Financial reporting in the utilities industry* · PDF file · 2015-06-031.3.1...

Energy, Utilities & Mining

Financial reporting in theutilities industry*International Financial Reporting Standards

April 2008

*connectedthinking

08PwC0291 - IFRS Utilities final edit 10.04.2008 11:54 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 utilities industry is key to the world economy, and an increasing number of companies are nowoperating on an international and, sometimes,global scale. The development of IFRS offersconsiderable long-term advantages for manyutilities companies but, along the way, it bringsconsiderable challenges. The utilities industry ischaracterised, for example, by the need forsignificant upfront investment, often withuncertainty about outcomes over a long-termtime horizon. Its geopolitical, environmental,energy and natural resource supply and tradingchallenges, combined with often complex

stakeholder 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 utilities industry’ describes the financial reportingimplications of IFRS across a number of areasselected for their particular relevance to utilitiescompanies. 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.

This publication does not describe all IFRSs applicable to utilities 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 utilities partners.

Manfred WiegandGlobal Utilities Leader

Foreword

Foreword

1Financial reporting in the utilities industry


Contents

Introduction 5

1 Utilities Value Chain & Significant Accounting Issues 7

1.1 Generation 9

1.1.1 Fixed assets & components 9

1.1.2 Borrowing costs 9

1.1.3 Decommissioning obligations 10

1.1.4 Impairment 11

1.1.5 Arrangements that may contain a lease 12

1.1.6 Emission Trading Scheme and Certified Emission Reductions 13

1.2 Transmission & Distribution 15

1.2.1 Fixed assets & components 15

1.2.2 Customer contributions 16

1.2.3 Regulatory assets & liabilities 16

1.3 Retail 18

1.3.1 Customer acquisition costs 18

1.3.2 Customer discounts 18

1.4 Company-wide Issues 18

1.4.1 Service concession arrangements 18

1.4.2 Business combinations 19

1.4.3 Financial instruments 21

1.4.4 Trading and risk management 25

2 Developments from the IASB 29

2.1 Borrowing costs 30

2.2 Emissions Trading Schemes 30

2.3 Revenue recognition project 30


Contents


2.4 IFRS 3, Business Combinations (revised) and IAS 27, Consolidated and Separate Financial Statements (revised) 31

2.5 ED 9 Joint Arrangements 32

3 IFRS/US GAAP Differences 35

3.1 Fixed assets and components 36

3.2 Decommissioning obligations 37

3.3 Impairment 38

3.4 Arrangements that may contain a lease 39

3.5 Regulatory Assets and Liabilities 39

3.6 Business combinations 40

3.7 Concession arrangements 41

3.8 Financial instruments and trading & risk management 43

4 Financial disclosure examples 45

4.1 Decommissioning obligations 46

4.2 Impairment 48

4.3 Arrangements that may contain a lease 51

4.4 Emission Trading Scheme and Certified Emission Reductions 51

4.5 Customer contributions 52

4.6 Regulatory assets & liabilities 53

4.7 Business combinations 53

4.8 Concession arrangements 54

4.9 Financial instruments 54

Contact us 66


What is the focus of this publication?

This publication considers the major accountingpractices adopted by the utility industry underInternational Financial Reporting Standards(IFRS).

The need for this publication has arisen due to:

• the adoption of IFRS by utility 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 utility industry, who are often faced with alternative accounting practices;

• investors and other users of utility 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 utility entities; and/or

• historical varying international practice.

The utility industry has not only experienced the transition to IFRS, it has also seen:

• 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 of PricewaterhouseCoopers in the provision of accounting services to the utility industry. This leadership position enablesPricewaterhouseCoopers’ Global Utility IndustryGroup to make recommendations and leaddiscussions on international standards andpractice.

We hope you find this publication useful.

Introduction

Introduction



1 Utilities Value Chain & Significant Accounting Issues

7Financial reporting in the utilities industry1 U

tilities Value Chain &

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ccounting Issues


• Fixed Assets & Components

• Borrowing costs

• Decommissioning obligations

• Impairment

• Arrangements that may contain a lease

• Emission Trading Scheme and Certified Emission Reductions

Support Functions/Trading and Risk Management

Generation Transmission and Distribution Retail

All utility entities, whether gas, power or waterutilities, face similar issues associated withsourcing the item, delivering it to the customer,and maintaining the infrastructure used to do so.Power utilities face the added complexity ofhandling a commodity that cannot be stored inthe way that other commodities can be stored.

A traditional integrated power company (utility) generates electricity and sends it around thecountry or region via high-voltage transmissionlines, finally delivering it to customers through aretail distribution network. The industry continuesto evolve, and many different operational andregulatory models are now seen. Generatorscontinue to diversify supplies; fossil fuels stilldominate but there is an increasing focus on bio-fuels, co-generation and renewable sourcessuch as wind and wave power. Some Westerngovernments are considering the construction ofnew nuclear power plants, a move that wouldhave been unthinkable even a few years ago.

The regulatory environment differs from country to country, or even within a country and can becomplex and challenging. Pressure to introduceand increase competition and to diversify supplyis apparent, as well as schemes that createfinancial incentives to reduce emissions andincrease the use of renewable sources.

Previously integrated businesses may be split by regulation into generation, transmission,distribution and retail businesses. Competitionmay then be introduced for the generation andretail segments. Generators will look to competeon price and secure long-term fuel supplies,balancing this against potentially volatile marketprices for wholesale power. The distributionbusiness may see the incumbent operator forcedto grant access to other suppliers to its network.Power customers are beginning to behave likeany other group of retail customers and exercisechoice, develop brand loyalty, shop for the bestrates or look for an attractive bundle of services

1 Utilities Value Chain & Significant Accounting Issues

8 PricewaterhouseCoopers

Utilities Value Chain and Significant Accounting Issues

• Fixed Assets & Components

• Customer contributions

• Regulatory assets & liabilities

• Concession arrangements

• Business combinations

• Financial instruments

• Trading and risk management

• Customer acquisition costs

• Customer discounts


that might include gas, phone, water and internetservices as well as power.

The regulatory environment with continuing government involvement in pricing, security ofsupply, pressure to reduce emissions and otherpollutants and increasing competition all impacton how business is conducted, and give rise tosome difficult accounting issues. This publicationexamines the accounting issues that are mostsignificant for the utilities industry. The issues areaddressed following the utilities value chain:generation, transmission & distribution, retail andissues that impact on the entire entity.

For published financial disclosure examples, seeSection 4 on page 45.

1.1 Generation

1.1.1 Fixed assets & components

IFRS has a specific requirement for ‘component’ depreciation, as described in IAS 16 Property,plant and equipment. Each significant part of anitem of property, plant and equipment isdepreciated separately. Significant parts of anasset that have similar useful lives and pattern ofconsumption can be grouped together. Thisrequirement can create complications for utilitiesentities, as there are many assets that includecomponents with a shorter useful life than theasset as a whole.

Identification of components of an asset

Generating assets are often large and complex installations. They are expensive to construct,tend to be exposed to harsh operating conditionsand require periodic replacement or repair.Generating assets might comprise a significantnumber of components, many of which will havediffering useful lives. The significant componentsof these types of assets must be separatelyidentified. It can be a complex process,particularly on transition to IFRS, as the detailedrecordkeeping may not have been required tocomply with national GAAP. This can particularlybe an issue for old power-generating plants.However, some regulators may require detailedasset records, which can be useful for IFRScomponent identification purposes.

An entity might look to its operating data if the necessary information for components is notreadily identified by the accounting records.Some components can be identified byconsidering the routine shutdown or overhaulschedules for power stations and thereplacement and maintenance routinesassociated with these. Consideration should alsobe given to those components that are prone totechnological obsolescence, corrosion or wearand tear more severe than that of the otherportions 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 their recoverable amount overthat shorter useful life. The remaining carryingamount of the component is derecognised onreplacement and the cost of the replacement partis capitalised.

The costs of performing a turnaround/overhaul are capitalised as a component of the plant,provided 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 when incurred. Turnaround/overhaulcosts should not be accrued over the periodbetween the turnarounds/overhauls becausethere is no legal or constructive obligation toperform the turnaround/overhaul – the entitycould choose to cease operations at the plantand hence avoid the turnaround/overhaul costs.

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.



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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 Decommissioning obligations

The utilities industry can have a significantimpact 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 power plant or otherinstallation. The associated costs ofremediation/restoration can be significant. The accounting treatment for decommissioningcosts is therefore critical.

Decommissioning provisions

A provision is recognised when an obligation exists to remediate or restore. 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 asset is placed in service. 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 placed in serviceand depreciated over the asset’s useful life. Thetotal cost of the fixed asset, including the cost ofdecommissioning, is depreciated on the basisthat best reflects the consumption of theeconomic benefits of the asset: generally time-based for a power station.

Provisions for decommissioning and restoration are recognised even if the decommissioning isnot expected to be performed for a long time, forexample 80 to 100 years. The effect of the timeto expected decommissioning will be reflected inthe discounting of the provision. The discountrate used 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 theliability can be reflected either in the pre-tax cashflow forecasts prepared or in the discount rateused.

A similar accounting approach is taken for nuclear fuel rods. These rods are classified asinventory, and an obligation to reprocess them istriggered when the rods are placed into thereactor. A liability is recognised for thereprocessing obligation when the rods are placedinto the reactor, and the cost of reprocessingadded to the cost of the fuel rods.

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 thecarrying amount of the asset, the excess is recognised immediately in profit or loss;

• adjustments that result in an addition to thecost 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.



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

1.1.4 Impairment

The power industry is distinguished by the significant capital investment required, exposureto commodity prices and heavy regulation. The required investment in fixed assets leavesthe industry exposed to adverse economicconditions and therefore impairment charges.Utilities assets should be tested for impairmentwhenever indicators of impairment exist. Thenormal measurement rules for impairment apply.

Impairment indicators

External impairment triggers relevant for the utilities industry include falling retail prices, risingfuel costs, overcapacity and increased or adverseregulation or tax changes.

Impairment indicators can also be internal in nature. Evidence that an asset or CashGenerating Unit (CGU) has been damaged orbecome obsolete is an impairment indicator; forexample a power plant destroyed by fire is, inaccounting terms, an impaired asset. Otherindicators of impairment are a decision to sell orrestructure a CGU or evidence that businessperformance is less than expected. Performanceof an asset or group of assets that is below thatexpected by management in operational andfinancial plans is also an indicator of impairment.

Management should be alert to indicators on a CGU basis; for example learning of a fire at anindividual generating station would be anindicator of impairment for that station as aseparate CGU. However, generally managementis likely to identify impairment indicators on aregional, country or other asset grouping basis,reflective of how they manage their business.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.

Power generation assets will form CGUs by location or possibly by single generating facilityon a multiple turbine site. The determination ofhow many CGUs will depend on the extent ofshared infrastructure and the ability to generatelargely separate cash inflows. The determinationof CGUs is not driven by how managementchooses to use its assets. For example, an entitymay have three generating stations in a largemetropolitan area, which can be runindependently. Management makes the decisionto produce based on expected prices, demandand efficiency. It uses the three stations to meetdemand in a most efficient to least efficient basis.The three stations remain separate CGUs.

Calculation of recoverable amount

Impairments are recognised if the carrying amount of a CGU exceeds its recoverableamount. Recoverable amount is the higher of fairvalue less 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.



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balance sheet at fair value as a derivative.Including the contracted prices of such acontract would double count the effects of thecontract. Impairment of financial instruments thatare 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 the VIU cash flows. These contracts are alsoaccounted for in accordance with IAS 39.

1.1.5 Arrangements that may contain alease

IFRS requires that arrangements that convey the right to use an asset in return for a payment orseries of payments be accounted for as a leaseeven if the arrangement does not take the legalform of a lease. Some common examples ofsuch arrangements might include a series ofpower plants built to exclusively supply the railnetwork; a generator located on the site of analuminium smelter or a generator constructed ona build–own–operate–transfer arrangement with anational utility. Tolling arrangements may alsoconvey the use of the asset to the party thatsupplies the fuel.

IFRIC 4 Determining whether an Arrangement contains a Lease sets out guidelines to determinewhen an arrangement might contain a lease.Once a determination is reached that anarrangement contains a lease, the leasearrangement must be classified as either financeor operating. The principles in IAS 17 Leasesapply: a lease that conveys the majority of therisks and rewards of operation is a finance lease.A lease other than a finance lease is an operatinglease.

The classification has significant implications; a lessor in a finance lease would find itselfderecognising its generating assets andrecognising a finance lease receivable in return. A lessee in a finance lease would recognise fixedassets and a corresponding lease liability ratherthan an executory contract, as in the past.

Classification as an operating lease leaves the lessor with the fixed assets on the balance sheetand the lessee with an executory contract.


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 36Impairment of Assets. The cash flows are basedon the asset that the entity has now and mustexclude any plans to enhance the asset or itsoutput in the future but includes expenditurenecessary to maintain the current performance ofthe asset. The VIU cash flows for assets that areunder construction and not yet complete shouldinclude the cash flows necessary for theircompletion and the associated additional cashinflows or reduced cash 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 calculationat the spot price at the date of the impairmenttest, or if appropriate, prices obtained from theforward price curve at the date of the impairmenttest.

There may be commodities – both fuel and the resultant electricity output – covered by purchaseand sales contracts. Management should use thecontracted 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 the


Operating lease classification might be achievedwhere the utility has other customers and most ofthe capacity production is sold to third parties.

Power purchase agreements

Power purchase agreements where the purchaser controls the dispatch of power, takesall of the output and has guaranteed a return tothe operator or provides a de facto guarantee ofthe obligation assumed to finance the facility arenot difficult to classify as a finance lease.Difficulties tend to arise where there is a powerpurchase agreement (PPA) for substantially all, orall, of the output of a wind farm or hydro facilitybecause the amount of generation is determinedby an uncontrollable factor, in this case the windor the amount of rain/snowfall.

For example, a typical wind farm contract would be:

• for 100% of the output of the wind farm;

• for substantially all of the asset’s life;

• guarantees a level of availability when the wind is blowing;

• allows the purchaser to agree the timing ofmaintenance outages;

• has pricing which is fixed per unit of output rather than a time-based payment.

Government requirements or incentives for the production of power from renewable sourceshave led to the development of many wind farms and other green generating sources. The developer and owner of the wind farmtypically agrees to sell 100% of the output of thewind farm to a single purchaser, allowing thedeveloper to recover its operating costs, debtservice cost and a development premium.Available wind studies are used to help site windfarms and assess the economic viability early inthe development stage of the project.

A PPA for 100% of the output of a wind farm with a guaranteed minimum production maymeet the requirement for finance leaseaccounting. The developer may establish thecontract so that it will get its full return from asingle contract, even though the generation ofelectricity is contingent on the wind.

Co-located assets

Power companies may construct generating facilities at customer locations on propertyowned or controlled by a customer. This mayoccur where a customer is a heavy user of powerand steam. These arrangements may also befound where the customer produces waste by-products that can be burned to produceelectricity.

These arrangements may have the substance of a finance lease under IAS 17 where the customerhas the majority of the risks and rewardsincidental to ownership of the asset. Some of the characteristics consistent with a financelease are where the customer takes most of theoutput and makes payments for the asset to‘stand ready’ in addition to payments for outputreceived. A common indicator of a finance leaseis that the customer provides a de factoguarantee of obligations assumed to finance thefacility. The guarantee may take the form of atake or pay contract or an outright guarantee ofindebtedness.

1.1.6 Emission Trading Scheme andCertified Emission Reductions

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 marketsin 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.



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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 entities are 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 todeliver 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.

Certified Emission Reductions (CERs)

There is another scheme under the Kyoto Protocol for fast-growing countries and countriesin transition that are not subject to a Kyoto targeton emissions reduction. Entities in thesecountries can generate Certified EmissionsReductions (CERs). CERs represent a unit ofgreenhouse gas reduction that has beengenerated and certified by the United Nationsunder the Clean Development Mechanism (CDM)provisions of the Kyoto Protocol. The CDMallows industrialised countries that are committedto reducing their greenhouse gas emissionsunder the Kyoto protocol to earn emissionsreductions credits towards Kyoto targets throughinvestment in ‘green’ projects. Examples ofprojects include reforestation schemes andinvestment in clean energy technologies. Oncereceived, the CERs have value because they areexchangeable for EU ETS allowances and hencecan be used to meet obligations under thatparticular scheme.



An entity that acquires CERs accounts for these as described under ETS; they are accounted forat cost at initial recognition and then subsequentlyin accordance with the accounting policy chosenby the entity. There is no specific accountingguidance under IFRS that covers the generationof CERs. Entities that generate CERs shoulddevelop an appropriate accounting policy. Most entities that need CERs are likely to acquirethem from third parties and account for them asseparately acquired assets.

The key question that drives the accounting for self-generated CERs by ‘green’ entities is: whatis the nature of the CERs? The answer to thisquestion lies in the specific circumstances of thegreen entity’s core business and processes. If theCERs generated are held for sale in the entity’sordinary course of business, CERs are within thescope of IAS 2 Inventories. If they are not theyshould be considered as identifiable non-monetary assets without physical substance ie,intangible assets.

The accounting for CERs is also driven by the applicability of IAS 20. If CERs are granted bygovernment the accounting would be as follows:

• recognition when there is a reasonable assurance that the entity will comply with the conditions attached to the CERs and the grant will be received;

• initial measurement at nominal amount or fair value, depending on the policy choice;

• subsequent measurement depends on the classification of CERs and should follow the relevant standard ie, IAS 2 for inventory, IAS 38 for intangible assets, IFRS 5 for non-current assets held for sale.

1.2 Transmission & Distribution

1.2.1 Fixed assets & components

Some network companies applied renewals accounting for expenditure related to theirnetworks under national GAAP. Expenditure wasfully expensed and no depreciation was chargedagainst the network assets. This accountingtreatment is not acceptable under IFRS as thenormal fixed asset accounting and depreciationrequirements apply. This may be a significant

change for network companies and introducessome application challenges.

Network assets such as an electricity transmission system or a gas pipeline comprise manyseparate components. Many individualcomponents may not be significant. A practicalapproach to identifying components is toconsider the entity’s mid/long-term capitalbudget, which should identify significant capitalexpenditures and pinpoint major components ofthe network that will need replacement over thenext few years. The entity’s engineering staffshould also be involved in identification ofcomponents based on repairs and maintenanceschedules and planned major renovations orreplacements.

A network must be broken down into its significant parts that have different useful lives.The determination of the number of parts and thesplit is specific to the circumstances of the entity.A number of factors might be considered indoing the analysis; the cost of different parts,how the asset is split for operational purposes,physical location of the asset and technicaldesign considerations.

An entity that has a history of expensing all current expenditure may struggle initially toreinstate what should have been capitalised andwhat should have been expensed. Materiality is auseful guide; if replacement costs are material tothe asset then, provided recognition criteria aremet (cost can be reliably measured and futureeconomic benefits are probable), these costsshould be capitalised.

Network companies may be used to a working assumption that assets have an indefinite usefullife. All significant assets under IAS 16 Property,Plant and Equipment will have a finite life to bedetermined, being the time remaining before theasset needs to be replaced. Maintenance andrepair activities may extend this life, butultimately the asset will need to be replaced.

A residual value must be determined for all significant components. This value in many casesis likely to be scrap only or zero, since IAS 16defines it as the disposal proceeds if the assetwere already of an age and in the conditionexpected at the end of its useful life. An entity is



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required to allocate costs at initial recognition toits significant parts. Each part is then depreciatedseparately over its useful life. Separate parts thathave the same useful life and depreciationmethod can be grouped together to determinethe depreciation charge.

1.2.2 Customer contributions

The provision of utility services to customers requires some form of physical connection,whether the service is gas, water or power. The investment required to provide thatconnection to the customer from the national orregional network may be significant. This is likelywhen the customer is located far from thenetwork or when the volume of the utility that will be purchased requires substantial equipment.An example may be the provision of power to aremote location where the construction of asubstation is required to connect the user to thenational network.

Many utility entities require the customer to contribute to the cost of the connection, and inreturn the customer receives the right to accessthe utility services. The utility entity constructsthe connecting infrastructure and retainsresponsibility for maintaining it. Commonaccounting practice is for the utility entity tocapitalise the connection equipment as property,plant and equipment (PPE) and recognise thecontribution as deferred income, which isamortised to the income statement over anappropriate period – usually over the life of thePPE.

Major connection expenditures, such as substations or network spurs, will often benefitmore than one customer and contributions maybe received from several of these. However, whenmajor connection equipment is constructed forthe sole benefit of one customer and can bedistinguished from the general network,consideration should be given to whether theequipment has, in substance, been leased to thecustomer. IFRIC 4 and IAS 17 should be appliedto determine whether the arrangement is insubstance a lease and whether it should beclassified as an operating or finance lease.

A recent draft interpretation published by the IFRIC, D24 Customer Contributions, is broadlyconsistent with the approach described above,

although some detailed requirements may needto be considered when the interpretation isfinalised.

1.2.3 Regulatory assets & liabilities

Complete liberalisation of utilities is not practical because of the physical infrastructure requiredfor the transmission and distribution of thecommodity. Privatisation and the introduction ofcompetition is often balanced by price-regulation. Some utilities continue as monopolysuppliers with prices limited to a version of costplus margin overseen by the regulator.

The regulatory regime is often unique to each country. The two most common types ofregulation are incentive-based regulation andrate-based regulation. The regulator governing anincentive-based regulatory regime usually setsthe ‘allowable revenues’ for a period with theintention of encouraging cost efficiency from theutility. A utility entity operating under rate-basedregulation is usually permitted the recovery of anagreed level of operating costs, together with areturn on assets employed.

An entity’s accounting policies should take account of the regulatory regime and therequirements of IFRS. Any regulatory type assetor liability recognised under IFRS needs to be afinancial asset, an intangible asset or a financialliability in its own right, as there are no specialrecognition requirements for regulatory assets orliabilities under IFRS.

Future price increases

A common feature of price-regulated markets is the agreement of the regulator to allow future price increases in compensation for certainidentified past costs. These price increases areabove those that otherwise might have beenpermitted by the regulator in normal cost pluscalculations.

The costs associated with these price increases can be considered in two broad categories: thosethat are operating in nature and those that arecapital. Examples of operating costs mightinclude previously unbudgeted employee costs(for example, pension cost increases) andincreased fuel costs in volatile market conditions.These costs are expensed as incurred under



IFRS and included in cost of sales in the periodin which the employee service is rendered or thefuel is consumed. These costs have beenincurred directly in generating the power sold inthat period.

Examples of capital costs include damage to fixed assets from extreme weather, such ashurricanes and ice storms, or from otherunexpected and uninsured events. An impairmentcharge is recognised under IFRS for anydamaged assets. The cost of replacement assetsare capitalised as appropriate as PPE.

The regulator may grant the utility permission to add an additional charge per unit to futurebillings to customers. This gives rise to a financialreceivable only as the power, water or gas isdelivered to the customer, not when the rateagreement is reached. The rate agreement doesnot give rise to the recognition of an intangibleasset as it does not change the nature of theexisting licence. Any ‘compensation’ receivablethrough an increased future price is notrecognised until that amount becomesreceivable, which is when the future electricity,water, or gas is delivered. A regulatoryadjustment, billable to identifiable existingcustomers with no further obligation to deliverservices, might meet the recognition criteria as afinancial asset. Few regulatory regimes allow thiskind of retroactive pricing adjustment.

Future price decreases

Price regulation can also lead to the requirement from a regulator for a utility entity to reduce itsprices in a future period. A decrease in pricesseldom leads to the recognition of a liability, as itdoes not constitute a refund of past amountscollected. The benefit of reduced prices is onlyreceived by customers if they continue topurchase the commodity. This is not sufficient tocause the recognition of a liability. It might beappropriate to recognise a liability if the entitywas obliged to repay cash to the customers (orperhaps to the government) or if the reduction inprices was so significant that it represented anonerous contract. An obligation to pay cash tocustomers or the government would berecognised as a financial liability. An onerouscontract would be recognised as a provision. It isextremely rare that the recognition of a liability

under IAS 39 or IAS 37 Provisions, ContingentLiabilities and Contingent Assets is met in thecontext of price regulation because the customermust purchase future services or commodity toreceive the benefits.

The IFRIC has considered the topic of regulatory assets and liabilities twice; once when dealingwith service concessions and a second time inresponse to a question about whether FAS 71could be applied under IAS 8 AccountingPolicies, Changes in Accounting Estimates andErrors. The IFRIC concluded on both occasionsthat the recognition criteria in FAS 71 were notfully consistent with IFRS and that any assets orliabilities recognised in relation to rate-regulatedutilities needed to meet the normal recognitioncriteria in the IFRS standards.

Regulatory assets and business combinations

The acquisition of a utility in a business combination requires the recognition of all of theutility’s identifiable assets and liabilities at theirfair values. A utility’s rights to charge a highertariff in the future or to reduce future pricesprovides additional information about the value of the licence. The tariff value will usually bereflected in the fair value of the licencerecognised on acquisition rather than therecognition of a separate regulatory asset.

Stranded costs

Stranded costs are a particular type of regulatory asset that are not associated with a utility’snormal day-to-day operations. They arise as aresult of a regulator requiring a utility to disposeof capital assets at a loss in order to achievegreater liberalisation of the utility. The lossincurred is known as a stranded cost, andtypically the regulator allows the utility entity tocharge a higher tariff to customers in the future inorder to compensate it for the loss incurred ondisposal of the capital assets. There may beunusual circumstances in which recognising suchstranded costs as an asset could be justified; forexample, if the entity had a substantial change tothe terms of its operating licence such that it hadexchanged its existing licence (an intangibleasset under IAS 38) for a new operating licence.



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1.3 Retail

1.3.1 Customer acquisition costs

Deregulation of markets and the introduction of competition often provides customers with theability to switch from one supplier to another.Utility entities invest in winning and developingtheir relationships with their customers. The costsof acquiring and developing these customerrelationships are capitalised if certain conditionsare met. The costs directly attributable toconcluding a contractual agreement with acustomer are capitalised and amortised over thelife of the contract. These costs includecommissions or bonuses paid to sign the utilitycustomers where the utility entity has thesystems to separately record and assess thecustomer contract for future economic benefits.

However, expenditure relating to the general development of the business, such as providingservice in a new location or an advertisingcampaign for new customers, represents thedevelopment of internally-generated goodwill andcannot be capitalised. Such general expenditureis not capitalised because the specific costsassociated with individual customers cannot beseparately identified or because the entity hasinsufficient control over the new relationship for itto meet the definition of an asset.

However, customer relationships must be recognised when they are acquired through abusiness combination. Customer-related intangiblessuch as customer lists, customer contracts andcustomer relationships are recognised by theacquirer at fair value at the acquisition date.

1.3.2 Customer discounts

Utility entities may offer discounts and other incentives to customers to encourage them tosign up to certain tariffs or payment plans. The costs associated with these programmesneed to be identified carefully to ensure that theyare appropriately separated from the salesrevenue. For example, when customers receive a lower tariff for paying monthly compared withother customers who pay quarterly, considerationshould be given to whether separation of thesales revenue from the finance income that isembedded in the price charged to the customerswho pay quarterly is required.

1.4 Company-wide Issues

1.4.1 Service concession arrangements

Public/private partnerships are one method whereby governments attract private sectorparticipation in the provision of infrastructureservices. These services might include, amongothers, toll roads, prisons, hospitals, publictransportation facilities and water and powerdistribution. These types of arrangements areoften described as concessions and many fallwith the scope of IFRIC 12 Service ConcessionArrangements. Arrangements within the scope ofthe standard are those where a private sectorentity may construct the infrastructure, maintain itand provide the service to the public. The entitywill be paid for its services in different ways.Many concessions require that the relatedinfrastructure assets are returned or transferredto the government at the end of the concession.

IFRIC 12 applies to arrangements where the grantor (the government or its agents) controls orregulates what services the operator provideswith the infrastructure, to whom it must providethem and at what price. The grantor also controlsany significant residual interest in theinfrastructure at the end of the term of thearrangement.

Water distribution facilities and energy supply networks are examples of infrastructure thatmight be the subject of service concessionarrangements. The government may haveauthorised the building of a new town. It maygrant a concession to a power distributioncompany to construct the distribution network,maintain it and operate it for a period of 25 years.The distribution network is transferred to thegovernment at the end of the concession periodwith a specified level of functionality for noconsideration. The national regulator sets priceson a cost-plus basis. The concession agreementhas base-line service commitments that willtrigger substantial penalties if service isinterrupted. The government requires that thepower company provide universal access toelectricity for all residents of the town andregulates the prices at which it is supplied.Customers can be disconnected for non-payment subject to hardship provisions for thepoor and elderly.



This arrangement would fall with in the scope of IFRIC 12, as it has many of the common featuresof a service concession arrangement:

• The grantor of the service agreement is a public sector entity or a private sector entity to which the responsibility for the service is delegated (in this case the government has authorised the new town and granted the licence).

• The operator is not an agent acting on behalf of the grantor but responsible for at least some of the management of the infrastructure (the operator has an obligation to maintain the network and deliver electricity).

• The arrangement is governed by a contract (or by the local law, as applicable) that sets outperformance standards, mechanisms foradjusting prices and arrangements forarbitrating disputes (there are financialpenalties for poor operating performance anda cost-plus tariff).

• The operator is obliged to hand over the infrastructure to the grantor in a specified condition at the end of the period of the arrangement (transfer with no consideration from the government at the end of the concession period).

There are two accounting models under IFRIC 12 that an operator applies to recognise the rightsreceived under a service concessionarrangement:

• Financial asset – an operator with a contractual and unconditional right to receive specified or determinable amounts of cash (or other financial asset) from the grantor recognises a financial asset. The financial asset is within the scope of IAS 32 Financial Instruments: Presentation, IAS 39 and IFRS 7 Financial Instruments: Disclosures.

• Intangible asset – an operator with a right to charge the users of the public service recognises an intangible asset. There is no contractual right to receive cash when payments are contingent on usage. The licence is within the scope of IAS 38.

IFRIC 12 is a new interpretation, applicable for the first time in 2008. Arrangements betweengovernments and service providers are complex,and seldom will the conclusion be as obvious asthe example above. Once within the scope ofIFRIC 12, the appropriate accounting model may not always be obvious. Entities should beanalysing arrangements in detail to conclude onwhether these are within the scope of theinterpretation and whether the arrangement fallsunder the financial asset or intangible assetmodels. Some complex arrangements may have elements of both models for the differentphases. It may be appropriate to separatelyaccount for each element of the consideration.Applying IFRIC 12 for the first time will require aretrospective application, ie, comparatives will berestated for those concessions within its scope.

1.4.2 Business combinations

Acquisitions of assets and businesses are common in the utility industry. These may bebusiness combinations or acquisitions of groupsof assets. IFRS 3 Business Combinationsprovides guidance on both types of transactions,and the accounting can differ significantly.

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.

Issues commonly encountered in the utility industry include making the judgement aboutwhether a transaction is a business combinationor an asset deal, recognition and valuation ofintangible assets, goodwill and deferred tax.

Definition of a business

A business is an integrated set of activities managed together to provide a return toinvestors or other economic benefits. Two keyelements of the definition are ‘integration’ and‘return to investors’. The accounting for abusiness combination and a group of assets canbe substantially different. A business combinationwill usually result in the recognition of goodwill



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and deferred tax. An asset transaction qualifiesfor the initial recognition exemption and thereforethere is usually no deferred tax. The considerationin an asset transaction is allocated to individualassets acquired and liabilities assumed based onrelative fair values.

Acquisition of an integrated utility or a group of generators located in a country will fall squarelyinto the scope of IFRS 3 as a businesscombination. The classification of the acquisitionof a single generating facility, or a portion of atransmission network, may not be so clear cut. The acquisition of a generating facility that iscontracted out and is within the scope of IFRIC 4and classified as a finance lease may not be abusiness combination because often theoperator’s return is fixed or guaranteed by thecontract, and any variability in costs is passedthrough to the purchaser of the power.

Allocation of the cost of the combination toassets 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, forexample customer relationships.

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 intangible assets that might be identified inthe acquisition of a utility may differ dependingon the regulatory regime. Brand names andcustomer relationships might be significantassets of a utility in a less regulated and morecompetitive market. A utility in a monopolymarket might have a brand name and a logo, butthis would have much less value as customershave no choice of supplier. The transmissionnetwork might be a separate business and tradewith a number of generators and distributioncompanies. If it has a monopoly position it hascustomer relationships, but these again are likelyto be of little value. Existing contracts andarrangements, however, might give rise to assetsor liabilities for favourable or unfavourablepricing. This could include operating leases, fuel

purchase arrangements and contracts thatqualify for own-use that might otherwise bederivatives under IAS 39.

The utility usually has a licence or a series of licences to operate. These licences are almostalways included in the value of the fixed assets,as the two can seldom be separated. The licenceto operate a nuclear power plant is specific tothe location, assets and often the current entity(not freely transferable). The licence and fixedassets are usually valued on the basis ofexpected cash flows and will incorporate anyexisting rate agreements that will survive thebusiness combination. The regulator, in somecountries, may seek to re-negotiate existing rateagreements perhaps as part of agreeing to achange in control.

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

IFRS 3 requires that the fair value of the assets acquired and liabilities assumed are recognised.The difference between consideration and the fairvalue 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 recognition of goodwill in 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, ‘development premium’ reflectinguncertainty of the completion of the project 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 deferred



tax. 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.

1.4.3 Financial instruments

The accounting for financial instruments can have a major impact on a utility entity’s financialstatements. Many use a range of derivatives tomanage the commodity, currency and interestrate risks to which they are operationallyexposed. Other, less obvious, sources of financialinstruments issues arise through both the scopeof IAS 39 and the rules around accounting forembedded derivatives. Many entities that areengaged in generation, transmission anddistribution of electricity may be party tocommercial contracts that are either wholly withinthe scope of IAS 39 or contain embeddedderivatives from pricing formulas or currency.Other entities may have active energy tradingprogrammes that go far beyond mitigation of risk.This section looks at two broad categories offinancial instruments: those that may arise fromthe scope of IAS 39 and those that arise fromactive trading and treasury management activity.Separately, it addresses accounting for weatherderivatives.

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 mayinclude embedded derivatives, which may berequired to be separately accounted for. An ‘own-

use’ contract is one that was entered into andcontinues to be held for the purpose of thereceipt or delivery of the non-financial item inaccordance with the entity’s expected purchase,sale or usage requirements. In other words, it willresult in physical delivery of the commodity. The ‘net settlement’ notion in IAS 39 is quitebroad. A contract to buy or sell a non-financialitem can be net settled in any of the followingways:

(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 a 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, gas and electricity 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 regularly



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occurring 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 meets the own-use criteria cannot be selectivelyfair-valued unless it otherwise falls into the scopeof IAS 39.

If an own-use contract contains one or more embedded derivatives, an entity may designatethe entire hybrid contract as a financial asset orfinancial liability at fair value through profit or lossunless:

(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 Annual Improvementsproject will restrict this designation to hostcontracts that are financial instruments in thescope of IAS 39.

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

Measurement of long-term contracts that donot qualify for ‘own-use’

Long-term commodity contracts are not uncommon, particularly for purchase of fuel andsales of electricity. Some of these contracts maybe within the scope of IAS 39 if 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 any observable 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 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. Aday-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 market transactions in the same instrument; or

(2) is based on valuation techniques whose variables 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. Commoditycontracts include a volume component, andutility entities are likely to recognise the deferredgain/loss and release it to profit or loss on asystematic basis as the volumes are delivered, oras observable market prices become availablefor the remaining delivery period.

The recognition of the day-one gain/losses may change as the result of the IASB project on theFair Value Measurements.

Take or pay contracts

Generators may enter into long-term take-or-pay contracts with key fuel suppliers. Theseagreements give rise to an obligation for thegenerator to purchase a minimum quantity orvalue of the relevant fuel. The actual quantity orvalue of fuel the generator requires may be lessthan the minimum agreed amount in any onemeasurement period. The generator may berequired to pay the supplier the equivalentmonetary value of the shortfall. The shortfallamount may also be carried forward and used insatisfaction of supply in subsequent periods.

A long-term take-or-pay contract might not qualifyfor own-use treatment. The inherent variability inamount and the ability to ‘net settle’ may putsuch a contract outside the exemption because itwill not meet the criteria for own-use.

Volume flexibility (optionality)

Many contracts for the supply of commodities usually give the buyer the right to take either aminimum quantity or any amount based on thebuyer’s requirements. A minimum annualcommitment does not create a derivative as longas the entity expects to purchase all the

guaranteed volume for its own-use. However, if itbecomes likely that the entity will not take thecommodity, and instead pay a penalty under thecontract based on the market value of thecommodity or some other variable, a derivativeor an embedded derivative may well arise. In thissituation, since physical delivery is no longerprobable, the derivative would be recorded at theamount of the penalty payable. Changes inmarket price will affect the penalty’s carryingvalue until the penalty is paid. On the other hand,if the amount of the penalty payable is fixed orpre-determined, there is no derivative becausethe penalty’s value remains fixed irrespective ofchanges in the product’s market value. In otherwords, the entity will need to provide for thepenalty payable once it becomes clear that non-performance is likely.

On the other hand, if the quantity specified in the contract is more than the entity’s normal usagerequirement and the entity intends to net settlepart of the contract that it does not need in thenormal course of the business, the contract willfail the own-use exemption. For example, theentity could take all the quantities specified in thecontract and sell on the excess, or it could enterinto an offsetting contract for the excess quantity.In such situations, the entire contract falls withinIAS 39’s scope and should be marked-to-market.

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 derivativesthat may have to be separated and accounted forunder IAS 39 as a derivative. Examples are fuelprices that are linked to the electricity price 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.



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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 hostcontract at the inception of the contract. Apricing formula that is indexed to somethingother than the commodity delivered under the

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

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 embedded



derivative. The date of purchase is treated as thedate when the entity first becomes a party to thecontract.

1.4.4 Trading and risk management

Energy trading is the buying and selling of energy-related products, both fuel and power.This practice has many similarities to the tradingactivities of other commodities, such as gold,sugar or wheat. The introduction of competitionin the utilities area was the catalyst for energytrading to start in earnest. Energy trading is animportant but potentially risky part of a utility’sbusiness. Effective trading can limit volatility andprotect profit margins.

Centralised Trading Unit

Many integrated utility companies have established a centralised trading or riskmanagement unit over the last decade inresponse to the restructuring of the industry. The operation of the Central Trading Unit issimilar to the operation of the bank’s trading unit.

The scale and scope of the unit’s activities vary from market risk management through todynamic profit optimisation. An integrated utilitycompany is particularly exposed to themovements in the price of fuel and tomovements in the price of the power that isgenerated. The trading unit’s objectives andactivities are indicative of how management ofthe utility operates the business.

A unit focused on managing fuel-price risk and sales-price exposure to protect margins is morelikely to be entering into many contracts that willqualify for the own-use exemption as previouslydiscussed. A pattern of speculative activity ortrading directed to profit maximisation is unlikelyto result in many contracts qualifying for theown-use exemption. All external contracts maybe treated as derivatives and marked to market.The central trading unit often operates as aninternal market place in larger integrated utilities.The generating stations ‘sell’ their output to and‘purchase’ fuel from the trading unit. The retailunit would ‘purchase’ power to meet itscustomer demands. The centralised tradingfunction thus ‘acquires’ all of the company’sexposure to the various commodity risks. Thetrading unit is then responsible for hedging those

risks in the external markets. Some centralisedtrading departments are also given authority toenhance the returns obtained from the integratedbusiness by undertaking a degree of speculativetrading. A centralised trading unit thereforeundertakes two classes of transaction:

(a) Transactions that are non-speculative in nature: for example, the purchase of fuel to meet the physical requirements of the generation stations and the sale of any excess power generated compared to retail demand, or the purchase of power to meet a shortfall between that generated and that required by retail. Such activity is sometimes held in a ‘physical book’.

(b) Transactions that are speculative in nature, to achieve risk management returns from wholesale trading activities. Such activity issometimes held in a ‘trading book’ and often involves entering into offsetting sales and purchase contracts that are settled on a net basis. Those contracts and all similar contracts (i.e. all contracts in the trading book) do not qualify for the own-use exemption and are accounted for as derivatives.

A company that maintains separate physical andtrading books needs to maintain the integrity ofthe two books to ensure that the net settlementof contracts in the trading book does not ‘taint’similar contracts in the physical book, thuspreventing the own-use exemption from applyingto contracts in the physical book.

Hedge Accounting

Hedge accounting can mitigate the volatility of trading transactions. Practical experience ofhedge accounting has shown that complying withthe requirements can be onerous. A companythat chooses to apply hedge accounting mustcomply with the detailed requirements. Allderivatives are accounted for at fair value, butchanges in fair value are either deferred throughreserves, or matched to a significant extent by anadjustment to the value of the hedged item,dependent on the type of hedge. Companies thatcombine commodity risk from different businessunits before entering into external transactionsmight not qualify for hedge accounting, as thisusually creates a net exposure and IFRS does



Significant A

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not permit hedge accounting for transactionsundertaken to hedge net exposures.

Two key hurdles to implementing hedge accounting are the need for documentation andthe testing of effectiveness. IAS 39 requires thatindividual hedging relationships are formallydocumented, including linkage of the hedge to the company’s risk-management strategy,explicit identification of the hedged items and thespecific risks being hedged at the inception ofthe hedge. Failure to establish this documentationat inception will mean that hedge accountingcannot be adopted, regardless of how effectivethe hedge actually is in offsetting risk.

Hedges must be expected to be highly effective and must prove to be highly effective inmitigating the hedged risk or variability in cashflows in the underlying instrument.

There is no prescribed single method for assessing hedge effectiveness. Instead, acompany must identify a method that isappropriate to the nature of the risk beinghedged and the type of hedging instrument used.The method an entity adopts for assessing hedgeeffectiveness depends on its risk managementstrategy. A company must document at theinception of the hedge how effectiveness will beassessed and then apply that effectiveness teston a consistent basis for the duration of thehedge.

The hedge must be expected to be effective at the inception of the hedge and in subsequentperiods and the actual results of the hedgeshould be within a range of 80-125% (ie,changes in the fair value or cash flows of thehedged item should be between 80% and 125%of the changes in fair value or cash flows of thehedging instrument). Any ineffectiveness of aneffective hedge must be recognised in theincome statement.

The requirement for testing can be quite onerous. Effectiveness tests need to be performed foreach hedging relationship at least as frequentlyas financial information is prepared, which forlisted companies could be up to four times ayear. Experience shows that the application ofhedge accounting is not straightforward,particularly in the area of effectiveness testing,

and a company looking to apply hedgeaccounting to its commodity hedges needs toinvest time in ensuring that appropriateeffectiveness tests are developed.

Cash Flow Hedges and ‘Highly Probable’

Hedging of commodity-price risk or its foreignexchange component is often based onexpected cash inflow or outflow related toforecasted transactions, therefore cash flowhedges. Under IFRS, only a highly probableforecast transaction can be designated as ahedged item in a cash flow hedge relationship. The hedged item must be assessed regularlyuntil the transaction occurs. If the forecastschange and the forecasted transaction is nolonger expected to occur, the hedge relationshipmust be ended immediately and all retainedhedging results from the hedging reserve mustbe recycled to the income statement. Cash flowhedging is not available if an entity is not able to forecast the transaction reliably.

Weather Derivatives

Electricity consumption is heavily influenced by weather. More energy is consumed in coldwinters than in mild winters and, due to airconditioning, more in hot summers than in coolsummers. The correlation with outsidetemperatures is high, so load volumes are heavilydependent on weather conditions. Weatherderivatives make it possible to manage theconcerns related to extreme climate conditions,by paying the generator when the weather isadverse to revenue.

Weather derivatives are contracts that require a payment based on climatic variables or ongeological or other physical variables. For suchcontracts, payments are sometimes made on the amount of loss suffered by the entity andsometimes not. Weather derivatives are eitherinsurance contracts and fall into IFRS 4Insurance Contracts or financial instruments andwith the scope of IAS 39. Contracts that require a payment only if a particular level of theunderlying climatic, geological, or other physicalvariables adversely affects the contract holderare insurance contracts. Payment is contingenton changes in a physical variable that is specificto a party to the contract.



Contracts that require a payment based on a specified level of the underlying variableregardless of whether there is an adverse effecton the contract holder are derivatives and arewithin IAS 39’s scope. Derivatives should berecognised at fair value with the changes in fairvalue recognised in the income statement.



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2 Developments from the IASB

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2.1 Borrowing costs The IASB issued amendments to IAS 23 Borrowing Costs in March 2007. IAS 23Rremoves the policy choice of either capitalising or expensing 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.

2.2 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. The Board decided to limit the scope of theproject to the issues that arise in accounting foremissions trading schemes, rather thanaddressing broadly the accounting for allgovernment grants (which would have involvedre-activating the IAS 20 project).

The purpose of the project is to comprehensively address the accounting for emission trading

schemes. It will cover the following issues: • whether the emissions allowances are an asset

(considering the 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 should it be measured.

The project is in the research phase, with the Board gathering information on thecharacteristics of various emissions tradingschemes. This will be the basis for thepreparation of a comprehensive package thatoutlines the alternative models that could beused to account for emissions trading schemes.The timing of an initial due process documentand the estimated project completion date is notyet determined.

2.3 Revenue recognition projectThe IASB is conducting a joint project with FASB to develop concepts for revenue recognition anda general standard based on those concepts.The general standard would replace the existingstandards on revenue recognition: IAS 11Construction Contracts and IAS 18 Revenue. The comprehensive standard that is expected toresult from this project is planned to apply to allbusiness entities; however, the Boards mayconclude that certain transactions or industriesrequiring additional study should be excludedfrom the scope of that standard and addressedseparately.

The main reasons for undertaking this project are to:

• eliminate weaknesses in existing concepts and standards (eg, revenue recognition requirements – should there be a focus on changes in assets and liabilities rather than the occurrence of critical events; contracts that provide more than one good or service to the customer – when should contracts be divided into components and how much revenue should be attributed to each component);

• converge IFRS and US requirements.

The Board plans to issue a Discussion Paper (jointly with the FASB) for consultation in thesecond quarter of 2008.

2 Developments from the IASB



2.4 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 is 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 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 deferred tax assets of the acquiree 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 more interest to utilities entities. The requirement to re-assess all contracts and arrangements forembedded derivatives may result in moreclassified as derivatives with subsequent incomestatement volatility. Contingent consideration ismore common in extractive industries, withselling shareholders seeking to profit frompreviously undiscovered resources or favourableprice movements. These arrangements are lesscommon in utilities, but do exist. All such


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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 grossamounts is included in the notes to the financialstatements, removing them from the primarystatements diminishes their prominence.

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.

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 in


arrangements will be captured by the contingentconsideration guidance and recognised asliabilities of the acquirer whether or not paymentis probable at the date of the transaction. All subsequent changes are income statementitems.

2.5 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.


the 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 willreflect the cumulative impact of all relevantfactors. For example, if a company has aninterest in the net result of a joint venture itwill account for its interest in the joint ventureusing equity accounting. However, if it alsopurchases a share of the output (eg, power) fromthe joint venture and sells it to a third party, it willrecord revenue for those third-party sales inaddition to equity accounting for its interest inthe 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.

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.


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3 IFRS/US GAAP Differences

35Financial reporting in the utilities industry3 IFR

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3 IFRS/US GAAP Differences


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 utilities entities. Thesedifferences relate to: depreciation, decommissioning obligations, impairment, arrangements that maycontain a lease, regulatory assets, concessions, business combinations and financial instruments.

3.1 Fixed assets and components

Components ofproperty, plant andequipment

Significant parts (components) of anitem of PPE are depreciatedseparately if they have different usefullives.

Component approach todepreciation not required, howeveris often followed as a matter ofindustry practice.

Issue IFRS US GAAP



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3.2 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.

Indeterminate life of asset to be decommissioned does not removethe need to measure thedecommissioning obligation, but theeffect of discounting will have agreater impact on the measurementof the liability.

The adjustment to PPE when thedecommissioning liability isrecognised forms part of the asset tobe 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 existingliability 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 resultof adjustment to the decommissioningliability. In particular, 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



3.3 Impairment

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.

Testing power stations for impairment on a portfolio basis is not consistentwith the CGU approach.

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 an asset’scarrying amount will not berecovered from its use and eventualdisposal.

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

A pooled approach to impairment testing maybe appropriate in certaincircumstances.

Impairment is measured as theexcess of the asset’s carryingamount over its fair value. Fair valueis determined using a discountedcash flow valuation.

Impairment losses are neverreversed.

Issue IFRS US GAAP


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3.4 Arrangements that may contain a lease

Retrospectiveapplication

Arrangements that convey the rightto use an asset in return for apayment or series of payments arerequired to be accounted for asleases if certain conditions are met.This requirement applies even if thecontract does not take the form of alease.

The IFRS guidance that requires this analysis, IFRIC 4, was applicablefrom 2006 but required all existingarrangements to be analysed.

Similar to IFRS except that theapplicable US GAAP guidance, EITF01-8, was applicable only to newarrangements entered into (ormodifications made to existingarrangements) after the effectivedate.

Issue IFRS US GAAP

3.5 Regulatory Assets and Liabilities

Regulatory assetsand liabilities

Regulatory assets are generally notrecognised in rate regulated regimesbecause the utility entity does nothave control over the recoverability ofthe future economic benefits. It is notentitled to require payment fromcustomers in respect of past servicesunless future services are provided.

Regulatory liabilities are not recognised except in exceptional circumstanceswhen the utility is obliged throughsome mechanism to repay cash tothe customers without the sale offuture services to the customer.

FAS 71 specifically requiresrecognition of regulatory assets andliabilities in certain circumstances.

Issue IFRS US GAAP



3.6 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 acquireehas an existing liability at acquisitiondate. Liabilities for future losses orother costs expected to be incurredas 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

3.7 Concession arrangements

Identification andclassification ofconcessionarrangements

Public-to-private service concessionarrangements that meet certainconditions must be analysed todetermine whether the concessionrepresents a financial asset or anintangible asset.

No equivalent guidance.

Issue IFRS US GAAP



The following summary reflects differences between the requirements of IFRS 3 (Revised 2008) andFAS 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 thannot that they meet definition of assetor 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.

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3.8 Financial instruments and trading & risk managementIFRS 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.

Issue IFRS US GAAP

Continued on the next page



Separation of embeddedderivatives

Own-use exemption

Offsetting contracts

Derivatives embedded in hybrid contracts 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 modifies thecash flows that would otherwise berequired 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 financial instrumentare accounted for as financialinstruments unless the contract wasentered into and continues to be heldfor the purpose of the physical receiptor delivery of the non-financial item inaccordance with the entity’s expectedpurchase, sale or usage requirements.

Application of the own-use exemptionis a requirement – not an election.

A practice of entering into offsettingcontracts to buy and sell acommodity is considered to be apractice of net settlement. All similarcontracts must be accounted for asderivatives.

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.

Similar to IFRS, except that powerpurchase or sales agreements thatmeet the definition of a capacitycontract are not accounted for asderivatives even if they are enteredinto to offset other such contracts.

Issue IFRS US GAAP


4 Financial disclosure examples

45Financial reporting in the utilities industry4 Financial d

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4.1 Decommissioning obligationsAsset retirement obligations and recultivationobligations, & sinking funds

Fortum CorporationProvisions“Provisions for environmental restorations, asset retirement obligations, restructuring costs andlegal claims are recognised when the Group hasa present legal or constructive obligation as aresult of past events to a third party, it isprobable that an outflow of resources will berequired to settle the obligation and the amountcan be reliably estimated. Provisions aremeasured at the present value of theexpenditures expected to be required to settlethe obligation using a pre-tax rate that reflectscurrent market assessments of the time value ofmoney and the risks specific to the obligation.The increase in the provision due to the passageof time is recognised as interest expense.

Asset retirement obligationsAsset retirement obligation is recognised either, when there is a contractual obligation towards athird party or a legal obligation and the obligationamount and the definite lifetime can be estimatedreliably. Obligating event is e.g. when a plant isbuilt on a leased land with an obligation todismantle and remove the asset in the future orwhen a legal obligation towards Fortum changes.The asset retirement obligation is recognised aspart of the cost of an item of property and plantwhen the asset is put in service or whencontamination occurs. The costs will bedepreciated over the remainder of the assets’useful life.

Liabilities related to nuclear productionThe provision for future obligations for nuclear waste management including decommissioningof Fortum’s nuclear power plant and relatedspent fuel is based on long-term cash-flowforecasts of estimated future costs. The mainassumptions are technical plans, timing, costsestimates and discount rate. The technical plans,timing and cost estimates are approved bygovernmental authorities. Any changes in theassumed discount rate would affect the

provision. If the discount rate used would belowered, the provision would increase. Fortumhas contributed cash to the State Nuclear WasteManagement Fund based on a non-discountedlegal liability, which leads to that the increase inprovision would be offset by an increase in therecorded share of Fortum’s part of the StateNuclear Waste Management Fund in the balancesheet.

The total effect on the income statement would be positive since the decommissioning part ofthe provision is treated as an asset retirementobligation. This situation will prevail as long asthe legal obligation to contribute cash to theState Nuclear Waste Management Fund is basedon a non-discounted liability and IFRS is limitingthe carrying value of the assets to the amount ofthe provision since Fortum does not have controlor joint control over the fund.

Annual Report and Accounts 2007, Fortum Corporation, p. 35 and 37

RWE AG“The vast majority of provisions for nuclear waste management are recognized as non-currentprovisions, and their settlement amount isdiscounted to the balance-sheet date. As in theprevious year, an interest rate of 5.0% was usedas the discount rate. Volume-based increases inthe provisions are measured at their presentvalue. In the reporting period, they amounted toEuro 128 million (previous year: Euro 92 million).By releasing Euro 178 million in unusedprovisions (previous year: Euro 164 million), wehave taken into account that waste disposalcosts are expected to be lower, according tocurrent estimates. Additions to provisions fornuclear waste management primarily consist ofan interest accretion of Euro 425 million (previousyear: Euro 416 million). Euro 684 million inprepayments, primarily to foreign reprocessingcompanies and to the German Federal Office forRadiation Protection (BfS) for the construction offinal storage facilities, were deducted from theprovisions for nuclear waste management(previous year: Euro 640 million).

4 Financial disclosure examples



In terms of their contractual definition, provisions for nuclear waste management break down asfollows:

In respect of the disposal of spent nuclear fuelassemblies, the provisions for obligations whichare not yet contractually defined cover theestimated long-term costs of direct final storageof fuel assemblies, which is currently the onlypossible disposal method in Germany, and thecosts for the disposal of radioactive waste fromreprocessing. The latter essentially consist ofcosts for transport from centralized storagefacilities and the plants’ intermediate storagefacilities to reprocessing plants and final storageas well as conditioning for final storage andcontainers. These estimates are mainly based onstudies by internal and external experts, inparticular by Gesellschaft für Nuklear-ServicembH (GNS) in Essen, Germany. With regard tothe decommissioning of nuclear power plants,the costs for the post operational phase anddismantling are taken into consideration, on thebasis of data from external expert opinionsprepared by NIS Ingenieurgesellschaft mbH,Alzenau Germany, which are generally acceptedthroughout the industry and are updatedcontinuously. Finally, this item also covers all ofthe costs of final storage for all radioactivewaste, based on data provided by BfS.

Provisions for contractually defined nuclear obligations are related to all nuclear obligationsfor the disposal of fuel assemblies and radioactivewaste as well as for decommissioning, insofar asthe value of said obligations is specified incontracts under civil law. They include the

anticipated residual costs of reprocessing, return(transport, containers) and intermediate storageof the resulting radioactive waste, as well as theadditional costs of the utilization of uranium and plutonium from reprocessing activities.These costs are based on existing contracts with foreign reprocessing companies and withGNS. Moreover, these provisions also take into account the costs for transport and intermediatestorage of spent fuel assemblies within theframework of final direct storage. The powerplants’ intermediate storage facilities are licensedfor an operational period of 40 years andcommenced operations between 2002 and 2006.Furthermore, the amounts are also stated for theconditioning and intermediate storage ofradioactive operational waste, which is primarilyperformed by GNS.

With due consideration of the German Atomic Energy Act (AtG), in particular to Sec. 9a of AtG,the provision for nuclear waste managementbreaks down as follows:

Provisions for mining damage also consist primarily of non-current provisions. They arerecognized at the settlement amount discountedto the balance-sheet date. As in the previousyear, an interest rate of 5.0% was used as thediscount rate. In the reporting period, additionsto provisions for mining damage amounted toEuro 210 million (previous year: Euro 151 million). Of this, an increase of Euro 128 million (previousyear: Euro 108 million) did not have an impact onincome, as an identical amount was capitalizedunder property, plant and equipment. The interest

4 Financial disclosure exam

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Provisions for nuclear obligations, not yet contractually defined 7,159 6,895

Provisions for nuclear obligations,contractually defined 1,894 1,939

9,053 8,834

Provisions for nuclearwaste managementin Euro millions 12.31.2007 12.31.2006

Decommissioning of nuclear facilities 4,443 4,213

Disposal of nuclear fuel assemblies 4,061 4,168

Disposal of radioactive operational waste 549 453

9,053 8,834

Provisions for nuclearwaste managementin Euro millions 12.31.2007 12.31.2006



accretion of the additions to provisions for miningdamage amounted to Euro 123 million (previousyear: Euro 113 million).

Provisions for restructuring pertain mainly to measures for socially acceptable payrolldownsizing from previous years.”

Annual Report and Accounts 2007, RWE AG, p .183 f

4.2 ImpairmentDefinition of CGUs, e.g. for networks; treatmentof deferred taxes

RWE AG Management estimates and judgments“(…) The impairment test for goodwill is based on certain assumptions pertaining to the future.Based on current knowledge, changes in theseassumptions will not cause the carrying amountsof the cash-generating units to exceed therecoverable amounts, and thus will also not resultin an adjustment of the carrying amounts in thenext fiscal year. Due to the planned disposal ofthe North American water business, the valuationof this cash-generating unit is based on market-related data, and changes in such may have animpact on the carrying amount. In particular, thevaluation depends on the equity marketconditions prevailing at the time of recognition,the development of long-term interest rates onthe capital market and the development of assetssubject to regulation as well as the decisions ofthe local regulatory authorities. (…) ”

Annual Report and Accounts 2007, RWE AG, p. 155

Intangible assets“In the reporting period, a total of Euro 74 million(previous year: Euro 73 million) was spent onresearch and development. Development costsof Euro 52 million (previous year: Euro 62 million)were capitalized. Intangible assets in explorationactivities accounted for Euro 209 million in thereporting period (previous year: Euro 101 million).

Goodwill was allocated to cash-generating unitsat the segment level or at a level beneath thesegment level to carry out impairment tests.Goodwill breaks down as follows:

The goodwill of RWE Energy includes Euro 1,241million (previous year: Euro 1,270 million) whichwas recognized in accordance with IAS 32. Thisgoodwill stems from put options granted andforward purchases of minority interests.

In the reporting period, goodwill decreased byEuro 2,090 million (previous year: Euro 3,266million). Classification of American Water as adiscontinued operation resulted in a decline ofEuro 1,789 million, and divestments by RWEEnergy resulted in disposals of Euro 163 million.In accordance with IAS 12.68, the goodwill ofRWE npower was reduced by Euro 138 million(previous year: Euro 48 million), as tax benefitsfrom periods prior to first-time consolidation wererealized.

In the period under review, no impairment losses were recognized on goodwill on continuedoperations (previous year: Euro 6 million).Currency effects decreased the carrying amountof goodwill by Euro 520 million (previous year:Euro 23 million).

The impairment test involves determining the recoverable amount of the cash-generating units,which corresponds to the fair value less costs tosell or the value in use. The fair value reflects thebest estimate of the sum that an independentthird party would pay to purchase the cash-generating unit as of the balance-sheet date;selling costs are deducted. Value in use is thepresent value of the future cash flows which areexpected to be generated with a cash-generating

RWE Power 829 829

of which: RWE Dea (30) (30)

of which: RWE Trading (434) (434)

RWE Energy 5,003 5,118

RWE npower 3,876 4,370

Water Division 2,001

9,708 12,318

Goodwillin Euro millions 12.31.2007 12.31.2006



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unit. As of the balance-sheet date, both the fairvalue less costs to sell and the value in use ofthe cash-generating units were substantiallyhigher than their carrying amounts.

Fair value and value in use are determined on the basis of a business valuation model, whereby the fair value is assessed from an externalperspective and the value in use from acompany-internal perspective. Fair values andvalues in use are determined based on futurecash flows, which are based on the businessplan for a period of five years, which has beenapproved by the Executive Board and which isvalid when the impairment test is performed.Business plans are based on experience as wellas on future expected market trends. If available,market transactions or third-party valuations ofsimilar assets in the same sector are taken as abasis for determining the fair value.

Business plans are based on the general economic data derived from macroeconomic and financial studies and make country-specificassumptions, primarily regarding the developmentof gross domestic product, consumer prices,interest rates and nominal wages.

The main assumptions underlying the business planning for the divisions active on Europe’selectricity and gas markets – RWE Power, RWEEnergy and RWE npower – are the premisesrelating to the development of wholesale pricesfor electricity, crude oil, natural gas, coal andCO2 emission allowances, and retail prices forelectricity and gas, as well as to the developmentof market shares and regulatory frameworkconditions. The discount rates used for businessvaluations are determined on the basis of marketdata and range from 6.5 to 8.5% for cash-generating units after tax (previous year: 5.7 to6.9%). As in the previous year, the rate generallyapplied is 6.5%. By contrast, a discount rate of8.5% is used for RWE Dea, and in the previousyear a rate of 5.7% was used in the waterbusiness in North America. Before tax, all of theinterest rates used are between 9.5 and 13.0%(previous year: 7.5 and 10.5%).

RWE extrapolates future cash flows going beyond the detailed planning horizon based onconstant growth rates of 0.0 to 0.5% (previous

year: 0.0 to 1.26%), in order to account forexpected inflation. These figures are derived fromexperience and future expectations for eachdivision and do not exceed the long-termaverage growth rates of the markets on whichthe companies are active. The cash flow growthrates are determined subtracting the capitalexpenditure required to achieve the assumedcash flow growth.”

Annual Report and Accounts 2007, RWE AG, p. 166 f

Centrica plc“Goodwill and indefinite lived intangibles are tested for impairment annually, or morefrequently if there are indications that amountsmight be impaired. The impairment test involvesdetermining the recoverable amount of the cash-generating units, which corresponds to the fairvalue less costs to sell or the value in use. Valuein use calculations have been used to determinerecoverable amounts for the cash-generatingunits noted above. These are determined usingcash flow budgets, which are based on businessplans for a period of three years. These businessplans have been approved by the Board and arevalid when the impairment test is performed. The plans are based on past experience as wellas future expected market trends. Cash flowsbeyond the three-year plan period used in thevalue in use calculations are increased in linewith historic long-term growth rates in the UK, orwhere applicable the US, Canada, Belgium andthe Netherlands. Discount rates applied to thecash flow forecasts in determining recoverableamounts are derived from the Group’s weightedaverage cost of capital. Discount rates applied toNorth American cash-generating units range from9.4% to 9.5%, and from 8.5% to 11.2% for UKand Europe cash-generating units on a pre-taxbasis. Growth rates used to extrapolate cashflow projections beyond the period covered bythe most recent forecasts range from 1% to2.5%.

The key assumptions in the value in use calculations determining recoverable amounts forthe specific cash-generating units noted aboveare:



British Gas Business• Budgeted gross margin: for existing contract

customers this is based on contracted margins. For new and renewal contract customers this is based on achieved gross margin in the period prior to the approval of the business plan, adjusted in some areas to reflect market conditions. For tariff customers this is based on current prices in the period prior to the approval of the business plan, adjusted for the Group’s view of the forward energy curve.

• Budgeted market share: based on the average market share achieved immediately prior to the approval of the business plan, adjusted for growth forecasts based on sales and marketing activity.

British Gas Services – Dyno-Rod• Budgeted franchise fee income: based on the

average income achieved immediately prior to the approval of the business plan, adjusted for growth forecasts based on sales and marketing activity.

• Budgeted cost growth: based on the cost growth in the period prior to the approval of the business plan.

Texas residential energy• Budgeted gross margin: based on the average

gross margin achieved prior to the approval of the business plan, adjusted to reflect market conditions.

• Budgeted market prices: based on a combination of the Group’s view of forward gas and power prices immediately prior to the approval of the business plan and the price impact of targeted margins.

• Budgeted consumption: based on past experience of the average consumption per customer prior to the approval of the business plan.

• Budgeted customer numbers: based on past experience in the three years prior to the approval of the business plan adjusted for an expected marginal decline in customer numbers.

Canada mass markets• Budgeted gross margin: for existing customers

this is based on contracted margins. For new and renewal contract customers this is based

on gross margin achieved in the period immediately prior to the approval of the business plan.

• Budgeted market share: based on average market share achieved in the period immediately prior to the approval of the business plan, adjusted for growth and decline assumptions specific to each of the competitive and regulated businesses.

• Budgeted market prices: for existing customers this is based on contracted prices. For new or renewal customers this is based on the Group’s view of forward gas and power prices in Canada.

• Budgeted cost growth: based on current and forecasted experience required to support customer acquisition, renewal, retention and other servicing activities.

Canada Direct Energy business services• Budgeted gross margin: based on gross

margins achieved through recent sales and renewal activity and potentially adjusted for future expected market conditions.

• Budgeted churn: based on historic actual attrition and renewal rates prior to the approval of the business plan.

• Budgeted revenue growth: based on management’s view of forward commodity cost curves as provided by the internal energy management group at the time of approval of the business plan to determine future selling prices. Volume growth is estimated based on average achieved growth in the past, uplifted by expected future growth as a result of the planned sales activities that management believes to be reasonably attainable.

Canada home services• Budgeted gross margin: based on gross

margins achieved in the period immediately prior to the approval of the business plan.

• Budgeted revenue growth: based on the average revenue growth achieved for the three-year period prior to the approval of the business plan, uplifted for additional product offerings.

US home services• Budgeted gross margin: based on gross

margins achieved in the period immediately prior to the approval of the business plan.



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• Budgeted revenue growth: based on the average revenue growth achieved over the last three years prior to the approval of the business plan, uplifted for growth targets based on expected market penetration in certain key US state markets.

Europe – Oxxio• Budgeted revenue growth: based on revenue

in the period immediately prior to the approval of the business plan, uplifted for expected growth in customer base, cross-selling of products and reduction of customer churn.

• Budgeted gross margin: based on the average gross margin achieved in periods prior to the approval of the business plan, adjusted for the expected impact arising from the unbundling of the gas and electricity markets going forward.

• Budgeted operating expenditure: based on historical trends, adjusted for cost improvement programmes implemented.

The Group is of the opinion that, based on current knowledge, expected changes in theaforementioned key assumptions on which thedetermination of the recoverable amounts arebased would not cause the recoverable amountsto be less than the carrying amounts of the cash-generating units.”

Annual Report and Accounts 2007, Centrica plc, p. 91 f

4.3 Arrangements that may contain a leaseIFRIC 4: Wind parks and other generation plants;contracting

EDF Group Arrangements containing a lease“In compliance with interpretation IFRIC 4, the Group identifies agreements that convey the rightto use an asset or group of specific assets to thepurchaser although they do not have the legalform of a lease contract, as the purchaser in thearrangement benefits from a substantial share ofthe asset’s production and payment is notdependent on production or market price. Sucharrangements are treated as leases, and analyzedwith reference to IAS 17 for classification aseither finance or operating leases.”

Annual Report and Accounts 2007, EDF Group, p. 18

4.4 Emission Trading Scheme and Certified Emission Reductions

Fortum Corporation Emission allowances“The Group accounts for emission allowances based on currently valid IFRS standards wherepurchased emission allowances are accountedfor as intangible assets at cost, whereasemission allowances received free of charge areaccounted for at nominal value. A provision isrecognised to cover the obligation to returnemission allowances. To the extent that Groupalready holds allowances to meet the obligationthe provision is measured at the carrying amountof those allowances. Any shortfall of allowancesheld over the obligation is valued at the currentmarket value of allowances. The cost of theprovision is recognised in the income statementwithin materials and services. Gains from sales ofemission rights are reported in other income.”

CO2 emission allowance price risk“Fortum manages its exposure to CO2 allowance prices related to own production through the useof CO2 forwards and by ensuring that the costsof allowances are taken into account duringproduction planning. These are own usecontracts valued at cost. In addition to ownproduction Fortum has proprietary trading book.These allowances are treated as derivatives inthe accounts.”


Centrica plcEU Emissions Trading Scheme and renewable obligations 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 emissions



allowances are measured at fair value with gains 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 are initially 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 f

4.5 Customer contributionsRevenue recognition; customer subsidies/contributions for construction projects

Fortum CorporationGovernment grants“Grants from the government are recognised at their fair value where there is a reasonableassurance that the grant will be received and theGroup will comply with all attached conditions.Government grants relating to costs are deferredand recognised in the income statement over theperiod necessary to match them with the coststhat they are intended to compensate.Government grants relating to the purchase ofproperty, plant and equipment are deducted fromthe acquisition cost of the asset and arerecognised as income by reducing thedepreciation charge of the asset they relate to.”

Annual Report and Accounts 2007, Fortum Corporation, p. 31

RWE AGRevenue (including natural gas tax/electricity tax)“Revenue is recorded when the risk stemming from a delivery or service has been transferred tothe customer. To improve the presentation ofbusiness development, RWE reports revenuegenerated by energy trading operations as net

figures, reflecting realized gross margins. Bycontrast, electricity, gas, coal and oil transactionsthat are subject to physical settlement are statedas gross figures. Energy trading revenue isgenerated by RWE Trading. In fiscal 2007, grossrevenue (including energy trading) amounted toEuro 65,097 million (previous year: Euro 70,213million). The segment reporting on pages 196 to199 contains a breakdown of revenue (includingnatural gas tax/electricity tax) by division andgeographical region. Deconsolidations and first-time consolidations reduced revenue by a netEuro 806 million. Natural gas tax/electricity taxare the taxes paid directly by Group companies.”

Annual Report and Accounts 2007, RWE AG, p. 159

E.ON AGTrade Payables and Other Operating Liabilities“(…) Construction grants of Euro 3,412 million (2006: Euro 3,470 million) were paid by customersfor the cost of new gas and electricity connectionsin accordance with the generally binding termsgoverning such new connections. These grantsare customary in the industry, generally non-refundable and recognized as revenue accordingto the useful lives of the related assets. (...)”

Annual Report and Accounts 2007, E.ON AG, p. 183



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4.7 Business combinationsBusiness combinations, e.g. in-processdevelopment projects

Fortum Corporation“(…) The financial statements of Fortum Group have been consolidated according to thepurchase method. The cost of an acquisition ismeasured as the aggregate of fair value of theassets given and liabilities incurred or assumedat the date of exchange, plus costs directlyattributable to the acquisition. Identifiable assetsacquired and liabilities assumed in a businesscombination are measured initially at their fairvalues at the acquisition date, irrespective of theextent of any minority interest. The excess of thecost of acquisition over the fair value of theGroup’s share of the identifiable net assetsacquired is recorded as goodwill. If the cost ofacquisition is less than the fair value of the netassets of the subsidiary acquired, the differenceis recognised directly in the income statement.Subsidiaries are fully consolidated from the dateon which control is transferred to the Group andare no longer consolidated from the date thatcontrol ceases. Intercompany transactions,balances and unrealised gains on transactionsbetween Group companies are eliminated.Unrealised losses are also eliminated unless thetransaction provides evidence of an impairmentof the asset transferred. Where necessary,subsidiaries’ accounting policies have beenchanged to ensure consistency with the policiesthe Group has adopted.”


4.6 Regulatory assets & liabilities

E.ON AG U.S. Regulation“Accounting for E.ON’s regulated utility businesses, Louisville Gas and Electric Company,Louisville, Kentucky, U.S., and Kentucky UtilitiesCompany, Lexingtion, Kentucky, U.S., of the U.S.Midwest market unit, conforms to U.S. generallyaccepted principles as applied to regulatedpublic utilities in the United States of America.These entities are subject to SFAS No. 71,“Accounting for the Effects of Certain Types ofRegulation” (SFAS 71”), under which certaincosts that would otherwise be charged toexpense are deferred as regulatory assets basedon expected recovery of such costs fromcustomers in future rates approved by therelevant regulator. Likewise, certain credits thatwould otherwise be reflected as income aredeferred as regulatory provisions. The current orexpected recovery by the entities of deferredcosts and the expected return of deferred creditsis generally based on specific ratemakingdecisions or precedent for each item. Theregulatory assets and liabilities under U.S.GAAPdo not fulfill the recognition criteria for assets andliabilities under IFRS. As a result, these regulatoryassets and liabilities were offset against equityand resulted in an increase in equity of Euro 403million within the opening balance sheet(December 31, 2006: Euro 279 million).”


Fortum Corporation“(…) The prices charged to customers for thesale of distribution of electricity are regulated.The regulatory mechanism differs from country tocountry. Any over or under income decided bythe regulatory body is regarded as regulatoryassets or liabilities that do not qualify for balancesheet recognition due to the fact that no contractdefining the regulatory aspect has been enteredinto with a specific customer and thus thereceivable is contingent on future delivery. The overor under income is normally credited or chargedover a number of years in the future to thecustomer using the electricity connection at thattime. No retroactive credit or charge can be made.”




4.8 Concession arrangementsIFRIC 12: Concession agreements

EDF Group IFRIC 12“The IFRIC issued interpretation IFRIC 12, “Service Concession Arrangements”, inNovember 2006. Subject to completion of theendorsement process by the EuropeanCommission, application of this interpretation willbe mandatory in the EU for financial yearsbeginning on or after January 1, 2008. EDF hasnot opted for early application.

Nevertheless, a full review of the concessionagreements concerning each of the Group’sFrench and foreign entities was instigated in late2006 and continued into 2007, to determine thetreatment applicable in the light of interpretationIFRIC 12. This treatment depends on whether thegrantor has control, as defined by IFRIC 12, overthe infrastructures and services during theconcession: • If the grantor controls the infrastructures and

services, the concession falls into the scope of IFRIC 12 and the associated infrastructures are recorded in the operator’s accounts as either an intangible asset or a financial asset,

• Otherwise, the concession is not governed by IFRIC 12 and the infrastructure is accounted for under the IFRS applicable.

Analysis of the control exercised by the grantor involves examining, for each contract, the type ofinfrastructure concerned (electricity generation,transmission or distribution) but also the legalaspects (the respective rights and obligations ofthe grantor and operator as defined in theagreements) and business environments(particularly tariffs and regulations), both in andoutside France.”

Annual Report and Accounts 2007, EDF Group, p. 27

4.9 Financial instruments

Centrica plcDerivative financial instruments“The Group routinely enters into sale and purchase transactions for physical delivery ofgas, power and oil. A portion of these

transactions take the form of contracts that wereentered into and continue to be held for thepurpose of receipt or delivery of the physicalcommodity in accordance with the Group’sexpected sale, purchase or usage requirements,and are not within the scope of IAS 39.

Certain purchase and sales contracts for the physical delivery of gas, power and oil are withinthe scope of IAS 39 because they net settle orcontain written options. Such contracts areaccounted for as derivatives under IAS 39 andare recognised in the Balance Sheet at fair value.Gains and losses arising from changes in fairvalue on derivatives that do not qualify for hedgeaccounting are taken directly to the IncomeStatement for the year.

The Group uses a range of derivatives for both trading and to hedge exposures to financial risks,such as interest rate, foreign exchange andenergy price risks, arising in the normal course of business. The use of derivative financialinstruments is governed by the Group’s policiesapproved by the Board of Directors. Furtherdetail on the Group’s risk management policiesis included within the Directors’ Report –Governance on pages 39 to 40 and in note 4 tothe Financial Statements.

The accounting treatment for derivatives is dependent on whether they are entered into fortrading or hedging purposes. A derivativeinstrument is considered to be used for hedgingpurposes when it alters the risk profile of anunderlying exposure of the Group in line with the Group’s risk management policies and is inaccordance with established guidelines, whichrequire that the hedging relationship isdocumented at its inception, ensure that thederivative is highly effective in achieving itsobjective, and require that its effectiveness canbe reliably measured. The Group also holdsderivatives which are not designated as hedgesand are held for trading.

All derivatives are recognised at fair value on the date on which the derivative is entered into andare re-measured to fair value at each reportingdate. Derivatives are carried as assets when thefair value is positive and as liabilities when thefair value is negative. Derivative assets and



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Instruments commonly used are foreign currency forwards and swaps, as well as interest-rateswaps and cross-currency swaps. Equityforwards are entered into to cover price risks onsecurities. In commodities, the instruments usedinclude physically and financially settled forwardsand options related to electricity, gas, coal, oiland emission rights. As part of conductingoperations in commodities, derivatives are alsoacquired for proprietary trading purposes. (…)”


Fortum Corporation Accounting for derivative financial instrumentsand hedging activities“(…) Derivatives are initially recognised at fairvalue on the date a derivative contract is enteredinto and are subsequently re-measured at theirfair value. The method of recognising theresulting gain or loss depends on whether thederivative is designated as a hedging instrument,and if so, the nature of the item being hedged.The Group designates certain derivatives aseither: (1) hedges of highly probable forecasttransactions (cash flow hedges); (2) hedges ofthe fair value of recognised assets or liabilities ora firm commitment (fair value hedge); or (3)hedges of net investments in foreign operations.The Group documents at the inception of thetransaction the relationship between hedginginstruments and hedged items, as well as its riskmanagement objective and strategy forundertaking various hedge transactions. TheGroup also documents its assessment, both athedge inception and on an ongoing basis, ofwhether the derivatives that are used in hedgingtransactions are highly effective in offsettingchanges in fair values or cash flows of hedgeditems. Derivatives are divided into non-currentand current based on maturity. Only for thoseelectricity derivatives, which have cash flows indifferent years, the fair values are split betweennon current and current assets or liabilities.”


E.ON AG Valuation of Derivative Instruments“The fair value of derivative instruments is sensitive to movements in underlying marketrates and other relevant variables. The Company

derivative liabilities are offset and presented on anet basis only when both a legal right of set-offexists and the intention to net settle thederivative contracts is present.

The Group enters into certain energy derivative contracts covering periods for which observablemarket data does not exist. The fair value of suchderivatives is estimated by reference in part topublished price quotations from active markets,to the extent that such observable market dataexists, and in part by using valuation techniques,whose inputs include data, which is not based onor derived from observable markets. Where thefair value at initial recognition for such contractsdiffers from the transaction price, a fair value gainor fair value loss will arise. This is referred to as a day-one gain or day-one loss. Such gains andlosses are deferred and amortised to the IncomeStatement based on volumes purchased ordelivered over the contractual period until suchtime observable market data becomes available.When observable market data becomesavailable, any remaining deferred day-one gainsor losses are recognised within the IncomeStatement. Recognition of the gain or loss thatresults from changes in fair value depends on the purpose for issuing or holding the derivative. For derivatives that do not qualify for hedgeaccounting, any gains or losses arising fromchanges in fair value are taken directly to theIncome Statement and are included within grossprofit or interest income and interest expense.Gains and losses arising on derivatives enteredinto for speculative energy trading purposes arepresented on a net basis within revenue.”

Annual Report and Accounts 2007, Centrica plc, p. 65 and 66

E.ON AG Derivative Financial Instruments and Hedging Transactions“Derivative financial instruments and separated embedded derivatives are measured at fair valueas of the trade date at initial recognition and insubsequent periods. IAS 39 requires that they becategorized as held for trading as long as theyare not a component of a hedge accountingrelationship. Gains and losses from changes infair value are immediately recognized in netincome.



assesses and monitors the fair value of derivativeinstruments on a periodic basis. Fair values foreach derivative financial instrument aredetermined as being equal to the price at whichon party would assume the rights and duties ofanother party, and calculated using commonmarket valuation methods with reference toavailable market data as of the balance sheetdate.

The following is a summary of the methods and assumptions for the valuation of utilizedderivative financial instruments in theConsolidated Financial Statements.• Currency, electricity, gas, oil and coal forward

contracts, swaps, and emissions-related derivatives are valued separately at their forward rates and prices as of the balances sheet date. Forward rates and prices are based on spot rates and prices, with forward premiums and discounts taken into consideration. Market data are used to the extent possible.

• Market prices for currency, electricity and gasoptions are valued using standard option pricing models commonly used in the market. The fair value of caps, floors and collars are determined on the basis of quoted market prices or on calculations based on option pricing models.

• The fair values of existing instruments to hedge interest risk are determined by discounting future cash flows using market interest rates over the remaining term of the instrument. Discounted cash values are determined for interest rate, cross-currency and cross-currency interest rate swaps for each individual transaction as of the balance sheet date. Interest income is recognized in income at the date of payment or accrual.

• Equity forwards are valued on the basis of thestock prices of the underlying equities, taking into consideration any timing components.

• Exchange-traded energy futures and optioncontracts are valued individually at daily settlement prices determined on the futures markets that are published by their respective clearing houses. Paid initial margins are disclosed under other assets. Variation margins received or paid during the term of such contracts are stated under other liabilities or other assets, respectively.

• Certain long-term energy contracts are valuedwith the aid of valuation models that use internal data if market prices are not available.

Losses of Euro 11 million (2006: Euro 49 million) and gains of Euro 141 million (2006: Euro 96million) from the initial measurement of derivativefinancial instruments at the inception of thecontract were deferred and will be recognized inincome during subsequent periods as thecontracts are fulfilled. The following two tablesinclude both derivatives that qualify for IAS 39hedge accounting treatment and those that donot qualify.

The carrying amounts of cash and cashequivalents and of trade receivables areconsidered reasonable estimates of their fairvalues because of their short maturity.

Where financial instruments are listed on an active market, the respective price quotes at thatmarket constitute the fair value. This applies inparticular to equities held and bonds issued.

The fair value of shareholdings in unlisted companies and of debt securities that are notactively traded, such as loans received, loansgranted and financial liabilities, is determined bydiscounting future cash flows. Discounting takesplace using current customary market interestrates through the remaining terms of the financialinstruments. Fair value measurement was notapplied in the case of shareholdings with acarrying amount of Euro 58.3 million (2006: Euro58.3 million) as cash flows could not bedetermined reliably for them. Fair values couldnot be derived on the basis of comparabletransactions. The shareholdings are not materialby comparison with the overall position of theGroup.

The fair value of commercial paper and borrowings under revolving short-term creditfacilities and of trade receivables is used as thefair value due to the short maturities of these instruments. (...)



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12.31.2007 12.31.2007 12.31.2006 12.31.2006in Euro millions Nominal value Fair value Nominal value Fair value

FX forward transactions

Buy 8,466.8 -24.2 4,352.7 -27.1

Sell 9,738.3 67.3 6,982.4 19.4

FX currency options

Buy - - 7.4 0.1

Sell - - - -

Subtotal 18,205.1 43.1 11,522.5 -7.6

Cross-currency swaps 19,847.2 686.6 18,499.3 7.4

Cross-currency interest rate swaps 301.6 -49.6 321,9 -17.0

Subtotal 20,148.8 637.0 18,821.2 -9.6

Interest rate swaps

Fixed-rate payer 1,894.0 -21.5 2,292.5 -16.4

Fixed-rate receiver 6,153.7 -85.9 6,078.3 -89.8

Interest rate future 1,719.4 30.2

Subtotal 9,767.1 -77.2 8,370.8 -106.2

Other derivatives 117.3 12.0 636.7 31.0

Subtotal 117.3 12.0 636.7 31.0

Total 48,238.3 614.9 39,351.2 -92.4

Total Volume of Foreign Currency, Interest Rate and Equity-Based Derivatives



12.31.2007 12.31.2007 12.31.2006 12.31.2006 in Euro millions Nominal value Fair value Nominal value Fair value

Electricity forwards 25,733.5 -794.1 29,049.7 -854.0

Exchange-traded electricity forwards 10,033.6 -98.8 8,089.5 -275.0

Electricity swaps 21.4 -1.1 15.1 0.5

Exchange-traded electricity options 104.9 9.5 0.3 0.2

Coal forwards and swaps 5,024.4 193.1 1,320.2 29.2

Exchange-traded coal forwards 38.1 25.7 58.9 -1.1

Oil derivatives 708.4 11.6 1,213.4 -30.6

Gas forwards 12,932.1 335.3 16,757.1 6.7

Gas swaps 313.8 -36.2 153.4 -17.4

Gas options 4.5 -3.6 5.3 2.8

Exchange-traded gas forwards 1.2 0.1 - -

Emissions-related derivatives 1,808.0 6.0 461.0 2.8

Exchange-traded emissions-related derivatives 407.8 -0.1 33.9 3.8

Total 57,203.7 -352.6 57,157.8 -1,132.1

Total Volume of Electricity, Gas, Coal, Oil and Emissions-Related Derivatives



ples


in Euro millions Carrying Total IAS 39 Fair Determinedamounts carrying measurement value using

amounts category marketwithin the pricesscope ofIFRS 7

Equity investments 14,583 14,583 AfS 14,583 13,061

Financial receivables and other financial assets 3,964 3,920 4,140 262

Financial receivables from entities in which an ownership interest exists 899 899 LaR 899 -

Receivables from finance leases* 700 700 n/a 705 -

Other financial receivables and financial assets 2,365 2,321 LaR 2,536 262

Trade receivables and other operating assets 18,653 17,021 16,940 377

Receivables from entities in which an ownership interest exists 846 845 LaR 845 -

Trade receivables 9,064 9,064 LaR 9,064 -

Derivatives with no hedging relationships 4,928 4,928 HfT 4,928 365

Derivatives with hedging relationships 632 632 n/a 632 -

Other operating assets 3,183 1,552 LaR 1,471 12

Securities and fixed-term deposits 10,783 10,783 AfS 10,783 9,635

Cash and cash equivalents 2,887 2,887 AfS 2,887 2,860

Restricted cash 300 300 AfS 300 300

Assets held for sale 577 - AfS - -

Total assets 51,747 49,494 49,633 26,495

Additional Disclosures on Financial InstrumentsCarrying Amounts and Fair Values by Class Within the Scope of IFRS 7 as of December 31, 2007

Continued on the next page* Includes finance leases with third parties and withentities in which an ownership interest exists.



in Euro millions Carrying Total IAS 39 Fair Determinedamounts carrying measurement value using

amounts category marketwithin the pricesscope ofIFRS 7

Financial liabilities 21,464 21,464 21,903 12,869

Financial liabilities to entities in which an ownership interest exists 2,085 2,085 AmC 2,085 -

Bonds 14,470 14,470 AmC 14,886 12,823

Commercial paper 1,984 1,984 AmC 1,984 -

Bank loans/Liabilities to banks 2,012 2,012 AmC 1,931 -

Liabilities from finance leases* 193 193 n/a 297 -

Other financial liabilities 720 720 AmC 720 46

Trade payables and other operating liabilities 23,686 17,356 17,356 502

Liabilities to entities in which an ownership interest exists 539 539 AmC 539 -

Trade payables 4,477 4,477 AmC 4,477 -

Derivatives with no hedging relationships 4,630 4,630 HfT 4,630 502

Derivatives with hedging relationships 641 641 n/a 641 -

Put option liabilities under IAS 32 754 754 AmC 754 -

Other operating liabilities 12,645 6,315 AmC 6,315 -

Total liabilities 45,150 38,820 39,259 13,371

Table glossaryAfS – Available for saleLaR – Loans and receivables HfT – Held for trading AmC – Amortized cost

* Includes finance leases with third parties and withentities in which an ownership interest exists.



ples


Risk Managment(...) Price RisksIn the normal course of business, the E.ON Group is exposed to foreign exchange, interestand commodity price risks, and also to pricerisks in equity investments in the context of cashinvestments activities. These risks create volatilityin earnings, equity and cash flows from period toperiod. The Company makes use of derivativefinancial instruments in various strategies to limitor eliminate these risks.

The following discussion of the Company’s risk management activities and the estimatedamounts generated from profit-at-risk, Value-at-Risk and sensitivity analyses are “forward-lookingstatements” that involve risks and uncertainties.Actual results could differ materially from thoseprojected due to actual, unforeseeabledevelopments in the global financial markets. The methods used by the Company to analyzerisks, as discussed below, should not beconsidered projections of future events or losses.The Company also faces risks that are either non-financial or non-quantifiable. Such risksprincipally include country risk, operational riskand legal risk which are not represented in thefollowing analyses.

Foreign Exchange Risk ManagementDue to the international nature of some of its business activities, the E.ON Group is exposedto exchange risks related to sales, assets,receivables and liabilities denominated in foreigncurrencies, investments in foreign operations and anticipated foreign currency payments. The Company’s exposure results mainly fromtransactions in U.S. dollars, British pounds,Hungarian forint, Swedish kronor and Russianrubles, and from net investments in foreignoperations.

E.ON AG is responsible for controlling the currency risks to which the E.ON Group isexposed, and sets appropriate risk parameters.The subsidiaries are responsible for controllingtheir operating currency risks. Recognized assetsand liabilities are generally hedged in the fullamount. For unrecognized firm commitments,hedging takes place after consultation betweenthe subsidiary and E.ON AG.

(...) For financial liabilities that bear floatinginterest rates, the rates that were fixed on theBalances sheet date are used to calculate futureinterest payments for subsequent periods aswell. Financial liabilities that can be terminated atany time are assigned to the earliest maturitytime band in the same way as put options thatare exercisable at any time.

In gross-settled derivatives (usually currency derivatives and commodity derivatives), outflowsare accompanied by related inflows of funds orcommodities.

The net gains and losses form financial instruments by IAS 39 category are shown in thefollowing table:

In addition to interest income and expenses fromfinancial receivables, the net gains and losses inthe loans and receivables category consistprimarily of valuation allowances on tradepayables. Gains and losses on the disposal ofavailable-for-sale securities and equityinvestments are reported under other operatingincome and other operating expenses,respectively.

In addition, the interest income and expenses from interest-bearing securities is included in thisnet result.

The net gains and losses in the held-for-trading category encompass both the changes in fair value of the derivative financial instruments andthe gains and losses on realization. (...)

Loans and receivables 385 520

Available for sale 1,533 847

Held for trading 446 -1,858

Amortized cost -929 -989

Total 1,435 -1,480

in Euro millions 12.31.2007 12.31.2006

Net Gains and Losses by Category



The foreign exchange risk arising from net investments in foreign operations with a functionalcurrency other than the euro is reduced at Grouplevel as needed through hedges of net investments.In addition, borrowings are made in foreigncurrency to control foreign exchange risks.

In line with the Company’s internal risk-reporting process and international banking standards,market risk has been calculated using the Value-at-Risk method on the basis of historical marketdata. The Value-at-Risk (or “VaR”) is equal to themaximum potential loss (on the basis of aprobability of 99 percent) from foreign-currencypositions that could be incurred within thefollowing business day. The calculations takeaccount of correlations between individualtransactions; the risk of a portfolio is generallylower than the sum of its individual risks.

The one-day Value-at-Risk from the translation of deposits and borrowings denominated in foreigncurrency, plus foreign currency derivatives,amounted to Euro 148 million (2006: Euro 54million) and, as in 2006, resulted primarily fromthe open positions denominated in Britishpounds and U.S. dollars. The increase in the VaRover the previous year is due in particular to theincreased volatility of the Euro/GBP exchangerate and to overall higher volumes denominatedin foreign currency.

This VaR has been calculated in accordance with the requirements of IFRS 7. In practice, however,another value will result, since certain underlyingtransactions (e.g. scheduled transactions and off-balance-sheet own-use agreements) are notconsidered in the calculation according to IFRS 7.

Interest Risk ManagementSeveral line item on the Consolidated Balance Sheet and certain financial derivatives are basedon fixed interest rates, and are therefore subjectto changes in fair value resulting from changes inmarket rates. In the case of balance sheet itemsand financial derivatives based on floatinginterest rates, E.ON is exposed to profit risks.E.ON seeks to maintain a specific mix of fixed-and floating-rate debt in its overall debt portfolio.The company uses interest rate swaps in order tobenefit from the spread between short-term and

long-term interest rates and from any potentialeasing of interest rates in general.

As of December 31,2007, the E.ON Group has entered into interest rate swaps with a nominalvalue of Euro 9,767 million (2006: Euro 8,371million).

A sensitivity analysis was performed on the Group’s short-term and variable-rate borrowings,including interest rate derivatives. A one-percentincrease (decline) in the level of interest rateswould cause net interest expense to rise (fall) byEuro 30 million per annum (2006: Euro 35 million).

Commodity Price Risk ManagementE.ON is exposed to substantial risks resulting from fluctuations in the prices of commodities, both on the supply and demand side. This risk ismeasured based on potential negative deviation from the target adjusted EBIT.

The maximum permissible risk is determined centrally by the Board of Management in its medium-term planning and translated into adecentralized limit structure in coordination withthe market units. Before fixing any limits, theinvestment plans and all other known obligations and quantifiable risks have beentaken into account.

E.ON conducts commodity transactions primarily within the system portfolio, which includes core operations, existing sales and procurementcontracts and any energy derivatives used forhedging purposes or for power plantoptimization. The risk in the system portfolio thus arises from the open position between plannedprocurement and generation and plannedsales volumes. The risk of these open positionsis measured using the profit-at-risk (“PaR”) number, which quantifies the risk by taking intoaccount the size of the open position and the prices, the volatility and the liquidity of theunderlying commodities. PaR is defined as the maximum potential negative change in the valueof the portfolio at a probability of 95 percent in the event that the open position is closed asquickly as possible.



ples


The principal derivative instruments used by E.ON to cover commodity price risk exposuresare electricity, gas, coal and oil swaps andforwards, as well as emissions-relatedderivatives. Commodity derivatives are used bythe market units for the purposes of price risk management, system optimization, equalizationof burdens and improvement of margins.Proprietary trading is permitted only within verytightly defined limits. The risk metric used for The proprietary trading portfolio is a five-dayValue-at-Risk with a 95-percent confidenceinterval.

The trading limits for proprietary trading as well as for all other trading activities are establishedand monitored by bodies that are independentfrom trading operations. Limits used on hedgingand proprietary trading activities include five-dayValue-at-Risk and profit-at-risk numbers, as well as stop-loss limits. Additional key elementsof the risk management system are a set ofGroup-wide commodity risk guidelines, the clear devision of duties between scheduling,trading, settlement and controlling, as well as arisk reporting system independent of the tradingoperations. Group-wide developments incommodity risks are reported to the RiskCommittee on a monthly basis.

As of December 31, 2007, the E.ON Group has entered into electricity, gas, coal, oil andemissions-related derivatives with a nominalvalue of Euro 57,204 million (2006: Euro 57,158million).

The VaR for the proprietary trading portfolio amounted to Euro 13 million as of December 31,2007 (2006: Euro 16 million). The PaR for thefinancial instruments in the scope of IFRS 7included in the system portfolio was Euro 433million as of December 31, 2007 (2006: Euro289 million).

The restriction to financial instruments included in the scope of IFRS 7 that has been appliedin this calculation does not reflect the economicpositions of the E.ON Group. Consequently,none of the off-balance sheet transactions, suchas own-use contracts under normal tradingrelationships, may be included when calculatingthe PaR according to IFRS 7, even though such transactions represent a materialcomponent of the economic position. The PaR reflecting the actual economic position thereforediffers significantly from the PaR determined in accordance with IFRS 7.”

Annual Report and Accounts 2007, E.ON AG, p. 188 ff

Fortum CorporationCounterparty Risk“Exposures against limits and counterparties’ creditworthiness are monitored to ensure that therisks are at an accepted level. When changesappear to be leading to unacceptable risksaccording to approved policies, Corporate CreditControl initiates actions to mitigate risks.Counterparty risk exposures relating to financialderivative instruments are often volatile. Themajority of the Group’s commodity derivatives

Investment grade receivables 173 – 79 –

Electricity exchanges 9 – 101 –

Associated companies 639 – 603 –

Other 219 – 211 –

Total 1,040 – 994 –

12.31.2007 12.31.2006

in Euro millions Carrying of which Carrying of whichamount past due amount past due



are cleared by the Nordic electricity exchange,Nord Pool. Derivative transactions are also donewith other individual external counterparties onthe financial or commodity markets. Counterpartyrisk in the retail and wholesale business is welldiversified over a large number of privateindividuals and industrial companies.

Amounts disclosed below are presented bycounterparties for interest-bearing receivablesincluding leasing receivables and derivativefinancial instruments recognised as assets.”

CO2 emission allowance price risk“Fortum manages its exposure to CO2 allowance prices related to own production through the useof CO2 forwards and by ensuring that the costsof allowances are taken into account duringproduction planning. These are own usecontracts valued at cost. In addition to ownproduction Fortum has proprietary trading book.These allowances are treated as derivatives inthe accounts. At 31 December 2007 the tradingvolumes of sold and bought CO2 emissionallowances were 3,101 ktCO2 (2006: 405) and3,121 ktCO2 (2006: 418). The respective net fairvalues were Euro – 13 million (2006:0) and Euro13 million (2006:0).”


RWE AG“Market risks result from fluctuations in prices on financial markets. Changes in exchange rates,interest rates and share prices can have an

influence on the Group’s results on operatingactivities. Due to the Group’s international profile,exchange rate management is a key issue. The British pound and the US dollar are the twomost important foreign currencies for two mainreasons: On the one hand, the Group is engagedin business activities in these two currencyzones. On the other hand, fuels are traded inthese currencies. Group companies are generallyrequired to hedge all currency risks via RWE AG,which determines the net financial position foreach currency and hedges it with external marketpartners if necessary.

Interest rate risks stem primarily from financial debt and the Group’s interest-bearinginvestments. Negative changes in value causedby unexpected interest-rate movements arehedged with non-derivative and derivativefinancial instruments.

Opportunities and risks from changes in the values of securities are controlled by a professionalfund management system. The Group’s financialtransactions are recorded using centralized riskmanagement software and monitored by RWEAG. This enables the balancing of risks acrossindividual companies.

Group risk management has established directives for commodity operations, stipulatingthat derivatives may be used to hedge againstprice risks, optimize power plant schedules andincrease margins. Furthermore, commodityderivatives may be traded, subject to strict limits.These limits are defined by independent

12.31.2007 12.31.2006

Foreign currency derivatives 43.9 22.7

Forwards 5.3 5.7

Options 0.1 0.9

Interest rate currency derivatives 44.8 25.4

Interest rate derivatives 5.8 3.4

Share-price/index-related derivatives 1.9

Value-at-Risk for financial derivatives in Euro million

Value-at-Risk



ples


organizational units and monitored on a dailybasis.

All derivative financial instruments are recognized as assets or liabilities and are measured at fairvalue. When interpreting the positive andnegative fair values of derivative financialinstruments, with the exception of the relativelylow commodity trading volumes, it must be takeninto account that they are generally matched withunderlying transactions that carry offsetting risks.

Maturities of interest rate, currency, share price or indexrelated and commodity derivatives arebased on the maturities of the underlyingtransactions and are thus primarily short-termand medium-term in nature. Maturities of up to30 years have been agreed upon to hedgeforeign currency risks of foreign investments.

The Value-at-Risk method is used to quantify the interest rate, foreign currency and share-pricerisks for financial instruments as well ascommodity price risks, in line with theinternational banking standard. The maximumexpected loss arising from changes in marketprices is calculated on the basis of historicalmarket volatility and is monitored continuously.

The following Value-at-Risk information relates exclusively to recognized financial instruments, in line with the mandatory rules of IFRS 7. Off-balance-sheet planned positions which arehedged and so-called executory contracts incommodities may not be taken into account. As a result, an incomplete picture of the risksituation of the RWE Group is presented.

As of December 31, 2007, the foreign currencyValue-at-Risk for all items to be taken intoaccount pursuant to IFRS 7 amounted to Euro17.2 million (previous year: Euro 10.9 million). In accordance with IFRS 7, underlyingtransactions which are the subject of a cash flowhedge were not taken into consideration indetermining this position. The Value-at-Riskdetermined in this manner thus represents aslightly pessimistic scenario, taking into accountrisk aspects.

As of December 31, 2007, the interest rate Value-at-Risk from financial debts and related hedgingtransactions amounted to Euro 69.3 million(previous year: Euro 34.5 million). Taking intoaccount the hedges, the Value-at-Risk frominterest-bearing assets amounted to Euro 21.2million (previous year: Euro 18.8 million).

Share price Value-at-Risk was Euro 17.3 million as of December 31, 2007 (previous year: Euro24.8 million).

As of December 31, 2007, commodity price Value-at-Risk pursuant to IFRS 7 amounted toEuro 35.2 million (previous year: Euro 97.6million).

The Value-at-Risk figures are based on a confidence interval of 95% and a holding periodof one day.”

Annual Report and Accounts 2007, RWE AG, p. 192 f

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

Manfred WiegandGlobal Utilities LeaderTelephone: +49 201 438 1517Email: [email protected]

Norbert SchwietersGlobal Utilities IFRS GroupTelephone: +49 211 981 2153Email: [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]

IndiaKameswara RaoTelephone: +91 40 2330 0750Email: [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]

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

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

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

Norbert SchwietersTelephone: +49 211 981 2153 Email: [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]

NorwayStåle Johansen Telephone: +47 9526 0476Email: [email protected]

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

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

Contact us




Middle East

Reinhard SchulzTelephone: +971 2 694 6905Email: [email protected]

The Americas

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

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

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

United StatesPaul KeglevicTelephone: +1 213 356 6309Email: [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]


© 2008 PricewaterhouseCoopers. All rights reserved. PricewaterhouseCoopers refers to the network of member firms of PricewaterhouseCoopers International Limited, each of which is a separate andindependent legal entity.

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