KPMG. Impact of IFRS. Oil and Gas

7/27/2019 KPMG. Impact of IFRS. Oil and Gas

1/36

ENERGY & NATURAL RESOURCES

Impact of IFRS:Oil and Gas

kpmg.com/ifrs

KPMG International


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-nancial 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

Benets 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 rms of the KPMG network are afliated.



1Impact of IFRS: Oil and Gas

Foreword

Accounting for oil and gas activities

presents many difculties. Signicant

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-specic 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 nal 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

nancial reporting requirements for

US domestic issuers.

As countries adopt a single set of

high quality, global accounting and

nancial 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 KPMGs

survey The Application of IFRS: Oil and

Gaspublished 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 Activitiesin 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 IASBs 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

signicantly 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




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

specically 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.




Accounting and reporting issuesEarly identication of

differences is critical to a

successful conversion project

The rst 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-specic 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 dened benet pension scheme

accounting, share-based payments,

presentation of nancial 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-nancial assets

4 Decommissioning and environmental provisions

5 Joint arrangements

6 Revenue recognition

7 Reserves reporting

8 Financial instruments


In our experience, these issues aresignicant to oil and gas companies for

the following reasons.

Issues may be pervasive across the

sector and will require signicant

time and cost to evaluate and

implement; for example, accounting

for E&E expenditure and assets.

Conversion may have a signicant

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 signicant 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 KPMGs 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.





Discussion PaperExtractive Activities

IFRS 6 Exploration for and Evaluation of

Mineral Resourceswas 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

Activitiesin 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

IASBs 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 signicant 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 teams specic proposals. The

responses to the discussion paper highlight the range of opinions

on the future of accounting for oil and gas operations under IFRS.




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 todays advanced technology,

exploration is a risky and complex activity.These factors create specic challenges

in accounting for E&E expenditure.

There was no IFRS that specically

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

dened methods: the successful

efforts method or the full cost method.

However, as there is no single accepted

denition 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 benet of IFRS 6,

expenditure would not be recognised

as an asset unless it is probable that

it will give rise to future economic

benets. 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.

Denition 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 betweennance and technical specialists.

Classication

Classication 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 classied 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-specic

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 ratabasis using reservevolumes or reserve values at transition

date.

This exemption can assist oil and gas

companies in preparing their rst IFRS

nancial 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 KPMGs

publication IFRS Handbook: First-timeAdoption of IFRS.

IFRS does not dene either successful efforts or modied full cost accounting, despite these

being the two most common accounting approaches applied by IFRS companies






Discussion Paper Extractive Activities

The Discussion Paper supported a separate accounting model for E&E costs in extractive industries. The views of

respondents varied signicantly on the approach that the IASB should take, and on the asset recognition model.

The project teams 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 didnt 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 sufciently

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 signicant majority

of respondents (88%) disagreed with the project teams view that the subsequent E&E activity would always represent an

enhancement of the asset.

Many of those respondents suggested that the project teams 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 benet 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 Equipmentand/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 difculties 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 veriable, can

be prepared in a timely manner and can be used to assess nancial 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 nancialstatements. It was also thought that the use of fair value would impose signicant preparation and audit costs that are not

justied 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.





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 signicant effort

Component accounting

Signicant 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 signicant 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 signicant

judgement.

An item of property, plant and

equipment should be separated into

components when those parts are

signicant in relation to the total costof the item. This does not mean that a

company should split its assets into an

innite number of components if the

effect on the nancial 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 eld; this is because each eld

may be signicant and the lives of the

elds, 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 reects

the pattern in which the economic

benets 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 reects the annual

production of a eld in proportion to the

estimate of reserves within that eld.

IFRS provides no specic 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

eld 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 eld is ready to

commence operations, since, in

effect, it is from this point that

economic benets 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.




DiscussionPaper Extractive

Activities

The scope of the discussion paper

did not specically 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.






3 Impairment of non-nancial assets


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 reclassication 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 specic area

is neither budgeted nor planned;

commercially viable reserves have

not been discovered and the company

plans to discontinue activities in thespecic 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 36Impairment of Assetsrequirescompanies

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 cashinows 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)

Identication of appropriate CGUs

can be complex

A CGUis the smallest group of

assets that generates cash inows

from continuing use that are largelyindependent of the cash inows 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

identication of CGUs on licence, eld

or core areas. For some companies that

operate a number of areas or elds that

have shared infrastructure and E&E

assets, the identication 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

signicantly or the company has

operating or cash losses. For

example, a signicant 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 companys net assets exceeds

its market capitalisation. This may be

a particular risk for companies with

large E&E assets.

Signicant 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.

Signicant 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 indenite useful

lives) for impairment at least annually,



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 inows independently of other

assets or group of assets and therefore

is not tested for impairment separately.

Instead, it should be allocated to the

acquirers CGUs that are expected to

benet 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 dened

in IFRS 8 Operating Segments, before

aggregation. An impairment loss

is recognised and measured at the

amount by which the CGUs 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.



Proposals maintain the exemption from applying

all requirements of IAS 36 to E&E assets

The project teams proposals relating to impairment

included the following.

l The indicators of impairment for E&E assets differ

from those in IAS 36.

l 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.

l 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

sufcient 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 difculties

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.





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 signicant

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 outow

of resources is probable. Probableisdened 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 difcult to

determine the extent of the obligation.

A constructive obligation may arisefrom a companys 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 nancial 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 prot 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 ows or discount rate used in

measuring the provision. The discount

rate should reect the risks specic 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 indenite useful lives, the timing

of decommissioning may be so distant

that the present value of liabilities is not

signicant. 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 signicant until the

expected date at which the facilities

will be decommissioned is less distant.

Signicant 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.




5 Joint arrangementsThe termjoint ventureis a widely used operational term, although not all such arrangements

are joint ventures for accounting purposes. A recently issued standard could signicantly

impact the accounting



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 termjoint ventureis 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 givesjoint 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

Arrangementsis governed by IAS 31

Interests in Joint Ventures. There are

three classications 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

KPMGs 2008 survey The Application of

IFRS: Oil and Gasthere 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

signicantly 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 classications of joint

arrangements under IFRS 11: Joint

ventures and joint operations. The

denitions of each category differ

from those in IAS 31. The classication

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 classication of the

arrangement for accounting purposes.

Joint venture

Ajoint ventureis 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 classication 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

Ajoint operation is an arrangement

in which the jointly controlling parties

have rights to assets and obligations for



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 classication

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.



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 specically 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 specic

guidance in IFRS.

These comments underline the

importance and accounting

complexities of risk-sharing

arrangements in the extractive

industries.




6 Revenue recognition


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 renery/

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 specied quantity and grade of oil

to be delivered at a specied location,

while simultaneously agreeing to sell

a specied 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 signicant 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 xed 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 companys entitlement, resulting

in an overlift (a lifting in excess of the

companys contractual allocation of

production) or an underlift (a lifting

less than the companys 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 satises 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, nancial 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 rst 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.




7 Reserves reporting


There is no specic 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 nancial statements, there are no

explicit requirements for the disclosure

of reserve information in IFRS.

Disclosures

In the absence of specic 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

classication, meaningful comparison

between companies would be difcult

without in-depth analysis of the

many assumptions inherent in the

core disclosures.

The US Securities and Exchange

Commissions rules require any issuer

providing disclosure under ASC 932-235

Extractive Activities Oil and Gas

Notes to Financial Statementsto

continue to provide that disclosure

even if the issuer is preparing nancial

statements in accordance with IFRS.

Impact of reserve estimates on

nancial 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 eld 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 prot

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 nancial statements,

oil and gas companies typically include

some information about reserves in the

critical estimates and judgements note

to the nancial statements.





DiscussionPaper ExtractiveActivities

Signicant disclosure requirements

proposed

The project teams proposals relating

to reserves reporting included

the following.

Use of Petroleum Resource

Management System (PRMS)

denitions 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.

Signicant 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 denition respondents

views

Most respondents agreed with

recommendations that industry-baseddenitions of reserves and resources

be used in any future IFRS to set

disclosures and complement the

accounting requirements. Most also

agreed with the PRMS denition.

Concerns raised related to the

approach for incorporating the

denition 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 teams proposal that reserves

estimates be prepared using a

market participants 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 signicant 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

signicant 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.





8 Financial instrumentsThe conversion process must include a review of the existence, classication and accounting

for nancial instruments, including derivatives. Future changes in the accounting are expected

Oil and gas companies generally have

nancial instrument accounting issues

owing to the signicant commodity

price risk that they face and the

structures in place to manage this

and other exposures such as currency

uctuations. A thorough review of theexistence, classication and accounting

for nancial instruments will be required

on conversion.

Current requirements

Accounting and disclosure

requirements may be signicantly

different from national GAAP

Contracts to buy and sell oil and gas

and other non-nancial items may be

included in the scope of the nancial

instruments standards. There is anexemption for contracts that are held

for physical delivery or receipt for

the companys expected purchase,

sale or usage requirements (the own

use exemption). However, specic

conditions must be met to apply this

exemption, and its applicability should

be reviewed carefully.

Specic 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 Measurementrequires nancial

assets to be classied into one of four

categories: at fair value through prot

or loss; loans and receivables; held to

maturity; and available for sale. Financial

liabilities are categorised as either

nancial liabilities at fair value through

prot or loss or other liabilities.

Financial assets and nancial 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 prot or loss except when

they qualify as hedging instruments in a

cash ow or net investment hedge.

A nancial asset is derecognised only

when the contractual rights to cash ows

from that particular asset expire or when

substantially all risks and rewards of

ownership of the asset are transferred.

A nancial liability is derecognised when

it is extinguished or when the terms are

modied substantially.

Forthcoming requirements/

Future developments

Simplied classications

In November 2009 the IASB published

the rst chapters of IFRS 9 Financial

Instruments, which will supersede

the requirements of IAS 39 Financial

Instruments: Recognition and

Measurementon the classication

and measurement of nancial assets.

In October 2010 requirements with

respect to the classication and

measurement of nancial liabilities and

the derecognition of nancial assets and

nancial 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 nancial 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 nancial

assets: amortised cost and fair value.

Other classications, such as held to

maturity and available for sale, have

been eliminated. The classication and

measurement requirements for nancial

liabilities are generally unchanged

other than a change to the treatment of

changes in fair value as a result of own

credit risk.





IASBs review of nancial

instruments accounting may result in

signicant changes in accounting

The IASB continues to work on

elements of its comprehensive nancial

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 nancial assets managed

in an open portfolio (the supplement).

The supplement proposes to replace the

incurred loss approach to impairment

of nancial assets with an approach

based on expected losses. Extensive

disclosures were also proposed.

The IASB issued Exposure DraftHedge Accountingin December 2010,

proposing signicant 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.





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-

specic solutions;

whether the system has been kept

current, as older versions rst 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

specications.

One of the difculties that oil and

gas companies may face in creating

technical specications is to understand

the detailed end-to-end ow 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 simplied

diagram below outlines a process thatorganisations can adopt to identify the

impact on information systems.




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 nancial 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 elds; 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 reclassications and additional reporting criteria.

Create new accounts and delete accounts that are no

longer required.

Reconguration of existing systems

Existing systems may have built-in capabilities for specic

IFRS changes, particularly the larger enterprise resource

planning (ERP) systems and high-end general ledger

packages.

Recongure existing software to enable accounting under

IFRS (and parallel local GAAP, if required).

Modications 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 nancial reporting process should

be included when considering the required systems

modications.

Make amendments such as:

new or changed calculations

new or changed reports

new models.

New systems interface and mapping changes

When previous nancial 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 nancial system. When

separate reporting tools are used to generate the nancial

statements, mapping these tools will require updating to

reect 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:

modications made to existing systems

the need to collect new data

the timing and frequency of data transfer requirements.






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

groups consolidated nancial statements. For example,

the application of the concept of control may be different

under IFRS (based on IFRS 10 Consolidated Financial

Statementsfrom 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 modied 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

nancial accounting packages.

Modify reporting packages and the accounting systems

used by subsidiaries and branches to provide nancial

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 nancial

statements based on data transferred from the general

ledger; or

prepare only the nancial statements based on receipt of

consolidated information from the general ledger.

Modify:

reporting tools used by subsidiaries and branches to

provide nancial 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 reect 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 specications of

the xed 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-

nancial assets

Impact on impairment models for any changes to CGUs on transition.

Selection of impairment model with links to tax, nancing etc.

Decommissioning

and environmental

provisions

Impact on the interface with E&E and development assets to reect work progress and

changes in estimates as extraction occurs.

Accounting systems need to identify discount rates specic to each liability and this may

lead to changes in the sub-ledger and provision calculation models as well as the generalledger.




Accounting differences Potential systems and process impact

Joint arrangements Identication 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 nancial statements.

Revenue recognition Clear identication 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.






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 ow

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 rst 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 rst day of the year in which

IFRS reporting commences.

Real-time reporting of two GAAPs

in comparative year has benets,

but puts more stress on the nancegroup.

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.





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.




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.


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.




People: Knowledge transfer and change management


When your company reports for the rst time under IFRS, the preparation of those nancial

statements will require IFRS knowledge to have been successfully transferred to the nancial

reporting team. Timely and effective knowledge transfer is an essential part of a successful and

efcient 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

changes that are needed under the IFRS

reporting regime.

The success of the project will depend

on the people involved. There needs to

be an emphasis on communications,

engagement, training, support and

senior sponsorship, all of which are part

of change management.

Training should not be underestimated

and companies often dont fullyappreciate the levels of investment and

resource involved in training. Although

most conversions are driven by a central

team, you ultimately need to ensure that

the conversion project is not dependent

on key individuals and is sustainable

in the long term across the whole

organisation. Distinguishing between

different audiences and the nature

of the content is key to successful

training. The following are some useful

knowledge transfer pointers.

Training tends to be more successful

when tailored to the specic needs of

the company. Few companies claim

signicant benet from external non-

tailored training courses.

Geographically disparate companies

are considering web-based training as

a cost- and time-efcient method of

disseminating knowledge.

More complex areas such as revenue

recognition or accounting for

exploration expenditure tend to bebest conveyed through workshop

training approaches in which

company-specic issues can be

tackled.

Many companies manage their

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KPMG. Impact of IFRS. Oil and Gas

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