www.pwc.

com/powerandutilities

Financial reporting
in the power and
utilities industry

International Financial
Reporting Standards
2nd edition
Foreword

Of course, it is not just the IFRSs that

International Financial Reporting are constantly evolving, but also the

Foreword
Standards (IFRS) provide the basis for operational issues faced by power and
company reporting in an increasing utilities companies. We look at some of
number of countries around the world. the main developments in this context
Over 100 countries either use or are with a selection of reporting topics that
adopting IFRS reporting. The pace of are of most practical relevance to power
standard-setting from the International and utilities companies’ activities.
Accounting Standards Board (IASB)
has been intense in recent years, with a This publication does not seek to
constant flow of changes for companies describe all IFRSs applicable to power
to keep up with. and utilities entities. The ever-changing
landscape means that management
One of the biggest challenges of any should conduct further research and
reporting standard is how best to seek specific advice before acting on
interpret and implement it in the any of the more complex matters raised.
context of a specific company or PwC has a deep level of insight into and
industry. In general, IFRS is short on commitment to helping companies in
industry guidance. PwC is filling this the sector report effectively. For more
gap with a regularly updated series information or assistance, please do not
of publications that take a sector- hesitate to contact your local office or
by-sector look at IFRS in practice. one of our specialist power and utilities
In this edition, we look at the issues partners.
faced by utilities companies. We draw
on our considerable experience of
helping utilities companies apply IFRS
effectively and we include a number
of real-life examples to show how
companies are responding to the various
challenges along the value chain.

Manfred Wiegand Norbert Schwieters

Global Power & Utilities Leader Global Power & Utilities IFRS Group
September 2011

Financial reporting in the power and utilities industry 3

 Contents

Introduction 7
1 Power and Utilities value chain and significant accounting issues 9
1.1 Overview 10
1.2 Generation 11
1.2.1 Fixed assets and components 11
1.2.2 Borrowing costs 11
1.2.3 Decommissioning obligations 13
1.2.4 Impairment 14
1.2.5 Arrangements that may contain a lease 15
1.2.6 Emission trading scheme and certified emission reductions 17
1.3 Transmission and distribution 19
1.3.1 Fixed assets and components 19
1.3.2 Customer contributions 20
1.3.3 Regulatory assets and liabilities 21
1.3.4 Line fill and cushion gas 21
1.3.5 Net realisable value of oil inventories 22
1.3.6 Network operation arrangements 22
1.4 Retail 23
1.4.1 Customer acquisition costs 23
1.4.2 Customer discounts 23
1.5 Entity-wide issues 23
1.5.1 Concession arrangements 23
1.5.2 Business combinations 24
1.5.3 Joint ventures 25

4 Financial reporting in the power and utilities industry

2 Financial instruments 29

Contents
2.1 Overview 30
2.2 Scope of IAS 39 30
2.3 Application of “own use” 32
2.4 Measurement of long-term contracts that do not qualify for “own use” 34
2.5 Take-or-pay contracts and volume flexibility (optionality) 35
2.6 Embedded derivatives 37
2.7 Hedge accounting 39
2.8 Trading and risk management 41
3 Future developments – standards issued and not yet effective 43
3.1 Overview 44
3.2 Consolidation and joint arrangements 44
3.2.1 Consolidation 44
3.2.2 Joint arrangements 44
3.3 Fair value measurement 47
3.4 Financial instruments 47
Appendices 53
A Financial statement disclosure examples 54
B US GAAP/IFRS differences 69
Acknowledgements 78
Contact us 79

Financial reporting in the power and utilities industry 5

Introduction

Introduction
What is the focus of this What is included?
publication?
This publication includes a discussion
This publication considers the major of issues that we believe are of financial
accounting practices adopted by the reporting interest due to their particular
utility industry under International relevance to power and utility entities and/
Financial Reporting Standards (IFRS). or historical varying international practice.

The need for this publication has arisen We focus our discussion not only on how
due to the following factors: the transition to IFRS has affected the
• The adoption of IFRS by power and power and utility industry, but also on how
utility entities across a number of the industry is dealing with the following
jurisdictions, with overwhelming factors:
acceptance that applying IFRS in this • Significant growth in corporate
industry will be a continual challenge acquisition activity
• Ongoing transition projects in a • Increased globalisation
number of other jurisdictions, from • Change in political landscape towards
which companies can draw upon the sustainability and renewable energy often
existing interpretations of the industry leading towards more regulation
• Continued increase in its exposure to
sophisticated financial instruments
Who should use this publication? and transactions
• An increased focus on environmental and
This publication is intended for: restoration liabilities
• Executives and financial managers in
the power and utility industries who are
often faced with alternative accounting PwC experience
practices
• Investors and other users of power and This publication is based on the experience
utility industry financial statements, gained from the worldwide leadership
so they can identify some of the position of PwC in the power and utility
accounting practices adopted to reflect industry. This leadership position enables
unusual features unique to the industry PwC’s Global Power & Utilities Centre of
• Accounting bodies, standard-setting Excellence to make recommendations and
agencies and governments throughout lead discussions on international standards
the world interested in accounting and and practice.
reporting practices and responsible
for establishing financial reporting We hope you find this publication useful.
requirements

Financial reporting in the power and utilities industry 7

 1

Power & Utilities value chain and significant accounting issues

1 Power & Utilities value
chain and significant
accounting issues

Financial reporting in the power and utilities industry 9

 1 Power & Utilities value chain and
significant accounting issues
1.1 Overview businesses may be split by regulation into generation,
transmission, distribution and retail businesses.
A traditional integrated power entity (utility) generates Competition may then be introduced for the generation
electricity and sends it around the country or region via and retail segments. Generators will look to compete
high-voltage transmission lines, finally delivering it to on price and secure long-term fuel supplies, balancing
customers through a retail distribution network. Some this against potentially volatile market prices for
utilities also or exclusively transport water and/or gas. wholesale power. The distribution business may see
As the industry continues to evolve, many operational the incumbent operator forced to grant other suppliers
and regulatory models have emerged. Generators access to its network. Power customers are beginning
continue to diversify supplies; fossil fuels still dominate to behave like any other group of retail customers,
but there is an increasing focus on bio-fuels, co- exercising choice, developing brand loyalty, shopping
generation and renewable sources such as wind, solar for the best rates or looking for an attractive bundle
and wave power. Some governments are supporting of services that might include gas, phone, water and
the construction of new nuclear power plants, and internet as well as power.
in some countries, construction has already started;
other governments are reconsidering or reversing their The power and utility industry is highly regulated,
support in response to the Fukushima event. with continuing government involvement in pricing,
security of supply and pressure to reduce greenhouse
The regulatory environment can be complex and gas emissions and other pollutants. Add this to a
challenging and may differ between geographies background of increased competition and a challenging
or even within a country. Pressure to introduce financial environment and difficult accounting issues
and increase competition and to diversify supply is result. This publication examines the accounting issues
apparent, as well as schemes that create financial that are most significant for the utilities industry. The
incentives to reduce emissions and increase the issues are addressed following the utilities value chain:
use of renewable sources. Previously integrated generation, transmission and distribution and issues
that affect the entire entity.

Power and Utilities Value Chain and Significant Accounting Issues

• Fixed assets and components • Fixed assets and components • Customer acquisition costs
• Borrowing costs • Customer contributions • Customer discounts
• Decommissioning obligations • Regulatory assets and liabilities
• Impairment • Line fill
• Arrangements that may contain a lease • Network operation agreements
• Emission trading scheme and CER
• Regulatory assets and liabilities

Generation Transmission & Distribution, Transport Retail

Support Functions/Trading and Risk Management

• Concession arrangements
• Business combinations
• Joint ventures
• Financial instruments
• Lease arrangements
• Trading and risk management

10 Financial reporting in the power and utilities industry

1.2 Generation Depreciation of components

Generating assets are often large and complex All components should be depreciated to their
installations. They are expensive to construct, tend to recoverable amount over their useful lives, which 1
be exposed to harsh operating conditions and require may differ among components. The remaining
periodic replacement or repair. This environment leads carrying amount of the component is derecognised

Power & Utilities value chain and significant accounting issues

to specific accounting issues. on replacement and the cost of the replacement part
is capitalised.
1.2.1 Fixed assets and components
The costs of performing major maintenance/overhaul
IFRS has a specific requirement for “component” are capitalised as a component of the plant, provided
depreciation, as described in IAS 16, Property, Plant and this provides future economic benefits. Turnaround/
Equipment. Each significant part of an item of property, overhaul costs that do not relate to the replacement of
plant and equipment is depreciated separately. components or the installation of new assets should
Significant parts of an asset that have similar useful be expensed when incurred. Turnaround/overhaul
lives and patterns of consumption can be grouped costs should not be accrued over the period between
together. This requirement can create complications for the turnarounds/overhauls because there is no legal
utility entities, as many assets include components with or constructive obligation to perform the turnaround/
a shorter useful life than the asset as a whole. overhaul. The entity could choose to cease operations
at the plant and hence avoid the turnaround/
Identification of components of an asset overhaul costs.

Generating assets might comprise a significant number 1.2.2 Borrowing costs

of components, many of which will have differing
useful lives. The significant components of these The cost of an item of property, plant and equipment
types of assets must be separately identified. This may include borrowing costs incurred for the purpose
can be a complex process, particularly on transition of acquiring or constructing it. IAS 23 (revised)
to IFRS, as the detailed recordkeeping needed for requires such borrowing costs to be capitalised if the
componentisation may not have been required to asset takes a substantial period of time to get ready for
comply with national generally accepted accounting its intended use. Examples of borrowing costs given
principles (GAAP). This can particularly be an issue by the standard are interest expense calculated using
for older power plants. However, some regulators may the effective interest method (described in IAS 39,
require detailed asset records, which can be useful for Financial Instruments: Recognition and Measurement);
IFRS component identification purposes. finance charges in respect of finance leases recognised
in accordance with IAS 17, Leases, and/or exchange
An entity might look to its operating data if the differences arising from foreign currency borrowings to
necessary information for components is not readily the extent that they are regarded as an adjustment to
identified by the accounting records. Some components interest costs.
can be identified by considering the routine
shutdown or overhaul schedules for power stations Borrowing costs should be capitalised while acquisition
and the associated replacement and maintenance or construction is actively underway. These costs
routines. Consideration should also be given to include the costs of specific funds borrowed for the
those components that are prone to technological purpose of financing the construction of the asset,
obsolescence, corrosion or wear and tear more severe and those general borrowings that would have been
than that of the other portions of the larger asset. avoided if the expenditure on the qualifying asset
had not been made. The general borrowing costs
First-time IFRS adopters can benefit from an exemption attributable to an asset’s construction should be
according to IFRS 1, First-time Adoption of International calculated by reference to the entity’s weighted-average
Financial Reporting Standards. This exemption allows cost of general borrowings.
entities to use a value that is not depreciated cost in
accordance with IAS 16, Property, Plant and Equipment,
and IAS 23, Borrowing Costs, as deemed cost on
transition to IFRS. It is not necessary to apply the
exemption to all assets or to a group of assets.

Financial reporting in the power and utilities industry 11

 Example Weighted-average borrowings during period:

A utility commences construction on a new power ((2b × 4)+(500 million × 3)+(750 million × 1))/4
plant 1 September 201X, which continues without = C2,562,500,000
interruption until after the year end 31 December
201X. Directly attributable expenditure on this asset Capitalisation rate (total finance costs in period/
is C100 million in September 201X and C250 million weighted-average borrowings during period)
in each of the months of October to December = 96,250,000/2,562,500,000
201X. Therefore, the weighted-average carrying = 3.756%
amount of the asset during the period is C475
million ((100 million + 350 million + 600 million The capitalisation rate, therefore, reflects
+ 850 million)/4). the weighted-average cost of borrowings for
the 4-month period that the asset was under
The entity has not taken out any specific borrowings construction. On an annualised basis 3.756% gives a
to finance the construction of the plant, but has capitalisation rate of 11.268% per annum, which is
incurred finance costs on its general borrowings what would be expected on the borrowings profile.
during the construction period. During the year
the entity had 10% debentures in issue with a face Therefore, the total amount of borrowing costs to be
value of C2 billion and an overdraft of C500 million, capitalised is the weighted-average carrying amount
which increased to C750 million in December 201X of asset × capitalisation rate
and on which interest was paid at 15% until 1 = C475 million × 11.268% × 4/12
October 201X, when the rate was increased to 16%. = C17,841,000
The capitalisation rate of the general borrowings
of the entity during the period of construction is
calculated as follows:
C (x1,000)
Finance cost on C2 billion 10% debentures during
September–December 201X 66,667
Interest at 15% on overdraft of C500 million in
September 201X 6,250
Interest at 16% on overdraft of C500 million in
October and November 201X 13,333
Interest at 16% on overdraft of C750 million in
December 201X 10,000

Total finance costs in September–December 201X
96,250

Utilities will sometimes use operating cash flows to

finance capital expenditure during a period when
there is also general financing. The borrowing rate is
applied to the full carrying amount of the qualifying
asset. This is the case even where the cash flows from
operating activities are sufficient to finance the capital
expenditure. IAS 23 (revised) does not deal with the
actual or imputed cost of capital.

12 Financial reporting in the power and utilities industry

 Example

A utility uses general borrowings and cash from interest-bearing debt from general borrowings. The 1
operating activities to finance its qualifying assets. borrowing rate is applied to the full carrying amount
It has a capital structure of 20% equity and 80% of the qualifying asset rather than to the 80% of the

Power & Utilities value chain and significant accounting issues

current and non-current liabilities including qualifying assets that are financed with borrowings.

A utility often contracts for a power plant on a turnkey operating life of a power plant or other installation.
basis. Down payments will often have to be paid by the The associated costs of remediation/restoration
utility, for example, over the construction period of a can be significant. The accounting treatment for
power plant. The borrowing costs incurred by an entity decommissioning costs is therefore critical.
to finance prepayments made to a third party to acquire
the qualifying asset are capitalised in accordance with Decommissioning provisions
IAS 23 (revised) on the same basis as the borrowing
costs incurred on an asset that is constructed by the A provision is recognised when an obligation exists
entity. Capitalisation starts when all three conditions to remediate or restore. The local legal regulations
are met: expenditures are incurred, borrowing costs should be taken into account when determining the
are incurred, and the activities necessary to prepare existence and extent of the obligation. Obligations to
the asset for its intended use or sale are in progress. decommission or remove an asset are created at the
Expenditures on the asset are incurred when the time the asset is placed in service. Entities recognise
prepayments are made (payments of the instalments). decommissioning provisions at the present value of
Borrowing costs are incurred when borrowing is the expected future cash flows that will be required
obtained. The last condition – the activities necessary to perform the decommissioning. The cost of the
to prepare the asset for its intended use or sale – is provision is recognised as part of the cost of the asset
considered to be met when the manufacturer has when it is placed in service and depreciated over the
started the construction process. Determining whether asset’s useful life. The total cost of the fixed asset,
the construction is in progress requires information including the cost of decommissioning, is depreciated
directly from the turnkey supplier. on the basis that best reflects the consumption of the
economic benefits of the asset: generally time-based for
Often utilities hedge borrowings. The effects of cash a power station.
flow or fair value hedge relationships on interest for a
specific project borrowing should also be capitalised. Provisions for decommissioning and restoration
While this is not addressed specifically by the standard, are recognised even if the decommissioning is not
the principles of IAS 39 are such that the hedging expected to be performed for a long time, for example
relationship modifies the borrowing costs of the utility 80 to 100 years. The effect of the time to expected
related to the specific debt. We believe therefore that decommissioning is reflected in the discounting of the
entities should take into account the effects of IAS provision. The discount rate used is the pre-tax rate
39 designated hedge accounting relationships for that reflects current market assessments of the time
borrowing costs. Ineffectiveness on such hedging value of money. Entities also need to reflect the specific
relationships should be recognised in profit or loss. risks associated with the decommissioning liability.
Different decommissioning obligations, naturally,
1.2.3 Decommissioning obligations have different inherent risks, for example different
uncertainties associated with the methods, the costs
The power and utilities industry can have a significant and the timing of decommissioning. The risks specific
impact on the environment. Decommissioning or to the liability can be reflected in the pre-tax cash flow
environmental restoration work at the end of the forecasts prepared or in the discount rate used.
useful life of a plant or other installation may be
required by law, the terms of operating licences or an A similar accounting approach is taken for nuclear fuel
entity’s stated policy and past practice. An entity that rods. These rods are classified as inventory, and an
promises to remediate damage, even when there is no obligation to reprocess them is triggered when the rods
legal requirement, may have created a constructive are placed into the reactor. A liability is recognised for
obligation and thus a liability under IFRS. There the reprocessing obligation when the rods are placed
may also be environmental clean-up obligations into the reactor, and the cost of reprocessing added to
for contamination of land that arises during the the cost of the fuel rods.

Financial reporting in the power and utilities industry 13

 Revisions to decommissioning provisions asset or group of assets that is below that expected by
management in operational and financial plans is also
Decommissioning provisions are updated at each an indicator of impairment.
balance sheet date for changes in the estimates of the
amount or timing of future cash flows and changes in Management should be alert to indicators of
the discount rate. Changes to provisions that relate to impairment on a CGU basis; for example, a fire at an
the removal of an asset are added to or deducted from individual generating station would be an indicator
the carrying amount of the related asset in the current of impairment for that station as a separate CGU.
period. Changes to provisions that relate to the removal Management may also identify impairment indicators
of an asset no longer used are recognised immediately on a regional, country or other asset grouping basis,
in the income statement. The adjustments to the asset reflective of how they manage their business. Once
are restricted, however. The asset cannot decrease an impairment indicator has been identified, the
below zero and cannot increase above its recoverable impairment test must be performed at the individual
amount: CGU level, even if the indicator was identified at a
• If the decrease to the provision exceeds the carrying regional level.
amount of the asset, the excess is recognised
immediately in profit or loss. Cash-generating units
• Adjustments that result in an addition to the
cost of the asset are assessed to determine if the A CGU is the smallest group of assets that generates
new carrying amount is fully recoverable. An cash inflows largely independent of other assets
impairment test is required if there is an indication or groups of assets. In identifying whether cash
that the asset may not be fully recoverable. inflows from an asset or groups of assets are largely
independent of the cash inflows from other assets (or
The accretion of the discount on a decommissioning groups of assets), an entity considers various factors,
liability is recognised as part of finance cost in the including how management monitors the entity’s
income statement. operations or how management makes decisions
about continuing or disposing of the entity’s assets and
1.2.4 Impairment operations.

The utility industry is distinguished by the significant Calculation of recoverable amount

capital investment required, exposure to commodity
prices and heavy regulation. The required investment Impairments are recognised if the carrying amount of
in fixed assets leaves the industry exposed to adverse a CGU exceeds its recoverable amount. Recoverable
economic conditions and therefore impairment amount is the higher of fair value less costs to sell
charges. Utilities’ assets should be tested for (FVLCTS) and value in use (VIU).
impairment whenever indicators of impairment exist.
The normal measurement rules for impairment apply. Fair value less costs to sell (FVLCTS)

Impairment indicators Fair value less costs to sell is the amount that a market
participant would pay for the asset or CGU, less the
Examples of external impairment triggers relevant costs of selling the asset. The use of discounted cash
for the utilities industry include falling retail prices, flows to determine FVLCTS is permitted where there is
rising fuel costs, overcapacity and increased or adverse no readily available market price for the asset or where
regulation or tax changes. there are no recent market transactions for the fair
value to be determined through a comparison between
Impairment indicators can also be internal in nature. the asset being tested for impairment and a recent
Evidence that an asset or cash-generating unit (CGU) market transaction. However, where discounted cash
has been damaged or has become obsolete is an flows are used, the inputs must be based on external,
impairment indicator; for example a power plant market-based data.
destroyed by fire is, in accounting terms, an impaired
asset. Other indicators of impairment are a decision The projected cash flows for FVLCTS therefore include
to sell or restructure a CGU or evidence that business the assumptions that a potential purchaser would
performance is less than expected. Performance of an include in determining the price of the asset. Thus,

14 Financial reporting in the power and utilities industry

industry expectations for the development of the There may be commodities – both fuel and the
asset may be taken into account, which may not be resultant electricity output – covered by purchase and
permitted under VIU. However, the assumptions and sales contracts. Management should use the contracted
resulting value must be based on recent market data price in its VIU calculation for any commodities 1
and transactions. unless the contract is already on the balance sheet at
fair value. Including the contracted prices of such a

Power & Utilities value chain and significant accounting issues

Post-tax cash flows are used when calculating FVLCTS contract would be to double count the effects of the
using a discounted cash flow model. The discount rate contract. Impairment of financial instruments that
applied in FVLCTS is a post-tax market rate based on a are within the scope of IAS 39, Financial Instruments:
typical industry participant’s cost of capital. Recognition and Measurement, is addressed by IAS 39
and not IAS 36.
Value in use (VIU)
The cash flow effects of hedging instruments, such as
VIU is the present value of the future cash flows caps and collars, for commodity purchases and sales are
expected to be derived from an asset or CGU in its also excluded from the VIU cash flows. These contracts
current condition. Determination of VIU is subject are also accounted for in accordance with IAS 39.
to the explicit requirements of IAS 36, Impairment
of Assets. The cash flows are based on the asset that 1.2.5 Arrangements that may contain
the entity has now and must exclude any plans to a lease
enhance the asset or its output in the future, but
includes expenditure necessary to maintain the current Accounting in this area will change due to the ongoing
performance of the asset. The VIU cash flows for IASB project on leases. Reporting entities should
assets under construction and not yet complete should continue to monitor the activities of the IASB in
include the cash flows necessary for their completion this area.
and the associated additional cash inflows or reduced
cash outflows. IFRS requires that arrangements that convey the
right to use an asset in return for a payment or series
Any foreign currency cash flows are projected in the of payments be accounted for as a lease, even if the
currency in which they are earned and discounted at a arrangement does not take the legal form of a lease.
rate appropriate for that currency. The resulting value Some common examples of such arrangements
is translated to the entity’s functional currency using include: a series of power plants built to exclusively
the spot rate at the date of the impairment test. supply the rail network, or a power plant located on
the site of an aluminium smelter or constructed on
The discount rate used for VIU is always pre-tax and a build–own–operate–transfer arrangement with a
applied to pre-tax cash flows. This is often the most national utility. Tolling arrangements may also convey
difficult element of the impairment test, as pre-tax rates the use of the asset to the party that supplies the fuel.
are not available in the marketplace and arriving at the Such arrangements have become very common in the
correct pre-tax rate is a complex mathematical exercise. renewable energy business where all of the output of
Grossing up the post-tax rate does not give the correct wind or solar farms or biomass plants is contracted to a
answer unless no deferred tax is involved. single party under a power purchase agreement.

Contracted cash flows in VIU IFRIC 4, Determining Whether an Arrangement

Contains a Lease, sets out guidelines to determine
The cash flows prepared for a VIU calculation should when an arrangement might contain a lease. Once
reflect management’s best estimate of the future a determination is reached that an arrangement
cash flows expected to be generated from the assets contains a lease, the lease arrangement must be
concerned. Purchases and sales of commodities are classified as either financing or operating according
included in the VIU calculation at the spot price at the to the principles in IAS 17, Leases. A lease that conveys
date of the impairment test, or, if appropriate, prices the majority of the risks and rewards of operation is a
obtained from the forward price curve at the date of finance lease. A lease other than a finance lease is an
the impairment test. operating lease.

Financial reporting in the power and utilities industry 15

 The classification has significant implications; a lessor market price at the time of delivery, the purchaser
in a finance lease would derecognise its generating is presumed to be paying for the output rather than
assets and recognise a finance lease receivable in leasing the asset.
return. A lessee in a finance lease would recognise
fixed assets and a corresponding lease liability rather There has been some debate over the meaning of “fixed
than account for the power purchase agreement as an per unit of output” in IFRIC 4 and two approaches
executory contract. have emerged in practice. “Fixed per unit of output” is
interpreted by some entities in a manner that allows
Classification as an operating lease leaves the lessor for no variability in pricing whatsoever over the entire
with the fixed assets on the balance sheet and the term of the contract (fixed equals fixed). However,
lessee with an executory contract. If lease accounting other entities have concluded that the fixed criterion
is inevitable, investors sometimes prefer operating is met if, at the inception of the arrangement, the
lease accounting. purchaser and seller can determine what the exact
price will be for every unit of output sold at each point
Power purchase agreements in time during the term of the arrangement (fixed
equals predetermined). There is support for both views,
It can be difficult to determine whether the power and the interpretation of “fixed” is an accounting policy
purchase agreement contains a lease. The purchaser election. The accounting policy should be disclosed and
may take all or substantially all of the output from a applied on a consistent basis to all similar transactions.
specified facility. However, this does not necessarily
mean that the entity is paying for the right of use of The following examples aid in the application of
the asset rather than for its output. If the purchase the “fixed equals predetermined” interpretation of
price is fixed per unit of output or equal to the current contractually fixed per unit of output:

Pricing is contractually predetermined and the 2) A power purchase agreement under which the
fixed price condition is deemed to be met: purchaser pays C75 for each MWh of electricity
1) A power purchase agreement under which the received during peak hours and C45 for each
purchaser pays C40 for each megawatt-hour MWh of electricity received during off-peak
(MWh) of electricity received during the first hours. Peak hours are defined in the agreement
year of the arrangement. The price per MWh in a manner whereby it can be determined at
increases by 2.5% during each subsequent year of the inception of the arrangement whether each
the arrangement. point in time is considered peak or off-peak.
For example: peak hours are from noon to 10:00
p.m. each day during July and August; all other
times are considered off-peak.

Pricing is not contractually predetermined and is not payable in any month that the capacity
the fixed price condition is deemed not met: factor drops below 30%. The pricing in this
1) A power purchase agreement under which the arrangement is not predetermined because
purchaser pays C40 for each megawatt-hour the price per MWh varies with the amount of
(MWh) of electricity received during the first electricity produced. Although the energy price is
year of the arrangement. The price per MWh fixed, the amount paid per MWh includes the fee
increases during each subsequent year of the for capacity and monthly changes in production
arrangement based on the annual change in the change the average cost per MWh. For example,
consumer price index. This price is not pre- if the plant produces 15,000 MWhs in the first
determined because it varies with inflation from month, the price is C42/MWh (C40/MWh energy
the second year on. charge plus C2/MWh allocated capacity charge).
2) A power purchase agreement under which the However, if the plant produces only 10,000
purchaser pays C40 per MWh plus a C30,000 MWhs, the price is C43/MWh.
per month capacity charge. The capacity charge

16 Financial reporting in the power and utilities industry

Similar to the “fixed price per unit” criterion, the What is output?
market price condition is narrowly interpreted. For
example, arrangements that include caps/floors would It is also important to determine what output should
not be considered to reflect the current market price at be taken into consideration in order to test whether 1
the time of delivery, because the price at delivery might the contract is, in substance, a lease. One question
be different from the spot market price. that arises with renewable plants is whether there is

Power & Utilities value chain and significant accounting issues

a power purchase agreement for substantially all, or
all, of the output, because the amount of generation
is determined by an uncontrollable factor (e.g., the
wind, sun or rain/snowfall). The following example
illustrates this concept:

Wind farm contract: purchaser, with the intention that the developer
• For 100% of the output of the wind farm recovers its operating costs, debt service cost and
• For substantially all of the asset’s life a development premium. Wind feasibility studies
• Guarantees a level of availability when the wind is are used to help site wind farms and assess the
blowing economic viability early in the development stage of
• Allows the purchaser to agree the timing of the project.
maintenance outages
• Pricing escalates annually based on annual A power purchase agreement for 100% of the output
changes in the consumer price index of a wind farm often contains a lease even though
the generation of electricity is contingent on the
The developer and owner of the wind farm agrees to wind. The variability in output does not impact the
sell 100% of the output of the wind farm to a single assessment of whether the contract contains a lease.

Another question that arises in lease classification • RECs are a government incentive: RECs are not
for renewable facilities is whether renewable energy considered as an output in the lease analysis.
certificates (RECs) are “output or other utility” Output is limited to the productive capacity of
in terms of IFRIC 4.9c. Some governments have the specified property and relates only to those
imposed on electricity suppliers a requirement to products that require “steel in the ground”. RECs
source an increasing proportion of electricity from result from a government programme (similar to
renewable sources. An accredited generator of tax incentives) created to promote construction
renewable electricity is granted a renewable energy of the plant and are a paper product, not a
certificate per MWh of renewable energy generated physical output.
to demonstrate that the electricity has been procured
from renewable sources. Although both approaches are supportable, the
approach used with RECs is an accounting policy
The determination of whether renewable energy choice to be applied consistently and to be disclosed.
certificates are “output or other utility” may impact the
evaluation of whether a power purchase agreement
contains a lease, particularly when the energy and 1.2.6 Emission trading schemes and
RECs are sold to different parties. Two approaches certified emission reductions
have emerged in practice as to what can be considered
output under IFRIC 4. These are explained as follows: The ratification of the Kyoto Protocol by the EU
• RECs are output: RECs are considered in the required total emissions of greenhouse gases within
lease evaluation. The construction of a specified the EU member states to fall to 92% of their 1990
facility and the pricing inherent in the contractual levels in the period between 2008 and 2012. Under the
arrangements with offtakers are based on the scheme, EU member states have set limits on carbon
combined benefit of energy, capacity, RECs and any dioxide emissions from energy-intensive companies.
other output from the facility. The scheme works on a “cap and trade” basis, and each
EU member state is required to set an emissions cap
covering all installations covered by the scheme.

Financial reporting in the power and utilities industry 17

 Even after the less specific Copenhagen Accord, the EU If initial recognition at fair value under IAS 20 is
cap and trade scheme is still considered to be a model elected, the government grant is amortised to the
for other governments seeking to reduce emissions. income statement on a straight-line basis over the
compliance period. An alternative to the straight-
Additionally, several non-Kyoto carbon markets exist. line basis can be used if it is a better reflection of
These include, for example, the New South Wales the consumption of the economic benefits of the
Greenhouse Gas Abatement Scheme, the Regional government grant.
Greenhouse Gas Initiative and Western Climate
Initiative in the United States. The entity may choose to apply the revaluation
model in IAS 38, Intangible Assets, for the subsequent
Accounting for emission trading schemes measurement of the emissions allowances. The
revaluation model requires that the carrying amount of
The emission rights permit an entity to emit pollutants the allowances is restated to fair value at each balance
up to a specified level. The emission rights are given sheet date, with changes to fair value recognised
or sold by the government to the emitter for a defined directly in equity, except for impairment, which is
compliance period. Schemes in which the emission recognised in the income statement.
rights are tradable allow an entity to do one of
the following: A provision is recognised for the obligation to deliver
• Emit fewer pollutants than it has allowances for allowances or pay a fine to the extent that pollutants
and sell the excess allowances have been emitted. The allowances reduce the
• Emit pollutants to the level that it holds provision when they are used to satisfy the entity’s
allowances for obligations through delivery to the government at the
• Emit pollutants above the level that it holds end of the scheme year. However, the carrying amount
allowances for and either purchase additional of the allowances cannot reduce the liability balance
allowances or pay a fine until the allowances are delivered.

IFRIC 3, Emission Rights, was published in December Certified emission reductions

2004 to provide guidance on how to account for
cap and trade emission schemes. The interpretation Another scheme under the Kyoto Protocol is in place
proved controversial and was withdrawn in June 2005 for fast-growing countries and countries in transition
because of concerns over the consequences of the that are not subject to a Kyoto target on emissions
required accounting. As a result, there is no specific reduction. Entities in these countries can generate
comprehensive accounting for cap and trade schemes certified emission reductions (CERs). CERs represent
or other emission allowances. a unit of greenhouse gas reduction that has been
generated and certified by the United Nations under
The guidance in IFRIC 3 remains valid, but entities the Clean Development Mechanism (CDM) provisions
are free to apply variations, provided that the of the Kyoto Protocol. The CDM allows industrialised
requirements of all relevant IFRS standards are met. countries that are committed to reducing their
Several approaches have emerged in practice under greenhouse gas emissions under the Kyoto protocol to
IFRS. The scheme can result in the recognition of earn emission reduction credits towards Kyoto targets
assets (allowances), expense of emissions, a liability through investment in “green” projects. Examples of
(obligation to submit allowances) and potentially a projects include reforestation schemes and investment
government grant. in clean energy technologies. Once received, the CERs
have value because they are exchangeable for EU ETS
The allowances are intangible assets – often presented allowances and hence can be used to meet obligations
as part of inventory – and are recognised at cost if under that particular scheme.
separately acquired. Allowances received free of charge
from the government are recognised either at fair value An entity that acquires CERs accounts for these
with a corresponding deferred income (liability), or at following the ETS cost model; they are accounted for
cost (nil) as allowed by IAS 20, Government Grants. at cost at initial recognition and then subsequently in
accordance with the accounting policy chosen by the
The allowances recognised are not amortised, entity. No specific accounting guidance under IFRS
provided residual value is at least equal to carrying covers the generation of CERs. Entities that generate
value. The allowances are recognised in the income CERs should develop an appropriate accounting policy.
statement as they are delivered to the government in Most entities that need CERs are likely to acquire them
settlement of the liability for emissions on a units-of- from third parties and account for them as separately
production basis. acquired assets.

18 Financial reporting in the power and utilities industry

The key question that drives the accounting for A network must be broken down into its significant
self-generated CERs is: What is the nature of the parts that have different useful lives. The
CERs? The answer to this question lies in the specific determination of the number and breakdown of parts
circumstances of the entity’s core business and is specific to the entity’s circumstances. A number of 1
processes. If the CERs generated are held for sale in factors should be considered in this analysis: the cost
the entity’s ordinary course of business, CERs are of different parts, how the asset is split for operational

Power & Utilities value chain and significant accounting issues

within the scope of IAS 2, Inventories. If they are not purposes, physical location of the asset and technical
held for sale, they should be considered as identifiable design considerations.
non-monetary assets without physical substance
(i.e., intangible assets – often presented as part Some network companies apply renewals accounting
of inventory). for expenditure related to their networks under
national GAAP. Expenditure is fully expensed and no
The accounting for CERs is also driven by the depreciation is charged against the network assets. This
applicability of IAS 20, Government Grants and accounting treatment is not acceptable under IFRS as
Disclosure of Government Assistance. If CERs are granted the normal fixed asset accounting and depreciation
by a government, the accounting would be as follows: requirements apply. This may be a significant
• Recognition when there is a reasonable assurance change for network companies and introduces some
that the entity will comply with the conditions application challenges.
attached to the CERs and the grant will be received
• Initial measurement at nominal amount or fair value, An entity with a history of expensing all current
depending on the policy choice expenditure may struggle initially to reinstate what
• Subsequent measurement depends on the should have been capitalised and what should have
classification of CERs and should follow the relevant been expensed. Materiality is a useful guide; if
standard (i.e., IAS 2 for inventory, IAS 38 for replacement costs are material to the asset, then,
intangible assets, IFRS 5 for non-current assets held provided recognition criteria are met (cost can be
for sale) reliably measured and future economic benefits are
probable), these costs should be capitalised. First-time
1.3 Transmission and distribution IFRS adopters can benefit from an exemption according
to IFRS 1, First-time Adoption of International Financial
Transmission and distribution activities in the power Reporting Standards. This exemption allows entities to
and utilities industry include the transmission of use a value that is not depreciated cost in accordance
power and the transportation of water or gas as with IAS 16, Property, Plant and Equipment, and IAS 23,
well as the distribution of these resources. This part Borrowing Costs, as deemed cost on transition to IFRS.
of the value chain is also dependent on significant It is not necessary to apply the exemption to all assets
capital investment in electric grid facilities and or to a group of assets.
pipeline networks.
Network companies may be accustomed to a working
1.3.1 Fixed assets and components assumption that assets have an indefinite useful life.
All significant assets have a finite life to be determined
Network assets, such as an electricity transmission under IAS 16, being the time remaining before the asset
system or a gas pipeline, comprise many separate needs to be replaced. Maintenance and repair activities
components. Many individual components may not may extend this life, but ultimately the asset will need
be significant. A practical approach to identifying to be replaced.
components is to consider the entity’s mid-/long-term
capital budget, which should identify significant capital A residual value must be determined for all significant
expenditures and pinpoint major components of the components. This value in many cases is likely to be
network that will need replacement over the next scrap only or nil, since IAS 16 defines residual value as
few years. The entity’s engineering staff should also the disposal proceeds if the asset were already of an age
be involved in identification of components based on and in the condition expected at the end of its useful
repairs and maintenance schedules and planned major life. An entity is required to allocate costs at initial
renovations or replacements. recognition to its significant parts. Each part is then
depreciated separately over its useful life. Separate
parts that have the same useful life and depreciation
method can be grouped together to determine the
depreciation charge.

Financial reporting in the power and utilities industry 19

 1.3.2 Customer contributions It is assumed that the entity has received the asset in
exchange for the delivery of services. Examples may
The provision of utility services to customers requires be the connection to a network and/or providing
some form of physical connection, whether the service ongoing access to a supply of goods or services. For
is gas, water or power. The investment required to each identifiable service within the agreement, revenue
provide that connection to the customer from the should be recognised as each service is delivered in
national or regional network may be significant. This accordance with IAS 18.
is likely when the customer is located far from the
network or when the volume of the utility that will be Where an entity provides both connection to a network
purchased requires substantial equipment. An example and ongoing access to goods or services, management
may be the provision of power to a remote location should determine whether these services are separate
where the construction of a substation is required to elements of the arrangement for the purposes of
connect the user to the national network. revenue recognition.

Many utility entities require the customer to The accounting depends on facts and circumstances
contribute to the cost of the connection, and in that differ from country to country. Management
return the customer receives the right to access should consider the following features for determining
the utility services. The utility entity constructs the whether the connection service is a separately
connecting infrastructure and retains responsibility for identifiable service:
maintaining it. The question is how the utility accounts • The connection represents standalone value to
for the contribution of the customer, whether the the customer. If the network entity concludes
assets contributed are recorded at cost or fair value, that the connection service does not represent
and whether the credit goes to income immediately or standalone value, it defers revenue over the period
whether it has to be deferred over the life of the asset or of the ongoing access service (or life of the asset
the contractual right to use. if shorter).
• The fair value of the connection service is reliably
The diversity of accounting methods used by entities measurable. If the fair value of the connection
for the assets they received led the Interpretation service cannot be measured reliably, revenue might
Committee of the IASB to issue IFRIC 18, Transfers be deferred and recognised over the period in which
of Assets from Customers. The interpretation requires the ongoing access service is provided.
the transferred assets to be recognised initially at
fair value and the related revenue to be recognised Features indicating that the ongoing access service
immediately; or, if there is a future service obligation, might be a separately identifiable service are:
revenue is deferred and recognised over the relevant • The customer receives the ongoing access service or
service period. goods and services at a price that is lower than for
customers who have not transferred an asset. When
The entity should assess whether the transferred item a customer pays a lower price in the future, revenue
meets the definition of an asset as set out in the IFRS is recognised over the period in which the service is
Framework. A key element is whether the entity has delivered, or the life of the asset, if shorter.
control of the item. The transfer of right of ownership • Where customers transferring assets to the entity pay
is not sufficient for establishing control. All facts and the same price for goods or services as those that do
circumstances should be analysed. An example may be not, management may determine that this indicates
the ability of the entity to decide how the transferred that the provision of ongoing access arises from
asset is operated and maintained and when it is the entity’s operating licence or other regulation,
replaced. If the definition is met, the asset is measured rather than as a result of the asset transfer from
at its fair value, which is its cost. the customer. If management determines that

20 Financial reporting in the power and utilities industry

 the ongoing access service does not arise from In July 2009, the IASB released an exposure draft,
the transfer of the connection asset, it is only the Rate-regulated Activities, which would allow for the
connection service that is provided in exchange for recognition of regulatory assets and liabilities for
the transfer of the asset, and revenue is recognised reporting entities within its scope. The project was not 1
immediately. completed due to resource constraints. However, the
IASB has suggested possible ways forward, including

Power & Utilities value chain and significant accounting issues

Major connection expenditures, such as substations a short- or medium-term project, or, alternatively,
or network spurs, often benefit more than one consideration of rate-regulated activities as part of
customer, and contributions may be received from a broader intangible asset project. Furthermore, the
several of these. However, when major connection IASB has included rate-regulated activities as a project
equipment is constructed for the sole benefit of one suggestion in its July 2011 Agenda Consultation.
customer, consideration should be given to whether Reporting entities should continue to monitor the
the equipment has, in substance, been leased to the activities of the IASB in this area.
customer. IFRIC 4 and IAS 17 should be applied to
determine whether the arrangement is, in substance, 1.3.4 Line fill and cushion gas
a lease and whether it should be classified as an
operating or finance lease. Some items of property, plant and equipment, such as
pipelines and gas storage, require a certain minimum
1.3.3 Regulatory assets and liabilities level of product to be maintained in them in order for
them to operate efficiently. This product is usually
Complete liberalisation of utilities is not practical classified as part of the property, plant and equipment
because of the physical infrastructure required for because it is necessary to bring the PPE to its required
the transmission and distribution of the commodity. operating condition. The product is therefore
Privatisation and the introduction of competition are recognised as a component of the PPE at cost and
often balanced by price regulation. Some utilities subject to depreciation to estimated residual value.
continue as monopoly suppliers with prices limited to a
version of cost plus margin overseen by the regulator. However, product owned by an entity that is stored in
PPE owned by a third party continues to be classified as
The regulatory regime is often unique to each country. inventory. This includes, for example, all gas in a rented
The two most common types of regulation are storage facility. It does not represent a component of
incentive-based regulation and cost-based regulation. the third party’s PPE or a component of PPE owned by
The regulator governing an incentive-based regulatory the entity. Such product should therefore be measured
regime usually sets the “allowable revenues” for a at first-in, first-out (FIFO) or weighted-average cost.
period with the intention of encouraging cost efficiency
from the utility. A utility entity operating under cost-
based regulation is typically permitted the recovery
of an agreed level of operating costs, together with a
return on assets employed.

An entity’s accounting policies should consider the

regulatory regime and the requirements of IFRS.
Any asset or liability arising from regulation to be
recognised under IFRS should be evaluated based
on applicable IFRSs or the Framework, as there is no
specific standard for the accounting for such assets or
liabilities under IFRS.

Financial reporting in the power and utilities industry 21

 Example – Cushion gas gas storage facility. It is therefore part of the storage
facility and should be capitalised as a component of
Entity A has purchased salt caverns to use as the storage facility PPE asset.
underground gas storage. The salt cavern storage
is reconditioned to prepare it for injection of gas. The cushion gas should be depreciated to its
The natural gas is injected and as the volume of gas residual value over the life of the storage facility in
injected increases, so does the pressure. The salt accordance with IAS 16.43. However, if the cushion
cavern therefore acts as a pressurised container. The gas is recoverable in full when the storage facility
pressure established within the salt cavern is used is decommissioned, then depreciation is recorded
to push out the gas when it needs to be extracted. against the cushion gas component only if the
When the pressure drops below a certain threshold estimated residual value of the gas decreases below
there is no pressure differential to push out the cost during the life of the facility.
remaining natural gas. This remaining gas within the
cavern is therefore physically unrecoverable until the When the storage facility is decommissioned and
storage facility is decommissioned. This remaining the cushion gas extracted and sold, the sale of
gas is known as “cushion gas”. the cushion gas is accounted for as the disposal
of an item of PPE in accordance with IAS 16.68.
Should Entity B’s management account for the Accordingly, the gain/loss on disposal is recognised
cushion gas as PPE or as inventory? in profit or loss. The natural gas in excess of the
cushion gas that is injected into the cavern should
Entity B’s management should classify and account be classified and accounted for as inventory in
for the cushion gas as PPE. The cushion gas is accordance with IAS 2.
necessary for the cavern to perform its function as a

1.3.5 Net realisable value of oil inventories own or enter into co-operations with network operating
companies or other municipalities. The arrangements
Oil purchased for use by a utility is valued at the lower may take various forms, such as:
of cost and net realisable value if it will be used as • Leasing the grid assets directly to network operating
a fuel. entities
• Establishing together with a network operator
Determining net realisable value requires consideration network holding companies, which lease the grid
of the estimated selling price in the ordinary course of assets out to the network operator
business less the estimated costs to complete processing • Joint arrangements with other municipalities
and to sell the inventories. An entity determines the or entities which can comprise numerous
estimated selling price of the oil product using the collaboration and service contracts
market price for oil at the balance sheet date.
Usually the arrangements are rather complex because
Movements in the oil price after the balance sheet date they comprise a multitude of contracts between the
typically reflect changes in the market conditions after parties, such as contracts regulating the rights and
that date and therefore should not be reflected in the obligations between the shareholders of the network
calculation of net realisable value. holding companies, lease contracts and service
contracts. All entities involved in these arrangements
1.3.6 Network operation arrangements have to analyse all facts and circumstances in order to
conclude the appropriate accounting treatment. The
Rights to use public ground for constructing and contracts could also give rise to a concession service
operating electricity grids are often limited in time. agreement, which is discussed in chapter 1.5.1.
Municipalities may decide to not prolong these rights
once they have expired, but operate the grids on their

22 Financial reporting in the power and utilities industry

1.4 Retail 1.5 Entity-wide issues
1.4.1 Customer acquisition costs 1.5.1 Service concession arrangements 1
Deregulation of markets and the introduction of Public/private partnerships are one method whereby
competition often provides customers with the ability governments attract private sector participation

Power & Utilities value chain and significant accounting issues

to switch from one supplier to another. Utility entities in the provision of infrastructure services. These
invest in winning and developing their relationships services might include, toll roads, prisons, hospitals,
with their customers. The costs of acquiring and public transportation facilities and water and power
developing these customer relationships are capitalised distribution. These types of arrangements are often
as separately acquired intangible assets if certain described as concessions and many fall within the
conditions are met. The costs directly attributable to scope of IFRIC 12, Service Concession Arrangements.
concluding a contractual agreement with a customer Arrangements within the scope of the standard are
are capitalised and amortised over the life of the those where a private sector entity may construct the
contract. These costs include commissions or bonuses infrastructure, maintain and provide the service to
paid to sign the utility customers where the utility the public. The provider may be paid for its services
entity has the systems to separately record and assess in different ways. Many concessions require that the
the customer contract for future economic benefits. related infrastructure assets are returned or transferred
to the government at the end of the concession.
However, expenditure relating to the general
development of the business, such as providing service IFRIC 12 applies to arrangements where the grantor
in a new location or an advertising campaign for new (the government or its agents) controls or regulates
customers, is not capitalised because it does not meet what services the operator provides with the
the asset recognition criteria. Such general expenditure infrastructure, to whom it must provide them and at
is not capitalised because the specific costs associated what price. The grantor also controls any significant
with individual customers cannot be separately residual interest in the infrastructure at the end of the
identified or because the entity has insufficient control term of the arrangement.
over the new relationship for it to meet the definition
of an asset. Water distribution facilities and energy supply
networks are examples of infrastructure that might be
However, customer relationships must be recognised the subject of service concession arrangements. For
when they are acquired through a business example, the government may have authorised the
combination. Customer-related intangibles such as building of a new town. It may grant a concession to a
customer lists, customer contracts and customer power distribution entity to construct the distribution
relationships are recognised by the acquirer at fair network, maintain it and operate it for a period of 25
value at the acquisition date. years. The distribution network is transferred to the
government at the end of the concession period, with
1.4.2 Customer discounts a specified level of functionality for no consideration.
The national regulator sets prices on a cost plus basis.
Utility entities may offer discounts and other incentives The concession arrangement has base-line service
to customers to encourage them to sign up to certain commitments that trigger substantial penalties if
tariffs or payment plans. The costs associated with service is interrupted. The government requires
these programmes need to be identified carefully to the power to entity provide universal access to the
ensure that they are appropriately separated from electricity network for all residents of the town.
the sales revenue. For example, when customers
receive a discount for paying monthly compared with This arrangement would fall within the scope of IFRIC
other customers who pay quarterly, the sales revenue 12, as it has many of the common features of a service
should be separated from the finance income that is concession arrangement, including:
embedded in the price charged to the customers who • The grantor of the service arrangement is a public
pay quarterly. sector entity or a private sector entity to which the
responsibility for the service is delegated (in the
case the government has authorised the new town
and granted the licence).

Financial reporting in the power and utilities industry 23

 • The operator is not an agent acting on behalf of the The changes introduced by IFRS 3R in accounting for
grantor, but is responsible for at least some of the business combinations include:
management of the infrastructure (the operator has • Recognition at fair value of all forms of consideration
an obligation to maintain the network). at the date of the business combination
• The arrangement is governed by a contract (or by the • Remeasurement to fair value of previously held
local law, as applicable) that sets out performance interests in the acquiree with resulting gains
standards, mechanisms for adjusting prices and through the income statement as part of the
arrangements for arbitrating disputes (there are accounting for the business combination
financial penalties for poor operating performance • Providing more guidance on separation of other
and cost plus tariff). transactions from the business combination,
• The operator is obliged to hand over the including share-based payments and settlement of
infrastructure to the grantor in a specified condition pre-existing relationships
at the end of the period of the arrangement • Expensing transaction costs
(transfer with no consideration from the • Two options for the measurement of any non-
government at the end of the concession period). controlling interest (previously minority interest)
on a combination by combination basis – fair value
The two accounting models under IFRIC 12 that an or proportion of net asset value
operator applies to recognise the rights received under
a service concession arrangement are: Issues commonly encountered in the utility industry
• Financial asset – An operator with a contractual include making the judgement about whether a
and unconditional right to receive specified or transaction is a business combination or an asset
determinable amounts of cash (or other financial acquisition. The distinction is likely to have a
assets) from the grantor recognises a financial asset. significant impact on the recognition and valuation
The financial asset is within the scope of IAS 32, of intangible assets, goodwill and deferred tax. IFRS
Financial Instruments: Presentation, IAS 39, and 3R has expanded the scope of what is considered
IFRS 7, Financial Instruments: Disclosures. to be a business and guidance continues to evolve.
• Intangible asset – An operator with a right to However, more transactions are business combinations
charge the users of the public service recognises under IFRS 3R than were considered such under the
an intangible asset. There is no contractual right previous standard.
to receive cash when payments are contingent on
usage. The licence is within the scope of IAS 38. IFRS 3R amended the definition of a business and
provided further implementation guidance. A business
Arrangements between governments and service is a group of assets that includes inputs, outputs and
providers are complex, and seldom are the conclusions processes that are capable of being managed together
as obvious as the example above. Detailed analysis of for providing a return to investors or other economic
the specific arrangement is necessary to determine benefits. Not all of the elements need to be present for
whether it is in the scope of IFRIC 12 and whether the group of assets to be considered a business.
the financial asset or intangible asset model should
be applied. Some complex arrangements may have Integrated utilities typically represent a business, as
elements of both models for the different phases. It may a number of assets and additional processes exist to
be appropriate to separately account for each element manage that portfolio.
of the consideration.
If the assets purchased do not constitute a business,
1.5.2 Business combinations the acquisition is accounted for as the purchase of
individual assets. The distinction is important because
Acquisitions of assets and businesses are common in an asset purchase:
in the utility industry. These may be business • No goodwill is recognised
combinations or acquisitions of groups of assets. • Deferred tax is generally not recognised for asset
IFRS 3R, Business Combinations, provides guidance purchases (because of the initial recognition
on both types of transactions, and the accounting can exemption in IAS 12, Income Taxes, which does not
differ significantly. These guidelines are mandatory for apply to business combinations)
all calendar year companies from 2010 onward. • Transaction costs are generally capitalised

24 Financial reporting in the power and utilities industry

• Asset purchases settled by the issue of shares are freely transferable). The licence and fixed assets are
within the scope of IFRS 2, Share-Based Payments usually valued on the basis of expected cash flows
and incorporate any existing rate agreements that
Acquisition of an integrated utility or a group of survive the business combination. 1
generators located in a country falls squarely into • A utility might have a right to develop and
the scope of IFRS 3R as a business combination. The construct a wind farm on a specified area of land

Power & Utilities value chain and significant accounting issues

classification of the acquisition of a single pipeline, or sea or to repower an existing wind farm. These
or a portion of a transmission network, may not be so rights might have value as intangible assets in a
clear cut. business combination.

IFRS 3R requires the acquisition method of accounting 1.5.3 Joint ventures

to be applied to all business combinations. The
acquisition method comprises the following steps: Joint ventures and other similar arrangements
• Identify the acquirer and determine the (joint arrangements) are sometimes used by utility
acquisition date entities as a way to share the higher risks and costs
• Recognise and measure the consideration associated with the industry. The legal basis for a joint
transferred for the acquiree arrangement may take various forms, for example:
• Recognise and measure the identifiable assets establishing a joint venture might be achieved through
acquired and liabilities assumed, including any non- a formal joint venture contract, or the governance
controlling interest arrangements set out in a company’s formation
• Recognise and measure goodwill or a gain from a documents might provide the framework for a joint
bargain purchase arrangement. The feature that distinguishes a joint
arrangement from other forms of cooperation between
These aspects of the business combination are not parties is the presence of joint control. An arrangement
unique to the utility industry. Please refer to PwC’s without joint control is not a joint arrangement.
publication “A Global Guide to Accounting for Business
Combinations and Noncontrolling Interests” for further The IASB published IFRS 11, Joint Arrangements,
guidance on these issues. in May 2011. The standard introduces a number
of significant changes in the accounting for joint
A number of common industry-specific issues do arise arrangements, including:
when recognising and measuring the identifiable assets • “Joint arrangement” replaces “joint venture” as the
and liabilities of an acquired utility. These include new umbrella term to describe all arrangements
for example: where two or more parties have joint control.
• A utility might have a brand name and a logo. The • The two types of joint arrangement are: “joint
fair value of the intangible assets may be significant operations” and “joint ventures”.
in a market with customer choice but less so in a • Contractual rights and obligations drive the
monopoly market. categorisation of a joint arrangement as a joint
• A transmission network might be a separate operation or a joint venture.
business that holds relationships with a number • The policy choice of proportionate consolidation for
of generators and distribution companies. These joint ventures is eliminated.
customer relationships may have value, but likely • An “investor in a joint venture” is defined as a party
less so in a monopoly market. who does not participate in joint control, with
• Existing contracts and arrangements might give rise guidance on the appropriate accounting.
to assets or liabilities for above or below market
pricing. This could include operating leases, fuel Unanimous consent must be present over the financial
purchase arrangements and contracts that qualify and operating decisions in order for joint control
for own use that might otherwise be derivatives to exist.
under IAS 39.
• The utility usually has a licence or a series of licences IFRS 11 becomes effective in 2013, although earlier
to operate. In practice, these licences are almost application is allowed. Most companies are expected to
always embedded into the value of the fixed assets, adopt the standard only when it becomes mandatory.
as the two can seldom be separated. For example, a The requirements of IFRS 11 are discussed in Chapter
licence to operate a nuclear power plant is specific 3 of this document, Future developments–Standards
to the location, assets and often the operator (not issued and not yet effective. This chapter is based on

Financial reporting in the power and utilities industry 25

 the requirements of IAS 31, although it uses the new circumstances. If joint control does not exist, the
umbrella term “joint arrangements”. arrangement would not be a joint venture.

Joint control A key test when identifying if joint control exists

is to identify how disputes between ventures are
Joint control is the contractually agreed sharing resolved. If joint control exists, resolution of disputes
of control over an economic activity. An identified usually requires eventual agreement between the
group of venturers must unanimously agree on all key venturers, independent arbitration or dissolution of the
financial and operating decisions. Each of the parties joint venture.
that share joint control has a veto right; they can block
key decisions if they do not agree. One of the venturers acting as operator of the joint
venture (for example a power plant) does not prevent
Not all parties to the joint venture need to share joint joint control. The operator’s powers are usually limited
control. Some participants may share joint control and to day-to-day operational decisions; key strategic
other investors participate in the activity but not in the financial and operating decisions remain with the joint
joint control. Those investors account for their interest venture partners collectively.
in its share of assets and liabilities, an investment in
an associate (if they have significant influence) or as Classification of joint arrangements
an available-for-sale financial asset in accordance with
IAS 39. Joint arrangements are analysed into three classes
under the current standard: jointly controlled
Similarly, joint control may not be present even if an operations, jointly controlled assets and jointly
arrangement is described as a joint venture. Decisions controlled entities.
over financial and operating decisions that are made
by simple majority rather than by unanimous consent Jointly controlled assets exist when the venturers
could mean that joint control is not present, even in jointly own and control the assets used in the joint
situations where there are only two shareholders but venture. Jointly controlled assets are likely to meet the
each has appointed a number of directors to the Board definition of joint operations when companies adopt
or relevant decision-making body. IFRS 11.

Joint control exists only if decisions require the Jointly controlled operations are arrangements
unanimous consent of the parties sharing control. If where each venture uses its own property, plant and
decisions are made by simple majority, the following equipment; raises its own financing; and incurs its own
factors may indicate that joint control does not exist: expenses and liabilities.
• The directors are not agents or employees of the
shareholders Jointly controlled entities exist when the venturers
• The shareholders have not retained veto rights jointly control an entity which in turn owns the assets
• There are no side agreements requiring that and liabilities of the joint venture. A jointly controlled
directors vote together entity is usually, but not necessarily, a legal entity. The
• A quorum of Board members can be achieved key to identifying an entity is to determine whether
without all members being in attendance the joint venture can perform the functions associated
with an entity, such as entering into contracts in its
If it is possible that a number of combinations of the own name, incurring and settling its own liabilities and
directors would be able to reach a decision, it may holding a bank account in its own right.
be that joint control does not exist. This is a complex
area which requires careful analysis of the facts and

26 Financial reporting in the power and utilities industry

Accounting for joint arrangements Contributions to jointly controlled entities

A venturer in a jointly controlled asset arrangement It is common for venturers to contribute assets, such
recognises: as cash, non-monetary assets or a business, to a joint 1
• Its share of the jointly controlled asset, classified venture on formation. Contributions of assets are a
according to the nature of the asset partial disposal by the contributing party. The venturer

Power & Utilities value chain and significant accounting issues

• Any liabilities the venturer has incurred in return receives a share of the assets contributed
• Its proportionate share of any liabilities that arise by the other venturers. Accordingly, the contributor
from the jointly controlled assets should recognise a gain or loss on the partial disposal.
• Its share of expenses from the operation of the assets The gain is measured as the proportionate share
• Its share of any income arising from the operation of of the fair value of the assets contributed by the
the assets (for example, ancillary fees from use by other venturers less the portion of the book value of
third parties) contributor’s disposed asset now attributed to the
Jointly controlled assets tend to reflect the sharing of other venturers.
costs and risk rather than the sharing of profits. An
example is an undivided interest in a wind farm where The venturer recognises its share of an asset
each venturer receives its share of the power produced, contributed by other venturers at its share of the fair
is jointly liable for costs and is part of the joint control value of the asset contributed. This is classified in the
decision making. balance sheet according to the nature of the asset in the
case of jointly controlled assets or when proportionate
The parties to the joint operation share the revenue consolidation is applied. The equivalent measurement
and expenses of the jointly produced end product. Each basis is achieved when equity accounting is applied;
retains title and control of its own assets. The venturer however, the interest in the asset forms part of the
should recognise 100% of the assets it controls and the equity accounted investment balance.
liabilities it incurs as well as its own expenses, its share
of income from the sale of goods or services of the joint The same principles apply when one of the other
operation and its share of expenses jointly incurred. venturers contributes a business to a joint venture;
however, one of the assets recognised is normally
Jointly controlled entities can be accounted for goodwill, which is calculated in the same way as in a
either by proportionate consolidation or using equity business combination.
accounting using the policy choice available under IAS
31. The policy must be applied consistently to all jointly
controlled entities. Proportionate consolidation will be
eliminated as a policy choice when IFRS 11 is adopted.

The key principles of the equity method of

accounting are:
• Investment in the jointly controlled entity is initially
recognised at cost.
• Changes in the carrying amount of the investment
are recognised based on the venturer’s share of the
profit or loss of the jointly controlled entity after the
date of acquisition.
• The venturer reflects only its share of the profit or
loss of the jointly controlled entity.
• Distributions received from a jointly controlled entity
reduce the carrying amount of the investment.

Financial reporting in the power and utilities industry 27

 Entities A and B have brought together their power Can Entity A’s management do this?
plants in a market in order to strengthen their
market position and reduce costs. They established Yes, there is a policy choice available to Entity A
a new entity, J, and contributed the plants to Entity in certain circumstances because of the conflict in
J. Entity A receives 60% of the shares in Entity J, and the accounting standards described below. Entity
Entity B receives 40%. A can choose partial recognition of the gain or loss
being the difference between 40% of the fair value
Entity J has recognised the contribution of the of its plants contributed and 40% of their carrying
plants from Entities A and B at fair value. Entity J is amount plus its 60% share of the fair value of the
compelled to do this by local company law, as shares plants contributed by Entity B. This is the approach
issued must be backed by the fair value of assets set out in SIC 13. Entity A may also recognise 100%
recognised. Effectively, Entity J follows the “fresh of the gain arising on its disposal of its power plants
start” method of accounting for its formation. business following IAS 27 – see narrative below.

Entity A accounts for jointly controlled entities Entity A must therefore eliminate its share (retained)
using the equity method. Entity A’s management of the fair value of the power plants it previously
wants to include its share of Entity J’s net assets and held and that are accounted for at fair value at the
profits and losses on the same basis on which they level of Entity J when applying the equity method
are accounted for in Entity J, without adjustment. of accounting.
They point out that Entity J has used an acceptable
method under IFRS of accounting for its formation.

The example above is based on guidance provided

within SIC-13, Jointly Controlled Entities – Non-
Monetary Contributions by Venturers. An inconsistency
exists between SIC-13 and IAS 27, Consolidated and
Separate Financial Statement, when the contribution to
the jointly controlled entity is considered to represent
a business.

IAS 27 has different guidance on the loss of control of

a business. Any investment a parent has in the former
subsidiary after control is lost is measured at fair value
at the date that control is lost, and any resulting gain or
loss is recognised in profit or loss in full.

The IASB have not dealt with this conflict in IFRS

11, but will do so as part of a wider project on equity
accounting. While this conflict remains, entities can
make a policy choice in these types of transactions.

28 Financial reporting in the power and utilities industry

 2

Financial instruments
2 Financial instruments

Financial reporting in the power and utilities industry 29

 2 Financial instruments

2.1 Overview The “net settlement” notion in IAS 39 is quite broad. A

contract to buy or sell a non-financial item can be net
The accounting for financial instruments can have a settled in any of the following ways:
major impact on a power and utility entity’s financial (a) The terms of the contract permit either party to
statements. Many utilities use a range of derivatives to settle it net in cash or another financial instrument.
manage the commodity, currency and interest rate risks (b) The entity has a practice of settling similar contracts
to which they are operationally exposed. Other, less net, whether:
obvious, sources of financial instruments issues arise • With the counterparty
through both the scope of IAS 39 and the rules around • By entering into offsetting contracts
accounting for embedded derivatives. Many entities • By selling the contract before its exercise or lapse
that are engaged in generation, transmission and (c) The entity has a practice, for similar items, of taking
distribution of electricity may be party to commercial delivery of the underlying and selling it within
contracts that are within the scope of IAS 39. Other a short period after delivery for the purpose of
entities may have active energy trading programmes generating a profit from short-term fluctuations in
that go far beyond mitigation of risk. This section looks price or a dealer’s margin.
at the accounting issues associated with two broad (d) The commodity that is the subject of the contract is
categories of financial instruments: those that may readily convertible to cash.
arise from the scope of IAS 39 and those that arise from
active trading and treasury management activity. It also The process for determining the accounting for a
addresses accounting for weather derivatives. commodity contract can be summarised through the
following decision tree:
2.2 Scope of IAS 39
Contracts to buy or sell a non-financial item, such as a
commodity, that can be settled net in cash or another
financial instrument, or by exchanging financial
instruments, are within the scope of IAS 39 and are
subject to fair value accounting unless the own use
exemption applies. Contracts within the scope of IAS
39 are treated as derivatives and are marked to market
through the income statement unless management can
and does elect cash flow hedge accounting.

30 Financial reporting in the power and utilities industry

Commodity contracts decision tree (IAS 39)

Financial Item Non-financial Item 2

Financial instruments
IAS 39.5 & 6 (a-d)
Can the contract be settled net in cash or another
financial instrument or by exchanging financial
instruments?

YES NO

IAS 39.9
Is the contract a derivative?
a) Does it have an underlying
b) Does it require little or no initial net investment?
c) Does it settle at a future date?

Host contract
YES NO
out of scope

IAS 39.7
Is the contract a
written option? NO YES
Does it contain
a premium? IAS 39.5 & 6 (a-d)
Is the contract held for
receipt/delivery for own
purchase/sale or usage
YES requirements?

Cannot qualify for NO

Are there
the own use
embedded
exemption
Consider hedge derivatives?
accounting

NO YES NO YES

Fair value through Cash flow Fair value embedded

the P&L (held hedge accounting Accrual
accounting through the P&L and
for trading) through equity accruals account for
host OR
Designate the whole
contract at fair value
through the P&L

Financial reporting in the power and utilities industry 31

 2.3 Application of “own use” period after delivery for the purpose of generating a
profit from short-term fluctuations in price or a dealer’s
Own use applies to those contracts that were entered margin (c) the contract cannot qualify for own use
into and continue to be held for the purpose of the treatment. These contracts must be accounted for as
receipt or delivery of a non-financial item in accordance derivatives at fair value.
with the entity’s expected purchase, sale or usage
requirements. In other words, the contract results in If the terms of the contracts permit either party to settle
physical delivery of the commodity. Own use is not an it net in cash or another financial instrument (a) or the
election. A contract that meets the own use criteria commodity that is the subject of the contracts is readily
cannot be selectively measured at fair value unless it convertible to cash (d) the contracts are evaluated to
otherwise falls into the scope of IAS 39 (for example, by see if they qualify for own use treatment. There are
applying the fair value option election to a contract if it active markets for many commodities, such as oil, gas
contains an embedded derivative). Own use contracts and electricity, and such contracts would meet the
cannot be designated as a financial asset or financial readily convertible to cash criterion. An active market
liability at fair value through profit or loss because they exists when prices are publicly available on a regular
are not financial instruments in the scope of IAS 39. basis with sufficient liquidity and those prices represent
regularly occurring arm’s length transactions between
The practice of settling similar contracts net prevents willing buyers and willing sellers. Consequently, sale
an entire category of contracts from qualifying for the and purchase contracts for commodities in locations
own use treatment (i.e., all similar contracts must then where an active market exists must be accounted for
be recognised as derivatives at fair value). If the entity at fair value unless own use treatment is applicable.
has a practice of settling similar contracts net (b) or An entity’s policies, procedures and internal controls
the entity has a practice, for similar items, of taking are therefore critical in determining the appropriate
delivery of the underlying and selling it within a short treatment of its commodity contracts.

Own use – Example 1

Based on the expected change in consumption, the
A utility enters into a sales contract with an customer takes an option under the contract to take
industrial customer for delivery of 500 MWh of a volume of only 300 MWh and as compensation the
electricity for a fixed price in 2012. Management utility is paid the difference between the contract
concludes all criteria for own use are met and price and the actual forward price for 200 MWh. The
therefore the utility accounts for the contracts as 300 MWh are still expected to be delivered to the
an own use executory contract. After signing the customer. The contract fails to meet own use at the
contract, but before delivery, the industrial customer time of exercising the option and has to be accounted
decides to restructure its business and its expected for as a derivative in accordance with IAS 39 because
consumption declines to only 300 MWh in 2012. the contract was settled net.

32 Financial reporting in the power and utilities industry

Own use – Example 2
The contract seems to be net settled because the
Entity A, the buyer, is engaged in power generation penalty mechanism requires Entity B to compensate 2
and Entity B, the seller, produces natural gas. Entity Entity A at the current prevailing market price. This
A has entered into a 10-year contract with Entity B meets the condition in IAS 39.6(a). The expected

Financial instruments
for purchase of natural gas. frequency/intention to pay a penalty rather than
deliver does not matter as the conclusion is driven by
Entity A extends an advance of C1 billion to Entity the presence of the contractual provision. Further,
B, which is the equivalent of the total quantity if natural gas is readily convertible into cash in the
contracted for 10 years at the rate of C4.5 per location where the delivery takes place, the contract
MMBtu (forecasted price of natural gas). This is considered net settled.
advance carries interest of 10% per annum which is
settled by way of supply of gas. However, the contract still qualifies as own use as
long as it has been entered into and continues to be
As per the agreement, predetermined/fixed held for the expected counterparties’ sales/usage
quantities of natural gas have to be supplied each requirements. However, if there is volume flexibility
month. There is a price adjustment mechanism then the contract is to be regarded as a written
in the contract such that upon each delivery the option. A written option is not entered into for
difference between the forecasted price of gas and own use.
the prevailing market price is settled in cash.
Therefore, although the contract may be considered
If Entity B falls short of production and does not net settled (depending on how the penalty
deliver gas as agreed, Entity A has the right to claim mechanism works and whether natural gas is readily
penalty by which Entity B compensates Entity A at convertible into cash in the respective location), the
the current market price of gas. own use exemption does still apply provided the
contract is entered into and is continued to be held
Is this contract an own use contract? for the parties’ own usage requirements.

The own use criteria are met. There is an embedded

derivative (being the price adjustment mechanism)
but it does not require separation.

Financial reporting in the power and utilities industry 33

 2.4 Measurement of long-term are crucial to ensure users understand the entity’s
financial statements. Under IFRS 7, the valuations
contracts that do not qualify of such long-term contracts generally fall in level 3
for “own use” of the fair value hierarchy. The disclosures for level
3 are extensive and include reconciliations from the
Long-term commodity contracts are not uncommon, beginning and ending balances that include recognised
particularly for purchase of fuel and sale of power and gains and losses in profit and loss, total gains and losses
gas. Some of these contracts may be within the scope in comprehensive income as well as purchases, sales,
of IAS 39 if they contain net settlement provisions and/ issues and settlements (IFRS 7.27B). Also, if changes
or do not qualify for own use treatment. Due to the of valuation inputs to other possible alternative
long duration of such contracts, it may be more difficult assumptions would change the fair value of the
to prove the intention to hold such contracts for an contract, the effects need to be disclosed.
entity’s purchase, sale or usage requirements over
the full lifetime of the contract. In such cases, these Day One profits or losses
contracts are measured at fair value using the guidance
in IAS 39, with changes recorded in the income Commodity contracts that fall within the scope of IAS
statement. Market prices may not be available for the 39 and fail to qualify for own use treatment have the
entire period of the contract. For example, prices may potential to create Day One profits or losses.
be available for the next three years and then some
prices for specific dates further out. This is described as The contracts are initially recognised under IAS 39
having illiquid periods in the contract. These contracts at fair value. Any such Day One profit gains or losses
are valued using valuation techniques. can be recognised only if the fair value of the contract
is either:
Contracts for commodities that are not readily (1) Evidenced by other observable market transactions
convertible to cash (i.e., for which no active market in the same instrument
exists, such as gas in certain markets or gas capacity) (2) Based on valuation techniques whose variables
do not meet the definition of a derivative and therefore include only data from observable markets
are accounted for as executory contracts.
Thus, the profit or loss must be supported by
Valuation can be complex and valuation techniques are objective market-based evidence. Observable market
intended to establish what the transaction price would transactions must be for the same instrument (i.e.,
have been on the measurement date in an arm’s length without modification or repackaging) and in the same
exchange motivated by normal business considerations. market where the contract was originated. Prices
Therefore, valuation techniques should: must be established for transactions with different
(a) Incorporate all factors that market participants counterparties for the same commodity and for the
would consider in setting a price, making maximum same duration at the same delivery point.
use of market inputs and relying as little as possible
on entity-specific inputs Any Day One profit or loss that is not recognised
(b) Be consistent with accepted economic initially is recognised subsequently only to the extent
methodologies for pricing financial instruments that it arises from a change in a factor (including time)
(c) Be tested for validity using prices from any that market participants would consider in setting
observable current market transactions in the same a price. Generally, utilities recognise the deferred
instrument or based on any available observable profit/loss in the income statement on a systematic
market data basis as the volumes are delivered or as observable
market prices become available for the remaining
This is an area where transparent disclosure of the delivery period.
policy and approach, including significant assumptions,

34 Financial reporting in the power and utilities industry

2.5 Take-or-pay contracts and required to pay the supplier the equivalent monetary
value of the shortfall, or the shortfall amount may also
volume flexibility (optionality) be carried forward and used in satisfaction of supply in
subsequent periods. 2
Take-or-pay contracts
A long-term take-or-pay contract may not fall within
Generators may enter into long-term take-or-pay

Financial instruments
the scope of IAS 39 because of inherent variability in
contracts with fuel suppliers. These arrangements give
amount and/or the ability to “net settle” may preclude
rise to an obligation for the generator to purchase a
“own use”. In most cases, however, a payment of the
minimum quantity or value of the relevant fuel. The
contractual amount for the volume that was not taken
actual quantity or value of fuel the generator requires
is not considered a net settlement because there is no
may be less than the minimum agreed amount in
payment based on the difference between contract
any one measurement period. The generator may be
price and market price.

Example IAS 39 (no net settlement). In 2011 the customer

consumes only 80% of the determined quantity. The
A utility enters into a fixed price gas sales contract utility charges the customer the fixed price for 95%
with an industrial customer for the years 2011 of the determined quantity, which results in cash
through 2013. The expected gas quantity to be settlement for the quantity of 15% not delivered.
delivered is determined, but the customer has The payment of the total amount (fixed price) for
the right to take between 95% and 105% of the the non-delivered quantity does not constitute a net
determined quantity at the same fixed price. If the settlement because there is no payment between
customer consumes less than 95% it has to pay the the parties for the net amount calculated as the
price for 95% (take-or-pay volume). The utility difference between contract price and the market
operates in a local gas market which is not liquid price. As such, a contract with these terms would not
and therefore does not record a derivative under be accounted for as a derivative.

Volume flexibility (optionality)

The contracts will fail the own use exemption if the
Contracts for the supply of commodities may give the quantity specified in the contract is more than the
buyer the right to take either a minimum quantity entity’s normal usage requirement and the entity
or any amount based on the buyer’s requirements. intends to net settle part of the contract that it does not
A minimum annual commitment does not create need in the normal course of business. The entity could
a derivative for the purchaser as long as the entity take all the quantities specified in the contract and sell
expects to purchase all the guaranteed volume for its the excess or enter into an offsetting contract for the
own use. excess quantity. The entire contract in these situations
falls within IAS 39’s scope and should be marked to
A derivative or an embedded derivative may arise market.
if it becomes likely that the entity will not take the
commodity, and instead pay a penalty under the The supplier of the commodity may look at the volume
contract based on the market value of the commodity flexibility feature in the contract in two ways. The first
or some other variable. Since physical delivery is no is to view the contract as a whole. The contract includes
longer probable, the derivative would be recorded at a written option for the element of volume flexibility.
the amount of the penalty payable. Changes in market The whole contract should be viewed as one instrument
price will affect the penalty’s carrying value until the and, if the item being supplied (electricity) is readily
penalty is paid. convertible to cash, the supplier would be prevented
from classifying the contract as own use by paragraph
A penalty payable that is fixed or predetermined does 7 of IAS 39. This states that a written option on a
not give rise to a derivative because the penalty’s value non-financial item that is readily convertible to cash
remains fixed irrespective of changes in the product’s cannot be entered into for the purpose of the receipt or
market value. The entity will need to provide for the delivery of a non-financial item in accordance with the
penalty payable, however, once it becomes clear that entity’s expected purchase, sale or usage requirements.
non-performance is likely.

Financial reporting in the power and utilities industry 35

 A second view is that the contract has two components, net cash settlement as laid out in paragraphs 5 and 6 of
an own use fixed volume host contract outside of IAS IAS 39. Such contracts would not be considered to be
39’s scope for any contractually fixed volume element within the scope of IAS 39.
and an embedded written option within IAS 39’s scope
for the volume flexibility element. The latter would be Both qualitative and quantitative tests should be used
in IAS 39’s scope if the item being supplied (electricity) to determine whether a contract with volume flexibility
is readily convertible to cash for the same reason as contains a written option that can be settled net in cash
under the first view. or another financial instrument.

The IFRIC discussed the issue of volume flexibility in Qualitative tests:

March 2010 and recognised that significant diversity • Does the purchaser have the ability to monetise
exists in practice with respect to volumetric optionality. the option?
However, IFRIC decided not to add the issue to its • Does the purchaser have a choice in deciding
agenda because of the Board’s project to develop a whether to exercise the option?
replacement for IAS 39. If both answers are positive, the contract contains a
written option.
Volume flexibility exists within a contract when the
buyer contractually has the right but not the obligation Quantitative test:
to take volumes of the commodity within a volume The quantitative test may take the form of comparing
range at a specified (often fixed) price. Within that the price charged in the contract with the flexibility
range, the actual volume to be supplied is not fixed to the price charged in otherwise similar contracts
at the inception of the contract, but is notified by with no flexibility. The entity may need a sophisticated
the buyer during the course of the contract, thereby valuation system and relatively large number of data
resulting in unpredictability in actual volumes for inputs (which may require access to historical data)
the supplier. In most cases, a higher price is charged that can value options over commodities to carry
for the commodity for entering into these contracts out the test if there are no similar contracts without
to compensate the supplier for the capacity, storage volume flexibility.
and other costs arising due to the additional volume
flexibility offered to the purchaser. The existence of a premium, paid at inception or
over the life of the contract, is a good quantitative
In accounting for such contracts, the reporting entity indicator for the existence of a written option [IAS
should first analyse whether it has a written option 39 IG para F.1.3]. Conversely, if the writer of the
or a purchased option. In cases where the buyer has option can demonstrate it received no premium, this
the right to choose the volume of the commodity would indicate that the contract does not contain a
purchased, the buyer has a purchased option and the written option.
supplier a written option.
Two approaches are available if management
Next it is necessary to determine whether the option determines that a commodity supply/sale contract
can be settled net in cash or another financial asset. contains a written option component:
A written option to buy or sell a non-financial item (i) The contract is deemed to consist of a fixed price/
that can be settled net in cash or another financial fixed volume part and a fixed price/written option
instrument, or by exchanging financial instruments, is volume part. The fixed price contract is out of scope
within the scope of IAS 39. Such a contract cannot be of IAS 39 if it fulfils the own use requirements
entered into for the purpose of the receipt or delivery of in paragraph 5 of IAS 39. However, the written
the non-financial item in accordance with the entity’s option volume part would be treated as a derivative
expected purchase, sale or usage requirements [IAS 39 and would be fair valued through profit or loss in
paragraph 7]. accordance with paragraph 7 of IAS 39.
(ii) The contract is evaluated as a single contract. The
In March 2007, the International Financial Reporting contract is considered as a whole to be a written
Interpretations Committee (IFRIC) received a request option. Accordingly, IAS 39.7 would be applicable
(that was primarily concerned with the accounting for to the contract in its entirety, because the entity
energy supply contracts to retail customers) to interpret cannot consider the contract as held for own use
what is meant by “written option” within the context of by the counterparty. Hence, the entire contract
paragraph 7 of IAS 39. The IFRIC rejected the request, is treated as a derivative and fair valued through
explaining that analysis of such contracts suggests that profit or loss.
in many situations these contracts are not capable of

36 Financial reporting in the power and utilities industry

Both approaches are seen in practice. It is an An embedded derivative that is required to be
accounting policy choice which should be applied separated may be designated as a hedging instrument,
consistently to similar transactions as per IAS 8 in which case the hedge accounting rules are applied.
paragraph 13. A contract that contains one or more embedded 2
derivatives can be designated as a contract at fair value
2.6 Embedded derivatives through profit or loss at inception, unless:

Financial instruments
(a) The embedded derivative(s) does not significantly
Long-term commodity purchase and sale contracts modify the cash flows of the contract
frequently contain a pricing clause (i.e., indexation) (b) It is clear with little or no analysis that separation of
based on a commodity or index other than the the embedded derivative(s) is prohibited
commodity deliverable under the contract. Such
contracts contain embedded derivatives that may have Assessing whether embedded derivatives
to be separated and accounted for under IAS 39 as a are closely related
derivative. Examples are fuel prices that are linked to
the electricity price or pricing formulas that include an Embedded derivatives must be assessed to determine
inflation component. if they are closely related to the host contract at the
inception of the contract. A pricing formula that is
An embedded derivative is a derivative instrument that indexed to something other than the commodity
is combined with a non-derivative host contract (the delivered under the contract could introduce a new risk
host contract) to form a single hybrid instrument. An to the contract. Some common embedded derivatives
embedded derivative can change some or all of the cash that routinely fail the closely related test are indexation
flows of the host contract. An embedded derivative of a published market price and denomination in a
can arise through market practices or common foreign currency that is not the functional currency of
contracting arrangements. An embedded derivative is either party and not a currency in which such contracts
separated from the host contract and accounted for as are routinely denominated in transactions around
a derivative if: the world.
(a) The economic characteristics and risks of the
embedded derivative are not closely related to The assessment of whether an embedded derivative
the economic characteristics and risks of the is closely related is both qualitative and quantitative,
host contract and requires an understanding of the economic
(b) A separate instrument with the same terms as the characteristics and risks of both instruments.
embedded derivative would meet the definition of
a derivative In the absence of an active market price for a particular
(c) The hybrid (combined) instrument is not measured commodity, management should consider how other
at fair value with changes in fair value recognised in contracts for that particular commodity are normally
the profit or loss (i.e., a derivative that is embedded priced. It is common for a pricing formula to be
in a financial asset or financial liability at fair value developed as a proxy for market prices. When it can
through profit or loss is not separated) be demonstrated that a commodity contract is priced
by reference to an identifiable industry norm and
Embedded derivatives that are not closely related must contracts are regularly priced in that market according
be separated from the host contract and accounted to that norm, the pricing mechanism does not modify
for at fair value, with changes in fair value recognised the cash flows under the contract and is not considered
in the income statement. In rare cases, it may not be an embedded derivative.
possible to measure the embedded derivative. In those
cases, the entire combined contract must be measured
at fair value, with changes in fair value recognised in
the income statement.

Financial reporting in the power and utilities industry 37

 Example – Embedded derivatives Does this pricing mechanism represent an
embedded derivative?
Entity A enters into a gas delivery contract with
Entity B, which is based in a different country. Management has a contract to purchase gas. There
There is no active market for gas in either country. is no market price. The contract price for gas is
The price specified in the contract is based on Tapis therefore linked to the price of oil, for which an
crude, which is the Malaysian crude price used as a active market price is available. Oil is used as a proxy
benchmark for Asia and Australia. market price for gas.

The indexation to oil does not constitute an

embedded derivative. The cash flows under the
contract are not modified. Management can only
determine the cash flows under the contract by
reference to the price of oil.

Timing of assessment of embedded

derivatives

All contracts need to be assessed for embedded A first-time adopter of IFRS assesses whether an
derivatives at the date the entity first becomes a party embedded derivative is required to be separated from
to the contract. Subsequent reassessment of potential the host contract and accounted for as a derivative on
embedded derivatives is prohibited unless there is the basis of the conditions that existed at the later of
a significant change in the terms of the contract, in the date it first became a party to the contract and the
which case reassessment is required. A significant date a reassessment is required.
change in the terms of the contract has occurred when
the expected future cash flows associated with the The same principles apply to an entity that purchases a
embedded derivative, host contract, or hybrid contract contract containing an embedded derivative. The date
have significantly changed relative to the previously of purchase is treated as the date when the entity first
expected cash flows under the contract. becomes a party to the contract.

Example – Embedded derivatives

Under the assumption that the contract still meets
Utility A acquires Entity B in a business combination own use, the gas and fuel oil price indices need
under IFRS. In 2000, Entity B entered into a long- to be bifurcated and accounted for as derivatives
term gas purchase contract with prices indexed to separately because they are not closely related to
gas and fuel oil that it determined met the own use the gas price (a quantitative analysis failed). The
exemption. In 2000 the gas market was not active. At contract is recorded at its fair value at acquisition
the date of acquisition this gas market is active and date but is not accounted for as a derivative in the
therefore gas meets the net settlement criteria under post-acquisition period. Both price indices have to
IAS 39.6(d). The utility must assess the contract be recorded with a fair value of nil at acquisition
as if it entered into it at the date of the business date and accounted for as derivatives in the post-
combination. Therefore, embedded derivatives need acquisition period.
to be evaluated.

38 Financial reporting in the power and utilities industry

 LNG contracts of net settlement. The principles of paragraphs 5–7
of IAS 39 should still be applied; however, there may
The LNG market has been developing and becoming be some practical challenges to this. The explanation 2
more active over recent years. This development in section 2.8 of how energy trading units operate
has been mostly emphasised by the fact that more provides some of the practical considerations.

Financial instruments
LNG contracts are currently managed with a dual In the absence of a global LNG reference price, most
objective: contracts are currently priced based on other energy
a) To provide a security of supply via long-term indices (e.g., Henry Hub Natural gas index, Brent Oil
bilateral contracts index). An assessment of the existence of embedded
b) To benefit from the potential arbitrage between derivatives is required in order to determine whether
various gas networks across the world which are they are closely related to the host contract at
not connected otherwise the inception of the contract. In practice it is not
uncommon that the pricing within LNG contracts is
The application of the own use exemption could considered to be closely related if it is based on proxy
become quite complex, particularly for the definition pricing typical to the industry.

2.7 Hedge accounting There is no prescribed single method for assessing

hedge effectiveness. Instead, an entity must identify
Principles and types of hedging a method that is appropriate to the nature of the risk
being hedged and the type of hedging instrument
Hedge accounting can mitigate the volatility of trading used. The method an entity adopts for assessing hedge
transactions. From a practical perspective, complying effectiveness depends on its risk management strategy.
with the requirements of hedge accounting can be An entity must document at the inception of the hedge
onerous. Entities able to qualify for the own use how effectiveness will be assessed and then apply that
exemption may find it operationally easier to use than effectiveness test on a consistent basis for the duration
hedge accounting. An entity that chooses to apply of the hedge.
hedge accounting must comply with the detailed
requirements. All derivatives are accounted for at fair The hedge must be expected to be highly effective at
value, but changes in fair value are either deferred the inception of the hedge and in subsequent periods;
through reserves in other comprehensive income (cash the actual results of the hedge should be within a range
flow hedge) or matched, to a significant extent, in the of 80%–125% effective (i.e., changes in the fair value
income statement by an adjustment to the value of the or cash flows of the hedged item should be between
hedged item (fair value hedge). 80% and 125% of the changes in fair value or cash
flows of the hedging instrument).
Two hurdles to implementing hedge accounting
are the need for documentation and the testing of Testing for hedge effectiveness can be quite onerous.
effectiveness. IAS 39 requires that at inception of Effectiveness tests need to be performed for each
the hedge, individual hedging relationships are hedging relationship at least as frequently as financial
formally documented, including linkage of the hedge information is prepared, which for listed companies
to the entity’s risk-management strategy, explicit could be up to four times a year. An entity interested
identification of the hedged items and the specific risks in applying hedge accounting to its commodity hedges
being hedged. Failure to establish this documentation needs to invest time in ensuring that appropriate
at inception precludes hedge accounting, regardless of effectiveness tests are developed.
how effective the hedge actually is in offsetting risk.
The IASB has an ongoing project on hedge accounting.
Hedges must be expected to be highly effective Two significant expected developments for energy
and must prove to be highly effective in mitigating companies are a proposed relaxation in the
the hedged risk or variability in cash flows in the requirements for hedge effectiveness and the ability to
underlying instrument. hedge non-financial portions in some circumstances.
These may make hedge accounting much more
attractive. Entities should monitor the progress on this
and assess what the impact on their current accounting
will be.

Financial reporting in the power and utilities industry 39

 Cash flow hedges and “highly probable” Weather derivatives

Hedging of commodity-price risk or its foreign Gas and electricity consumption is heavily influenced
exchange component is often based on expected cash by weather. More energy is consumed in cold winters
inflows or outflows related to forecasted transactions, and hot summers than in mild winters and cool
and therefore are cash flow hedges. Under IFRS, only a summers. Weather derivatives make it possible to
highly probable forecast transaction can be designated manage the concerns related to extreme climate
as a hedged item in a cash flow hedge relationship. conditions by paying the generator when the weather
The hedged item must be assessed regularly until the adversely affects revenue.
transaction occurs. If the forecasts change and the
forecasted transaction is no longer expected to occur, Weather derivatives are contracts that require a
the hedge relationship must be ended immediately and payment based on climatic, geological or other physical
all retained hedging results in the hedging reserve must variables. For such contracts, payments may or may not
be recycled to the income statement. Cash flow hedging be based on the amount of loss suffered by the entity.
is not available if an entity is not able to forecast the Weather derivatives are either insurance contracts and
hedged transactions reliably. fall into IFRS 4 or financial instruments and within
the scope of IAS 39. Contracts that require a payment
Entities that buy or sell commodities (e.g., utilities) only if a particular level of the underlying climatic,
may designate hedge relationships between hedging geological or other physical variables adversely affects
instruments, including commodity contracts that are the contract holder are insurance contracts. Payment
not treated as own use contracts, and hedged items. In is contingent on changes in a physical variable that is
addition to hedges of foreign currency and interest rate specific to a party to the contract.
risk, energy companies primarily hedge the exposure to
variability in cash flows arising from commodity price Contracts that require a payment based on a specified
risk in forecast purchases and sales. level of the underlying variable regardless of whether
there is an adverse effect on the contract holder are
derivatives and are within IAS 39’s scope.
Hedging of non-financial items
Reassessment of hedge relationships in
It is difficult to isolate and measure the appropriate business combinations
portion of the cash flows or fair value changes
attributable to specific risks other than foreign currency An acquirer re-designates all hedge relationships of the
risks. Therefore, a hedged item which is a non-financial acquired entity on the basis of the pertinent conditions
asset or non-financial liability may be designated as a as they exist at the acquisition date (i.e., as if the
hedged item only for: hedge relationship started at the acquisition date).
a. Foreign currency risks Since derivatives previously designated as hedging
b. In its entirety for all risks derivatives were entered into by the acquired entity
c. All risks apart from foreign currency risks before the acquisition, these contracts are unlikely to
have a fair value of nil at the time of the acquisition. For
In practice, the main sources of ineffectiveness cash flow hedges in particular, this is likely to lead to
in hedging non-financial items arise from more hedge ineffectiveness in the financial statements
differences in location and differences in grade or of the post-acquisition group and also to more hedge
quality of commodities delivered in the hedged relationships failing to qualify for hedge accounting as
contract compared to the one referenced in the a result of failing the hedge effectiveness test.
hedging instrument.

40 Financial reporting in the power and utilities industry

Some of the option-based derivatives that the acquired for hedging those risks in the external markets.
entity had designated as hedging instruments may Some centralised trading departments are also given
meet the definition of a written option when the authority to enhance the returns obtained from the
acquiring entity reassesses them at the acquisition date. integrated business by undertaking optimisation 2
Consequently, the acquiring entity won’t be able to activities which include asset-based trading and
designate such derivatives as hedging instruments. speculative trading. A centralised trading unit therefore

Financial instruments
undertakes transactions for two purposes:
2.8 Trading and risk management
(a) Transactions that are non-speculative in nature
Energy trading is the buying and selling of energy- The purchase of fuel to meet the physical
related products, both fuel and power. This practice requirements of the generation stations and the
has many similarities to the trading activities of other sale of any excess power generated compared to
commodities, such as gold, sugar or wheat. The retail demand, or the purchase of power to meet a
introduction of competition in the utilities area was the shortfall between that generated and that required
catalyst for energy trading to start in earnest. Energy by retail. This is often characterised by management
trading is an important but potentially risky part of a as price-risk management, with volume risks
utility’s business. However, effective trading can also relating to operational assets and customer demand
limit volatility and protect profit margins. remaining within the operational divisions (i.e., no
re-optimisation to take advantage of market price
Centralised trading unit movements). Such activity is sometimes held in a
“physical book”.
Many integrated utility companies have established
a centralised trading or risk management unit over (b) Transactions that are speculative in nature
the last decade in response to the restructuring of the To achieve risk management returns from wholesale
industry. The operation of the central trading unit is trading activities. Such activity is sometimes held
similar to the operation of the bank’s trading unit. in a “trading book”. The result of carrying out the
transactions in (a) in an optimal manner without re-
The scale and scope of the unit’s activities vary from optimisation would be the elimination of price risk
market risk management through to dynamic profit and the management of revenues and costs in future
optimisation. An integrated utility entity is particularly periods. If an entity maintains separate physical and
exposed to the movements in the price of fuel and to trading books, the contracts in the physical book
movements in the price of the power generated. The may qualify for the own use exemption.
trading unit’s objectives and activities are indicative of
how management of the utility operates the business. An entity that maintains separate physical and trading
books needs to maintain the integrity of the two books
A unit focused on managing fuel-price risk and to ensure that the net settlement of contracts in the
sales-price exposure to protect margins is more trading book does not “taint” similar contracts in the
likely to enter into many contracts that qualify for physical book, thus preventing the own use exemption
the own use exemption. A pattern of speculative from applying to contracts in the physical book. Other
activity or trading directed to profit maximisation is entities may have active energy trading programmes
unlikely to result in many contracts qualifying for the that go far beyond mitigation of risk. This practice
own use exemption. The central trading unit often has many similarities to the trading activities of other
operates as an internal marketplace in larger integrated commodities, such as gold, sugar or wheat.
utilities. The generating stations “sell” their output to
and “purchase” fuel from the trading unit. The retail A contract must meet the own use requirements to be
unit would “purchase” power to meet its customer included in the own use or physical book. Contracts
demands. The centralised trading function thus must meet the physical requirements of the business
“acquires” all of the entity’s exposure to the various at inception and continue to do so for the duration of
commodity risks. The trading unit is then responsible the contract.

Financial reporting in the power and utilities industry 41

 Practical requirements for a contract to be own use are: • If the contract fails to reduce the market demand
• At inception and through its life, the contract has to or supply requirements of the entity or is used
reduce the market demand or supply requirements for a different purpose, the contract ceases to be
of the entity by entering into a purchase contract or accounted for as a contract for own use purposes.
a sale contract, respectively. • The number of own use contracts would be capped
• The market exposure is identified and measured by reference to virtually certain production and
following methodologies documented in the distribution volumes (confidence levels) to avoid
risk management policies of production and the risk of own use contracts becoming surplus to
distribution. These contracts should be easily the inherent physical requirements. If in exceptional
identifiable by recording them in separate books. circumstances the confidence levels proved to be
insufficient they would have to be adjusted.

Volume

Expected total
physical delivery
1,400

800
300: physical delivery highly probable

500
500: physical delivery virtually certain-confidence level

Time

The only reason that physical delivery would We would expect the result of the operations that are
not take place at the confidence level would be speculative in nature to be reported on a net basis on
unforeseen operational conditions beyond control the face of the income statement. The result could be
of the management of the entity (such as a power reported either within revenue or as a separate line
plant closure due to a technical fault). Entities would (e.g., trading margin) above gross operating profit.
typically designate contracts that fall within the Such a disclosure would provide a more accurate
confidence level (with volumes up to 500 in the above reflection of the nature of trading operations than
diagram) as own use, contracts with physical delivery presentation on a gross basis.
being highly probable (up to 800) as “all in one” hedges
and other contracts where physical delivery is expected
but is not highly probable (over 800) as at fair value
through profit or loss.

42 Financial reporting in the power and utilities industry

 3

Future developments – standards issued and not yet effective

3 Future developments –
standards issued and
not yet effective

Financial reporting in the power and utilities industry 43

 3 Future developments – standards
issued and not yet effective
3.1 Overview of renewable technologies, the determination of the
type of control which exists is important. The rights
of investors to make decisions over relevant activities
2011 is a period of significant activity for the IASB.
(now defined as those which significantly affect the
The timetable had originally called for a number
investee’s returns) are critical in this determination.
of financial-crisis-related projects (including
consolidation, joint arrangements and hedge
Factors to be assessed to determine control under the
accounting) to be finalised. Some key memorandum of
new standard include:
understanding projects, such as leasing and revenue,
• The purpose and design of an investee
were also scheduled to be published in summer 2011.
• Whether rights are substantive or protective
in nature
Consolidation, joint arrangements and fair value
• Existing and potential voting rights
measurement have all now been issued as final
• Whether the investor is a principal or agent
standards; however, the decision was taken to re-
• Relationships between investors and how they
expose leasing and revenue. At the time of writing,
affect control
these projects, together with hedge accounting, remain
ongoing, and the final versions of these standards could
IFRS 10 requires that only substantive rights shall be
have significant differences from proposals to date.
considered in the assessment of power – protective
rights, designed only to protect an investor’s interest
This section focuses on those standards which have
without giving power over the entity and which
been issued and are not yet effective. Ongoing projects
may only be exercised under certain conditions, are
which have not been finalised will be examined in
not considered.
separate publications as the development of those
standards progresses.
Potential voting rights are defined as “rights to obtain
voting rights of an investee, such as those within an
3.2 Consolidation and joint option or convertible instrument.” If these rights can be
arrangements exercised prior to major decision-making events, such
as annual general meetings, they should be considered
The IASB issued three new standards in May 2011: when determining control.
IFRS 10, Consolidation, IFRS 11, Joint Arrangements,
and IFRS 12, Disclosure. The standards replace IAS 27, The “principal vs. agent” determination is also
Consolidated and Separate Financial Statements (which important. Sometimes one party may be designated
is amended to become IAS 27, Separate Financial to operate the project on behalf of the investors. A
Statements), and IAS 31, Interests in Joint Ventures. principal may delegate some of its decision authority to
There have also been consequential amendments to the agent, but the agent would not be viewed as having
IAS 28, Investments in Associates, which is now IAS control when it exercises such powers on behalf of
28, Investments in Associates and Joint Ventures. The the principal.
standards are effective for 2013, and early adoption
is permitted if all five standards are adopted at the Economic dependence of an arrangement, such as a
same time. generator which relies solely on one fuel source, is not
uncommon but is not a priority indicator. If the supplier
3.2.1 Consolidation has no influence over management or decision-making
processes, dependence would be insufficient to
IFRS 10 confirms consolidation is performed where constitute power.
control exists but does not affect the mechanics
of consolidation. However, the standard redefines 3.2.2 Joint arrangements
control to exist where an investor has power, exposure
to variable returns and the ability to use that power Under the new IFRS 11, “joint arrangement” is the term
to affect its returns from the investee. As a result, now used to describe all types of arrangements where
changes to the composition of the consolidated group two or more parties have joint control. The definition of
may occur. joint control is unchanged from IAS 31, and exists only
when decisions about key decisions require unanimous
As multiple-party arrangements are becoming more consent. There is some clarification that such key
common in the utilities industry with introduction decisions must be about relevant activities (previously
IAS 31 referred to “strategic financial and operating
decisions”) which IFRS 10 defines as activities which
significantly affect the investee’s returns.

44 Financial reporting in the power and utilities industry

The standard also introduces other new terminology:

Under IAS 31 Under new IFRS 11 IFRS 11 definition

3
Jointly controlled asset Joint operation Parties have rights to the assets
and obligations for the liabilities
relating to the arrangement

Future developments – standards issued and not yet effective

Jointly controlled operation Joint operation Parties have rights to the assets and
obligations for the liabilities

Jointly controlled entity Joint venture Parties have rights to the net assets
of the arrangement

Classification
are joint ventures. A joint arrangement in a separate
The classification of the joint arrangement is now vehicle can still be a joint operation; it depends on
based on the rights and obligations of the parties to the rights and obligations of the venturers and is
the arrangements. This represents a significant change further influenced by the economic purpose of the
from IAS 31, where the classification was instead based joint arrangement.
on the legal form of the arrangement.
As the standard has been issued recently, entities, users
Determination of the type of joint arrangement can be and practitioners are in the early stages of forming
a complex decision under IFRS 11. Legal form remains their views, and practices may evolve as the standard
relevant for determining the type of joint arrangement is further assessed and applied. The flowchart below,
but is less important than under the previous standard. based on our current interpretation of the standard,
A joint arrangement that is not structured through attempts to illustrate the decision-making process and
a separate vehicle is a joint operation. That does not what needs to be considered to properly classify joint
mean that all joint arrangements in separate vehicles arrangements as operations or ventures.

What are my joint arrangements?

Yes
Is the arrangement
Does the vehicle create separation?
in a vehicle?
No Yes
No Yes Does investor have direct rights to assets and
obligations for liabilities in normal course of business?

Joint Operation No

Is the venture partner required to consume its share

of output or capacity in the venture?
Yes

No

Joint Venture

Financial reporting in the power and utilities industry 45

 Joint arrangements operate in different types of Accounting
vehicles in the utilities industry, including partnerships,
unincorporated entities, limited companies and The classification of the joint arrangement is important
unlimited liability companies. Venturers will have to because IFRS 11 requires use of equity accounting for
assess all their joint arrangements and identify those investments in joint arrangements. Therefore, investors
that are operated through vehicles. who previously had a choice between equity accounting
and proportionate consolidation will no longer have
Sometimes the legal structure of the vehicle or the that choice. Arrangements previously accounted for
contractual terms between the venturers does not under proportionate consolidation will have to change
allow legal separation of the venture from the venture to equity accounting if the arrangement is concluded to
partners (i.e., the venturers remain exposed to direct be a joint venture.
interest in the assets and liabilities of the venture). For
example, sometimes general partnerships do not create Investors in joint operations are required to account for
separation from the partners because the contractual their share of assets and liabilities. Again, this would
terms contained in the partnership provide direct rights mean a change in accounting where they had chosen
to assets and expose the partners to direct obligations equity accounting for a jointly controlled entity, but
for liabilities of the partnership in the normal course that arrangement was concluded to be a joint operation
of business. Similarly, unlimited liability companies under IFRS 11. It should also be noted that the share of
provide direct rights and obligations to the venture assets and liabilities is not the same as proportionate
partners. It can be challenging to assess the contractual consolidation. “Share of assets and liabilities” means
terms of all arrangements to identify whether it creates that the investor should consider their interest or
separation. Vehicles that do not create separation are obligation in each underlying asset and liability under
joint operations. the terms of the arrangement – it will not necessarily
be the case that they have a single, standard percentage
The parties’ rights and obligations arising from the interest in all assets and liabilities. This is also an
arrangement have to be assessed as they exist in important consideration when transitioning to the
the “normal course of business” (Para B14 of IFRS new standard.
11). Hence, legal rights and obligations arising in
circumstances which are other than in the “normal Transition
course of business”, such as liquidation and
bankruptcy, should not be considered. For example, a Entities must re-evaluate the terms of their existing
separate vehicle may give the venture partners rights contractual arrangement to ensure that their
to assets and obligations to liabilities as per the terms involvement in joint arrangements are correctly
of their agreement. However, in case of liquidation accounted for under the new standard. Joint
of the vehicle, secured creditors have the first right to arrangements that were previously accounted for
the assets and the venture partners have rights only in as joint operations may need to be treated as joint
the net assets remaining after settling all third-party ventures, or vice versa, on transition to the new
obligations. Such a vehicle would be considered a joint standard. This will change the way they report
operation since in the “normal course of business” their respective rights and obligations in their
the venture partners have direct interest in assets and financial statements.
liabilities. Separate vehicles that give venture partners
direct rights to assets and obligation for liabilities of the When transitioning from the proportionate
vehicle are joint operations. consolidation method to the equity method, entities
should recognise their initial investment in the joint
Separate vehicles structured in a manner that all venture as the aggregate of the carrying amounts that
of their outputs are purchased or consumed by the were previously proportionately consolidated.
venture partners are more likely to be joint operations.
However, contractual terms and legal structure of the To transition from the equity method to proportionate
vehicle need to be carefully assessed. There has to consolidation, entities will derecognise their
be a contractual agreement or commitment between investment in the jointly controlled entity and
the venture parties that requires them to purchase/ recognise their rights and obligations to the assets and
consume their share of the output or capacity in the liabilities of the joint operation. Their interest in those
venture. If the venture can sell the output to third assets and liabilities may be different from their interest
parties at prices independently determined by it, this in the jointly controlled entity.
criterion will not be met.

46 Financial reporting in the power and utilities industry

Moving from the equity method to a share of assets and largely consistent with current valuation practices, it is
liabilities is not always a simple process. For example, not expected that adoption of this standard will result
parties may have contributed specific assets to a joint in substantial change.
arrangement. When evaluating interest based on The main changes introduced are: 3
share of assets and liabilities, parties account for their • An introduction of fair value hierarchy levels
interest in the arrangement based on the share of assets for non-financial assets, similar to current

Future developments – standards issued and not yet effective

contributed by them. The interest calculated based on IFRS 7 requirements
assets contributed does not necessarily result in the • A requirement for the fair value of financial liabilities
same interest that the party may have in the equity of (including derivatives) to be determined based on
that entity. Where there is a difference between the the assumption that the liability will be transferred
value recorded under equity accounting and the net to another party rather than settled or extinguished
value of the gross assets and liabilities, this is written • The removal of the requirement for bid prices to
off against opening retained earnings. be used for actively quoted financial assets and
ask prices to be used for actively quoted financial
Similarly, moving from proportionate consolidation liabilities. Instead, the most representative price
to equity method could pose challenges. For example, within the bid-ask spread should be used.
the liabilities of a joint arrangement assessed to be a • Additional disclosure requirements
joint venture may exceed the assets. Netting these may The new standard is available for immediate adoption,
result in the venturer’s investment becoming negative, and is mandatory from 2013.
in which case the venturers have to assess whether they
need to record a liability in respect of that negative 3.4 Financial instruments
balance. This depends on whether the venturer
has an obligation to fund the liabilities of the joint IFRS 9
arrangement. If there is no obligation, then the balance
is written off against opening retained earnings. If The IASB has issued IFRS 9, Financial Instruments,
there is an obligation, further consideration should be which addresses the classification and measurement of
given as to whether the assessment of the arrangement financial assets and liabilities. It replaces the existing
as a joint venture was correct. guidance under IAS 39. IFRS 9 is applicable from
January 1, 2015 (as tentatively agreed by recent Board
Impact in the power and utilities industry decisions – this is expected to be confirmed by the
end of 2011), and early adoption is permitted. IFRS 9
Entities in the sector that are likely to be most should be applied retrospectively; however, if adopted
significantly impacted include those that: before January 2012, the standard does not require
• Enter into new joint arrangements comparative periods to be restated.
• Currently apply proportionate consolidation for
jointly controlled entities The main feature of IFRS 9 is that it emphasises the
• Currently apply equity method for jointly controlled entity’s business model when classifying financial
entities which are assessed to be joint operations assets. Accordingly, the business model and the
under IFRS 11 characteristics of the contractual cash flows of the
• Participate in a significant number of existing financial asset determine whether the financial asset is
complex joint arrangements subsequently measured at amortised cost or fair value.
• Have old joint arrangements with limited This is a key difference to current practice.
documentation detailing the terms of
the arrangement How does it impact the power and
utility sector?
3.3 Fair value measurement
The effect of IFRS 9 on the financial reporting of utility
The IASB released IFRS 13, Fair Value Measurement, entities is expected to vary significantly depending on
in May 2011. IFRS 13 consolidates fair value entities’ investment objectives. Utility entities will be
measurement guidance across various IFRSs into impacted by the new standard if they hold many or
a single standard, and applies when another IFRS complex financial assets. The degree of the impact will
requires to permit fair value measurements, including depend on the type and significance of financial assets
fair value less costs to sell. As the requirements are held by the entity and the entity’s business model for
managing financial assets.

Financial reporting in the power and utilities industry 47

 For example, entities that hold bond instruments with IFRS 9 prohibits reclassifications from amortised cost to
complex features (such as interest payments linked fair value (or vice versa) except in rare circumstances
to entity performance or foreign exchange rates) will when the entity’s business model changes. In cases
be significantly impacted. In contrast, utility entities where it does, entities will need to reclassify affected
that hold only shares in publicly listed companies that financial assets prospectively.
are not held for trading won’t be impacted, as these
continue to be measured at fair value with changes There is specific guidance for contractually linked
taken to the income statement. instruments that create concentrations of credit risk,
which is often the case with investment tranches
What are the key changes for in a securitisation. In addition to assessing the
financial assets? instrument itself against the IFRS 9 classification
criteria, management should also “look through”
IFRS 9 replaces the multiple classification and to the underlying pool of instruments that generate
measurement models in IAS 39, Financial Instruments: cash flows to assess their characteristics. To qualify
Recognition and Measurement, with a single model that for amortised cost, the investment must have equal
has only two classification categories: amortised cost or lower credit risk than the weighted-average credit
and fair value. A financial instrument is measured at risk in the underlying pool of other instruments, and
amortised cost if two criteria are met: those instruments must meet certain criteria. If a look
a) The objective of the business model is to hold through is impractical, the tranche must be classified at
the financial instrument for the collection of the fair value through profit or loss.
contractual cash flows.
b) The contractual cash flows under the instrument Under IFRS 9, all equity investments should be
solely represent payments of principal and interest. measured at fair value. However, management has
an option to present in other comprehensive income
If these criteria are not met, the asset is classified at unrealised and realised fair value gains and losses on
fair value. This will be welcome news for most utility equity investments that are not held for trading. Such
entities that hold debt instruments with simple loan designation is available on initial recognition on an
features (such as bonds that pay only fixed interest instrument-by-instrument basis and it is irrevocable.
payments and the principal amount outstanding) There is no subsequent recycling of fair value gains and
which are not held for trading. losses on disposal to the income statement; however,
dividends from such investments will continue to be
The new standard removes the requirement to separate recognised in the income statement. This is good news
embedded derivatives from the rest of a financial for many because utility entities may own ordinary
asset. It requires a hybrid contract to be classified in shares in public entities. As long as these investments
its entirety at either amortised cost or fair value. In are not held for trading, fluctuations in the share price
practice, we expect many of these hybrid contracts to will be recorded in other comprehensive income. Under
be measured at fair value. The convertible bonds held the new standard, recent events such as the global
by utility entities are often considered to be hybrid financial crisis will not yield volatile results in the
contracts and may need to be measured at fair value. income statement from changes in the share prices.

48 Financial reporting in the power and utilities industry

How could current practice change for
power and utility entities?
3
Type of instrument/ Accounting under IAS 39 Accounting under IFRS 9 Insight
Categorisation of

Future developments – standards issued and not yet effective

instrument

Investments in equity Usually classified as Measured at fair value Equity securities that are
instruments that are not “available for sale”, with with gains/losses not held for trading can be
held for trading purposes gains/losses deferred recognised in the income classified and measured
(e.g., equity securities of a in other comprehensive statement or through at fair value with gains/
listed entity). income (but may other comprehensive losses recognised in other
be measured at fair income if applicable. comprehensive income.
Note. This does not value through profit This means no charges to
include associates or or loss, depending on the income statement for
subsidiaries unless the instrument). significant or prolonged
entities specifically make impairment on these
that election. equity investments, which
will reduce volatility in
the income statement as
a result of the fluctuating
share prices.

Available-for-sale debt Recognised at fair Measured at amortised Determining whether the

instruments (e.g., value with gains/ cost where certain criteria debt instrument meets
corporate bonds) losses deferred in other are met. Where criteria the criteria for amortised
comprehensive income. are not met, measured at cost can be challenging
fair value through profit in practice. It involves
and loss. determining what the
bond payments represent.
If they represent more
than principal and
interest on principal
outstanding (e.g., if they
include payments linked
to a commodity price),
this would need to be
classified and measured at
fair value with changes in
fair value recorded in the
income statement.

Financial reporting in the power and utilities industry 49

 Type of instrument/ Accounting under IAS 39 Accounting under IFRS 9 Insight
Categorisation of
instrument

Convertible instruments Embedded conversion The entire instrument Many entities found
(e.g., convertible bonds) option split out and is measured at fair the separation of
separately recognised at value, with gains/ conversion options
fair value. The underlying losses recognised in the and the requirement to
debt instrument is income statement. separately fair value the
usually measured at instrument challenging.
amortised cost.
However, management
should be aware that the
entire instrument will
now be measured at fair
value. This may result in
a more volatile income
statement because it will
need to have fair value
gains/losses recognised
not only on the conversion
option, but also on the
entire instrument.

Held-to-maturity Measured at Measured at amortised Determining whether

investments (e.g., amortised cost. cost where certain criteria the government bond
government bonds) are met. Where criteria payments meet the
are not met, measured at criteria for amortised
fair value through profit cost remains a challenge.
and loss. For example, if the
government bond
includes a component
for inflation, as long as
the payment represents
only compensation for
time value of money, it
may still meet the criteria
for amortised cost. In
contrast, a government
bond that is linked to
foreign currency exchange
rates would not meet the
criteria for amortised cost;
instead this would need to
be measured at fair value
through profit and loss.

50 Financial reporting in the power and utilities industry

What are the key changes for What else should entities in the power
financial liabilities? and utility sector know about the
new standard?
The main concern in revising IAS 39 for financial 3
liabilities was potentially showing in the income Entities that currently classify their investments as
statement the impact of “own credit risk” for liabilities loans and receivables need to carefully assess whether

Future developments – standards issued and not yet effective

recognised at fair value – that is, fluctuations in value their business model is based on managing the
due to changes in the liability’s credit risk. This can investment portfolio to collect the contractual cash
result in gains being recognised in income when the flows from the financial assets. To meet that objective,
liability has had a credit downgrade, and losses being the entity does not need to hold all of its investments
recognised when the liability’s credit risk improves. until maturity, but the business must be holding the
Many users found these results counterintuitive, investments to collect their contractual cash flows.
especially when there is no expectation that the change We expect most utility entities to be managing their
in the liability’s credit risk will be realised. In view loans and receivables (normally trade receivables)
of this concern, the IASB has retained the existing to collect their contractual cash flows. As a result, for
guidance in IAS 39 regarding classifying and measuring many entities these new rules will not have a significant
financial liabilities, except for those liabilities where impact on their financial assets.
the fair value option has been elected.
Entities in the utility sector that manage their
IFRS 9 changes the accounting for financial liabilities investments and monitor performance on a fair value
that an entity chooses to account for at fair value basis will need to fair value their financial assets with
through profit or loss, using the fair value option. For gains and losses recognised in the income statement.
such liabilities, changes in fair value related to changes Primarily that is because their business model is not
in own credit risk are presented separately in other considered to be based on managing the investment
comprehensive income (OCI). portfolio to collect the contractual cash flows, and so a
different accounting treatment is required. We expect
In practice, a common reason for electing the fair value only a minority of entities in the sector to be managing
option is where entities have embedded derivatives their investments on this basis.
that they do not wish to separate from the host liability.
In addition, entities may elect the fair value option Some entities made use of the cost exception in the
where they have accounting mismatches with assets existing IAS 39 for their unquoted equity investments.
that are required to be held at fair value through profit Under the new standard, these entities can continue to
or loss. use cost only where it is an appropriate estimate of fair
value. Utility entities should be aware that the scenarios
Financial liabilities that are required to be measured at in which cost would be an appropriate estimate of
fair value through profit or loss (as distinct from those fair value are limited to cases when insufficient recent
that the entity has chosen to measure at fair value information is available to determine the fair value.
through profit or loss) continue to have all fair value Therefore, entities will need to implement mechanisms
movements recognised in profit or loss with no transfer to determine fair value periodically. There will be a
to OCI. This includes all derivatives (such as foreign substantial impact on entities that hold investments
currency forwards or interest rate swaps), or an entity’s in unlisted entities where the investing entity doesn’t
own liabilities that it classifies as being held for trading. have significant influence. This could significantly affect
businesses because IFRS 9 requires a process or system
Amounts in OCI relating to own credit are not recycled in place to determine the fair value or range of possible
to the income statement, even when the liability is fair value measurements.
derecognised and the amounts are realised. However,
the standard does allow transfers within equity.

Financial reporting in the power and utilities industry 51

 Entities that currently classify their financial assets as entities would like to reclassify their financial assets.
available-for-sale and plan to make use of the “other Upon adoption of this standard, entities need to apply
comprehensive income option” to defer fair value the new rules retrospectively. This will allow some
gains should be aware that it is only available for entities to reverse some impairment charges recognised
equity investments on an instrument-by-instrument on listed equity securities as a result of the global
basis. These entities will not be able to use other financial crisis, as long as they are still holding the
comprehensive income for debt instruments. Once this investment. We expect that some utility entities will
election is chosen, it will irrevocably prevent the entity consider early adopting the standard to take advantage
from recycling gains and losses through the income of this.
statement on disposal. For some entities in the sector
this will remove some of the freedoms they currently Management should bear in mind that the financial
enjoy with the accounting for debt instruments. instruments project is evolving. IFRS 9 is only the first
part of the project to replace IAS 39. Other exposure
Entities in the utility sector may want to consider drafts have been issued in respect of asset-liability
early adopting the standard, particularly where they offsetting and hedge accounting with the intention of
have previously recorded impairment losses on equity improving and simplifying hedge accounting.
investments that are not held for trading or where

52 Financial reporting in the power and utilities industry

 Appendices
Appendices

Financial reporting in the power and utilities industry 53

 Appendix A – Financial
statement disclosure examples
The following financial statement disclosure examples are measured at their present value. In the reporting
represent extracts from the annual reports and period, they amounted to €92 million (previous year:
accounts of the relevant companies. These should be €122 million). Further additions of €88 million in
read in conjunction with the relevant full annual report provisions (previous year: release of €388 million)
and accounts for a full understanding. stem from the fact that current estimates project
a net increase in anticipated waste disposal costs
Decommissioning (previous year: decrease). Additions to provisions for
nuclear waste management primarily consist of an
RWE AG interest accretion of €472 million (previous year: €446
(31 December 2010, pages 203, 204) million). €833 million in prepayments, primarily to
foreign reprocessing companies and to the German
“Provisions for nuclear waste management are almost Federal Office for Radiation Protection (BfS) for the
exclusively recognised as non-current provisions, and construction of final storage facilities, were deducted
their settlement amount is discounted to the balance- from these provisions (previous year: €796 million).
sheet date. From the current perspective, the majority
of utilisation is anticipated to occur in the years 2020 In terms of their contractual definition, provisions for
to 2050. As in the previous year, the discount factor nuclear waste management break down as follows:
was 5.0 %. Volume-based increases in the provisions

Provisions for nuclear waste management 31 Dec 31 Dec

€ million 2010 2009
Provisions for nuclear obligations,
7,977 7,557
not yet contractually defined
Provisions for nuclear obligations,
2,033 1,934
contractually defined
10,010 9,491

In respect of the disposal of spent nuclear fuel Provisions for contractually defined nuclear obligations
assemblies, the provisions for obligations which are not are related to all nuclear obligations for the disposal
yet contractually defined cover the estimated long- of fuel assemblies and radioactive waste as well as for
term costs of direct final storage of fuel assemblies, the decommissioning of nuclear power plants, insofar
which is currently the only possible disposal method as the value of said obligations is specified in contracts
in Germany, as well as the costs for the disposal of under civil law. They include the anticipated residual
radioactive waste from reprocessing, which essentially costs of reprocessing, return (transport, containers)
consist of costs for transport from centralised storage and intermediate storage of the resulting radioactive
facilities and the plants’ intermediate storage facilities waste, as well as the additional costs of the utilisation
to reprocessing plants and final storage as well as of uranium and plutonium from reprocessing activities.
conditioning for final storage and containers. These These costs are based on existing contracts with foreign
estimates are mainly based on studies by internal and reprocessing companies and with GNS. Moreover,
external experts, in particular by GNS Gesellschaft these provisions also take into account the costs for
für Nuklear-Service mbH in Essen, Germany. With transport and intermediate storage of spent fuel
regard to the decommissioning of nuclear power assemblies within the framework of final direct storage.
plants, the costs for the post-operational phase and The power plants’ intermediate storage facilities are
dismantling are taken into consideration, on the basis licensed for an operational period of 40 years. These
of data from external expert opinions prepared by NIS facilities commenced operations between 2002 and
Ingenieurgesellschaft mbH, Alzenau, Germany, which 2006. Furthermore, the amounts are also stated for the
are generally accepted throughout the industry and are conditioning and intermediate storage of radioactive
updated continuously. Finally, this item also covers all operational waste, which is primarily performed
of the costs of final storage for all radioactive waste, by GNS.
based on data provided by BfS.

54 Financial reporting in the power and utilities industry

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

Provisions for nuclear waste management 31 Dec 31 Dec

Appendix A – Financial statement disclosure examples

€ million 2010 2009
Decommissioning of nuclear facilities 4,490 4,626
Disposal of nuclear fuel assemblies 4,831 4,303
Disposal of radioactive operational waste 689 562
10,010 9,491

Provisions for mining damage also consist almost rates are dealt with prospectively and reflected as
entirely of non-current provisions. They are reported an adjustment to the provision and corresponding
at the settlement amount discounted to the balance- decommissioning asset included within property,
sheet date. As in the previous year, we use a discount plant and equipment. For gas production facilities and
factor of 5.0 %. In the reporting period, additions offshore storage facilities the decommissioning asset
to provisions for mining damage amounted to €117 is amortised using the unit of production method,
million (previous year: €165 million). Of this, an based on proven and probable reserves. For power
increase of €67 million (previous year: €84 million) stations the decommissioning asset is amortised on a
was capitalised under property, plant and equipment. straight-line basis over the useful life of the facility. The
The interest accretion of the additions to provisions for unwinding of the discount on the provision is included
mining damage amounted to €151 million (previous in the Income Statement within interest expense.
year: €121 million).”
[…]
Centrica plc (31 December 2010,
pages 76, 82) The estimated cost of decommissioning at the
end of the producing lives of fields is reviewed
“Provision is made for the net present value of the periodically and is based on proven and probable
estimated cost of decommissioning gas production reserves, price levels and technology at the balance
facilities at the end of the producing lives of fields, and sheet date. Provision is made for the estimated
storage facilities and power stations at the end of the cost of decommissioning at the balance sheet
useful life of the facilities, based on price levels and date. The payment dates of total expected future
technology at the balance sheet date. decommissioning costs are uncertain and dependent on
the lives of the facilities, but are currently anticipated
When this provision gives access to future economic to be between 2011 and 2055, with the substantial
benefits, a decommissioning asset is recognised and majority of the costs expected to be paid between 2020
included within property, plant and equipment. and 2030.”
Changes in these estimates and changes to the discount

Financial reporting in the power and utilities industry 55

 Impairment

National Grid plc (31 March 2011,

page 136)

“9.Goodwill Total £m
Cost at 31 March 2009 5,391
Exchange adjustments (289)
Cost at 31 March 2010 5,102
Exchange adjustments (280)
Impairment of goodwill on businesses reclassified as held for sale (notes 3 and 18) (I) (34)
Reclassified as held for sale (12)
Cost at 31 March 2011 4,776
Net book value at 31 March 2011 4,776
Net book value at 31 March 2010 5,102
(I) Relates to our gas operations (£30m) and our electricity distribution operations (£4m)

The amounts disclosed above as at 31 March 2011 The future growth rate used to extrapolate projections
include balances relating to our US gas operations of beyond four years has been reduced to 2.4%. The
£2,876m (2010: £3,077m), our New England electricity growth rate has been determined having regard to data
distribution operations of £819m (2010: £881m), our on projected growth in US real gross domestic product
operations run by our subsidiary Niagara Mohawk (GDP). Based on our business’s place in the underlying
Power Corporation of £849m (2010: £898m) and our US economy, it is appropriate for the terminal growth
New England transmission operations of £232m rate to be based upon the overall growth in real GDP
(2010: £246m). and, given the nature of our operations, to extend over
a long period of time. Cash flow projections have been
Goodwill is reviewed annually for impairment and the discounted to reflect the time value of money, using
recoverability of goodwill at 31 March 2011 has been an effective pre-tax discount rate of 10% (2010: 10%).
assessed by comparing the carrying amount of our The discount rate represents the estimated weighted-
operations described above (our cash generating units) average cost of capital of these operations.
with the expected recoverable amount on a value-in-
use basis. In each assessment the value-in-use has been While it is possible that a key assumption in the
calculated based on four year plan projections that calculation could change, the Directors believe that
incorporate our best estimates of future cash flows, no reasonably foreseeable change would result in
customer rates, costs, future prices and growth. Such an impairment of goodwill, in view of the long-term
projections reflect our current regulatory rate plans nature of the key assumptions and the margin by which
taking into account regulatory arrangements to allow the estimated fair value exceeds the carrying amount.”
for future rate plan filings and recovery of investment.
Our plans have proved to be reliable guides in the past
and the Directors believe the estimates are appropriate.

56 Financial reporting in the power and utilities industry

RWE AG (31 December 2010, Development costs of €112 million were capitalised
pages 187, 188) (previous year: €104 million).

“In the reporting period, the RWE Group’s total As of the balance-sheet date, the carrying amount
expenditures on research and development amounted of intangible assets related to exploration activities
to €149 million (previous year: €110 million). amounted to €374 million (previous year: €415 million).

Appendix A – Financial statement disclosure examples

Goodwill breaks down as follows:

Goodwill 31 Dec 31 Dec

€ million 2010 2009
Germany 4,186 3,937
Power Generation (404) (404)
Sales and Distribution Networks (3,782) (3,533)
Netherlands/Belgium 2,665 3,504
United Kingdom 2,968 2,877
Central Eastern and South Eastern Europe 2,048 1,956
Renewables 736 441
Upstream Gas & Oil 25 26
Trading/Gas Midstream 944 434
Others 77
13,572 13,252

In the reporting period, goodwill increased by €130 amount of the cash-generating units, which is defined
million. An increase in current redemption liabilities as the higher of fair value less costs to sell or value in
from put options resulted in an adjustment without use. The fair value reflects the best estimate of the price
an effect on income of €213 million to the goodwill that an independent third party would pay to purchase
of the segment Sales and Distribution Networks. the cash-generating unit as of the balance-sheet date.
Declines in goodwill primarily resulted from the Value in use is the present value of the future cash
reporting of Thyssengas as “Assets and liabilities flows which are expected to be generated with a cash-
held for sale” (€77 million). In respect of additions generating unit.
to goodwill in the previous year (€3,871 million),
€3,435 million resulted from the acquisition of Essent. Fair value is assessed from an external perspective and
With the assignment of Essent’s trading activities and value in use from a company-internal perspective. We
wind power generation to the segments Trading/Gas determine both variables using a business valuation
Midstream and Renewables, goodwill of €510 million model, taking into account planned future cash flows.
and €285 million, respectively, was allocated to these These cash flows, in turn, are based on the business
segments. Goodwill of €43 million was allocated to the plan, as approved by the Executive Board and valid
segment Sales and Distribution Networks, based on the at the time of the impairment test, and pertain to a
assignment of Essent’s gas storage activities. detailed planning period of up to five years. In certain
justifiable cases, a longer detailed planning period
In the third quarter of each fiscal year, the regular is taken as a basis, insofar as this is necessary due to
impairment test is performed to determine if there is economic or regulatory conditions. The cash flow plans
any need to write down goodwill. In order to carry are based on experience as well as on expected market
out this impairment test, goodwill is allocated to trends in the future. If available, market transactions in
the cash-generating units at the segment level. The the same sector or third-party valuations are taken as a
impairment test involves determining the recoverable basis for determining fair value.

Financial reporting in the power and utilities industry 57

 Mid-term business plans are based on country-specific discount rate of 6.75 % and a growth rate of 1.0 %.
assumptions regarding the development of key An increase in the discount rate by more than 1.21
economic indicators such as gross domestic product, percentage points to above 7.96 %, the assumption of a
consumer prices, interest rate levels and nominal negative growth rate higher than 1.53 % or a decrease
wages. These estimates are, amongst others, derived of more than £85 million in the operating result after
from macroeconomic and financial studies. taxes in terminal value would result in the recoverable
amount being lower than the carrying amount of the
The key planning assumptions for the business cash-generating unit United Kingdom.
segments active in Europe’s electricity and gas markets
are estimates relating to the development of wholesale The goodwill allocated to the segment Netherlands/
prices for electricity, crude oil, natural gas, coal and Belgium amounted to €2,665 million. The recoverable
CO2 emission allowances, retail prices for electricity amount exceeded the carrying amount by €0.9
and gas, and the development of market shares and billion. Impairment would have been necessary if the
regulatory framework conditions. calculations had used a discount rate increased by more
than 0.42 percentage points to above 6.67 %, a growth
The discount rates used for business valuations are rate decreased by more than 0.69 percentage points to
determined on the basis of market data. With regard to below 0.31 % or an operating result reduced by more
cash-generating units, during the period under review than €61 million in terminal value.”
they ranged from 6.25 % to 9.00 % after tax (previous
year: 6.5 % to 9.0 %) and from 8.0 % to 16.5 % before GDF SUEZ SA (31 December 2010,
tax (previous year: 8.8 % to 15.6 %). pages 302, 303)

For the extrapolation of future cash flows going beyond “In accordance with IAS 36, impairment tests are
the detailed planning horizon, we assumed constant carried out on items of property, plant and equipment
growth rates of 0.0 % to 1.0 % (previous year: 0.0 % and intangible assets where there is an indication
to 1.0 %). These figures are derived from experience that the assets may be impaired. Such indications
and future expectations for the individual divisions may be based on events or changes in the market
and do not exceed the long-term average growth rates environment, or on internal sources of information.
in the markets in which the Group companies are Intangible assets that are not amortized are tested for
active. In calculating cash flow growth rates, the capital impairment annually.
expenditures required to achieve the assumed cash
flow growth are subtracted. Impairment indicators

As of the balance-sheet date, both the fair values Property, plant and equipment and intangible assets
less costs to sell and the values in use were higher with finite useful lives are only tested for impairment
than the carrying amounts of the cash-generating when there is an indication that they may be impaired.
units. These surpluses react very sensitively to This is generally the result of significant changes to the
changes in the discount rate, the growth rate and the environment in which the assets are operated or when
operating result after taxes in terminal value as key economic performance is worse than expected.
measurement parameters.
The main impairment indicators used by the Group are
Of all the segments, United Kingdom and Netherlands/ described below:
Belgium exhibited the smallest surpluses of recoverable • external sources of information:
amount over carrying amount. The goodwill allocated – significant changes in the economic, technological,
to the segment United Kingdom amounted to €2,968 political or market environment in which the entity
million as of 31 December 2010. The impairment operates or to which an asset is dedicated;
test showed a recoverable amount which exceeded – fall in demand;
the carrying amount by £1.1 billion. Valuation of – changes in energy prices and US dollar
the segment United Kingdom was calculated using a exchange rates;
– carrying amount of an asset exceeding its regulated
asset base.

58 Financial reporting in the power and utilities industry

• internal sources of information: • terminal values in line with the available market data
– evidence of obsolescence or physical damage specific to the operating segments concerned and
not budgeted for in the depreciation/ growth rates associated with these terminal values,
amortization schedule; not to exceed the inflation rate.
– worse-than-expected performance;
– fall in resources for Exploration & Discount rates are determined on a post-tax basis

Appendix A – Financial statement disclosure examples

Production activities. and applied to post-tax cash flows. The recoverable
amounts calculated on the basis of these discount rates
Impairment are the same as the amounts obtained by applying the
pre-tax discount rates to cash flows estimated on a pre-
Items of property, plant and equipment and intangible tax basis, as required by IAS 36.
assets are tested for impairment at the level of the
individual asset or cash generating unit (CGU) as For operating entities which the Group has decided
appropriate, determined in accordance with IAS 36. to sell, the related carrying amount of the assets
If the recoverable amount of an asset is lower than its concerned is written down to estimated market value
carrying amount, the carrying amount is written down less costs of disposal. Where negotiations are ongoing,
to the recoverable amount by recording an impairment this value is determined based on the best estimate
loss. Upon recognition of an impairment loss, the of their outcome as of the statement of financial
depreciable amount and possibly the useful life of the position date.
assets concerned is revised.
In the event of a decline in value, the impairment
Impairment losses recorded in relation to property, loss is recorded in the consolidated income statement
plant and equipment or intangible assets may be under “Impairment”.”
subsequently reversed if the recoverable amount of the
assets is once again higher than their carrying value. Arrangements that may contain
The increased carrying amount of an item of property,
plant or equipment attributable to a reversal of an
a lease
impairment loss may not exceed the carrying amount
that would have been determined (net of depreciation/
E.ON AG (31 December 2010, page 69)
amortization) had no impairment loss been recognized
“Leasing transactions are classified according to the
in prior periods.
lease agreements and to the underlying risks and
rewards specified therein in line with IAS 17, “Leases”
Measurement of recoverable amount
(“IAS 17”). In addition, IFRIC 4, “Determining Whether
an Arrangement Contains a Lease” (“IFRIC 4”), further
In order to review the recoverable amount of property,
defines the criteria as to whether an agreement that
plant and equipment and intangible assets, the assets
conveys a right to use an asset meets the definition of
are grouped, where appropriate, into cash-generating
a lease. Certain purchase and supply contracts in the
units (CGUs) and the carrying amount of each unit is
electricity and gas business as well as certain rights of
compared with its recoverable amount.
use may be classified as leases if the criteria are met.
E.ON is party to some agreements in which it is the
For operating entities which the Group intends to hold
lessor and other agreements in which it is the lessee.
on a longterm and going concern basis, the recoverable
amount of an asset corresponds to the higher of its fair
Leasing transactions in which E.ON is the lessee are
value less costs to sell and its value in use. Value in use
classified either as finance leases or operating leases.”
is primarily determined based on the present value
of future operating cash flows and a terminal value.
Standard valuation techniques are used based on the
following main economic data:
• discount rates based on the specific characteristics of
the operating entities concerned;

Financial reporting in the power and utilities industry 59

 Emission Trading Scheme and Centrica plc (31 December 2010,
Certified Emission Reduction pages 75, 76)

“Granted carbon dioxide emissions allowances

National Grid plc (31 March 2011,
received in a period are recognised initially at
page 118)
nominal value (nil value). Purchased carbon dioxide
emissions allowances are recognised initially at cost
“Emission allowances, principally relating to the
(purchase price) within intangible assets. A liability
emissions of carbon dioxide in the UK and sulphur and
is recognized when the level of emissions exceeds the
nitrous oxides in the US, are recorded as intangible
level of allowances granted. The liability is measured
assets within current assets and are initially recorded
at the cost of purchased allowances up to the level of
at cost and subsequently at the lower of cost and
purchased allowances held, and then at the market
net realisable value. Where emission allowances are
price of allowances ruling at the balance sheet
granted by relevant authorities, cost is deemed to be
date, with movements in the liability recognised in
equal to the fair value at the date of allocation. Receipts
operating profit.
of such grants are treated as deferred income, which
is recognised in the income statement as the related
Forward contracts for the purchase or sale of carbon
charges for emissions are recognised or on impairment
dioxide emissions allowances are measured at fair
of the related intangible asset. A provision is recorded
value with gains and losses arising from changes in
in respect of the obligation to deliver emission
fair value recognised in the Income Statement. The
allowances and emission charges are recognised in the
intangible asset is surrendered and the liability is
income statement in the period in which emissions
utilised at the end of the compliance period to reflect
are made.”
the consumption of economic benefits.
E.ON AG (31 December 2010, page 68)
Purchased renewable obligation certificates are
recognised initially at cost within intangible assets. A
“Under IFRS, emission rights held under national and
liability for the renewables obligation is recognised
international emission-rights systems for the settlement
based on the level of electricity supplied to customers,
of obligations are reported as intangible assets.
and is calculated in accordance with percentages set
Because emission rights are not depleted as part of the
by the UK Government and the renewable obligation
production process, they are reported as intangible
certificate buyout price for that period. The intangible
assets not subject to amortization. Emission rights
asset is surrendered and the liability is utilised
are capitalized at cost when issued for the respective
at the end of the compliance period to reflect the
reporting period as (partial) fulfillment of the notice of
consumption of economic benefits.”
allocation from the responsible national authorities, or
upon acquisition.
Customer Contributions
A provision is recognized for emissions produced. The
provision is measured at the carrying amount of the E.ON AG (31 December 2010, pages 120,
emission rights held or, in case of a shortfall, at the 121)
current fair value of the emission rights needed. The
expenses incurred for the recognition of the provision “Capital expenditure grants of €739 million (2009:
are reported under cost of materials. €345 million) were paid primarily by customers for
capital expenditures made on their behalf, while
As part of operating activities, emission rights are also E.ON retains ownership of the assets. The grants are
held for proprietary trading purposes. Emission rights non-refundable and are recognized in other operating
held for proprietary trading are reported under other income over the period of the depreciable lives of the
operating assets and measured at the lower of cost or related assets.
fair value.”

60 Financial reporting in the power and utilities industry

Construction grants of €2,940 million (2009: €3,217 fair values, at the date of exchange, of other assets
million) were paid by customers for the cost of new transferred, liabilities incurred or assumed, and
gas and electricity connections in accordance with equity instruments issued by the Group in exchange
the generally binding terms governing such new for control of the acquiree. The acquiree’s identifiable
connections. These grants are customary in the assets, liabilities and contingent liabilities that meet
industry, generally non-refundable and recognized the conditions for recognition under IFRS 3 (revised),

Appendix A – Financial statement disclosure examples

as revenue according to the useful lives of the Business Combinations, are recognised at their fair
related assets.” value at the acquisition date, except for non-current
assets (or disposal groups) that are classified as held for
Regulatory Assets & Liabilities resale in accordance with IFRS 5, Non-Current Assets
Held for Sale and Discontinued Operations, which are
National Grid plc (31 March 2011, recognised and measured at fair value less costs to sell.
page 115)
Goodwill arising on a business combination represents
“Revenue primarily represents the sales value derived the excess of the cost of acquisition over the Group’s
from the generation, transmission, and distribution interest in the fair value of the identifiable assets and
of energy and recovery of US stranded costs together liabilities of a subsidiary, jointly controlled entity or
with the sales value derived from the provision of other associate at the date of acquisition. Goodwill is initially
services to customers during the year and excludes recognised as an asset at cost and is subsequently
value added tax and intra-group sales. measured at cost less any accumulated impairment
losses. If, after reassessment, the Group’s interest in
US stranded costs are various generation-related the net fair value of the acquiree’s identifiable assets,
costs incurred prior to the divestiture of generation liabilities and contingent liabilities exceeds the cost
assets beginning in the late 1990s and costs of legacy of the business combination, the excess is recognised
contracts that are being recovered from customers. The immediately in the Income Statement.”
recovery of stranded costs and other amounts allowed
to be collected from customers under regulatory Concession Arrangements
arrangements is recognised in the period in which
these amounts are recoverable from customers. RWE AG (31 December 2010, page 223)

Revenue includes an assessment of unbilled energy and “In the fields of electricity, gas and water supply, there
transportation services supplied to customers between are a number of easement agreements and concession
the date of the last meter reading and the year end. contracts between RWE Group companies and
governmental authorities in the areas supplied by RWE.
Where revenue received or receivable exceeds the
maximum amount permitted by regulatory agreement Easement agreements are used in the electricity and
and adjustments will be made to future prices to reflect gas business to regulate the use of public rights of way
this over-recovery, no liability is recognised as such an for laying and operating lines for public energy supply.
adjustment to future prices relates to the provision of These agreements are generally limited to a term of 20
future services. Similarly no asset is recognised where a years. After expiry, there is a legal obligation to transfer
regulatory agreement permits adjustments to be made ownership of the local distribution facilities to the new
to future prices in respect of an under-recovery.” operator, for appropriate compensation.

Business Combinations Water concession agreements contain provisions for the

right and obligation to provide water and wastewater
Centrica plc (31 December 2010, page 75) services, operate the associated infrastructure, such
as water utility plants, as well as to implement capital
“The acquisition of subsidiaries is accounted for using expenditure. Concessions in the water business
the purchase method. The cost of the acquisition is generally have terms of up to 25 years.”
measured as the cash paid and the aggregate of the

Financial reporting in the power and utilities industry 61

 E.ON AG (31 December 2010, page 77) 1.3.14.2 French concessions

“IFRIC 12, “Service Concession Arrangements” In France, the Group is the operator for three types of
public service concessions:
IFRIC 12, “Service Concession Arrangements” • public electricity distribution concessions in which
(“IFRIC 12”), was published in November 2006. The the grantors are local authorities (municipalities or
interpretation governs accounting for arrangements syndicated municipalities);
in which a public-sector institution grants contracts • hydropower concessions with the State as grantor;
to private companies for the performance of public • the public transmission network operated under
services. In performing these services, the private concession from the State.
company uses infrastructure that remains under
the control of the public-sector institution. The 1.3.14.2.1 Public electricity
private company is responsible for the construction, distribution concessions
operation and maintenance of the infrastructure. The
interpretation has been transferred by the EU into General background
European law and its application is thus mandatory, at
the latest, for fiscal years beginning on or after March Since the enactment of the French Law of April 8,
29, 2009. The transitional provisions additionally 1946, EDF has by law been the sole operator for the
require retrospective application of IFRIC 12. In that main public distribution concessions in France. The
context, E.ON has made corresponding reclassifications accounting treatment of concessions is based on the
in the prior-year values, consisting primarily of concession agreements, with particular reference
approximately €0.4 billion reclassified from property, to their special clauses. It takes into consideration
plant and equipment to intangible assets in the network the possibility that EDF may one day lose its status
operations in Romania.” as the sole authorized State concession operator.
These contracts cover terms of between 20 and
Électricité de France SA (31 December 30 years, and generally use standard concession
2010, pages 23, 24) rules deriving from the 1992 Framework Contract
negotiated with the National Federation of Licensing
“1.3.14.1 Accounting treatment Authorities (Fédération Nationale des Collectivités
Concédantes et Régies – FNCCR) and approved by the
The EDF group records public/private agreements public authorities.
in compliance with standards and interpretations
IAS 16, IAS 17, IAS 18, IAS 37, IFRS 6 and IFRIC Recognition of assets as property, plant
4 as appropriate to the specific features of those and equipment operated under French
agreements. IFRIC 12, “Service concession public electricity distribution concessions
arrangements” was adopted by the European Union
on March 25, 2009 and has been applied by the EDF All assets used by EDF in public electricity distribution
group since January 1, 2010. This interpretation has a concessions in France, whether they are owned by the
limited impact on the consolidated balance sheet and grantor or the operator, are reported together under a
income statement in view of the features of the Group’s specific line in the balance sheet assets at acquisition
concession agreements. For most of its concessions, cost or their estimated value at the transfer date when
the Group considers that in substance the grantors supplied by the grantor.
do not have the characteristic features of control over
infrastructures as defined in IFRIC 12. 1.3.14.2.2 Hydropower concessions

Hydropower concessions in France follow standard

rules approved by decree. Assets attributed to the
hydropower concessions comprise hydropower
generation equipment (dams, pipes, turbines, etc.) and,
in the case of recently-renewed concessions, electricity
generation and switching facilities. Assets used in

62 Financial reporting in the power and utilities industry

these concessions are recorded under “Property, plant Nuclear fuel purchased is consumed in the process
and equipment operated under concessions for other of producing electricity over a number of years. The
activities” at acquisition cost. As a result of changes consumption of this nuclear fuel inventory is recorded
in the regulations following removal of the outgoing based on estimates of the quantity of electricity
operator’s preferential right when a concession is produced per unit of fuel.”
renewed, the Group has shortened the depreciation

Appendix A – Financial statement disclosure examples

periods used for certain assets. Électricité de France SA (31 December
2010, page 28)
1.3.14.2.3 French public
transmission concession “Inventory accounts include:
• nuclear materials, whatever their form during the
The assets operated under this concession belong by fuel production cycle;
law to RTE. At December 31, 2009, they were recorded • fuel components in the warehouse or in the reactor.
under “Property, plant and equipment operated under
concessions for other activities”. Following a change in The stated value of nuclear fuel and materials and
the consolidation method for RTE, which is accounted work-in-progress is determined based on direct
for under the equity method from December 31, 2010, processing costs including materials, labor and
these assets are now included in RTE’s equity value in subcontracted services (e.g., fluoration, enrichment,
the consolidated balance sheet for 2010.” production, etc.).

Nuclear Fuel In accordance with regulatory obligations, inventories

of fuel components (new or not entirely consumed)
IBERDROLA SA (31 December 2010, may also comprise expenses for spent fuel management
page 41) and long-term radioactive waste management, with
corresponding provisions or debts in the liabilities, or
“The IBERDROLA Group measures its nuclear fuel full and final payments made when the fuel is loaded.
stocks on the basis of the costs actually incurred
in acquiring and subsequently processing the fuel. Interest expenses incurred in financing inventories of
Nuclear fuel costs include the finance charges accrued nuclear fuels are charged to expenses for the period.
during construction, calculated as indicated in Note
4.g. The amounts capitalised in this connection in 2010 Nuclear fuel consumption is determined as a proportion
and 2009 were EUR 681 thousand and EUR 1,377 of the expected output when the fuel is loaded in
thousand, respectively (Notes 14 and 37). The nuclear the reactor. These quantities are valued at weighted-
fuel consumed is recognised under “Procurements” in average cost of inventories. Inventories are periodically
the Consolidated Income Statement from when the fuel corrected in view of forecast burnt quantities based on
loaded into the reactor starts to be used, based on the neutronic measurements and physical inventories.”
cost of the fuel in each reporting period. The nuclear
fuel stocks consumed in 2010 and 2009 amounted to Financial Instruments
EUR 108,793 thousand and EUR 82,415 thousand,
respectively (Notes 14 and 32).” Centrica plc (31 December 2010,
pages 78 to 79)
GDF SUEZ SA (31 December 2010,
page 303) “Financial Instruments

“Inventories are measured at the lower of cost and net Financial assets and financial liabilities are recognised
realizable value. Net realizable value corresponds to in the Group Balance Sheet when the Group becomes
the estimated selling price in the ordinary course of a party to the contractual provisions of the instrument.
business, less the estimated costs of completion and the Financial assets are de-recognised when the Group
estimated costs necessary to make the sale. no longer has the rights to cash flows, the risks and
rewards of ownership or control of the asset. Financial
The cost of inventories is determined based on the liabilities are de-recognised when the obligation under
first-in, first-out method or the weighted-average the liability is discharged, cancelled or expires.
cost formula.

Financial reporting in the power and utilities industry 63

 (a) Trade receivables attributable transaction costs. After initial recognition,
interest-bearing loans and other borrowings are
Trade receivables are recognised and carried at original subsequently measured at amortised cost using the
invoice amount less an allowance for any uncollectible effective interest method, except when they are
amounts. Provision is made when there is objective the hedged item in an effective fair value hedge
evidence that the Group may not be able to collect relationship, where the carrying value is also adjusted
the trade receivable. Balances are written off when to reflect the fair value movements associated with
recoverability is assessed as being remote. If collection the hedged risks. Such fair value movements are
is due in one year or less they are classified as current recognised in the Income Statement. Amortised cost
assets. If not they are presented as non-current assets. is calculated by taking into account any issue costs,
discount or premium.
(b) Trade payables
(f) Available-for-sale financial assets
Trade payables are recognised at original invoice
amount. If payment is due within one year or less Available-for-sale financial assets are those non-
they are classified as current liabilities. If not, they are derivative financial assets that are designated as
presented as non-current liabilities. available-for-sale, which are recognised initially at
fair value within the Balance Sheet. Available-for- sale
(c) Share capital financial assets are re-measured subsequently at fair
value with gains and losses arising from changes in fair
Ordinary shares are classified as equity. Incremental value recognized directly in equity and presented in the
costs directly attributable to the issue of new shares Statement of Comprehensive Income, until the asset is
are shown in equity as a deduction from the proceeds disposed of or is determined to be impaired, at which
received. Own equity instruments that are reacquired time the cumulative gain or loss previously recognised
(treasury shares) are deducted from equity. No gain in equity is included in the Income Statement for
or loss is recognised in the Income Statement on the the period. Accrued interest or dividends arising on
purchase, sale, issue or cancellation of the Group’s own available-for-sale financial assets are recognised in the
equity instruments. Income Statement.

(d) Cash and cash equivalents At each balance sheet date the Group assesses whether
there is objective evidence that available-for-sale
Cash and cash equivalents comprise cash in hand and financial assets are impaired. If any such evidence
current balances with banks and similar institutions, exists, cumulative losses recognized in equity are
which are readily convertible to known amounts of removed from equity and recognised in profit and loss.
cash and which are subject to insignificant risk of The cumulative loss removed from equity represents
changes in value and have an original maturity of three the difference between the acquisition cost and current
months or less. fair value, less any impairment loss on that financial
asset previously recognised in profit or loss.
For the purpose of the Group Cash Flow Statement,
cash and cash equivalents consist of cash and cash Impairment losses recognised in the Income Statement
equivalents as defined above, net of outstanding for equity investments classified as available-for-sale
bank overdrafts. are not subsequently reversed through the Income
Statement. Impairment losses recognised in the Income
(e) Interest-bearing loans and other Statement for debt instruments classified as available-
borrowings for-sale are subsequently reversed if an increase in the
fair value of the instrument can be objectively related
All interest-bearing loans and other borrowings to an event occurring after the recognition of the
are initially recognised at fair value net of directly impairment loss.

64 Financial reporting in the power and utilities industry

(g) Financial assets at fair value through of an underlying exposure of the Group in line with the
profit or loss Group’s risk management policies and is in accordance
with established guidelines, which require the hedging
The Group holds investments in gilts which it relationship to be documented at its inception, ensure
designates as fair value through profit or loss in order that the derivative is highly effective in achieving its
to reduce significantly a measurement inconsistency objective, and require that its effectiveness can be

Appendix A – Financial statement disclosure examples

that would otherwise arise. Investments are measured reliably measured. The Group also holds derivatives
at fair value on initial recognition and are re-measured which are not designated as hedges and are held
to fair value in each subsequent reporting period. for trading.
Gains and losses arising from changes in fair value are
recognised in the Income Statement within interest All derivatives are recognised at fair value on the
income or interest expense. date on which the derivative is entered into and are
re-measured to fair value at each reporting date.
(h) Derivative financial instruments Derivatives are carried as assets when the fair value
is positive and as liabilities when the fair value is
The Group routinely enters into sale and purchase negative. Derivative assets and derivative liabilities
transactions for physical delivery of gas, power and are offset and presented on a net basis only when both
oil. A number of these transactions take the form a legal right of set-off exists and the intention to net
of contracts that were entered into and continue to settle the derivative contracts is present.
be held for the purpose of receipt or delivery of the
physical commodity in accordance with the Group’s The Group enters into certain energy derivative
expected sale, purchase or usage requirements, and are contracts covering periods for which observable market
not within the scope of IAS 39. data does not exist. The fair value of such derivatives
is estimated by reference in part to published price
Certain purchase and sales contracts for the physical quotations from active markets, to the extent that such
delivery of gas, power and oil are within the scope of observable market data exists, and in part by using
IAS 39 due to the fact that they net settle or contain valuation techniques, whose inputs include data which
written options. Such contracts are accounted for as is not based on or derived from observable markets.
derivatives under IAS 39 and are recognised in the Where the fair value at initial recognition for such
Balance Sheet at fair value. Gains and losses arising contracts differs from the transaction price, a fair value
from changes in fair value on derivatives that do not gain or fair value loss will arise. This is referred to as
qualify for hedge accounting are taken directly to the a day-one gain or day-one loss. Such gains and losses
Income Statement for the year. are deferred and amortised to the Income Statement
based on volumes purchased or delivered over the
The Group uses a range of derivatives for both trading contractual period until such time observable market
and to hedge exposures to financial risks, such as data becomes available. When observable market data
interest rate, foreign exchange and energy price risks, becomes available, any remaining deferred day-one
arising in the normal course of business. The use of gains or losses are recognised within the Income
derivative financial instruments is governed by the Statement. Recognition of the gains or losses resulting
Group’s policies approved by the Board of Directors. from changes in fair value depends on the purpose for
Further detail on the Group’s risk management issuing or holding the derivative. For derivatives that
policies is included within the Directors’ Report – do not qualify for hedge accounting, any gains or losses
Governance on pages 46 to 48 and in note 4 to the arising from changes in fair value are taken directly
Financial Statements. to the Income Statement and are included within
gross profit or interest income and interest expense.
The accounting treatment for derivatives is dependent Gains and losses arising on derivatives entered into for
on whether they are entered into for trading or hedging speculative energy trading purposes are presented on a
purposes. A derivative instrument is considered to be net basis within revenue.
used for hedging purposes when it alters the risk profile

Financial reporting in the power and utilities industry 65

 Embedded derivatives: Derivatives embedded in is recognized in the Income Statement. The gains
other financial instruments or other host contracts are or losses that are recognized directly in equity are
treated as separate derivatives when their risks and transferred to the Income Statement in the same period
characteristics are not closely related to those of the in which the highly probable forecast transaction
host contracts and the host contracts are not carried at affects income, for example when the future sale of
fair value, with gains or losses reported in the Income physical gas or physical power actually occurs. Where
Statement. The closely-related nature of embedded the hedged item is the cost of a non-financial asset or
derivatives is reassessed when there is a change in the liability, the amounts taken to equity are transferred to
terms of the contract which significantly modifies the the initial carrying amount of the non-financial asset
future cash flows under the contract. Where a contract or liability on its recognition. Hedge accounting is
contains one or more embedded derivatives, and discontinued when the hedging instrument expires or
providing that the embedded derivative significantly is sold, terminated or exercised without replacement or
modifies the cash flows under the contract, the option rollover, no longer qualifies for hedge accounting or the
to fair value the entire contract may be taken and the Group revokes the designation.
contract will be recognised at fair value with changes in
fair value recognised in the Income Statement. At that point in time, any cumulative gain or loss on
the hedging instrument recognised in equity remains
(i) Hedge accounting in equity until the highly probable forecast transaction
occurs. If the transaction is no longer expected to occur,
For the purposes of hedge accounting, hedges are the cumulative gain or loss recognised in equity is
classified either as fair value hedges, cash flow hedges recognised in the Income Statement.
or hedges of net investments in foreign operations.
Net investment hedges: Hedges of net investments in
Fair value hedges: A derivative is classified as a fair foreign operations are accounted for similarly to cash
value hedge when it hedges the exposure to changes flow hedges. Any gain or loss on the effective portion
in the fair value of a recognised asset or liability. Any of the hedge is recognised in equity, any gain or loss
gain or loss from re-measuring the hedging instrument on the ineffective portion of the hedge is recognized
to fair value is recognised immediately in the Income in the Income Statement. On disposal of the foreign
Statement. Any gain or loss on the hedged item operation, the cumulative value of any gains or losses
attributable to the hedged risk is adjusted against the recognised directly in equity is transferred to the
carrying amount of the hedged item and recognised Income Statement.”
in the Income Statement. The Group discontinues fair
value hedge accounting if the hedging instrument Huaneng Power International Inc.
expires or is sold, terminated or exercised, the hedge (31 December 2010, pages 134 to 138)
no longer qualifies for hedge accounting or the Group
revokes the designation. Any adjustment to the “FINANCIAL, CAPITAL AND
carrying amount of a hedged financial instrument for
which the effective interest method is used is amortised
INSURANCE RISKS MANAGEMENT
to the Income Statement. Amortisation may begin as
soon as an adjustment exists and shall begin no later
(a) Financial risk management
than when the hedged item ceases to be adjusted
Risk management, including the management on the
for changes in its fair value attributable to the risk
financial risks, is carried out under the instructions
being hedged.
of the Strategic Committee of Board of Directors and
the Risk Management Team. The Company works out
Cash flow hedges: A derivative is classified as a cash
general principles for overall management as well
flow hedge when it hedges exposure to variability in
as management policies covering specific areas. In
cash flows that is attributable to a particular risk either
considering the importance of risks, the Company
associated with a recognized asset, liability or a highly
identifies and evaluates risks at head office and
probable forecast transaction. The portion of the gain
individual power plant level, and requires analysis
or loss on the hedging instrument which is effective is
and proper communication for the information
recognised directly in equity while any ineffectiveness
collected periodically.

66 Financial reporting in the power and utilities industry

SinoSing Power and its subsidiaries are subject to SinoSing Power and its subsidiaries also exposed
financial risks that are different from the entities to foreign exchange risk on fuel purchases that is
operating within the PRC. They have a series of denominated primarily in US$. They use forward
controls in place to maintain the cost of risks occurring exchange contracts to hedge almost all of its estimated
and the cost of managing the risks at an acceptable foreign exchange exposure in respect of forecast
level. Management continually monitors the risk fuel purchases over the following three months. The

Appendix A – Financial statement disclosure examples

management process to ensure that an appropriate Company and its subsidiaries classify its forward
balance between risk and control is achieved. SinoSing foreign currency contracts as cash flow hedges. Please
Power and its subsidiaries have their written policies refer to Note 13 for details.
and financial authorization limits in place they are
reviewed periodically. These financial authorization (2) Price risk
limits seek to mitigate and eliminate operational risks
by setting approval thresholds required for entering The available-for-sale financial assets of the Company
into contractual obligations and investments. and its subsidiaries are exposed to equity security price
risk. The exposure of such a risk is presented on the
(i) Market risk balance sheets.

(1) Foreign exchange risk Detailed information relating to the available-for-

sale financial assets are disclosed in Note 10. Being
Foreign exchange risk of the entities operating within a strategic investment in nature, the Company has a
the PRC primarily arises from loans denominated in supervisor in the supervisory committee of the investee
foreign currencies of the Company and its subsidiaries. and exercises influence in safeguarding the interest.
SinoSing Power and its subsidiaries are exposed to The Company also closely monitors the pricing trends
foreign exchange risk on accounts payable and other in the open market in determining their long-term
payables that are denominated primarily in US$, a strategic stakeholding decisions.
currency other than Singapore dollar (“S$”), their
functional currency. Please refer to Notes 22 and 25 The Company and its subsidiaries exposed to fuel price
for details. The Company and its subsidiaries manage risk on fuel purchases. In particular, SinoSing Power
exchange risk through closely monitoring interest and and its subsidiaries use fuel oil swap to hedge against
exchange market. such a risk and designate them as cash flow hedges.
Please refer to Note 13 for details.
As at 31 December 2010, if RMB had weakened/
strengthened by 5% (2009: 5%) against US$ and (3) Cash flow interest rate risk
3% (2009: 3%) against € with all other variables
constant, exchange gain of the Company and its The interest rate risk of the Company and its
subsidiaries would have been RMB312 million (2009: subsidiaries primarily arises from long-term loans.
RMB357 million) and RMB25 million (2009: RMB31 Loans borrowed at variable rates expose the Company
million) lower/higher, respectively. The ranges of and its subsidiaries to cash flow interest rate risk. The
such sensitivity disclosed above were based on the exposures of these risks are disclosed in Note 22 to the
observation on the historical trend of related exchange financial statements. The Company and its subsidiaries
rates during the previous year under analysis. have entered into interest rate swap agreements with
banks to hedge against a portion of cash flow interest
As at 31 December 2010, if S$ had weakened/ rate risk.
strengthened by 10% (2009: 10%) against US$
with all other variables constant, exchange gain of As at 31 December 2010, if interest rates on RMB-
the Company and its subsidiaries would have been denominated borrowings had been 50 basis points
RMB121 million (2009: RMB93 million) lower/higher, (2009: 50 basis points) higher/lower with all
respectively. The ranges of such sensitivity disclosed other variables held constant, interest expense
above were based on the management’s experience for the year would have been RMB334 million
and forecast.

Financial reporting in the power and utilities industry 67

 (2009: RMB339 million) higher/lower. If interest Most of the power plants of the Company and its
rates on US$-denominated borrowings had been 50 subsidiaries operating within PRC sell electricity
basis points (2009: 50 basis points) higher/lower with generated to their sole customers, the power grid
all other variables held constant, interest expense companies of their respective provinces or regions
for the year would have been RMB14 million (2009: where the power plants operate. These power plants
RMB14 million) higher/lower. If interest rates on S$- communicate with their individual grid companies
denominated borrowings had been 100 basis points periodically and believe that adequate provision
(2009: 100 basis points) higher/lower with all other for doubtful accounts have been made in the
variables held constant, interest expense for the year financial statements.
would have been RMB89 million (2009: RMB150
million) higher/lower. The ranges of such sensitivity Singapore subsidiaries derive revenue mainly from
disclosed above were based on the observation on the sale of electricity to the National Electricity Market
historical trend of related interest rates during the of Singapore operated by Energy Market Company
previous year under analysis. Pte Ltd., which is not expected to have high credit
risk. They also derive revenue mainly from retailing
The Company has entered into a floating-to-fixed electricity to consumers with monthly consumption
interest rate swap agreement to hedge against cash of more than 10,000kWh. These customers engage in
flow interest rate risk of a loan. According to the a wide spectrum of manufacturing and commercial
interest rate swap agreement, the Company agrees activities in a variety of industries. They hold cash
with the counterparty to settle the difference between deposits and guarantees from creditworthy financial
fixed contract rates and floating-rate interest amounts institutions to secure substantial obligations of
calculated by reference to the agreed notional amounts the customers.
quarterly until 2019. In the current year, Tuas Power
Generation Pte Ltd. (“TPG”) also entered into a number The concentrations of accounts receivable are disclosed
of floating-to- fixed interest rate swap agreements to in Note 5.
hedge against cash flow interest rate risk of a loan.
According to these interest rate swap agreements, TPG Regarding balances with subsidiaries, the Company
agrees with the counterparty to settle the difference and its subsidiaries can obtain the financial statements
between fixed contract rates and floating-rate interest of all subsidiaries and assess the financial performance
amounts calculated by reference to the agreed notional and cash flows of those subsidiaries periodically to
amount semi-annually until 2020. Please refer to manage the credit risk of loans.
Note13 for details.
(iii) Liquidity risk
(ii) Credit risk
Liquidity risk management is to primarily ensure the
Credit risk arises from bank deposits, credit exposures ability of the Company and its subsidiaries to meet its
to customers, other receivables, other non-current liabilities as and when they are fall due. The liquidity
assets and loans to subsidiaries. The maximum reserve comprises the undrawn borrowing facility and
exposures of bank deposits, accounts and other cash and cash equivalents available as at each month
receivables are disclosed in Notes 33, 18, 17 and 15 to end in meeting its liabilities.
the financial statements, respectively while maximum
exposures of loans to subsidiaries are presented on The Company and its subsidiaries maintained flexibility
balance sheets. in funding by cash generated by their operating
activities and availability of committed credit facilities.
Bank deposits are placed with reputable banks and
financial institutions, including which a significant Financial liabilities due within 12 months are
portion is deposited with a non-bank financial presented as the current liabilities in the balance
institution which is a related party of the Company. sheets. The repayment schedules of the long-term
The Company has a director in the Board of this non- loans and long-term bonds and cash flows of derivative
bank financial institution and exercises influence. financial liabilities are disclosed in Notes 22, 23 and
Corresponding maximum exposures of these 13, respectively.”
bank deposits are disclosed in Note 34(a)(i) to the
financial statements.

68 Financial reporting in the power and utilities industry

Appendix B –
IFRS/US GAAP differences
This section summarises the differences between IFRS
and US GAAP that are particularly relevant to utility
entities. These differences relate to: depreciation,
decommissioning obligations, impairment, regulatory
assets and financial instruments.

Appendix B – IFRS/US GAAP differences

Property, plant and equipment –
components

Issue IFRS US GAAP

Components of property, plant and Follows a component approach Does not require the component
equipment to depreciation. Significant parts approach to depreciation; however,
(components) of an item of it is sometimes followed as a matter
property, plant and equipment are of industry practice. The use of
depreciated separately if they have composite (group) depreciation is
different useful lives. also commonly used.

Financial reporting in the power and utilities industry 69

 Property, plant and equipment –
decommissioning obligations
Issue IFRS US GAAP

Measurement of liability A decommissioning liability is A decommissioning liability

measured initially at the best (asset retirement obligation) is
estimate of the expenditure recorded initially at fair value
required to settle the obligation. if a reasonable estimate of fair
value can be made. An expected
Risks associated with the liability present value technique based on
are reflected in the cash flows or in expected cash flows to perform
the discount rate. the decommissioning activities
is usually the only appropriate
The decommissioning liability is technique to apply.
remeasured each reporting period
by updating the discount rate. Risks associated with the
performance of the activities are
The fact that an asset to be reflected in the cash flows. Credit
decommissioned has an risk is reflected in the discount rate.
indeterminate life does not
remove the need to measure the An asset retirement obligation is
decommissioning obligation, but remeasured if and when there is a
the effect of discounting will have a change in the amount or timing of
greater impact on the measurement cash flows.
of the liability. • Downward revisions to
undiscounted cash flows are
discounted using the credit-
adjusted, risk-free rate used
when the liability was originally
recognised.
• Upward revisions to
undiscounted cash flows are
discounted using the credit-
adjusted, risk-free rate at the
time of the revision.

A decommissioning liability does

not need to be recognised for assets
with indeterminate lives if there is
insufficient information available to
estimate fair value.

Recognition of The adjustment to property, The adjustment to property, plant

decommissioning asset plant and equipment associated and equipment associated with
with the decommissioning the decommissioning liability
liability forms part of the asset to is recognised by increasing the
be decommissioned. carrying value of the asset to
be decommissioned. The asset
retirement cost can be subsumed
as part of the overall asset or
can be tracked as a separate unit
of account.

70 Financial reporting in the power and utilities industry

Property, plant and equipment –
impairment
Issue IFRS US GAAP

Impairment test triggers Assets or groups of assets (cash Long-lived assets are tested for

Appendix B – IFRS/US GAAP differences

generating units) are tested for impairment when events or
impairment when indicators of circumstances indicate the carrying
impairment are present. value may not be recoverable. The
carrying value is not recoverable
if it exceeds the sum of the
undiscounted cash flows based on
the entity’s planned use.

Measurement of Impairment is measured as the Impairment is measured as the

impairment excess of the asset’s carrying excess of the asset’s carrying
amount over its recoverable amount over its fair value. Fair
amount. The recoverable amount value is defined as the price that
is the higher of its value in use and would be received to sell the
fair value less costs to sell. Value in asset in an orderly transaction
use represents the future cash flows between market participants at the
discounted to present value by measurement date.
using a pre-tax, market-determined
rate that reflects the current
assessment of the time value of
money and the risks specific to
the asset for which the cash flow
estimates have not been adjusted.
Fair value less cost to sell represents
the amount obtainable from the
sale of an asset or CGU in an
arm’s length transaction between
knowledgeable, willing parties less
the costs of disposal.

Reversal of impairment charge If certain criteria are met, the The reversal of impairments
reversal of impairments, other is prohibited.
than those relating to goodwill,
is permitted.

Financial reporting in the power and utilities industry 71

 Arrangements that may
contain a lease
Issue IFRS US GAAP

Retrospective application Arrangements that convey the Similar to IFRS, except that the US
right to use an asset in return for GAAP guidance, EITF 01-8 (codified
a payment or series of payments into ASC 840), was applicable
are required to be accounted for as only to new arrangements entered
leases if certain conditions are met. into (or modifications made to
This requirement applies even if existing arrangements) after the
the contract does not take the legal effective date (i.e., grandfathering
form of a lease. of existing arrangements
was provided).
The IFRS guidance that requires
this analysis, IFRIC 4, requires
all existing arrangements to
be analysed on adoption (i.e.,
no grandfathering of existing
arrangements).

Regulatory assets and liabilities

Issue IFRS US GAAP

Regulatory assets and liabilities IFRS does not contain specific US GAAP (ASC 980) contains
guidance for the recognition of guidance for the recognition of
regulatory assets and liabilities. regulatory assets and liabilities
Assets and liabilities arising from in appropriate circumstances,
rate-regulated activities that meet by regulated entities that
the definition of an asset or liability meet specified requirements
pursuant to existing IFRSs or under for recognition.
the conceptual framework should
be recognised.

72 Financial reporting in the power and utilities industry

Business combinations

Issue IFRS US GAAP

Fair values on acquisition IFRS and US GAAP are largely Fair value is defined as the price

Appendix B – IFRS/US GAAP differences

converged. Most acquired assets that would be received to sell an
and liabilities are generally required asset or paid to transfer a liability
to be recorded at fair value upon in an orderly transaction between
acquisition, with some detailed market participants as of the
differences from US GAAP. measurement date.
Fair value is the amount for which
an asset could be exchanged
or a liability settled between
knowledgeable, willing parties in an
arm’s length transaction. IFRS does
not specifically refer to either an
entry or exit price (when IFRS 13
is effective, the fair value definition
will be converged with US GAAP).

Contingent consideration Contingent consideration is Contingent consideration is

recognised initially at fair value recognised initially at fair value as
as either an asset, liability or either an asset, liability or equity
equity according to the applicable according to the applicable US
IFRS guidance. GAAP guidance.

Non-controlling interests Entities have an option, on a Non-controlling interests are

transaction-by-transaction basis, measured at fair value. No gains or
to measure non-controlling losses are recognised in earnings
interests at their proportion of for transactions between the parent
the fair value of the identifiable company and the non-controlling
net assets or at full fair value. This interests, unless control is lost.
option applies only to instruments
that represent present ownership
interests and entitle their holders
to a proportionate share of the net
assets in the event of liquidation.
No gains or losses are recognised in
earnings for transactions between
the parent company and the non-
controlling interests, unless control
is lost.

Goodwill Goodwill is allocated to a CGU or Goodwill impairment testing

group of CGUs, as defined within is performed using a two-step
the guidance. Goodwill impairment approach to impairment. The
testing is performed under a one- first step comprises determining
step approach: the recoverable whether the reporting unit is
amount of the CGU or group of impaired; the second step is the
CGUs is compared with its carrying measurement of the impairment.
amount. Any impairment amount
is recognised in operating results as
the excess of the carrying amount
over the recoverable amount.

Financial reporting in the power and utilities industry 73

 Concession arrangements

Issue IFRS US GAAP

Identification and classification of Public-to-private service concession No equivalent guidance

concession arrangements arrangements that meet certain specifically addressing
conditions must be analysed to concession arrangements.
determine whether the concession
represents a financial asset or an
intangible asset.

Financial instruments and

trading and risk management
IFRS and US GAAP take broadly consistent approaches
to the accounting for financial instruments; however,
there are many detailed differences. IFRS and US
GAAP define financial assets and financial liabilities in
similar ways.

Selected differences between

IFRS and US GAAP are
summarised below.

Issue IFRS US GAAP

Definition of a derivative A derivative is a financial A derivative instrument:

instrument that: • Includes an underlying and a
• Changes value in response to a notional amount
specified variable or underlying • Requires no or little
rate (e.g., commodity index or net investment
interest rate) • Requires or permits net
• Requires no or little settlement (either within the
net investment contract, through a market
• Is settled at a future date mechanism, or delivery of
asset that is readily convertible
to cash)

Because of differences in the

definition, some contracts, either in
their entirety or partially, contain
derivatives under IFRS but not
US GAAP.

74 Financial reporting in the power and utilities industry

Financial instruments and trading
and risk management
Issue IFRS US GAAP

Separation of embedded derivatives Derivatives embedded in hybrid The separation of embedded

Appendix B – IFRS/US GAAP differences

contracts are separated when: derivatives is similar to IFRS,
• The economic characteristics although there are some detailed
and risks of the embedded differences in evaluating whether
derivatives are not closely the embedded derivative is “clearly
related to the economic and closely related”. The clearly
characteristics and risks of the and closely related is a one-
host contract time evaluation.
• A separate instrument with the
same terms as the embedded If a hybrid instrument contains an
derivative would meet the embedded derivative that is not
definition of a derivative clearly and closely related to the
• The hybrid instrument is not host contract at inception, but is
measured at fair value through not required to be bifurcated (e.g.,
profit or loss it does not meet the definition
of a derivative on a standalone
Reassessment of whether an basis), the embedded derivative
embedded derivative needs to be is continually reassessed to
separated is permitted only when determine if it subsequently meets
there is a change in the terms of the the definition of a derivative and
contract that significantly modifies bifurcation is required.
the cash flows that would otherwise
be required under the contract.

A host contract from which an

embedded derivative has been
separated qualifies for the own use
exemption if the own use criteria
are met for the host.

Financial reporting in the power and utilities industry 75

 Financial instruments and
trading and risk management
Issue IFRS US GAAP

Own use exemption compared to Contracts to buy or sell a non- Contracts that qualify and are
normal purchase and normal sale financial item that can be settled designated as normal purchases
exemption net in cash or another financial and normal sales are not accounted
instrument are accounted for for as derivatives. The conditions
as financial instruments, unless under which the normal purchase
the contract was entered into and normal sales exemption is
and continues to be held for the available are similar to the own use
purpose of the physical receipt exemption under IFRS, although
or delivery of the non-financial there are some detailed differences.
item in accordance with the
entity’s expected purchase, sale or Application of the normal
usage requirements. purchases and normal sales
exemption must be elected by the
Application of the own use entity in order to be applied.
exemption is a requirement, not
an election. If there is a pricing provision in
the contract that is not clearly and
closely related to the underlying
item being delivered, the contract
does not qualify for the exemption.

Transaction costs Transaction costs that are directly Transaction costs are specifically
attributable to the acquisition or excluded from a fair value
issuance of a financial asset or measurement.
financial liability are added to its
fair value on initial recognition,
unless the asset or liability is
measured subsequently at fair
value with changes in fair value
recognised in profit or loss.

76 Financial reporting in the power and utilities industry

Financial instruments and
trading and risk management
Issue IFRS US GAAP

Subsequent measurement Subsequent measurement depends The general classes of financial

Appendix B – IFRS/US GAAP differences

on the classification of the financial asset and financial liability are used
asset or financial liability. under both IFRS and US GAAP, but
the classification criteria differ in
Certain classes of financial asset certain respects.
or financial liability are measured
subsequently at amortised cost The issuance of IFRS 9 (see Chapter
using the effective-interest method 3, Future developments – Standards
and others, including derivative issued and not yet effective) has
financial instruments, at fair value resulted in further differences
through profit or loss. between the accounting for
financial instruments between IFRS
The available-for-sale (AFS) and US GAAP.
class of financial assets is
measured subsequently at fair
value through equity (other
comprehensive income).

These general classes of financial

asset and financial liability are used
under both IFRS and US GAAP,
but the classification criteria differ
in certain respects. The issuance
of IFRS 9 (see Chapter 3, Future
developments – Standards issued
and not yet effective) has resulted
in further differences between
the accounting for financial
instruments between IFRS and
US GAAP.

Offsetting contracts A practice of entering into Similar to IFRS, except that power
offsetting contracts to buy and sell purchase or sales agreements that
a commodity is considered to be meet the definition of a capacity
a practice of net settlement. All contract qualify to be treated as
similar contracts must be accounted normal purchases and normal sales,
for as derivatives. provided certain criteria are met.

Financial reporting in the power and utilities industry 77

 Acknowledgements

Authors Review Panel

Ralph Welter Mary Dolson
Telephone: +49 201 438 1367 Telephone: +44 20 7804 2930
Email: ralph.welter@de.pwc.com Email: mary.dolson@uk.pwc.com

Folker Trepte Heather Horn

Telephone: +49 89 5790 5530 Telephone: +1 213 830 8302
Email: folker.trepte@de.pwc.com Email: heather.horn@us.pwc.com

Christine Hilka Michael Timar

Telephone: +49 89 5790 5539 Telephone: +44 141 355 4180
Email: christine.hilka@de.pwc.com Email: michael.timar@uk.pwc.com

Andrea Allocco Jan Backhuijs

Telephone: +44 20 7212 3722 Telephone: +31 88 792 52 72
Email: a.allocco@uk.pwc.com Email: jan.backhuijs@nl.pwc.com

Aissata Touré Michael Reuther

Telephone: +49 211 981 4941 Telephone: +49 211 981 7441
Email: aissata.toure@de.pwc.com Email: michael.reuther@de.pwc.com

Mia DeMontigny
Telephone: +1 973 236 4012
Email: mia.l.demontigny@us.pwc.com

78 Financial reporting in the power and utilities industry

Contact us

Global contacts Territory contacts

Contact us
Manfred Wiegand
Global Power & Utilities Leader Asia-Pacific
Telephone: +49 201 438 1509
Email: manfred.wiegand@de.pwc.com Australia
Michael Happell
Norbert Schwieters Telephone: +61 3 8603 6016
Global Power & Utilities IFRS Group Email: michael.happell@au.pwc.com
Telephone: +49 211 981 2153
Email: norbert.schwieters@de.pwc.com Michael Shewan
Telephone : +613 8603 6446
Email: michael.shewan@au.pwc.com

China
Gavin Chui
Telephone: +86 10 6533 2188
Email: gavin.chui@cn.pwc.com

India
Kameswara Rao
Telephone: +91 40 6624 6688
Email: kameswara.rao@in.pwc.com

Indonesia
William Deertz
Telephone: +62 21 5289 1030
Email: william.deertz@id.pwc.com

Japan
Koji Hara
Telephone : +81 90 1618 5601
Email: koji.hara@jp.pwc.com

Financial reporting in the power and utilities industry 79

 Europe Germany
Norbert Schwieters
Austria Telephone: +49 211 981 2153
Gerhard Prachner Email: norbert.schwieters@de.pwc.com
Telephone: +43 1 501 88 1800
Email: gerhard.prachner@at.pwc.com Greece
Socrates Leptos-Bourgi
Belgium Telephone: +30 210 687 4630
Bernard Gabriels Email: socrates.leptos.-.bourgi@gr.pwc.com
Telephone: +32 3 259 3304
Email: bernard.gabriels@be.pwc.com Ireland
Ann O’Connell
Denmark Telephone: +353 1 792 8512
Per Timmermann Email: ann.oconnell@ir.pwc.com
Telephone: + 45 39 45 91 45
Email: per.timmermann@dk.pwc.com Italy
Giovanni Poggio
Finland Telephone: +39 06 570252588
Mauri Hätönen Email: giovanni.poggio@it.pwc.com
Telephone: + 358 9 2280 1946
Email: mauri.hatonen@fi.pwc.com Netherlands
Jeroen van Hoof
France Telephone: +31 88 792 1328
Philippe Girault Email: jeroen.van.hoof@nl.pwc.com
Telephone: +33 1 5657 8897
Email: philippe.girault@fr.pwc.com Norway
Ståle Johansen
Telephone: +47 9526 0476
Email: staale.johansen@no.pwc.com

80 Financial reporting in the power and utilities industry

Portugal Middle East and Africa

Contact us
Luis Ferreira
Telephone: +351 213 599 296 Middle East
Email: luis.s.ferreira@pt.pwc.com Paul Navratil
Telephone: +971 2 694 6956
Russia & Central and Eastern Europe Email: paul.navratil@ae.pwc.com
Michael O’Riordan
Telephone: +7 495 232 5774 Southern Africa
Email: michael.oriordan@ru.pwc.com Stanley Subramoney
Telephone: +27 11 797 4380
Spain Email: stanley.subramoney@za.pwc.com
Iñaki Goiriena Basualdu
Telephone: +34 915 684469 Sub-Saharan Africa
Email: inaki.goiriena@es.pwc.com Vishal Agarwal
Telephone: +254 20 285 5581
Sweden Email: vishal.agarwal@ke.pwc.com
Martin Gavelius
Telephone: +46 8 555 33529
Email: martin.gavelius@se.pwc.com

Switzerland
Marc Schmidli
Telephone: +41 58 792 15 64
Email: marc.schmidli@ch.pwc.com

United Kingdom
Ross Hunter
Telephone: +44 20 7804 4326
Email: ross.hunter@uk.pwc.com

Steven Jennings
Telephone: +44 207 212 1449
Email: steven.m.jennings@uk.pwc.com

Financial reporting in the power and utilities industry 81

 The Americas Further information
Argentina Olesya Hatop
Jorge Bacher Global Energy, Utilities & Mining Marketing
Telephone: +54 11 5811 6952 Telephone: +49 201 438 1431
Email: jorge.c.bacher@ar.pwc.com Email: olesya.hatop@de.pwc.com

Brazil
Guilherme Valle
Telephone: +55 21 3232 6011
Email: guilherme.valle@br.pwc.com

Canada
Alistair Bryden
Telephone: +1 403 509 7354
Email: alistair.e.bryden@ca.pwc.com

United States
David Etheridge
Telephone: +1 415 498 7168
Email: david.etheridge@us.pwc.com

82 Financial reporting in the power and utilities industry

83
This publication has been prepared for general guidance on matters of interest only, and does not constitute
professional advice. It does not take into account any objectives, financial situation or needs of any recipient;
any recipient should not act upon the information contained in this publication without obtaining independent
professional advice. No representation or warranty (express or implied) is given as to the accuracy or completeness
of the information contained in this publication, and, to the extent permitted by law, PricewaterhouseCoopers
LLP, its members, employees and agents do not accept or assume any liability, responsibility or duty of care for any
consequences of you or anyone else acting, or refraining to act, in reliance on the information contained in this
publication or for any decision based on it.

© 2011 PricewaterhouseCoopers. All rights reserved. PricewaterhouseCoopers refers to the network of member
firms of PricewaterhouseCoopers International Limited, each of which is a separate and independent legal entity
DH-12-0033