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Property, plant and equipment
A distinguishing and common feature in oil and gas
and utilities is the asset intensive nature of operations.
Productive assets tend to be large and complex installations.
Assets are expensive to construct, tend to be exposed
to harsh environmental or operating conditions and
require periodic replacement or repair.
Components
Large network or infrastructure assets
comprise a significant number of components, many
of which will have differing useful lives. Examples
include refineries, chemical plants, distribution
networks, etc.
The cost of the significant components of these
types of assets must be separately identified and
depreciated to their residual values over the useful
lives [IAS16R.43-44]. Identifying the significant
components can be a complex process for very large,
advanced plants .
Some components can be identified by considering
the routine shutdown/turnaround (for oil and gas)
or overhaul (for power stations) schedules and the
replacement and maintenance routines associated
with these. Consideration should also be given to
those components that are prone to technological
obsolescence, corrosion or wear and tear more severe
than that of the other portions of the larger asset
.
Those components that have a shorter useful life
than the remainder of the asset should be depreciated
to recoverable amount over that shorter useful life,
the remaining carrying amount derecognised on replacement
and the cost of the replacement part capitalised
[IAS16R.13-14]. Turnaround/overhaul costs that do
not relate to the replacement of components or the
installation of new assets should be expensed when
incurred [IAS16R.12]. Turnaround/overhaul costs
should not be accrued over the period between the
turnarounds/overhauls because there is no legal
or constructive obligation to perform the turnaround/overhaul
- the entity could choose to cease operations at
the plant and hence avoid the turnaround/overhaul
costs .
Depreciation of PPE / renewals accounting
Each item of PPE must be depreciated over its useful
life to its residual value [IAS16.43-50]. The useful
life is the period over which the entity expects
to use the asset. An asset that is scheduled to
be replaced as part of a major overhaul or turnaround
is depreciated over the period to the turnaround.
An issue faced by some entities on transition to
IFRS is the separate identification of assets and
components as described above, particularly where
the entity owns a significant network asset. Calculation
of depreciation is dependent on identifying the
cost and useful life of each asset or network component.
The calculation of a depreciation charge cannot
be avoided on the basis that a high level of maintenance
expenditure is incurred that will continuously maintain
the network's operating capacity. The practice of
assuming that the maintenance charge approximates
the depreciation charge and thus avoiding the calculation
of depreciation on an asset or component basis,
known as renewals accounting, is not acceptable
under IFRS.
Intangible
assets
Customer acquisition costs
The costs of acquisition and development of customer
relationships may be capitalised if certain conditions
are met. The costs directly attributable to concluding
a contractual agreement with a customer should be
capitalised and amortised over the life of the contract.
The customer contract acquisition costs meet the
criteria in IAS 38.25 as a separately purchased
intangible asset. Commissions or bonuses paid to
sign utility customers to contracts are capitalised
where the entity has the systems to separately record
and assess the customer contract for future economic
benefits. Management assessing the criteria in IAS
38.25 should pay particular attention to (1) the
notice period in the customer contract, (2) any
offers made to induce the customer to switch, (3)
historical levels of customer churn and (4) propensity
of a customer to switch, that is, there is evidence
that customers have changed suppliers previously.
However, expenditure relating to the general development
of the business, such as providing service in a
new location or an advertising campaign for new
customers, represents internally generated goodwill
and should not be capitalised. Such general expenditure
cannot be capitalised either because the specific
costs associated with individual customers cannot
be separately identified or because the entity does
not have sufficient control over the new relationships
for it to meet the definition of an asset. Similarly
the costs of developing a customer relationship
after a contract has been signed represents an internally
generated intangible asset whose costs cannot be
distinguished from the general costs of running
the business and serving the customer.
Customer relationships must be recognised where
they have been acquired through a business combination.
Customer-related intangibles, such as customer lists,
customer contracts and customer relationships are
recognised by the acquirer at the fair value of
the asset at the acquisition date.
Emission rights
Regulations designed to reduce the level of greenhouse
gases have been introduced in a number of countries.
Tradable emission rights arise in cap and trade
schemes. The emission rights permit an entity to
emit pollutants up to a specified level. The emission
rights are either given or sold by the government
to the emitter for a defined compliance period.
Schemes in which the emission rights are tradable
allow an entity to:
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emit less pollutants than it has allowances for and sell the excess allowances; |
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emit pollutants to the level that it holds allowances for; or |
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emit pollutants above the level that it holds allowances for and either purchase additional allowances or pay a fine. |
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IFRIC 3, "Emission Rights", was published
in December 2004 to provide guidance on how to account
for cap and trade emission schemes; however this
interpretation was withdrawn in June 2005 due to
the concerns over the consequences of the required
accounting. The guidance in IFRIC 3 remains valid
but entities are free to apply variations provided
that the requirements of all relevant IFRS standards
are met.
The allowances should be recognised as intangible
assets at cost if separately acquired. Allowances
that are received free of charge from the government
are recognised either at fair value with a corresponding
deferred income, or at cost (nil) in accordance
with the two choices available in IAS 20 Government
Grants [IAS20R.23].
The intangible assets recognised are not amortised
provided residual value is at least equal to carrying
value [IAS38R.100]. The balance recognised as deferred
income for the government grant (if initial recognition
at fair value under IAS 20 is chosen) is amortised
to the income statement on a straight line basis
over the compliance period. An alternative to the
straight line bases should be used if this can be
determined to provide a better reflection of the
consumption of the economic benefits of the government
grant.
The entity may choose to apply the revaluation
model in IAS 38 for the subsequent measurement of
the emissions allowances. The revaluation model
requires that the carrying amount of the allowances
are restated to fair value at each balance sheet
date with changes to fair value recognised directly
in equity except for impairments which are recognised
in the income statement [IAS38R.75] [IAS38R.85-86].
Emissions allowances are tested for impairment
when there are indicators of impairment. Testing
of impairment is performed in accordance with normal
IAS 36 requirements .
A provision is recognised for the obligation to
deliver allowances or pay a fine to the extent that
pollutants have been emitted. Guidance on the accounting
for the liability is included in Chapter 129 Liabilities
for energy and utilities . The allowances are offset
against the provision when they are used to satisfy
the entity's obligations through delivery to the
government at the end of the scheme year.
Impairment of energy and utility assets
Energy and utility assets should be tested for impairment
whenever indicators of impairment exist [IAS36R.9]. The exception
is for Exploration and Evaluation (E&E) assets
for which certain relief is available . The normal
measurement rules for impairment apply to energy
and utility assets with the exception of the grouping
of E&E assets with existing producing CGUs as
described in Chapter 127 Exploration and production
assets for energy and utilities .
Impairment indicators
The energy industry - oil and gas as well as power
and other utilities - is distinguished by the significant
capital investment required. The heavy investment
in fixed assets leaves the industry exposed to adverse
economic conditions and therefore impairment charges.
Some impairment triggers relevant for the petroleum
sector include declining market prices for oil and
gas, increased regulation or tax changes, deteriorating
local conditions such that it may become unsafe
to continue operations, expropriation of assets
. Utilities, particularly
power, are exposed to overcapacity, changes in the
regulatory environment, environmental legislation,
falling retail prices and rising fuel costs .
Impairment indicators can also be internal in nature.
Evidence that an asset or CGU has been damaged or
become obsolete is an impairment indicator; for
example a refinery destroyed by fire is, in accounting
terms, an impaired asset. Other indicators of impairment
are a decision to sell or restructure a CGU or evidence
that business performance is less than expected
.
Management should be alert to indicators on a CGU
basis, for example learning of a fire at an individual
petrol station would be an indicator of impairment
for that station as a separate CGU. However, generally
management is likely to identify impairment indicators
on a regional or area basis, reflective of how they
manage their business. Once an impairment indicator
has been identified, the impairment test must be
performed at the individual CGU level, even if the
indicator was identified at a regional level.
Cash generating units
A cash generating unit (CGU) is the smallest group
of assets that generates cash flows largely independent
of other assets or groups of assets [IAS36R.6].
A CGU in a petroleum upstream entity will often
be identified as a field and its supporting infrastructure
assets. Production, and therefore cash flows, can
be associated with individual wells. The field investment
decision is made based on expected field production,
not a single well, and all wells are dependent on
the field infrastructure .
Downstream, an entity may own petrol stations,
clustered in geographic areas to ease management
oversight, supply and logistics. The petrol stations,
by contrast, are not dependent on fixed infrastructure
and generate largely independent cash flows .
Power generation assets will form CGUs by location
or possibly by single generating facility on a multiple
turbine site. The determination of how many CGUs
will depend on the extent of shared infrastructure
and the ability to generate largely separate (not
wholly separate) cash flows. The determination of
CGUs is not driven by how management chooses to
use the asset. For example, an entity may have three
generating stations in a large metropolitan area.
Management makes the decision to produce based on
expected prices and demand. It uses the three stations
to meet demand in a most efficient to least efficient
basis. The three stations remain separate CGUs .
Calculation of recoverable amount
Impairments are recognised if the carrying mount
of a CGU exceeds its recoverable amount. Recoverable
amount is the higher of fair value less costs to
sell ("FVLCTS") and Value In Use ("VIU")
[IAS36R.6].
Fair value less costs to sell is the amount that
a market participant would pay for the asset or
CGU, less the costs of sale. The use of discounted
cash flows for FVLCTS is permitted where there is
no readily available market price for the asset
or where there are no recent market transactions
for the fair value to be determined through a comparison
between the asset being tested or impairment and
the recent market transaction. However, where discounted
cash flows are used, the inputs must be based on
external, market-based data.
The projected cash flows for FVLCTS therefore include
the assumptions that a potential purchaser would
include in determining the price of the asset. Thus
industry expectations for the development of the
asset may be taken into account which may not be
permitted under VIU. However the assumptions and
resulting value must be based on recent market data
and transactions.
The discount rate applied in FVLCTS will be a post-tax
market rate based on a typical industry participant's
cost of capital.
VIU is the present value of the future cash flows
expected to be derived from an asset or CGU [IAS36R.6].
Determination of VIU is subject to the strict requirements
of IAS 36. The cash flows are based on the asset
which the entity has now and must exclude any plans
to enhance the asset or its output in the future
[IAS36R.44]. Any foreign currency cash flows are
projected in the currency in which they will be
earned and discounted at a rate appropriate for
that currency. The resulting value is translated
to the entity's functional currency using the spot
rate at the date of the impairment test [IAS36R.54].
The discount rate used for VIU is always pre-tax
and applied to pre-tax cash flows [IAS36R.55]. This
is often the most difficult element of the impairment
test as pre-tax rates are not available in the market
place. Grossing up the post tax rate does not give
the correct answer unless no deferred tax is involved
as IAS 12 does not permit deferred tax to be discounted.
Arriving at the correct pre-tax rate is a complex
mathematical exercise.
Contracted cash flows in the value in use
calculation
The cash flows prepared for the value in use ("VIU")
calculation should reflect management's best estimate
of the future cash flows expected to be generated
from the assets concerned. Purchases and sales of
commodities are included in the VIU the spot price
at the date of the impairment test.
However, management should use the contracted price
in its VIU calculation for any commodities unless
the contract is already on the balance sheet at
fair value. A commodity contract that can be settled
net in cash and for which the own use exception
cannot be claimed, for example, is recognised separately
on the balance sheet at fair value. Including the
contracted prices of such a contract would be to
double count the effects of the contract. Impairment
of financial instruments that are within the scope
of IAS 39 is addressed by IAS 39 and not IAS 36
.
Working capital balances including commodity contracts
recognised at fair value are excluded from both
the carrying amount of the CGU and the cash flows
of the VIU calculation.
The cash flow effects of hedging instruments such
as caps and collars for commodity purchases and
sales are also excluded from the VIU cash flows
because such contracts are accounted for in accordance
with IAS 39.
Interaction of decommissioning provisions
and impairment calculations
The cash flows associated with the decommissioning
obligations of an asset being tested for impairment
are excluded from the VIU cash flows because the
provision for the decommissioning liability is already
recognised [IAS36R.43]. Similarly the carrying amount
of the decommissioning provision is not included
in the carrying amount of the CGU.
Including the decommissioning cash outflows with
out the carrying amount of the provision would be
inconsistent and vice versa. It is not appropriate
to include both the carrying amount and the associated
cash outflows because the measurement of value in
use and the measurement of the provision may require
different discount rates to be applied.
Determination of FVLCTS should be consistent in
the treatment of decommissioning. The FVLCTS should
be determined gross of the obligation to decommission
and compared with the carrying value of the CGU
gross of the decommissioning liability.
Assets under construction
The cash flows included in the VIU calculation should
not include any capital expenditure that is expected
to arise from improving or enhancing an asset's
performance [IAS36R.44]. This is a particular problem
when testing impairment of network assets such as
those in a distribution system. The cash flows used
in the VIU cash flow estimates should be those that
are required to maintain the network rather than
those that will result in enhanced performance of
the network. This can require the creation of an
"artificial" cash flow estimate because
the cash outflows and associated revenue cash inflows
must assume the replacement of like-for-like even
if this is not realistic given advances in technology
since the original network was constructed. The
use of fair value less cost to sell as an alternative
to VIU, when calculating recoverable amount, provides
more flexibility to include expansion cash flows.
However, assumptions used for fair value calculations
must use market-based data.
The VIU cash flows for assets that are under construction
and not yet complete should include the cash flows
necessary for their completion and the associated
additional cash inflows or reduced cash outflows.
An oil or gas field that is part-developed is an
example of a part-constructed asset. The VIU cash
flows should therefore include the cash flows to
complete the development and the associated cash
inflows form the sale of the oil/gas should be included.
Inventories
Inventories are generally measured at the lower
of cost and net realisable value
[IAS2R.9]. Net realisable value is the estimated
selling price of the inventory in the ordinary course
of business, less estimated completion costs and
estimated selling costs [IAS2R.6]. The estimated selling price for commodities with an active market,
such as oil and gas, will be the market price at the balance sheet
However, exceptions
exist in respect of inventories held by producers
of minerals and mineral products and commodity broker-traders.
Inventories held by producers of minerals and
mineral products
Producers of minerals and mineral products should
measure their inventories at net realisable value
when this is the basis on which these inventories
are measured in accordance with well-established
industry practice [IAS2R.3].
Changes in the carrying amount of inventories that
are carried at net realisable value are recognised
in the income statement in the period. Determination
of net realisable value reflects the conditions
such as market prices at the balance sheet date
[IAS2R.30]. Adjustments are not made to valuations
to reflect the time that it will take to dispose
of the inventory or the effect that the sale of
a significant inventory quantity might have on the
market price.
The prices of firm sales contracts are used to
calculate net realisable value to the extent of
the contract quantities but only if the contracts
are not themselves recognised on the balance sheet
under another standard, such as IAS 39 .
Inventories held by broker-dealers
Inventories held by broker-dealers are measured
at fair value less costs to sell [IAS2R.3]. The
fair value used is the spot price at the balance
sheet date. It would not be appropriate to modify
the price to reflect a future expected sale by applying
a future expected price from a forward price curve.
Changes in the carrying amount of such inventories
are recognised in the income statement.
The carrying amount of inventories that are valued
at fair value less costs to sell must be disclosed
in the notes [IAS2R.36].
Base inventories / linefill
Some items of property plant and equipment, such
as pipelines, refineries and gas storage, require
a certain minimum level of inventory to be maintained
in them in order for them to operate efficiently.
Such inventory should be classified as part of the
property, plant and equipment because it is necessary
to bring the PPE to its required operating condition
[IAS16R.16(b)]. The inventory will therefore be
recognised as a component of the PPE at cost and
subject to depreciation to estimated residual value.
However, inventory that an entity owns but stores
in PPE owned by a third party continues to be classified
as inventory, for example all gas in a rented storage
facility. It does not represent a component of the
third party's PPE nor a component of PPE owned by
the entity. Such inventory should therefore be measured
at FIFO or weighted average cost .
Overlift and underlift
Many JVs, particularly in the oil industry, share
the physical output (for example crude oil) between
the joint venture partners. Each JV partner is then
responsible for either using or selling the oil it
takes.
The physical nature of the taking (lifting) of
oil is such that is more efficient for each partner
to lift a full tanker-load of oil at a time. A lifting
schedule is therefore prepared which identifies
the order and frequency with which each partner
can lift. Consequently at each balance sheet date
the amount of oil lifted by each partner will not
be equal to its equity interest in the field. Some
partners will have taken more than their share (overlifted)
and others will have taken less than their share
(underlifted).
Overlift and underlift represents as a sale of
oil at the point of lifting by the underlifter to
the overlifter. The criteria for revenue recognition
in IAS 18 paragraph 14 are considered to have been
met [IAS18R.14]. Overlift is therefore treated as
a purchase of oil by the overlifter from the underlifter.
The sale of oil by the underlifter to the overlifter
should be recognised at the market price of oil
at the date of lifting [IAS18R.9]. Similarly the
overlifter should reflect the purchase of oil at
the same value.
The extent of underlift by a partner is reflected
as an asset in the balance sheet and the extent
of overlift is reflected as a liability. An underlift
asset is the right to receive additional oil from
future production without the obligation to fund
the production of that additional oil. An overlift
liability is the obligation to deliver oil out of
the entity's equity share of future production.
The initial measurement of the overlift liability
and underlift asset is at the market price of oil
at the date of lifting, consistent with the measurement
of the sale and purchase. Subsequent measurement
depends on the terms of the JV agreement. JV agreements
which allow the net settlement of overlift and underlift
balances in cash will fall within the scope of IAS
39 unless the own use exemption can be claimed [IAS39R.5].
Overlift and underlift balances which fall within
the scope of IAS 39 must be remeasured to the current
market price of oil at the balance sheet date. The
change arising from this remeasurement is included
in the income statement as other income / expense
rather than revenue or cost of sales.
Overlift and underlift balances that do not fall
within the scope of IAS 39 should be measured at
the lower of carrying amount and current market
value. Any remeasurement should be included in other
income / expense rather than revenue or inventory
.
Regulatory
assets - rate-recoverable costs in price-regulated
markets
Complete liberalisation of utilities is not practical
because of the physical infrastructure required for
the distribution of natural gas, electricity and water.
Some countries have proceeded with the privatisation
of the distribution networks associated with these
utilities but with the counterbalance of price-regulation
to address concerns over the monopoly powers that
inevitably arise.
The nature of the agreements that utility entities
reach with regulators vary from country to country.
A thorough understanding of the terms of the agreements
is therefore necessary in order to determine the
appropriate accounting for the agreements.
A common feature of price-regulated markets is
the agreement of the regulator to allow future price
increases in compensation for certain identified
past costs. These price increases are above those
that otherwise might have been permitted by the
regulator.
The costs associated with these price increases
can be considered is two broad categories; those
that are operating in nature and those that are
capital. Examples of the operating costs include
employee costs, increased fuel costs for the production
of power, etc. The required accounting for these
costs under IFRS is to include them in cost of sales
in the income statement in the period in which the
employee service is received and the fuel is consumed.
These costs have been incurred directly in generating
the power sold in that period [IAS2R.12] [IAS2R.38].
Examples of capital costs include damage to fixed
assets from extreme weather, such as hurricanes,
or from other unexpected and uninsured events. The
required accounting treatment for such events is
to separately recognise an impairment charge for
the damaged asset and to capitalise the cost of
the replacement asset as PPE [IAS16R.66]. Any "compensation"
receivable through an increased future price is
not recognised until that amount becomes receivable,
which is when the future electricity is delivered
[IAS16R.66(c)].
Price regulation can also lead to the requirement from a regulator for a utility entity to reduce its prices in a future period. A decrease in prices generally will not lead to the recognition of a liability. The benefit of reduced prices is only received by the customer if it continues to purchase the commodity and this alone is not sufficient to cause the recognition of a liability. The only occasions on which recognition of a liability would be appropriate would be if the entity was obliged to repay cash to the customers (or perhaps to the government) or if the reduction in prices was so significant that it represented an onerous contract. An obligation to pay cash to customers or the government would be recognised as a financial liability in accordance with IAS 39. An onerous contract would be recognised as a provision under IAS 37. It is extremely rare that the recognition of a liability under IAS 39 or IAS 37 is met in the context of price regulation.
Some national GAAPs provide specific guidance that
requires the utility to depart from the regular
treatment of such costs and to recognise a regulatory
asset or liability. This is intended to reflect
the increase or decrease in future prices agreed
with the regulator. Thus a regulatory asset is the
deferral of costs to a future period to match with
the higher prices charged in that period. There is no specific guidance in IFRS dealing with price regulation that overrides the general IFRS standards. There is therefore no basis on which to recognise regulatory assets and liabilities under IFRS except for the rare circumstances described above.
Regulatory assets and business combinations
The acquisition of a utility in a business combination
requires the recognition of all identifiable assets
of the utility at their fair values. The rights
of a utility to charge a higher tariff in the future
as a result of past costs represents an increase
in the value of the licence as described above.
Consequently the value of the higher tariff will
be reflected in the fair value of the licence recognised
on acquisition rather than the recognition of a
separate regulatory asset.
Stranded costs
Stranded costs are a particular type of regulatory
asset which are not associated with the normal day-to-day
operations of a utility. They arise as a result
of a regulator requiring a utility to dispose of
capital assets at a loss in order to achieve greater
liberalisation of the utility. The loss incurred
is known as a stranded cost and typically the regulator
allows the utility entity to charge a higher tariff
to customers in the future in order to compensate
it for the loss incurred on disposal of the capital
assets. There may be unusual circumstances in which
recognising such stranded costs as an asset could
be justified.
Arrangements that contain leases
IFRS requires that arrangements that convey the use
of an asset in return for a payment or series of payments
be accounted for as a lease even if it the arrangement
does not take the legal form of a lease [IFRIC4.1].
IFRIC 4 provides guidance on determining whether a
lease is present and many of the tolling agreements
common to the energy and utilities industry fall within
its scope.
Determining whether or not coal/gas tolling agreements
where the purchaser controls the dispatch of power
contain a lease is normally straight-forward. Difficulties
tend to arise where there is a PPA for substantially
all, or all, of the output of a wind farm or hydro
facility because the amount of generation is determined
by an uncontrollable factor, in this case the wind
or rain/snowfall.
For example, a typical wind farm contract would
be:
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For 100% of the output of the wind farm |
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For substantially all of the asset's life |
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Guarantees a level of availability when the
wind is blowing |
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Allows the purchaser to agree the timing of maintenance outages |
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Has pricing which is fixed per unit of output rather than a time based payment. |
Government requirements or incentives for the
production of power from renewable sources have
led to the development of many wind farms and other
green generating sources. The developer and owner
of the wind farm typically agrees to sell 100% of
the output of the wind farm to a single purchaser,
allowing the developer to recover its operating
costs, debt service cost and a development premium.
Available wind studies are used to help site wind
farms and assess the economic viability early in
the development stage of the project.
A power purchase agreement ("PPA") for
100% of the output of a wind farm will often meet
the requirement for finance lease accounting under
IFRIC 4 and IAS 17 because the developer expects
to get its full return from a single contract, even
although the generation of electricity is contingent
on the wind.
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