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8/9/2019 Impact of IFRS Oil and Gas
1/36
ENERGY & NATURAL RESOURCES
Impact of IFRS: Oil and Gas
kpmg.com/ifrs
KPMG International
8/9/2019 Impact of IFRS Oil and Gas
2/36© 2011 KPMG IFRG Limited, a UK company, limited by guarantee. All rights reserved.
Contents
Overview of the IFRS conversion process 2
Accounting and reporting issues 3
1. Exploration and evaluation (E&E) assets 5
2. Depletion, depreciation and amortisation (DD&A) 83. Impairment of non-financial assets 10
4. Decommissioning and environmental provisions 12
5. Joint arrangements 14
6. Revenue recognition 16
7. Reserves reporting 18
8. Financial instruments 20
Information technology and systems considerations 22
From accounting gaps to information sources 22
How to identify the impact on information systems 23
Oil and gas accounting differences andrespective system issues 24
Parallel reporting: Timing the changeover
from local GAAP to IFRS reporting 26
Harmonisation of internal and external reporting 28
People: Knowledge transfer and change management 29
Business and reporting 30
Stakeholder analysis and communications 30
Audit Committee and Board of Directors
considerations 30
Monitoring peer group 30
Other areas of IFRS risks to mitigate 30
Benefits of IFRS 31
KPMG: An Experienced Team, a Global Network 32
Contact us IBC
© 2011 KPMG International Cooperative (“KPMG International”). KPMG International provides no client services and is a Swiss entity with which the independent member firms of the KPMG network are affiliated.
8/9/2019 Impact of IFRS Oil and Gas
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1Impact of IFRS: Oil and Gas
Foreword
Accounting for oil and gas activities
presents many difficulties. Significant
upfront investment, uncertainty over
prospects and long project lives have
led to a variety of approaches being
developed by companies, and a range of
country-specific guidance for the sector.
As countries around the world adopt
IFRS, accounting approaches for
affected companies may need to be
reassessed.
Many countries converted to IFRS in
2005 and conversions are imminent
for other countries such as Canada and
South Korea in 2011 and Mexico in 2012.
Japan has permitted the early adoption
of IFRS by listed companies from years
ending on or after 31 March 2010 and is
expected to announce a final decision
on whether to mandate adoption
in 2012. The US will likely announce
later in 2011 or 2012 its plan as to how
IFRS might be incorporated into the
financial reporting requirements for
US domestic issuers.
As countries adopt a single set of
high quality, global accounting and
financial reporting standards, there
should be greater global consistency
and transparency. However, it is
recognised that extractive activities
is an area in which there is little IFRS
guidance. There is also variation in
practice between companies applying
IFRS, which was highlighted in KPMG’s
survey The Application of IFRS: Oil and
Gas published in October 2008.
This publication looks at some of the
main accounting issues across oil and
gas companies. It considers currently
effective standards and notes future
developments that could impact
accounting in the sector.
The long-term future of accounting for
extractive activities is as yet unclear.
The IASB issued the discussion paper
Extractive Activities in April 2010, and
the main proposals of the project team
and the responses to this discussion
paper are discussed in this publication.
A decision on whether the Extractive
Activities project should be added to
the IASB’s active agenda is expected
when the IASB considers responses toits Agenda Consultation 2011, which are
due by 30 November 2011.
This publication also discusses the IFRS
conversion project as a whole, including
the importance of the conversion
management process, and considers
the impact of IFRS conversion across an
organisation.
Any conversion project will be
significantly more detailed than merely
addressing the issues discussed in this
publication. However, making a head
start in identifying the accounting and
business related issues on conversion
can avoid accounting challenges in the
years to come.
While the main audience of this
publication are those contemplating
IFRS conversion, we hope that there
is something stimulating and thought
provoking for all those already dealing
with IFRS in the oil and gas sector.
Jimmy Daboo
Global Energy & Natural Resources
Auditing and Accounting Leader
KPMG in the UK
© 2011 KPMG International Cooperative (“KPMG International”). KPMG International provides no client services and is a Swiss entity with which the independent member firms of the KPMG network are affiliated.
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Overview of the IFRS conversion processAddressing challenges and
opportunities of conversion for
all aspects of your business
All IFRS conversions have consistent
themes and milestones to them.
The key is to tailor the conversion
specifically to your own issues, your
internal policies and procedures, the
structure of your group reporting,
the engagement of your stakeholders
and the requirements of your corporate
governance. Oil and gas companies can
2 Impact of IFRS: Oil and Gas
be broadly grouped into the ‘majors’
and the ‘juniors’, and there may be
similarities among these organisations,
particularly within each group. However,
there always will be differences in
the corporate DNA that makes one
conversion project different from the
next.
The IFRS Conversion Management
Overview diagram below presents
a holistic approach to planning and
implementing an IFRS conversion
by helping ensure that all linkages
and dependencies are established
between accounting and reporting,
systems and processes, people and
the business. The conversion should
address proactively the challenges
and opportunities of adopting IFRS
for all aspects of your business. This
includes, for example, consideration
of the impact of IFRS transition on the
regulatory aspect of your operations,
which may vary depending on state,
federal, international, product, reporting
and competitive requirements.
© 2011 KPMG International Cooperative (“KPMG International”). KPMG International provides no client services and is a Swiss entity with which the independent member firms of the KPMG network are affiliated.
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Accounting and reporting issuesEarly identification of
differences is critical to a
successful conversion project
The first and fundamental area to tackle
is accounting and reporting. Getting a
timely and accurate assessment of the
impact of IFRS and ensuring that the
‘gap analysis’ is correct are critical steps
to a successful transition.
Based on our experience of IFRS
conversions, we outline below the mainsector-specific accounting issues for oil
and gas companies to consider when
converting to IFRS, and provide a glimpse
of the questions to be considered.
This is not meant to be a comprehensive
list; indeed it does not cover many areas
that oil and gas companies need to
consider. Owing to their generic nature,
there are material accounting topics
(such as defined benefit pension scheme
accounting, share-based payments,
presentation of financial statements and
business combinations) that we have
not considered in this publication.
1 Exploration and evaluation (E&E) assets
2 Depletion, depreciation and amortisation (DD&A)
3 Impairment of non-financial assets
4 Decommissioning and environmental provisions
5 Joint arrangements
6 Revenue recognition
7 Reserves reporting
8 Financial instruments
3Impact of IFRS: Oil and Gas
In our experience, these issues aresignificant to oil and gas companies for
the following reasons.
• Issues may be pervasive across the
sector and will require significant
time and cost to evaluate and
implement; for example, accounting
for E&E expenditure and assets.
• Conversion may have a significant
impact on information systems,
accounting processes and systems.
For example, the impact of different
depreciation and amortisation policies
may lead to adjustments in the asset
sub-ledger.
• Accounting requirements may require
careful consideration of contract
terms, for example those termsoutlined in joint arrangements.
• Judgement may be required in
selecting significant accounting
policies that impact future results.
• Accounting and reporting
requirements may be subject to
future change for which organisations
need to be prepared.
We recommend KPMG’s publication
The Application of IFRS: Oil and Gas
for greater detail on the issues raisedin this document, and examples of
disclosures from existing IFRS oil and
gas companies.
© 2011 KPMG International Cooperative (“KPMG International”). KPMG International provides no client services and is a Swiss entity with which the independent member firms of the KPMG network are affiliated.
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4 Impact of IFRS: Oil and Gas
Discussion PaperExtractive Activities
IFRS 6 Exploration for and Evaluation of
Mineral Resources was intended only as a
temporary measure. The future of accounting
for E&E expenditure is not yet clear.
The International Accounting Standards Board
(IASB) issued a discussion paper Extractive
Activities in April 2010. The discussion paper
outlines a revised framework for accounting for
extractive activities. A decision on whether the
Extractive Activities project should be added to the
IASB’s active agenda is expected when the IASB
considers responses to its Agenda Consultation 2011,which are due by 30 November 2011.
If the IASB adds a project on extractive activities to its
active agenda, then it will take the discussion paper and
the 141 comment letters received as the basis for its initial
deliberations.
The discussion paper and responses are discussed
throughout this section of the publication. It is clear that
there is currently variation in accounting and opinions
between companies in the extractive industries, and the
discussion paper generated significant interest in the oil and gas
sector. Respondents were supportive of a project to address theaccounting for extractive activities, although many respondents
did not agree with the project team’s specific proposals. The
responses to the discussion paper highlight the range of opinions
on the future of accounting for oil and gas operations under IFRS.
© 2011 KPMG International Cooperative (“KPMG International”). KPMG International provides no client services and is a Swiss entity with which the independent member firms of the KPMG network are affiliated.
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1 Exploration and evaluation (E&E) assets
The costs involved in E&E and
development activities are considerable,
and often there are years between
the start of exploration and the
commencement of production. Even
with today’s advanced technology,
exploration is a risky and complex activity.These factors create specific challenges
in accounting for E&E expenditure.
There was no IFRS that specifically
addressed E&E activities until IFRS 6
became effective in 2006. IFRS 6 was
intended to be a temporary standard
while the IASB undertook an in-depth
project on extractive activities. With
that in mind, the standard was written
with a view to allowing companies to
carry over to IFRS their previous GAAP
practices to a large extent.
Traditionally under national GAAPs, oil
and gas companies have accounted
for E&E costs using one of two broadly
defined methods: the successful
efforts method or the full cost method.
However, as there is no single accepted
definition of either method under IFRS,
the application of these approaches
can vary.
Capitalisation of E&E
expenditure
IFRS 6 relaxes asset recognition
requirements for E&E expenditure
Without the benefit of IFRS 6,
expenditure would not be recognised
as an asset unless it is probable that
it will give rise to future economic
benefits. This would mean that
expenditure on an exploration activity
likely would be expensed until the
earlier of the time at which:
• the estimated fair value less coststo sell of the exploration prospect is
positive; and
• it is determined that commercial
reserves are present.
Applying this test, it would be rare
for expenditure other than licence
acquisition costs to be capitalised prior
to the determination of commercial
reserves.
IFRS 6 relaxes this approach for E&E
assets, allowing capitalisation of
E&E costs by expenditure class if the
company elects that accounting policy.
Definition of E&E expenditure
The stage of a project is important
in determining the accounting
standards to be applied
IFRS 6 applies only to E&E expenditure.
Outside of the scope of IFRS 6 the usual
IFRS accounting requirements apply,
including in respect of impairmenttesting.
The standard provides a non-exhaustive
list of E&E expenditure that may
be capitalised, including the cost of
geological and geophysical studies,
the acquisition of rights to explore,
exploratory drilling, trenching and
sampling.
The stage of projects needs to be
monitored to ensure that accounting
policies are applied appropriately. IFRS 6
excludes pre-licence expenditure fromthe scope of E&E costs, implying
that E&E activities commence on
acquisition of the legal rights to explore
an area. Also, IFRS 6 does not apply
to expenditure incurred after the
technical feasibility and commercial
viability of extracting the oil and gas are
demonstrable. Determining when this is
demonstrable, and the level of detail at
which this assessment should be made,
can involve considerable judgement and
requires close communication betweenfinance and technical specialists.
Classification
Classification of expenditure forms
the basis of presentation and
subsequent measurement of assets
E&E assets are a separate class of
asset that is measured initially at cost.
E&E assets are classified as tangible
or intangible assets depending on their
nature. Tangible E&E assets may include
the items of plant and equipment
used for exploration activity, such as
vehicles and drilling rigs. Intangible
E&E assets may include costs of
exploration permits and licences as
well as depreciation of tangible assets
consumed in developing intangible
assets such as exploratory wells.
First-time adoptionOil and gas deemed cost election
There is an oil and gas industry-specific
exemption in IFRS 1 First-time Adoption
of IFRS . Oil and gas companies can
elect to measure E&E assets at the
amount determined under previous
GAAP at the date of transition to IFRS.
Development and production assets can
be measured at the amount determined
for the cost centre under previous GAAP,
with an allocation to the underlying
assets on a pro rata basis using reservevolumes or reserve values at transition
date.
This exemption can assist oil and gas
companies in preparing their first IFRS
financial statements without having to
revisit all previous accounting for these
items.
For more information on the reliefs
available on the adoption of IFRS, we
recommend that you refer to KPMG’s
publication IFRS Handbook: First-timeAdoption of IFRS.
IFRS does not define either successful efforts or modified full cost accounting, despite these
being the two most common accounting approaches applied by IFRS companies
5Impact of IFRS: Oil and Gas
© 2011 KPMG International Cooperative (“KPMG International”). KPMG International provides no client services and is a Swiss entity with which the independent member firms of the KPMG network are affiliated.
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6 Impact of IFRS: Oil and Gas
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7Impact of IFRS: Oil and Gas
Discussion Paper Extractive Activities
The Discussion Paper supported a separate accounting model for E&E costs in extractive industries. The views of
respondents varied significantly on the approach that the IASB should take, and on the asset recognition model.
The project team’s proposals relating to E&E assets included the following.
• A single accounting approach for both minerals and oil and gas extractive activities.
• Recognition of an asset on the acquisition of legal rights and capitalisation of all subsequent expenditure as part of that
asset. This includes expenditure that may be expensed currently.
• Three possible measurement bases for assets arising from extractive activities: historical cost, current value, and
a mixture of historical cost and current value. The project team recommended historical cost as the preferred
measurement basis.
Single and separate approach for mining and oil and gas activitiesThe project team proposed to limit the scope of a future IFRS to extractive activities for minerals, oil and natural gas. A
single accounting and disclosure model was proposed.
The responses highlighted the broad range of views on this subject.
Of respondents who addressed this question, 62% agreed with the single model approach. A small minority of
respondents didn’t believe that a separate accounting standard is required, but supported a disclosure standard that
applied a single approach to oil and gas and mining companies.
Some respondents who disagreed with a separate single model approach supported including extractive activities in a
broader project to reconsider intangible assets accounting.
The case for a broader project on intangible assets relates to the question of whether extractive activities are sufficiently
different from other industries to justify a separate accounting model. For example, the uncertainty and long project livesinherent in E&E activities are similar to issues in the technology and pharmaceutical industries.
Some respondents commented that separate standards should be developed for each of mining and oil and gas.
Asset recognition proposals problematic
Most respondents expressed at least some concern with the asset recognition model proposed by the project team. While
the majority (63%) agreed with the proposal to recognise an asset when the legal right is acquired, a significant majority
of respondents (88%) disagreed with the project team’s view that the subsequent E&E activity would always represent an
enhancement of the asset.
Many of those respondents suggested that the project team’s analysis of the treatment of E&E assets was inconsistent with
the asset recognition criteria and the IFRS conceptual framework because the information obtained may not have any future
economic benefit due to uncertainty in the exploration process.
Respondents urged the IASB to consider asset recognition further. Respondents who disagreed with the asset recognition
model made the following suggestions of alternative approaches.
• Recognise a mining/oil and gas property asset on the same basis as other assets (e.g. in accordance with IAS 38 Intangible Assets ,
IAS 16 Property, Plant and Equipment and/or the IFRS conceptual framework) (42%). Respondents who supported this approach to
asset recognition typically also recommended that the scope of a future project should extend beyond extractive activities.
• Use existing accounting methods such as successful efforts accounting (19%).
The range of responses and the concerns raised underline the difficulties in accounting for E&E assets and the divergence of practice.
Measurement at historical cost preferred
Almost all respondents agreed with the proposal to measure assets at historical cost because it is a measure that is verifiable, can
be prepared in a timely manner and can be used to assess financial performance and stewardship. These respondents explained
that they did not support fair value because it would introduce excessive subjectivity and short-term volatility to the financialstatements. It was also thought that the use of fair value would impose significant preparation and audit costs that are not
justified because users are not interested in that information.
The research conducted by the project team indicated that analysts, lenders and venture capitalists would make only limited
use of an estimate of fair value due to the subjectivity and degree of estimation involved.
© 2011 KPMG International Cooperative (“KPMG International”). KPMG International provides no client services and is a Swiss entity with which the independent member firms of the KPMG network are affiliated.
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8 Impact of IFRS: Oil and Gas
2 Depletion, depreciation and amortisation (DD&A)A move from group depreciation methods or depreciation pools under previous GAAP to
component depreciation under IFRS could require significant effort
Component accounting
Significant judgement may be
required in determining components,
and systems needs to be capable of
tracking components separately
Companies need to allocate the costof an item of property, plant and
equipment into its significant parts,
or ‘components’, and depreciate each
part separately. For each component
the appropriate depreciation method,
rate and period needs to be considered.
This process may involve significant
judgement.
An item of property, plant and
equipment should be separated into
components when those parts are
significant in relation to the total costof the item. This does not mean that a
company should split its assets into an
infinite number of components if the
effect on the financial statements would
be immaterial.
Some oil and gas companies that have
been applying full cost accounting
under previous GAAP may have been
calculating DD&A at a cost centre
(typically a country) level. While there
is no cost-pool concept under IFRS,
the standard does allow companiesto group and depreciate components
within the same asset class together,
provided they have the same useful life
and depreciation method. However,
it is unlikely that development or
production oil and gas assets will be
able to be grouped at a level greater
than a field; this is because each field
may be significant and the lives of the
fields, and therefore depreciation rates,
will vary.
Companies need to consider theimpact, including on accounting
systems, of depleting assets on a much
more detailed level than previous GAAP.
Depreciation method
Companies need to choose the most
appropriate depreciation method
IFRS do not specify one particular
method of depreciation as preferable.
Oil and gas companies have the optionto use the straight-line method, the
reducing balance method or the unit-of-
production method, as long as it reflects
the pattern in which the economic
benefits associated with the asset
are consumed. The unit-of-production
method is most commonly used to
deplete upstream oil and gas assets,
using a ratio that reflects the annual
production of a field in proportion to the
estimate of reserves within that field.
IFRS provides no specific guidance onhow the assumptions within the reserve
estimates should be calculated or
approximated. Consequently, practice
varies as to which reserves base is used
in the calculation of DD&A.
Commencement of
depreciation/amortisation
Available for use
Depreciation or amortisation starts
when an asset is available for use. For
assets in the development stage there
may be pilot testing phases prior to
the start of full production. Whether
incidental production arising during
any such phases triggers depreciation
depends on the assessment of whether
the asset is available for use.
Some E&E assets (e.g. a drilling rig)
may be available for use immediately
and so could be depreciated/amortised
during the E&E phase. Other assets will
not be available for use until the whole
field is ready to commence operations.
In our view, there are two reasonable
approaches to determining when
depreciation/amortisation of E&E assets
should commence.
• Commence depreciation/amortisation
when the whole field is ready to
commence operations, since, in
effect, it is from this point that
economic benefits will be realised.
• Commence depreciation/
amortisation during the E&E phase
as the assets are available for use
when considered on a stand-alone
basis; however such depreciation/
amortisation is capitalised to the
extent that the assets are used in
the development of other assets.
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DiscussionPaper Extractive
Activities
The scope of the discussion paper
did not specifically include DD&AThe discussion paper did not propose
to change the basis for calculating
depreciation, although it highlighted
some issues related to the application
of the unit-of-production method. One
issue is whether such a method should
be based on revenues or physical units.
Another issue is whether the unit-of-
production method should be based on
proved reserves, proved and probable
reserves or another unit basis. The project
team proposed that these issues be addressed
in any future standard.
Some respondents noted that they would like
additional issues such as depreciation/depletion to
be addressed if this project is added to the active
agenda of the IASB.
9Impact of IFRS: Oil and Gas
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10 Impact of IFRS: Oil and Gas
3 Impairment of non-financial assets
© 2011 KPMG International Cooperative (“KPMG International”). KPMG International provides no client services and is a Swiss entity with which the independent member firms of the KPMG network are affiliated.
Annual impairment testing for intangible assets that are not yet available for use is relaxed
for E&E assets
E&E assets
E&E assets are exempt from certain
impairment testing requirements
IFRS 6 requires E&E assets to be
assessed for impairment in two
circumstances.
• When facts and circumstances
suggest that the carrying amount
of an E&E asset may exceed its
recoverable amount.
• When E&E activities have been
completed, i.e. when the commercial
viability and technical feasibility of that
asset have been determined and prior
to reclassification to development
assets.
The standard provides the followingexamples of ‘trigger events’ that
indicate that an E&E asset should be
tested for impairment:
• expiration of the right to explore;
• substantive expenditure on further
exploration for and evaluation of
mineral resources in the specific area
is neither budgeted nor planned;
• commercially viable reserves have
not been discovered and the company
plans to discontinue activities in thespecific area; and
• data exists to show that while
development activity will proceed,
the carrying amount of the E&E asset
will not be recovered in full through
such activity.
This provides relief from the general
requirements of IFRS, which require
annual impairment testing for intangible
assets that are not yet available for use.
Impairment testing calculationsare performed in line with general
impairment requirements and take into
account the time value of money.
Development and production
assets
Reporting date consideration of
impairment indicators
For non-current assets (other than
goodwill and E&E assets) IAS 36 Impairment of Assets requires companies
to assess at the end of each reporting
period whether there are any indicators
that an asset is impaired. If there is such
an indication, then recoverable amount
needs to be assessed.
An impairment loss is recognised for
any excess of carrying amount over
recoverable amount. If recoverable
amount cannot be determined for the
individual asset, because the asset
does not generate independent cashinflows separate from those of other
assets, then the impairment loss is
recognised and measured based on
the cash-generating unit to which the
asset belongs.
Cash-generating units (CGUs)
Identification of appropriate CGUs
can be complex
A CGU is the smallest group of
assets that generates cash inflows
from continuing use that are largelyindependent of the cash inflows from
other assets or group of assets of the oil
and gas company.
In our experience, many companies
in the oil and gas sector base the
identification of CGUs on licence, field
or core areas. For some companies that
operate a number of areas or fields that
have shared infrastructure and E&E
assets, the identification of CGUs can
be more complex.
An accounting policy is also needed for
allocating E&E assets to CGUs when
an impairment test is to be performed.
For assets during the E&E phase, CGUs
can be aggregated to form a group of
units for impairment testing purposes.
Allocation of assets to CGUs and
impairment groups requires judgement
and the interaction with indicators of
impairment will require consideration.
Indicators of impairment
Some examples of indicators of
impairment are outlined below.
• Market value has declined
significantly or the company has
operating or cash losses . For
example, a significant downward
movement in the oil price may
result in operating cash losses and
represent a trigger for impairment.
• Technological obsolescence .
• Competition.
• Market capitalisation. For example,
the carrying amount of the oil and
gas company’s net assets exceeds
its market capitalisation. This may be
a particular risk for companies with
large E&E assets.
• Significant regulatory changes .
For example, increased regulation
of environmental rehabilitation
processes.
• Physical damage to the asset . For
example, damage to a drilling rigcaused by an explosion.
• Significant adverse effect on the
company that will change the
way in which the asset is used/
expected to be used . For example,
the re-nationalisation requirements
of some governments may lead
to some projects being diluted to
accommodate a government interest.
Goodwill
Impairment testing at least annually
Under IFRS, oil and gas companies
are required to test goodwill (and
intangible assets with indefinite useful
lives) for impairment at least annually,
8/9/2019 Impact of IFRS Oil and Gas
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irrespective of whether indicators of
impairment exist. Additional testing
at interim reporting dates is requiredif impairment indicators are present.
Goodwill by itself does not generate
cash inflows independently of other
assets or group of assets and therefore
is not tested for impairment separately.
Instead, it should be allocated to the
acquirer’s CGUs that are expected to
benefit from the synergies of the related
business combination.
Goodwill is allocated to a CGU that
represents the lowest level within
the company at which the goodwill ismonitored for internal management
purposes. The CGU cannot be larger
than an operating segment as defined
in IFRS 8 Operating Segments , before
aggregation. An impairment loss
is recognised and measured at the
amount by which the CGU’s carrying
amount, including goodwill, exceeds its
recoverable amount.
Impairment reversals
Reversal of impairment lossesrestricted
Impairment losses related to goodwill
cannot be reversed. However, for
other assets companies assess
whether there is an indication that
a previously recognised impairment
loss has reversed. If there is such an
indication, then impairment losses are
reversed if the recoverable amount
has increased, subject to certain
restrictions.
11Impact of IFRS: Oil and Gas
Discussion PaperExtractive Activities
Proposals maintain the exemption from applying
all requirements of IAS 36 to E&E assets
The project team’s proposals relating to impairment
included the following.
The indicators of impairment for E&E assets differ
from those in IAS 36.
When management determines that there is a high
likelihood that the carrying amount of the asset will not
be recovered, then the E&E asset should be tested for
impairment.
The proposals concluded that IAS 36 should not be applied
to E&E assets. The basis for this proposal was a view that
it is not possible to make a reliable judgement of whether
the carrying amount is less than the recoverable amount until
sufficient information is available.
Of respondents who commented on impairment, most (73%)
opposed the proposals. Some respondents suggested that the IASB
include a review of IAS 36 in any future project to alleviate difficulties
in applying IAS 36 to E&E assets. The potential of the proposed
approach to delay recognition of any impairment loss and the reliance
on management judgement were noted by some respondents.
Some respondents remarked that the fact that the IAS 36 impairment
test approach is not considered to work for E&E assets may imply that the
project team has proposed the wrong asset recognition model.
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12 Impact of IFRS: Oil and Gas
4 Decommissioning and environmental provisionsIFRS may result in the earlier recognition of provisions than many national GAAPs
Oil and gas companies often are
exposed to legal, contractual and
constructive obligations to meet
the costs of decommissioning and
dismantling assets at the end of their
production life and to restore the site.
These costs are likely to be a significant
item of expenditure for most oil and
gas companies.
Timing of recognition
A present obligation that is more
likely than not
Decommissioning and environmental
provisions are covered by IAS 37
Provisions, Contingent Liabilities and
Contingent Assets. Recognition of a
provision is required when there is
a present obligation and an outflow
of resources is probable. Probable isdefined as more likely than not.
A present obligation can be legal or
constructive in nature. For oil and
gas companies a legal obligation for
decommissioning and remediation
often is contained in the licence
agreement and related contracts, or in
legislation. However, in some countries
environmental legislation may be less
developed and it may be difficult to
determine the extent of the obligation.
A constructive obligation may arisefrom a company’s published policies
about environmental clean-up or from
past practices.
An obligation to make good damage or
dismantle equipment is provided for in
full when the damage is caused or the
asset installed. This may result in the
recognition of additional amounts or
earlier recognition of such amounts in
IFRS financial statements compared to
previous GAAP.
When the provision arises on
initial recognition of an asset, the
corresponding debit is treated as part of
the cost of the related asset and is not
recognised immediately in profit or loss.
Measurement
Judgement is required to arrive at the
‘best estimate’
The provision is measured at the best
estimate of costs to be incurred. This
takes the time value of money into
account, if material. The best estimate
may be based on the single most likelycost of decommissioning and takes
uncertainties into account in either
the cash flows or discount rate used in
measuring the provision. The discount
rate should reflect the risks specific to
the liability and adjusting the discount
rate for risk often is complex and
involves a high degree of judgement.
There are many complexities in
calculating an estimate of expenditure
to be incurred. Technological advances
may reduce the ultimate cost ofdecommissioning and may also affect
the timing by extending the expected
recoveries from reservoirs. The estimate
is updated at each reporting date.
For midstream and downstream assets
with indefinite useful lives, the timing
of decommissioning may be so distant
that the present value of liabilities is not
significant. When there is uncertainty
about the useful life of the asset, this
uncertainty needs to be taken into
account in the measurement of theprovision. In such cases, it may be that
the provision is not significant until the
expected date at which the facilities
will be decommissioned is less distant.
Significant judgement may be required
in measuring the provision.
Future developments
The IASB is reviewing accounting for
provisions
In 2005 the IASB began reviewing
the accounting for provisions and an
exposure draft was issued, which
would have resulted in changes to
both the timing of recognition and
the measurement of provisions. In
2010 the IASB issued a limited re-
exposure of the 2005 proposals, which
included a focus on the measurement
of provisions involving services, e.g.
decommissioning. The project currently
is inactive, and the IASB will decide
whether or how to progress the project
when it considers responses to its
Agenda Consultation 2011, which are
due by 30 November 2011.
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13Impact of IFRS: Oil and Gas
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5 Joint arrangementsThe term joint venture is a widely used operational term, although not all such arrangements
are joint ventures for accounting purposes. A recently issued standard could significantly
impact the accounting
14 Impact of IFRS: Oil and Gas
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Determining whether an
arrangement is a joint
arrangement
Companies need to review their
arrangements to determine whetherthey should be accounted for as a
joint arrangement
Joint arrangements are a common
way for oil and gas companies to share
the risks and costs of exploration and
production activities, and come in a
variety of forms. Within the sector,
the term joint venture is used widely
as an all-encompassing operational
expression to describe shared working
arrangements. However, under IFRS
there are strict criteria that must bemet in order for joint arrangement
accounting to be applied.
For an arrangement to be a joint
arrangement for accounting
purposes there must be a contractual
arrangement that gives joint control .
Joint control is not determined by
economic interest. Control is based
on the contractual arrangements
and exists when decisions about the
relevant activities require the unanimous
consent of more than one party to
the arrangement. Companies must
review their arrangements to determine
whether joint control exists. When the
company does not have joint control,
the arrangement likely will be accounted
for as an investment, subsidiary or
associate.
Accounting for joint ventures
prior to adoption of IFRS 11
Accounting is based on whetherthere is a separate legal entity. An
accounting policy choice is available
for jointly controlled entities
Accounting for joint arrangements
(currently referred to as joint ventures)
before the adoption of IFRS 11 Joint
Arrangements is governed by IAS 31
Interests in Joint Ventures . There are
three classifications of joint venture
under IAS 31: jointly controlled entity,
jointly controlled asset and jointlycontrolled operation.
Jointly controlled entities
A jointly controlled entity is a joint
arrangement that is carried out through
a separate legal entity. Currently there is
an accounting policy choice that applied
when accounting for jointly controlled
entities. A venturer accounts for its
interest using either proportionate
consolidation or the equity method. In
KPMG’s 2008 survey The Application of
IFRS: Oil and Gas there was an almosteven split between companies applying
the equity method and those using
proportionate consolidation.
Jointly controlled assets and jointly
controlled operations
Jointly controlled assets and jointly
controlled operations are joint ventures
that are not separate legal entities.
Venturers in jointly controlled assets and
jointly controlled operations recognise
the assets and liabilities, or share of
assets and liabilities, that they control,
as well as the costs incurred and income
received in relation to that arrangement.
Accounting for joint
arrangements from 2013
A new standard issued in 2011
significantly impacts the accounting
for joint arrangements
The IASB issued IFRS 11 in May 2011.
The standard is effective for periods
beginning on or after 1 January 2013,with early adoption permitted subject to
some conditions.
There are two classifications of joint
arrangements under IFRS 11: Joint
ventures and joint operations. The
definitions of each category differ
from those in IAS 31. The classification
of arrangements under IFRS 11 is
more judgemental and the terms of
arrangements and the nature of any
related agreements must be consideredto determine the classification of the
arrangement for accounting purposes.
Joint venture
A joint venture is a joint arrangement
in which the jointly controlling parties
have rights to the net assets of the
arrangement. Joint ventures include
only arrangements that are structured
through a separate vehicle (such as a
separate company). However, not all
joint arrangements that are companies
will necessarily be joint ventures.
The nature and terms of arrangements
need to be reviewed to determine
the appropriate classification of the
arrangement. The legal form is only
one factor to be considered. When
the contractual arrangements and
other facts and circumstances indicate
that the joint venturers have rights to
assets or obligations for liabilities of the
arrangement, the arrangement will be a
joint operation. One circumstance that
could indicate that an arrangement is ajoint operation is if the arrangement is
designed so that the jointly controlled
company cannot undertake its own trade,
and can only trade with the parties to the
joint arrangement. Related agreements
and other facts and circumstances also
need to be considered.
A joint venturer will account for its
involvement in the joint venture using
the equity method in accordance with
IAS 28 (2011) Investments in Associates
and Joint Ventures .
Joint operation
A joint operation is an arrangement
in which the jointly controlling parties
have rights to assets and obligations for
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liabilities relating to the arrangement.
An arrangement that is not structured
through a separate vehicle will be a jointoperation; however, other arrangements
may also fall into this classification
depending on the rights and obligations
of the parties to the arrangement.
A joint operator recognises its own
assets, liabilities and transactions,
including its share of those incurred
jointly.
15Impact of IFRS: Oil and Gas
Discussion PaperExtractive Activities
Joint arrangements were not in the scope of
the discussion paper
In commenting on the proposed scope of any
future project by the IASB, some respondents
requested that the IASB consider other issues
that were not specifically covered in the
discussion paper.
These included risk-sharing agreements
such as farm-in/ farm-outs, production-
sharing agreements and carried
interests. These issues are routinely
encountered in the oil and gas sector.
Some respondents indicated that they
considered addressing these, and
other additional areas, to be a high
priority in the absence of specific
guidance in IFRS.
These comments underline the
importance and accounting
complexities of risk-sharing
arrangements in the extractive
industries.
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6 Revenue recognition
16 Impact of IFRS: Oil and Gas
Oil and gas companies face challenges when applying the revenue recognition
requirements under IFRS due to common industry arrangements that can give rise to
complex revenue issues
Oil and gas companies reporting under
IFRS need to assess whether the risks
and rewards of ownership have been
transferred in order to determine when
to recognise revenue. The determination
of when this occurs can presentchallenges for oil and gas companies.
The individual facts and circumstances
will need careful consideration as they
may vary between contracts.
Timing of revenue recognition
There is no industry standard as to the
timing of the transfer of ownership in
oil and gas transactions. The revenue
arising from each transaction is
recognised based on the terms of the
underlying sales agreement.
For most transactions involving the sale
of physical oil and gas, the contractual
terms for the transfer of ownership
will be based on the delivery or lifting
of production. For example, for crude
oil sales generally there are two points
at which title could pass from seller to
buyer: when the crude oil is lifted from
the site of production; or when the
crude oil is delivered to the refinery/
storage depot. For petroleum products
sold to retail distribution networks,
generally revenue is recognised ondelivery to service stations.
Physical exchange of products
The physical exchange of products is
common within the oil and gas industry.
For example, under crude oil buy/sell
arrangements a company agrees to
buy a specified quantity and grade of oil
to be delivered at a specified location,
while simultaneously agreeing to sell
a specified quantity and grade of oil
at a different location with the same
counterparty, generally to facilitate
operational requirements.
In accordance with IAS 18 Revenue ,
the swapping of goods or services
that are of a similar nature and value is
a transaction that does not generate
revenue. The nature of the exchange
will determine if it is a like-for-like
exchange accounted for at book
value, or an exchange of dissimilar
goods within the scope of IAS 18. Thequantum of the balancing payment
is one important factor in deciding
whether the transaction is a sale and a
purchase or a swap of similar products.
The more significant the balancing
payment is compared to the value of the
products being exchanged, the more
likely the transaction is to be a swap of
dissimilar products.
Overlift and underlift
In many joint arrangements the timing
of revenue recognition will coincidewith a fixed schedule of lifting, which
stipulates when each participant lifts
its share of crude oil or gas from the
production facility. The practicalities
of loading an oil tanker mean that any
single lifting can be more or less than
a company’s entitlement, resulting
in an overlift (a lifting in excess of the
company’s contractual allocation of
production) or an underlift (a lifting
less than the company’s contractual
allocation of production). Oil and gascompanies need to consider how they
account for any overlift or underlift
balances, including what measurement
base to apply to any resulting asset
or liability.
Future developments
A new standard on revenue
recognition is expected
The IASB and the US Financial
Accounting Standards Board are
working on a joint project to developa comprehensive set of principles for
revenue recognition. An exposure draft
published in 2010 proposed a single
revenue recognition model in which
an entity would recognise revenue as
it satisfies a performance obligation
by transferring control of promised
goods or services to a customer. The
model was proposed to be applied to
all contracts with customers except
leases, financial instruments, insurancecontracts and non-monetary exchanges
between entities in the same line of
business to facilitate sales to customers
other than the parties to the exchange.
The Boards redeliberated the
proposals contained in the exposure
draft during the first half of 2011
and agreed tentatively to revise a
number of aspects of the proposals,
including the criteria for identifying
separate performance obligations, the
guidance on transfer of control, and themeasurement of the transaction price,
particularly for arrangements including
uncertain consideration. The Boards
concluded that, although there was no
formal due process requirement to re-
expose the proposals, it was appropriate
to go beyond established due process
given the importance of this topic to
all entities. A revised exposure draft is
expected in the second half of 2011.
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17Impact of IFRS: Oil and Gas
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7 Reserves reporting
18 Impact of IFRS: Oil and Gas
There is no specific IFRS reporting requirement on reserves, although many oil and gas
companies include an accounting policy for reserves or a commentary in the critical estimates
and judgements note, or in the management discussion and analysis section of the annual report
Oil and gas reserve estimates are
critical information in the evaluation of
oil and gas companies, and reserves
disclosure is an important component
of annual reports in the sector. The
purpose of reserves reporting is tomake available information about the
oil and gas reserves controlled by
companies in the sector. This is vital in
assessing their current performance
and future prospects. Despite their
importance to both the company and
the financial statements, there are no
explicit requirements for the disclosure
of reserve information in IFRS.
Disclosures
In the absence of specific guidance,
oil and gas companies tend to referto other requirements, such as those
in the US, Canada, Australia and the
UK. The nature of reserves estimates
is such that, even if all companies
provided disclosure based on a single
classification, meaningful comparison
between companies would be difficult
without in-depth analysis of the
many assumptions inherent in the
core disclosures.
The US Securities and Exchange
Commission’s rules require any issuer
providing disclosure under ASC 932-235
Extractive Activities – Oil and Gas
– Notes to Financial Statements to
continue to provide that disclosure
even if the issuer is preparing financial
statements in accordance with IFRS.
Impact of reserve estimates on
financial statement balances
While the reporting of reserves data
is important in its own right, reserves
measures are also used in deriving a
number of accounting estimates. • In our experience, DD&A calculations
usually are based on the unit-of-
production method and the volume
of reserves used in the calculation
affects the calculation of the
associated DD&A charge.
• Reserves estimates are a key factor
in determining the economic life of an
oil field and therefore impact on the
calculation of decommissioning and
environmental rehabilitation provisions.
• Impairment calculations include
assumptions for reserves. Downward
revisions in reserve estimates often
represent an indicator of impairment.
• Reserves are a key input to fair
value calculations in accounting for a
business combination.
• Assumptions about future profit
potential based on reserves
estimates may be the basis for the
recognition of deferred tax assets
arising from unused tax losses.
Because of the impact of reserves
information in the financial statements,
oil and gas companies typically include
some information about reserves in the
critical estimates and judgements note
to the financial statements.
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19Impact of IFRS: Oil and Gas
DiscussionPaper ExtractiveActivities
Significant disclosure requirements
proposed
The project team’s proposals relating
to reserves reporting included
the following.
• Use of Petroleum Resource
Management System (PRMS)
definitions for reservesand resources.
The discussion paper noted that
the PRMS is used by many oil
and gas companies for internal
resource management and it also
corresponds closely to market
regulator disclosure requirements
in most jurisdictions that have
formalised reserve disclosure
requirements.
• Significant disclosure requirements
relating to reserves and resources,
including:
– quantities of proved reserves and
proved plus probable reserves,
with reserve quantities presented
separately by commodity and by
material geographical area;
– the main assumptions used in
estimating reserve quantities,
and a sensitivity analysis; and
– a current value measurement of
reserves by major geographical
region if historical cost is used to
measure E&E assets.
Reserve definition – respondents’
views
Most respondents agreed with
recommendations that industry-baseddefinitions of reserves and resources
be used in any future IFRS to set
disclosures and complement the
accounting requirements. Most also
agreed with the PRMS definition.
Concerns raised related to the
approach for incorporating the
definition into any future IFRS.
Also, respondents suggested
that application guidance may
be required to ensure PRMS is
applied consistently.
Concern was also raised over the
project team’s proposal that reserves
estimates be prepared using a
market participant’s assumption of
commodity price. Respondents who
commented expressed a preferencefor a historical price assumption to
remove subjectivity.
Disclosure proposals – respondents’
views
While a majority (63%) of respondents
generally agreed with the disclosure
objectives, almost all respondents
expressed significant concern
about the level of granularity of the
disclosures proposed. Concern
was also raised as to whether the
disclosure of reserve quantities shouldbe subject to audit.
Some of the proposed disclosures differ
from those currently required by some
market regulators. Also, additional
information may be required in the
future if such disclosures are mandated.
Therefore, this area is likely to require
significant management focus as
practice and requirements develop.
The importance of reserves
reporting and the lack of currentguidance led some respondents to
support development of disclosure
requirements separately, and
more urgently, than accounting
requirements.
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20 Impact of IFRS: Oil and Gas
8 Financial instrumentsThe conversion process must include a review of the existence, classification and accounting
for financial instruments, including derivatives. Future changes in the accounting are expected
Oil and gas companies generally have
financial instrument accounting issues
owing to the significant commodity
price risk that they face and the
structures in place to manage this
and other exposures such as currency
fluctuations. A thorough review of theexistence, classification and accounting
for financial instruments will be required
on conversion.
Current requirements
Accounting and disclosure
requirements may be significantly
different from national GAAP
Contracts to buy and sell oil and gas
and other non-financial items may be
included in the scope of the financial
instruments standards. There is anexemption for contracts that are held
for physical delivery or receipt for
the company’s expected purchase,
sale or usage requirements (the ‘own
use exemption’). However, specific
conditions must be met to apply this
exemption, and its applicability should
be reviewed carefully.
Specific types of oil and gas contracts
also commonly contain embedded
derivatives that may need to be
accounted for separately. For example,gas contracts that are not derivatives
themselves may contain embedded
derivatives as a result of a pricing
mechanism linked to an index other than
a gas pricing index.
As it currently stands, IAS 39
Financial Instruments: Recognition
and Measurement requires financial
assets to be classified into one of four
categories: at fair value through profit
or loss; loans and receivables; held to
maturity; and available for sale. Financial
liabilities are categorised as either
financial liabilities at fair value through
profit or loss or ‘other’ liabilities.
Financial assets and financial liabilities
are measured initially at fair value. After
initial recognition, loans and receivables
and held-to-maturity investments
are measured at amortised cost. All
derivative instruments are measured
at fair value with gains and lossesrecognised in profit or loss except when
they qualify as hedging instruments in a
cash flow or net investment hedge.
A financial asset is derecognised only
when the contractual rights to cash flows
from that particular asset expire or when
substantially all risks and rewards of
ownership of the asset are transferred.
A financial liability is derecognised when
it is extinguished or when the terms are
modified substantially.
Forthcoming requirements/
Future developments
Simplified classifications
In November 2009 the IASB published
the first chapters of IFRS 9 Financial
Instruments , which will supersede
the requirements of IAS 39 Financial
Instruments: Recognition and
Measurement on the classification
and measurement of financial assets.
In October 2010 requirements with
respect to the classification and
measurement of financial liabilities and
the derecognition of financial assets and
financial liabilities were added to IFRS 9.
Most of these requirements have been
carried forward without substantive
amendment from IAS 39. However,
to address the issue of own credit
risk some changes were made to the
fair value option for financial liabilities.
The effective date of IFRS 9 is periods
beginning on or after 1 January 2013 but
an exposure draft, open for commentuntil 21 October 2011, requests views
on whether the effective date should be
pushed back to 1 January 2015.
IFRS 9 includes two primary
measurement categories for financial
assets: amortised cost and fair value.
Other classifications, such as held to
maturity and available for sale, have
been eliminated. The classification and
measurement requirements for financial
liabilities are generally unchanged
other than a change to the treatment of
changes in fair value as a result of own
credit risk.
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21Impact of IFRS: Oil and Gas
IASB’s review of financial
instruments accounting may result in
significant changes in accounting
The IASB continues to work on
elements of its comprehensive financial
instruments project, most notably
hedging and impairment. In November
2009 the IASB issued Exposure Draft
Financial Instruments: Amortised Cost
and Impairment , with supplementary
proposals in January 2011 relating to the
impairment of financial assets managed
in an open portfolio (the supplement).
The supplement proposes to replace the
incurred loss approach to impairment
of financial assets with an approach
based on expected losses. Extensive
disclosures were also proposed.
The IASB issued Exposure DraftHedge Accounting in December 2010,
proposing significant changes to the
current hedge accounting requirements.
The proposals were designed to
integrate hedge accounting more
closely with risk management policies
and objectives. For companies applying
hedge accounting to commodity price
transactions, the process for assessing
hedge effectiveness would change. The
proposals also expanded the range of
instruments that can be designated as
hedged instruments.
IASB deliberations on both projects
are ongoing.
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22 Impact of IFRS: Oil and Gas
Information technology and systems considerationsA major effect of converting to IFRS will
be the increased burden throughout the
oil and gas organisation of capturing,
analysing, and reporting new data to
comply with IFRS requirements. Making
strategic and tactical decisions relating
to information systems and supporting
processes early in the project helps limit
unnecessary costs and risks arising
from possible duplication of effort or
changes in approach at a later stage.
Much depends on factors such as:
• the type of enterprise system and
whether the vendor offers IFRS-
specific solutions;
• whether the system has been kept
current, as older versions first may
need updating; and
• the level of customisation, as the
more customised the system,
the more effort and planning the
conversion process will likely take.
From accounting gaps to
information sources
The foundation of the project, as
described earlier, is to understand
the local GAAP to IFRS accounting
differences and the effects of those
differences. That initial analysis needs
to be followed by determining the effect
of those accounting gaps on internal
information systems and internal
controls. What oil and gas companies
need to determine is which systems will
need to change and translate accounting
differences into technical system
specifications.
One of the difficulties that oil and
gas companies may face in creating
technical specifications is to understand
the detailed end-to-end flow of
information from the source systems,
such as project or licence operational
sub-ledgers to the general ledger
and further to the consolidation and
reporting systems. The simplified
diagram below outlines a process thatorganisations can adopt to identify the
impact on information systems.
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How to identify the impact on information systems
There are many ways in which information systems may be affected, from the initiation of transactions through to the
generation of financial reports. The following table shows some areas in which information systems change might be required
under IFRS, depending on facts and circumstances.
Change Action
New data requirements
New accounting disclosure and recognition requirements
may require more detailed information, new types of data,
and new fields; and information may need to be calculated
on a different basis.
Modify:
• general ledger and other reporting systems to capture
new or changed data; and
• work procedure documents.
Changes to the chart of accountsThere will almost always be a change to the chart of accounts
due to reclassifications and additional reporting criteria.
Create new accounts and delete accounts that are no
longer required.
Reconfiguration of existing systems
Existing systems may have built-in capabilities for specific
IFRS changes, particularly the larger enterprise resource
planning (ERP) systems and high-end general ledger
packages.
Reconfigure existing software to enable accounting under
IFRS (and parallel local GAAP, if required).
Modifications to existing systems
New reports and calculations will be required to
accommodate IFRS.
Spreadsheets and models used by management as an
integral part of the financial reporting process should
be included when considering the required systems
modifications.
Make amendments such as:
• new or changed calculations
• new or changed reports
• new models.
New systems interface and mapping changes
When previous financial reporting standards did not
require the use of a system or when the existing system
is inadequate for IFRS reporting, it may be necessary to
implement new software.
When introducing new source systems and
decommissioning old systems, interfaces may need to
be changed or developed and there may be changes toexisting mapping tables to the financial system. When
separate reporting tools are used to generate the financial
statements, mapping these tools will require updating to
reflect changes in the chart of accounts.
Implement software in the form of a new software
development project or select a package solution.
Interfaces may be affected by:
• modifications made to existing systems
• the need to collect new data
• the timing and frequency of data transfer requirements.
23Impact of IFRS: Oil and Gas
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24 Impact of IFRS: Oil and Gas
Change Action
Consolidation of entitiesUnder IFRS, there is the potential for changes to the
number and type of entities that need to be included in the
group’s consolidated financial statements. For example,
the application of the concept of ‘control’ may be different
under IFRS (based on IFRS 10 Consolidated Financial
Statements from 1 January 2013) and previous GAAP.
Update consolidation systems and models to account for
changes in consolidated entities.
Reporting packages
Reporting packages may need to be modified to:
• gather additional disclosures in the information from
branches or subsidiaries operating on a standard general
ledger package; or• collect information from subsidiaries that use different
financial accounting packages.
Modify reporting packages and the accounting systems
used by subsidiaries and branches to provide financial
information. Also communicate new requirements to
operators of joint ventures.
Financial reporting tools
Reporting tools can be used to:
• perform the consolidation and prepare the financial
statements based on data transferred from the general
ledger; or
• prepare only the financial statements based on receipt of
consolidated information from the general ledger.
Modify:
• reporting tools used by subsidiaries and branches to
provide financial information;
• mappings and interfaces from the general ledger; and
• consolidation systems based on additional requirements
such as segment reporting in some cases.
Oil and gas accounting differences and respective system issuesThe following table outlines some of the salient accounting differences that we have noted earlier, together with potential
systems and process impacts.
Accounting differences Potential systems and process impact
Exploration and
evaluation costs
• Interaction between technical E&E processes and accounting systems to clearly identify
milestones such as licence acquisition and determination of commercial reserves.
• Impact on master data settings to reflect changes in E&E capitalisation policies.
• Impact on general capitalisation process and systems settings based on differences in
eligible costs for capitalisation, e.g. unsuccessful drilling, seismic, pre-feasibility costs.
• Allocation of assets to CGUs and depletion units of account.
Depletion,
depreciation &
amortisation
• Impact of changes to depreciation methods and useful lives on the posting specifications of
the fixed assets sub-system.
• Impact on master data settings and structure based on a component approach to asset
depreciation.
• Impact on transition to IFRS of data conversion.
Impairment of non-
financial assets
• Impact on impairment models for any changes to CGUs on transition.
• Selection of impairment model with links to tax, financing etc.
Decommissioning
and environmental
provisions
• Impact on the interface with E&E and development assets to reflect work progress and
changes in estimates as extraction occurs.
• Accounting systems need to identify discount rates specific to each liability and this may
lead to changes in the sub-ledger and provision calculation models as well as the generalledger.
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Accounting differences Potential systems and process impact
Joint arrangements • Identification of accounting differences between information provided by joint arrangementoperators and IFRS principles could lead to changes in reporting packages used and central
adjustments required.
• System changes may be required to adjust for accounting policy differences for the
compilation of the consolidated financial statements.
Revenue recognition • Clear identification of transactions with out-of-the-ordinary revenue recognition
characteristics, such as exchanges of assets. Changes to the mapping of such transactions
within accounting systems.
25Impact of IFRS: Oil and Gas
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26 Impact of IFRS: Oil and Gas
Parallel reporting: Timing the changeover from local GAAP to IFRS reporting
Conversion from local GAAP to IFRS will require parallel accounting for a certain period of time. At a minimum, this will happen
for one year as local GAAP continues to be reported, but IFRS comparatives are prepared prior to the go-live date of IFRS.
Parallel reporting may be created either in the real-time collection of information through the accounting source systems to the
general ledger or through ‘top-side’ adjustments posted as an overlay to the local GAAP reporting system.
The manner and timing of processing information for the comparative periods in real-time or through top-side adjustments will
be based on a number of considerations:
Parallel accounting option incomparative year
Effect Considerations
Parallel accounting through top-
side adjustments
• No real-time adjustments to
systems and processes will be
required for comparative period.
• Local GAAP reporting will flow
through sub-systems to the general
ledger, i.e. business as usual.
• Comparative period will need to be
recast in accordance with IFRS, but
can be achieved off-line.
• Migration of local GAAP to IFRS
happens on first day of the year in
which IFRS reporting commences.
• Less risky for ongoing local
GAAP reporting requirements in
comparative year.
• Available for all, but more typical
when there is a lower volume of
transactions to consider.
• More applicable to small/less
complex organisations or when few
changes are required.
Real-time parallel accounting • Consideration needed for ‘leading
ledger’ in comparative year being
local GAAP or IFRS, i.e. which GAAPwill management use to run the
business.
• If leading ledger is IFRS in
comparative year, then conversion
back to local standards is necessary
for the usual reporting timetable and
requirements.
• Changes to systems and
information may continue to be
needed in the comparative year if
the IFRS accounting options have
not been fully established. • Migration to IFRS ledgers needed
prior to first day of the year in which
IFRS reporting commences.
• Real-time reporting of two GAAPs
in comparative year has benefits,
but puts more stress on the financegroup.
• Typically used when tracking two
sets of numbers for large volume of
transactions will make systemisation
of comparative year essential.
• More applicable for large/complex
organisations with many changes.
• Strict control on system changes
will need to be maintained over this
phased changeover process.
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27Impact of IFRS: Oil and Gas
Most major ERP systems (e.g. SAP®, Oracle®, Peoplesoft®) are able to handle parallel accounting in their accounting systems.
The two common solutions implemented are the Account solution or the Ledger solution.
Depending on the release of the respective ERP systems, one or both options are available for the general ledger solution.
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Harmonisation of internal and external
reporting
Oil and gas companies should consider the impact of IFRS
changes on data warehouses and relevant aspects of
internal reporting. In many organisations, internal reporting
is performed on a basis similar to external reporting, using
the same data and systems, which will therefore need to
change to align with IFRS. One key difference that may remain
after transitioning to IFRS is the reporting of reserves andresources.
The following diagram represents the possible internal
reporting areas that may be affected by changing systems to
accommodate the new IFRS reporting requirements.
28 Impact of IFRS: Oil and Gas
The process of aligning internal and external reporting
typically will involve the following.
• When mappings have changed from the source systems to
the general ledger, mappings to the management reporting
systems and the data warehouses also should be changed.
• When data has been extracted from the source systems
and manipulated by models to create IFRS adjustments
that are processed manually through the general ledger, the
impact of these adjustments on internal reporting should
be carefully considered.
• Alterations to calculations and the addition of new data in
source systems as well as the new timing of data feeds
could impact key ratios and percentages in internal reports,
which may need to be redeveloped to accommodate them.
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People: Knowledge transfer and change management
29Impact of IFRS: Oil and Gas
When your company reports for the first time under IFRS, the preparation of those financial
statements will require IFRS knowledge to have been successfully transferred to the financial
reporting team. Timely and effective knowledge transfer is an essential part of a successful and
efficient IFRS conversion project.
The people impacts of IFRS range
from an accounts payable clerk coding
invoices differently under IFRS to Audit
Committee approval of disclosures
for IFRS reporting. There is a broad
spectrum of people-related issues, allof which require an estimation of the
cha