ETS

Centrica plcEU Emissions Trading Scheme and renewableobligations certificates“Granted CO2 emissions allowances received ina period are initially recognised at nominal value(nil value). Purchased CO2 emissions allowancesare initially recognised at cost (purchase price)within intangible assets. A liability is recognisedwhen the level of emissions exceed the level ofallowances granted. The liability is measured atthe cost of purchased allowances up to the levelof purchased allowances held, and then at themarket price of allowances ruling at the balancesheet date, with movements in the liabilityrecognised in operating profit. Forward contractsfor the purchase or sale of CO2 emissionsallowances are measured at fair value withgains and losses arising from changes in fairvalue recognised in the Income Statement.The intangible asset is surrendered at the end ofthe compliance period reflecting the consumptionof economic benefit. As a result no amortisationis recorded during the period.

Purchased renewable obligation certificates areinitially recognised at cost within intangibleassets. A liability for the renewables obligation isrecognised based on the level of electricitysupplied to customers, and is calculated inaccordance with percentages set by the UKGovernment and the renewable obligationcertificate buyout price for that period. Theintangible asset is surrendered at the end of thecompliance period reflecting the consumption ofeconomic benefit. As a result no amortisation isrecorded during the period.”

Annual Report and Accounts 2007, Centrica plc, p. 62

4.10 Joint venturesAccounting for joint ventures

BP plcInterests in joint ventures“A joint venture is a contractual arrangementwhereby two or more parties (venturers)undertake an economic activity that is subject tojoint control. Joint control exists only when the

strategic financial and operating decisionsrelating to the activity require the unanimousconsent of the venturers. A jointly controlledentity is a joint venture that involves theestablishment of a company, partnership or otherentity to engage in economic activity that thegroup jointly controls with its fellow venturers.

The results, assets and liabilities of a jointlycontrolled entity are incorporated in thesefinancial statements using the equity method ofaccounting. Under the equity method, theinvestment in a jointly controlled entity is carriedin the balance sheet at cost, plus postacquisitionchanges in the group’s share of netassets of the jointly controlled entity, lessdistributions received and less any impairment invalue of the investment. Loans advanced tojointly controller entities are also included in theinvestment on the group balance sheet.The group income statement reflects the group’sshare of the results after tax of the jointlycontrolled entity. The group statement ofrecognized income and expense reflects thegroup’s share of any income and expenserecognized by the jointly controlled entity outsideprofit and loss.

Financial statements of jointly controlled entitiesare prepared for the same reporting year as thegroup. Where necessary, adjustments are madeto those financial statements to bring theaccounting policies used into line with those ofthe group.

Unrealized gains on transactions between thegroup and its jointly controlled entities areeliminated to the extent of the group’s interest inthe jointly controlled entities. Unrealized lossesare also eliminated unless the transactionprovides evidence of an impairment of the assettransferred.

The group assesses investments in jointlycontrolled entities for impairment wheneverevents or changes in circumstances indicatethat the carrying value may not be recoverable.If any such indication of impairment exists, thecarrying amount of the investment is comparedwith its recoverable amount, being the higher ofits fair value less costs to sell and value in use.



Where the carrying amount exceeds therecoverable amount, the investment is writtendown to its recoverable amount.

The group ceases to use the equity method ofaccounting on the date from which it no longerhas joint control over, or significant influence inthe joint venture, or when the interest becomesheld for sale.

Certain of the group’s activities, particularly inthe Exploration and Production segment, areconducted through joint ventures where theventurers have a direct ownership interest inand jointly control the assets of the venture.The income, expenses, assets and liabilities ofthese jointly controlled assets are included in theconsolidated financial statements in proportionto the group’s interest.”


Accounting for jointly controlled operations

BG Group plcBasis of consolidation“The Financial Statements comprise aconsolidation of the accounts of the Companyand its subsidiary undertakings and incorporatethe results of its share of jointly controlled entitiesand associates using the equity method ofaccounting. Consistent accounting policies havebeen used to prepare the consolidated FinancialStatements.

Most of BG Group’s Exploration and Productionactivity is conducted through jointly controlledoperations. BG Group accounts for its ownshare of the assets, liabilities and cash flowsassociated with these jointly controlledoperations using the proportional consolidationmethod.”


Accounting for jointly controlled or ownedassets

Hydro ASAJointly controlled assets or operations“Hydro accounts for jointly controlled assets oroperations using the proportional method ofaccounting. In some instances Hydro participatesin arrangements, where Hydro and the otherpartners have a direct ownership in specificallyidentified assets or direct participation in certainoperations of another entity. These jointlycontrolled assets or operations are accountedfor by including Hydro’s percentage ownershipshare of the assets, liabilities, income andexpense on a line-by-line basis in the groupfinancial statements (the proportional method).”

Jointly owned assets or operations“Hydro accounts for jointly owned assets oroperations using the proportional method ofaccounting. Based on a contractual commitment,Hydro and the other parties to the contract havedirect ownership in specifically identified assetsor direct participation in certain operations.These jointly owned assets or operations areaccounted for by including Hydro’s percentageownership share of the assets, liabilities, incomeand expense on a line-by-line basis in the groupfinancial statements (the proportional method).”



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Investments with less than joint control

Hydro ASAInvestments in associates and joint ventures“Associates Hydro accounts for associates usingthe equity method. The definition of an associateis based on Hydro’s ability to exercise significantinfluence, which is the power to participate in thefinancial and operating policies of the entity.Significant influence is assumed to exist if Hydroowns between 20 to 50 percent of the votingrights. However, exercise of judgment may leadto the conclusion of significant influence atownership levels less than 20 percent or a lack ofsignificant influence at ownership percentagesgreater than 20 percent. Hydro uses the equitymethod for a limited number of investees whereHydro owns less than 20 percent of the votingrights, based on an evaluation of the governancestructure in each investee.”


4.11 Business combinationsGoodwill

BG Group plc“Business combinations and goodwillIn the event of a business combination, fairvalues are attributed to the net assets acquired.Goodwill, which represents the differencebetween the purchase consideration and the fairvalue of the net assets acquired, is capitalisedand subject to an impairment review at leastannually, or more frequently if events or changesin circumstances indicate that the goodwill maybe impaired. Goodwill is treated as an asset ofthe relevant entity to which it relates, includingforeign entities. Accordingly, it is re-translatedinto pounds Sterling at the closing rate ofexchange at each balance sheet date.”


Allocation of the cost of the combination toassets and liabilities acquired

BP plcBusiness combinations and goodwill“Business combinations are accounted for usingthe purchase method of accounting. The costof an acquisition is measured as the cash paidand the fair value of other assets given, equityinstruments issued and liabilities incurred orassumed at the date of exchange, plus costsdirectly attributable to the acquisition. Theacquired identifiable assets, liabilities andcontingent liabilities are measured at their fairvalues at the date of acquisition. Any excess ofthe cost of acquisition over the net fair value ofthe identifiable assets, liabilities and contingentliabilities acquired is recognized as goodwill.Any deficiency of the cost of acquisition belowthe fair values of the identifiable net assetsacquired (i.e. discount on acquisition) is creditedto the income statement in the period ofacquisition. Where the group does not acquire100% ownership of the acquired company, theinterest of minority shareholders is stated at theminority’s proportion of the fair values of theassets and liabilities recognized. Subsequently,any losses applicable to the minorityshareholders in excess of the minority interest onthe group balance sheet are allocated against theinterests of the parent.At the acquisition date, any goodwill acquired isallocated to each of the cash-generating unitsexpected to benefit from the combination’ssynergies. For this purpose, cash-generatingunits are set at one level below a businesssegment.

Following initial recognition, goodwill is measuredat cost less any accumulated impairment losses.Goodwill is reviewed for impairment annually ormore frequently if events or changes incircumstances indicate that the carrying valuemay be impaired.

Impairment is determined by assessing therecoverable amount of the cash-generating unitto which the goodwill relates. Where therecoverable amount of the cash-generating unitis less than the carrying amount, an impairmentloss is recognized.



Goodwill arising on business combinations priorto 1 January 2003 is stated at the previouscarrying amount under UK generally acceptedaccounting practice.

Goodwill may also arise upon investments injointly controlled entities and associates, beingthe surplus of the cost of investment over thegroup’s share of the net fair value of theidentifiable assets. Such goodwill is recordedwithin investments in jointly controlled entitiesand associates, and any impairment of thegoodwill is included within the earnings fromjointly controlled entities and associates.”


4.12 Functional currencyDetermining the functional currency

Royal Dutch Shell plc“The functional currency for most upstreamcompanies and for other companies withsignificant international business is the USdollar, but other companies usually have theirlocal currency as their functional currency.Foreign exchange risk arises when certaintransactions are denominated in a currencythat is not the entity’s functional currency.Typically these transactions are income/expenseor non-monetary item related.”



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The extracts from third-party publications that are contained in this document are for illustrativepurposes only; the information in these third-party extracts has not been verified byPricewaterhouseCoopers and does not necessarily represent the views of PricewaterhouseCoopers;the inclusion of a third-party extract in this document should not be taken to imply any endorsementby PricewaterhouseCoopers of that third-party.


Global contacts

Richard PatersonGlobal Energy, Utilities & Mining LeaderTelephone: +1 713 356 5579Email: [email protected]

Mark KingGlobal Oil & Gas IFRS GroupTelephone: +44 20 7804 6878Email: [email protected]

Territory contacts

Africa

AngolaJulian InceTelephone: +244 222 395004Email: [email protected]

GabonElias PungongTelephone: +241 77 23 35Email: [email protected]

NigeriaUyiosa AkpataTelephone: +234 1 320 2101Email: [email protected]

Southern AfricaStanley SubramoneyTelephone: +27 11 797 4380Email: [email protected]

Asia-Pacific

AustraliaDerek KidleyTelephone: +61 2 8266 9267Email:[email protected]

ChinaGavin ChuiTelephone: +86 10 6533 2188Email: [email protected]

IndiaNityanand GuptaTelephone: +91 11 4141 0501Email: [email protected]

IndonesiaWilliam DeertzTelephone: +62 21 521 3975Email: [email protected]


Contact us


Europe

AustriaGerhard PrachnerTelephone: +43 1 501 88 1800Email: [email protected]

Central and Eastern EuropePeter MitkaTelephone: +420 251 151 231Email: [email protected]

DenmarkPer Timmermann Telephone: +45 3945 3945Email: [email protected]

FinlandJuha TuomalaTelephone: +358 9 2280 1451Email: [email protected]

France Philippe GiraultTelephone: +33 1 5657 8897Email: [email protected]

GermanyManfred WiegandTelephone: +49 201 438 1517Email: [email protected]

GreeceSocrates Leptis-BourgiTelephone: +30 210 687 4693Email: [email protected]

IrelandCarmel O’ConnorTelephone: +353 1 792 6288Email: [email protected]

ItalyJohn McQuistonTelephone: +390 6 57025 2439Email: [email protected]

NetherlandsAad GroenenboomTelephone: +31 26 3712 509Email: [email protected]

Fred KoningsTelephone: +31 70 342 6150Email: [email protected]

NorwayOle Schei MartinsenTelephone: +47 95 26 11 62Email: [email protected]

Gunnar SletteboTelephone: +47 95 26 11 45Email: [email protected]

PortugalLuis FerreiraTelephone: +351 213 599 296Email: [email protected]

Russia & CISDave GrayTelephone: +7 495 967 6311Email: [email protected]

Randol JusticeTelephone: +7 495 967 6465Email: [email protected]

SpainFrancisco MartinezTelephone: +34 915 684 704Email: [email protected]

SwedenMats EdvinssonTelephone: +46 8 555 33706Email: [email protected]

SwitzerlandRalf SchlaepferTelephone: +41 58 792 1620Email: [email protected]

United KingdomRoss HunterTelephone: +44 20 7804 4326Email: [email protected]

63Financial reporting in the oil and gas industryC

ontact us



Middle East

Paul SuddabyTelephone: +971 4 3043 451Email: [email protected]

The Americas

CanadaJohn WilliamsonTelephone: +1 403 509 7507Email: [email protected]

Alistair BrydenTelephone: +1 403 509 7354Email: [email protected]

Latin AmericaJorge BacherTelephone: +54 11 4850 6801Email: [email protected]

United StatesRich PatersonTelephone: +1 713 356 5579Email: [email protected]

Global Accounting Consulting Services IFRS

Mary DolsonTelephone: +44 20 7804 2930Email: [email protected]

Michael StewartTelephone: +44 20 7804 6829Email: [email protected]

Further information

Olesya HatopGlobal Energy, Utilities & Mining MarketingTelephone: +49 201 438 1431Email: [email protected]


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