Information Guide on
Adoption and Implementation of
International Financial
Reporting Standards
for the Canadian Upstream
Oil and Gas Industry
Additional support provided by:
February 2009
International Financial Reporting Standards
Information Guide
Small Explorers and Producers Association of Canada
Contents
Table of Contents
Purpose and Scope . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1
Section 1 — Exploration and Evaluation Expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .11
Section 2 — Componentization of Oil and Gas Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18
Section 3 — Basis and Calculation of Depletion, Depreciation and Amortization . . . . . . . . . . . . . . . .22
Section 4 — Cash Generating Unit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .27
Section 5 — Basis and Application of Impairment Tests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .33
Section 6 — Decommissioning Liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .47
Section 7 — Issues Specific to In-situ Heavy Oil and Oil Sands . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .55
Section 8 — Issues Specific to Oil Sands Mining Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .60
Section 9 — Oil and Gas Assets — Transitional Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .63
Appendices
Appendix A — Sources of Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .74
Appendix B — Contributors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .75
Canadian Association of Petroleum Producers
International Financial Reporting Standards
Information Guide
Disclaimer
This Information Guide (Guide) and the information contained herein are provided for general
information purposes only. Presentation of the information does not constitute a legal or any other
form of relationship among the Canadian Association of Petroleum Producers (CAPP), the Small
Explorers and Producers Association of Canada (SEPAC) (collectively, the Sponsors) and users of
the information.
The views expressed in this Guide are solely those of the Sponsors and the individuals and oil and
gas enterprises that assisted in its development. Since the Guide presents information in summary
form, it is not intended as a substitute for detailed research and professional judgment and advice.
Before making any decision or taking any action that might affect your organization or business,
you should seek the services of a qualified professional advisor.
The information contained in the Guide is provided on an “as is” basis. While the Sponsors have
used their best efforts to furnish up-to-date and accurate information, they do not warrant that the
information contained herein is accurate, complete, current or error-free. Your use of the Guide is
at your own risk and you assume full responsibility for risk of loss resulting from its use, including
any indirect, incidental, consequential or punitive damages which you might suffer as a result of
your reliance upon information contained herein.
February 2009
Small Explorers and Producers Association of Canada
PURPOSE AND SCOPE
Canadian upstream oil and gas companies have traditionally accounted for exploration and
development costs using either the “full cost” or “successful efforts” accounting method. With the
adoption of International Financial Reporting Standards (IFRS), full cost oil and gas companies will
be expected, for the most part, to abandon or significantly change their current accounting policies.
In developing this Guide, the Canadian Association of Petroleum Producers (CAPP) and the Small
Explorers and Producers Association of Canada (SEPAC), (collectively, the Sponsors), in conjunction
with industry participation in work groups assigned responsibility for analyzing the issues and
making recommendations, have attempted to present a general overview of IFRS with respect to
recognition and measurement of oil and gas assets and to provide what it considers a “best
practices” solution to the relevant issues. The Sponsors recognize that current IFRS permit upstream
oil and gas companies certain choices in selecting accounting policies and, accordingly, neither
recommend nor discourage the use of methods of accounting that comply with IFRS but are
inconsistent with the views contained herein. Furthermore, since various policy choices are available
under IFRS, particularly in respect of IFRS 6 “Exploration for and Evaluation of Mineral Resources”,
and interpretations under International Accounting Standards (IAS) 36 “Impairment of Assets” are
expected to vary among industry participants, the Sponsors recommend timely consultation
between management and professional advisors in conjunction with conversion to and
implementation of IFRS.
The Guide intentionally does not deal with IFRS and methods of accounting for mining processes and
the midstream and downstream businesses of transporting, refining and marketing of oil and gas and
related products. In addition, the Guide is limited in scope only to the recognition and measurement
of oil and gas exploration and development or production assets, including related integrated
facilities, and does not attempt to address any unassociated IFRS.
The Guide focuses attention on the historical “cost” accounting model alternative and not on
the “revaluation” accounting model, which in the Sponsor’s view is expected to be limited in its
application by the Canadian upstream oil and gas industry. The revaluation method is discussed in
detail in the following standards issued by the International Accounting Standards Board (IASB):
IAS 16 “Property, Plant and Equipment” and IAS 38 “Intangible Assets” and the underlying
requirements are stringent. Entities contemplating adopting the revaluation method should
consult with their professional accounting advisors.
As public upstream oil and gas entities assess the impact of implementation of IFRS, they must be
aware that conversion will involve more than an exercise in accounting for oil and gas assets and
expenditures. Entities will be required to assess the potential effects the implementation of IFRS,
including proposed future changes, will have on their accounting and reporting, business processes
and people. The Guide does not attempt to address these issues.
The Canadian Accounting Standards Board
The Canadian Accounting Standards Board (AcSB) will require Canadian public companies to adopt
IFRS no later than fiscal years beginning on or after January 1, 2011. It will incorporate IFRS into the
Handbook of the Canadian Institute of Chartered Accountants (CICA) in full and without modification.
The AcSB proposes to update the Handbook from time to time, as necessary, so that it contains
the complete and current body of IFRS in effect.
It is expected that IFRS will replace Canadian generally accepted accounting principles (GAAP) for
publicly accountable entities, including Canadian public companies whose businesses and activities
are centred in the extractive industries.
The AcSB has stated its views that Canadian GAAP should be the same as IFRS and IFRS 1 “First-time
Adoption of International Financial Reporting Standards” provides certain transitional guidance and
relief for entities applying IFRS for the first time only when an entity is in a position to make an
explicit and unreserved statement of compliance with IFRS.
Canadian Association of Petroleum Producers
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With the adoption of
International Financial
Reporting Standards (IFRS),
full cost oil and gas companies
will be expected, for the
most part, to abandon or
significantly change their
current accounting policies.
International Financial Reporting Standards
Information Guide
The Industry Position
Without this amendment,
Canadian entities would be
required to determine historic
cost for their oil and gas
assets under IFRS or use
fair value measures.
In a submission dated January 30, 2008 to the AcSB and IASB, the Sponsors requested an
amendment to IFRS 1 for an exemption that would allow Canadian oil and gas industry entities
following the full cost method of accounting to use the net book value of oil and gas assets (oil and
gas assets comprise assets in both the exploration and evaluation phase and in the development
or production phase) under previous Canadian GAAP as the opening net book value of oil and
gas assets under IFRS at transition, subject to impairment testing and other adjustments for
decommissioning and restoration. Without this amendment, Canadian entities would be required to
determine historic cost for their oil and gas assets under IFRS or use fair value measures. The
submission was supported by the IFRS Oversight Committee, a Committee established by the
Sponsors to act as liaison with other stakeholders in the financial reporting community on behalf
of the Canadian upstream oil and gas industry.
The submission described the time consuming, costly and difficult tasks associated with
reconstructing historical accounting records and noted, “the required historical data, including
operating, capital and acquisition costs, and production and reserves information, would rarely be
available at a sufficiently detailed level in order to make a reasonable allocation. Some, and possibly
extensive, estimates and allocations of prior costs would be inevitable as the detailed information to
create certain subledgers is not accessible or no longer exists. Accordingly, allocations of prior sunk
costs to fixed asset subledgers regardless of the allocation basis would then be inaccurate in the
detail. …The cost to recreate the fixed assets subledgers would significantly exceed [the] benefits
to stakeholders. … [In addition], it would be costly, and in some cases not possible, to recreate the
reserves [reports] of prior periods at a level of detail sufficient for IFRS.”
Further information on the AcSB submission, including the expected decision of the IASB,
is included in Section 9 of the Guide.
IFRS Framework and Basic Principles
The IFRS Framework states that the objective of financial statements is to provide information about
the financial position, performance and changes in financial position of an entity that is useful to a
wide range of users in making economic decisions. The authoritative literature includes: IFRS, IAS,
International Financial Reporting Interpretation Committee Interpretations (IFRIC) and Standing
Interpretations Committee Interpretations (SIC).
The underlying assumptions used in IFRS are:
• Accrual basis — the effect of transactions and other events are recognized when they occur,
not as cash is received or paid, and
• Going concern — the financial statements are prepared on the basis that an entity will continue
in operation for the foreseeable future.
The Framework describes the qualitative characteristics of financial statements as being
understandability, relevance, reliability and comparability, and the elements of financial statements
as comprising:
• Assets — resources controlled by the entity as a result of past events and from which future
economic benefits are expected to flow to the entity
• Liabilities — a present obligation of the entity arising from past events, the settlement of which
is expected to result in an outflow from the entity of resources embodying economic benefits
• Equity — the residual interest in the assets of the entity after deducting all its liabilities
• Income — the increases in economic benefits during the accounting period in the form of inflows
or enhancements of assets or reductions in liabilities that result in increases in equity, other than
those relating to contributions from equity participants, and
• Expenses — the decreases in such economic benefits.
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Small Explorers and Producers Association of Canada
Purpose and Scope
Emanating from the Framework are the building blocks to initial asset recognition: basic approach,
asset definition, unit of account selection and disclosure. Each of these building blocks in respect of
upstream oil and gas activities is discussed further in the Guide.
IFRS does not provide specific
guidance on the determination
of appropriate units of account
In the extractive industries the definition of a unit of account is important and plays a significant
role in deciding whether or not certain costs may be capitalized (recognition and derecognition),
determining the rate of amortization and impairment testing. IFRS does not provide specific
guidance on the determination of appropriate units of account and, therefore, the selection process
will require considerable judgment. Since judgments are necessary, disclosure may be required
under IAS 1 “Presentation of Financial Statements” of the choices “that management has made in
the process of applying the entity’s accounting policies that have the most significant effect on
the amounts recognized in the financial statements”.
and, therefore, the selection
process will require
considerable judgment.
IFRS 1
IFRS 1 requires an entity to comply with all IFRS effective at the reporting date of the entity’s first
annual financial statements prepared and presented in accordance with IFRS, including the balance
sheet at the beginning of the earliest comparative period. Thus, for an entity adopting IFRS for the
first time on January 1, 2011, it will be necessary to prepare and present a comparative opening
balance sheet under IFRS as at January 1, 2010. In the comparative opening balance sheet, an
entity must:
Thus, for an entity adopting
• Recognize all assets and liabilities that IFRS require be recognized
balance sheet under IFRS as
• Derecognize from assets and liabilities those items for which IFRS do not permit recognition
at January 1, 2010.
IFRS for the first time on
January 1, 2011, it will be
necessary to prepare and
present a comparative opening
• Reclassify items when, in accordance with the GAAP previously followed by the entity, they
would have been presented differently from how they would be presented in accordance with
IFRS, and
• Apply IFRS in remeasuring all recognized assets and liabilities.
The underlying principle in IFRS 1 is that a first time adopter should prepare and present financial
statements as if it had always applied IFRS, i.e., retrospective adjustment of accounts; however, there
are certain exemptions to the general principle which would allow prospective application. IFRS 1 also
prohibits retrospective application in certain areas, particularly when such application would require
judgments by management about past conditions after the outcome of a particular transaction or
event is already known, and when the cost of complying would exceed the benefits provided to
financial statement users. Exemptions are and will continue to be included in amendments to IFRS 1.
All comparative financial information for each quarter of 2010, as well as for the full year, will
need to be publicly reported subsequent to transition to IFRS in 2011. This will require companies
to initially prepare and present the 2010 interim financial statements in accordance with Canadian
GAAP and, in addition, to prepare the results in parallel under IFRS for purposes of comparative
reporting in 2011.
IFRS 6
An important standard for enterprises engaged in upstream oil and gas activities is IFRS 6 issued
by the IASB in December 2004. The IASB released this standard since an increasing number of
companies incurring exploration and evaluation (E&E) expenditures were issuing financial statements
stating they had been prepared in accordance with IFRS when no related IFRS oil and gas asset
recognition and measurement standard existed. Recognizing the importance of accounting for
extractive industries, and pending a detailed analysis of the issues and obtaining input from
stakeholders, the IASB determined that IFRS 6 would avoid unnecessary disruption to both preparers
and users and limit the need for entities to change their existing national accounting policies for
E&E activities by:
Canadian Association of Petroleum Producers
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International Financial Reporting Standards
Information Guide
• Making limited improvements to accounting practices for E&E expenditures
• Specifying the circumstances in which enterprises that recognize E&E assets should test such
assets for impairment under IAS 36, and
• Requiring such enterprises to disclose information about E&E assets, the level at which those
assets are assessed for impairment, and any impairment losses recognized.
The limited scope of IFRS 6
only provides relief to
entities for accounting
policies in respect of E&E
activities and does not
extend to extractive oil and
gas activities before or
after the E&E phase.
The limited scope of IFRS 6 only provides relief to entities for accounting policies in respect of E&E
activities and does not extend to extractive oil and gas activities before or after the E&E phase.
In accordance with IFRS 6, the result of changing accounting policies in respect of E&E expenditures
for the majority of Canadian upstream oil and gas companies will be to move closer to conformity
with the IFRS Framework and is expected to result in an improvement in comparability within the
industry with financial statements becoming more relevant and no less reliable (or more reliable and
no less relevant) to the economic decision-making needs of users. Clear disclosures of the IFRS 6
changes will be required.
Section 1 of the Guide provides an analysis of the issues and choices available to entities in the
application of IFRS 6 that will require consideration in conjunction with the selection of appropriate
accounting policies for E&E activities. Section 5 addresses impairment issues with respect to
measurement of E&E and development or production assets. Section 9 provides a possible
framework for the application of IFRS 1 in respect of oil and gas assets on the basis the IASB’s
Exposure Draft to amend IFRS 1 is approved. The wording of the proposed amendment, its
implications and an illustrative example are also included.
Risks and Assessments
The adoption of IFRS by
the Canadian oil and gas
industry will present a
number of business
The adoption of IFRS by the Canadian oil and gas industry will present a number of business
challenges that greatly exceed the required changes in accounting and disclosure. The Sponsors
have identified certain risks and assessment needs that are expected to be pervasive throughout the
industry and recommend Managements and Boards of Directors develop and implement a strategic
plan to mitigate potential risks through a robust assessment of IFRS implementation challenges.
challenges that greatly
exceed the required
changes in accounting
and disclosure.
Risks
Assessments
• Poor planning and delayed conversion execution
• Develop a strategic plan
• Underestimating the magnitude of the
changeover on all aspects of the business
(information systems and processes, external
reporting, contracts, corporate finance and
debt covenants, executive compensation,
investor relations, tax planning, etc.)
• Introduce an IFRS change management process
• Incorrect and/or incomplete opening IFRS
adjustments (identification and quantification)
• Consider European Union experiences
• Evaluate overall business impacts
• Develop an IFRS employee training strategy
• Evaluate buy-in from all departments, top
management and the Board
• Lack of guidance in the application of IFRS
leading to inconsistencies in accounting policies
within the industry (identification of cash
generating units, impairment triggers and
testing processes, reserves definitions and
models, discounting mechanisms, etc.) and
financial statement disclosures
• Differences in choices among recognition,
measurement and valuation of E&E
expenditures
• Loss of reputation, investor confidence
and/or key employees
• Increased regulation
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• Complete a detailed gap analysis between current
and IFRS reporting
• Evaluate accounting systems requirements and
IT capabilities
• Assess impact on internal controls and external
reporting requirements
• Consider IFRS accounting policy choices and
future impact of decisions
• Develop transparent communication strategy
with stakeholders, especially the investment
community
• Assess ability to proactively respond to future
changes
Small Explorers and Producers Association of Canada
Purpose and Scope
Reserves
Although neither the AcSB nor the IASB has established reserves classifications for the oil and
gas industry, reserves classifications used by regulators are the principal basis for communicating
information to users regarding the status of upstream oil and gas extractive activities.
Reserves classifications
There are currently various classifications and definitions of crude oil “reserves” in existence.
Among them:
communicating information
• Proved — 1P (assumes at least a 90% probability that the quantities ultimately recovered will
equal or exceed the estimated proved reserves)
of upstream oil and gas
used by regulators are
the principal basis for
to users regarding the status
extractive activities.
• Proved plus Probable — 2P (at least a 50% probability of ultimate recovery), and
• Proved plus Probable plus Possible — 3P (at least a 10% probability of ultimate recovery).
For purposes of this Guide, all references to “reserves”, unless otherwise stated, are to 2P reserves.
When in Doubt — Consult
IFRS are considered a principles-based set of standards in that they establish broad rules as well as
specific treatments. In the absence of specific treatments, entities should consider the Framework
and Basic Principles (as briefly set out above) in conjunction with accounting and financial reporting
matters requiring new or different decisions. For companies currently following full cost accounting,
a consultation process will be important and beneficial because of the number of choices that are
currently permitted under IFRS in respect of the selection of accounting policies for recognition and
subsequent measurement of oil and gas assets. Companies will need to assess and adopt the policies
that are the most appropriate to their individual needs and circumstances and management will
need to understand the current and future impact of the choices and ensure there is sufficient
documentation to support the recommended choice or decision. It will be important to choose the
right accounting policies the first time since, once adopted, future changes will be permitted only if
the new policy significantly improves financial reporting to shareholders.
Judgment on how to apply
The Sponsors recommend that senior management, industry colleagues and associations, and
external auditors be consulted on issues that are not addressed within the authoritative literature
encompassed by IFRS since judgment on how to apply IFRS principles may be required in certain
circumstances. In addition, all significant financial reporting issues and IFRS transition decisions
should be discussed with external auditors and approved by an entity’s Audit Committee.
IFRS principles may be
required in certain
circumstances.
Summary of Conclusions
Canadian public upstream oil and gas companies face a challenging transition to IFRS as they
significantly change their current accounting policies and perhaps their business practices. Oil and
gas accounting is complex and IFRS permit a variety of choices with respect to accounting for E&E
expenditures. Other policy choices are available in respect of accounting for costs before and after
the E&E phase, but none is expected to rival the choices available within the E&E bounds. The
challenge for the upstream oil and gas industry is to prepare and present financial statements
that are comparable and useful to decision makers, investors and other stakeholders. This can be
accomplished through effective presentation and disclosure, a cornerstone of IFRS; however, due
to the available accounting policy choices and their application, inconsistencies among reporting
entities are expected to continue.
As increasing familiarity with IFRS is developed throughout the upstream oil and gas industry, the
diversity of differences arising after transition is expected to narrow. IFRS prescribes minimum
standards of disclosure, which in turn requires companies to fully explain any unusual transactions
and circumstances. Furthermore, accounting policy choices made by companies have to be disclosed
in detail thereby helping users compare companies.
Canadian Association of Petroleum Producers
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International Financial Reporting Standards
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Companies need to be actively engaged in preparation for implementation of IFRS and the priority
is immediate. Although fundamental financial reporting remains essentially the same and IFRS
covers similar areas to current Canadian GAAP, it is the details that are considerably different.
Managements need to become familiar with the standards and consider which details are likely
to be relevant to their businesses, e.g., cause transitional and/or implementation issues.
The Guide provides an
overview of choices
available to companies as
they prepare for and
implement IFRS.
The Guide provides an overview of choices available to companies as they prepare for and implement
IFRS. The following Summary of Conclusions makes suggestions, where practicable, as to what the
Sponsors consider “best practices” but recognizes that certain entities may choose other available
options that more closely align with their individual businesses and management’s investment and
operating decisions. Completion of a diagnostic assessment of the full impact of IFRS changes,
including development of a comprehensive implementation plan, will be critical to a successful
transition and is highly recommended.
Section 1 — Exploration and Evaluation Expenditures
• IFRS 6 is the most important standard that will require careful consideration by management
of upstream oil and gas companies in conjunction with the transition to IFRS.
• Costs incurred in the exploration and evaluation (E&E) phase must be recognized under IFRS 6
and not under any other IFRS standard.
• Several choices of accounting policies for E&E expenditures and their method of application are
available, e.g., cost model or revaluation model, capitalize or expense, amortize or not.
• Both pre-E&E phase expenditures and post-E&E phase expenditures are outside the scope
of IFRS 6:
– Pre-exploration expenditures are expensed except in rare and limited circumstances; and
– Post E&E phase expenditures, i.e., development or production expenditures, are normally
capitalized provided they meet the recognition requirements of IAS 16.
• Capitalized E&E costs should be segregated between intangible and tangible classes since this
distinction must carry over to the measurement of development or production assets.
• There should be consistency of accounting for E&E expenditures by type of expense category in
identified E&E cash generating units.
• E&E assets must be tested for impairment at transition to IFRS.
• E&E assets must be reviewed at each subsequent financial reporting period for indicators of
impairment (and tested if impairment indicators are present).
• Impairment charges of E&E assets must be reversed if conditions change.
• Upon completion of the E&E phase, successful capitalized E&E costs must be tested for
impairment and reclassified to development or production assets; unsuccessful capitalized E&E
costs would normally be expensed, subject to the entity’s chosen accounting policy.
• Capitalized E&E costs may be kept whole and intact until:
– It is determined that the property contains mineral reserves, at which time the costs are
reclassified to development or production assets (subject to an impairment test); or
• It is determined that no future economic benefits will result or the outcome is uncertain.
• Best practice suggests that when E&E expenditures are determined to have no future economic
benefits they should be expensed and the specific E&E assets derecognized.
• Detailed disclosures are required.
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Small Explorers and Producers Association of Canada
Purpose and Scope
Section 2 — Componentization of Oil and Gas Assets
• Components and parts (physical and non physical) of an asset having a cost that is significant in
relation to the total cost of the asset should be identified and separately amortized over their
estimated useful lives.
• The estimated cost of major or significant components (including applicable costs such as labour,
engineering and consulting fees) should be separately identified and apportioned from the original
cost of the asset.
• Borrowing costs incurred to acquire or construct qualifying assets must be capitalized.
• Annual reviews of the estimated lives of assets and associated residual values and depreciation
methods must be conducted.
• Assets and their component parts should be derecognized when replaced or disposed.
• Asset apportionments and aggregations, including related cost / benefit analyses, require careful
management consideration.
• Increased disclosure is required.
Section 3 — Basis and Calculation of Depletion, Depreciation and Amortization
• Components of property, plant and equipment (PP&E) with a cost significant in relation to the
total cost of the related assets must be amortized separately over their estimated useful lives.
• Useful life of PP&E is defined in terms of an asset’s availability or expected utility to the
business, not economic life.
• The amount subject to depletion, depreciation and amortization (DD&A) is determined as the
cost of the asset less its residual value.
• DD&A should commence once an asset has achieved commercial viability, where commercial
viability is generally recognized as occurring when the asset is in the location and condition
necessary for it to be capable of operating in the manner for which it is intended by management.
• DD&A of development or production assets using the unit-of-production method would normally
commence once the asset has achieved commercial viability and reserves are being produced.
• The carrying value of a significant component of PP&E that is replaced must be derecognized.
• Although options are available under IFRS, entities may use proved plus probable (2P) reserves
estimates for long term planning and unit of production DD&A measurement.
• The selection of reserves, i.e., 2P, and related commodity pricing, as well as componentization
criteria are important considerations in establishing DD&A methods and rates and providing
information for stakeholders.
• The rate and method of DD&A should be reviewed at a minimum at the entity’s financial year-end.
• Increased and detailed disclosures are required.
Section 4 — Cash Generating Unit
• A cash generating unit (CGU) is the smallest identifiable asset or group of assets that generates
largely independent cash inflows.
• CGUs play a crucial role in impairment testing.
• The foremost consideration in identifying a CGU for the post-E&E phase is the IAS 36 definition
of a CGU; secondary considerations are asset allocations, asset aggregations and related cost /
benefit analyses.
• IFRS 6 provides for a flexible identification of CGUs in the E&E phase and on transition to the
post-E&E phase provided the identified CGU is not at a level higher than an operating segment.
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• Identification of CGUs requires careful management consideration and is entity-specific.
• Practice to date has evolved limited financial statement disclosure of CGU identification; however
significant disclosure is required in respect of CGU impairment.
• A field or a specifically defined area of interest may be an acceptable approach by Canada’s
upstream oil and gas industry for purposes of identifying a post-E&E phase CGU subject to
management’s consideration of the IAS 16 definition of a CGU,
Section 5 — Basis and Application of Impairment Tests
• Impairment tests are carried out and impairment losses are recognized to ensure the carrying
value of an entity’s assets do not exceed their recoverable amounts.
• Recoverable amount is the higher of fair value less costs to sell (FVLCTS) and value in use (VIU)
as defined in IAS 36.
• If either FVLCTS or VIU is higher than carrying value, no impairment exists.
• IFRS 6 sets out indicators of impairment to consider in assessing whether E&E assets are
impaired; the actual impairment amount is determined following guidance in IAS 36.
• Each entity must determine an accounting policy under IFRS 6 for recognition and subsequent
measurement of E&E assets and the policy must be applied consistently and disclosed.
• E&E assets may be allocated to and aggregated in a single CGU or group of CGUs up to an
operating segment level for purposes of impairment testing.
• Best practice suggests that when E&E expenditures are determined to have no future economic
benefits they should be expensed and the specific E&E assets derecognized.
• IAS 36 is the standard covering impairment of property, plant and equipment including oil and
gas assets, intangible and indefinite life assets and goodwill.
• Impairment indicators are different for E&E assets than for other assets.
• Impairment tests are determined under IAS 36 by reference to FVLCTS or VIU.
• For the upstream oil and gas industry, discounted cash flow may become the most common
method used as a starting point for assessing impairment of development or production assets.
• The IASB’s Exposure Draft to amend IFRS 1 proposes that impairment tests of E&E assets and
development or production assets will be required at transition to IFRS regardless of whether or
not impairment indicators have been identified.
• Subsequent to transition, impairment tests are required when indicators of impairment are
present and mandatory upon reclassification of E&E assets to development or production assets.
• Intangible assets with indefinite lives and goodwill must be tested for impairment at least annually
and goodwill must be tested at the same time each year.
• Previously recognized impairment charges must be reversed if conditions change (except goodwill
impairment is never reversed), including the related change in accumulated DD&A resulting from
the impairment reversal.
• Current market conditions and readily available market data, reserves categories, future cost
and pricing assumptions, and discount rates are important determining factors in completing
impairment tests for development or production assets.
• Increased and detailed disclosures are required.
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Small Explorers and Producers Association of Canada
Purpose and Scope
Section 6 — Decommissioning Liabilities
• Provisions for decommissioning and restoration liabilities should be recognized when an entity
has identified a present obligation (legal or constructive) arising from a past event, it is probable
that an outflow of resources will be required to settle the obligation, and a reliable estimate of
the obligation can be made.
• Both legal and constructive obligations must be considered when recognizing decommissioning
and restoration liabilities.
• The discounted cost of dismantling and removing an asset associated with the construction of
the asset should be recognized in the original cost of that asset and as a liability (however, under
the IASB’s Exposure Draft to amend IFRS 1, any measurement difference at transition between an
entity’s current GAAP and IAS 37 “Provisions, Contingent Liabilities and Contingent Assets” must
be determined and charged to retained earnings).
• Provisions are required in respect of PP&E and intangible and tangible oil and gas assets
including, if practicable, indefinite life assets.
• An appropriate discount rate to be used in measuring the obligation is one that includes current
market assessments of the time value of money and those risks specific to the liability that have
not been reflected in the best estimate of the expenditure.
• Changes in the estimated timing of cash flows of resources necessary to discharge the obligation
and changes in the discount rate are added to or deducted from the cost of the related asset and
the adjusted amounts are amortized prospectively over the estimated useful life of the asset.
• The unwinding of the discount arising from the passage of time is recognized as a financing cost
and cannot be capitalized.
• Expenditures for dismantling or removing equipment or restoring a site should be expensed when
they result from operating activities and capitalized when they are associated with drilling or
construction activities.
• Detailed disclosures continue to be required.
Sections 7 and 8 — Issues Specific to In-situ Heavy Oil, Oil Sands and Oil Sands Mining
Operations
• There is currently no guidance from the IASB in respect of reserves quantities and pricing
determinations for in-situ heavy oil and oil sands producers.
• Differences in various accounting policies currently followed by these producers are expected to
continue, subject only to overall IFRS compliance, until the IASB Extractive Industries Research
Project is completed.
• Increased and detailed disclosures are required.
Section 9 — Oil and Gas Assets — Transitional Issues
• The proposed IFRS 1 amendment, if approved by the IASB, will permit companies currently
following full cost accounting to elect to measure oil and gas assets at transition at historical
cost without retroactive application.
• At transition, companies must identify and segregate oil and gas assets into E&E assets and
development or production assets.
• Identified E&E assets may be carried forward at the amount determined under the entity’s
previous GAAP.
• Impairment tests of E&E assets and development or production assets will be required at
transition regardless of whether impairment indicators have been identified with any impairment
amounts being charged directly to retained earnings.
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• In the event the proposed amendment to IFRS 1 is passed and the election is used, at transition
an entity will have to:
– Carry forward development or production assets at the amount determined under the entity’s
previous GAAP and allocate the amount pro rata to the underlying assets (intangible and
tangible) using reserves volumes or reserves values
– Recognize the difference, if any, between decommissioning liabilities measured in accordance
with IAS 37 and decommissioning liabilities measured under the entity’s current GAAP and
charge the difference (plus or minus) directly to retained earnings, and
– Disclose that the entity has elected its deemed cost for oil and gas assets as the carrying
amounts determined under the entity’s previous GAAP, including the basis of allocation.
• Asset impairment amounts and measurement changes in decommissioning liabilities at transition
must be disclosed.
• Detailed disclosures with respect to IFRS 1 exemptions, measurement of oil and gas assets,
impairments and other adjustments and reconciliations from previous GAAP are required in
sufficient detail to allow readers to understand material changes in the entity’s financial
statements.
• Section 9 includes an oil and gas asset transitional example which may require modification if
the proposed IASB exposure draft is amended following the comment period.
The Future
Changes in accounting
for oil and gas assets are
only one of the changes
facing the industry as
the IFRS world continues
to evolve.
Changes in accounting for oil and gas assets are only one of the changes facing the industry as
the IFRS world continues to evolve. In addition to the Extractive Industries Research Project, which
could be finalized by 2014, more than a dozen projects are currently under review by the IASB. By
2011, new or modified standards are expected to be promulgated on such matters as consolidation,
revenue recognition, leases, earnings per share, related party disclosures, liabilities, emissions,
income taxes, joint arrangements and fair value measurement guidance, to name but a few. In
addition, the Securities and Exchange Commission (SEC) has publicly announced a Road Map, having
several milestones, that would allow the United States to stage-in the adoption of IFRS for SEC
registrants in the period from 2014 to 2016. This may result in further changes to standards and
interpretations as the IASB, SEC and Financial Accounting Standards Board (FASB) negotiate and
harmonize current differences and progress continues toward convergence of world-wide financial
reporting standards. These changes may have further significant effect on the Canadian oil and
gas industry and managements are encouraged to keep informed of developments.
Canadian entities should become aware of and consider potential changes in IFRS standards, both
before and after 2011, and factor those considerations into accounting policy choice decisions on
adoption of IFRS in order to lessen further changes.
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Small Explorers and Producers Association of Canada
SECTION 1 — EXPLORATION AND
EVALUATION EXPENDITURES
Background
Until the IASB issued IFRS 6 “Exploration for and Evaluation of Mineral Resources”, there was no
standard that addressed accounting practices for the extractive industries, in particular for costs
incurred in the exploration and evaluation (E&E) of mineral resources. The release of IFRS 6
effectively removed the recognition and measurement of E&E costs from the scope of IAS 38
“Intangible Assets” and IAS 16 “Property, Plant and Equipment”.
The purpose of IFRS 6 was to address, on a short term basis only, certain accounting issues in
relation to E&E costs until the IASB could undertake a more comprehensive review of accounting
practices within the extractive industries. This review is not expected to be completed until 2014,
i.e., after IFRS has been adopted by Canadian public oil and gas companies in 2011.
IFRS 6 allows an entity to determine an accounting policy for E&E expenditures based on its current
national generally accepted accounting principles (GAAP). As such, IFRS 6 does not refer specifically
to the successful efforts method or the full cost method of accounting, either of which is acceptable
under current Canadian GAAP. A review of financial statements prepared under IFRS indicates limited
disclosure with respect to the practice of capitalizing or expensing E&E expenditures, only which
policy has been selected and the related recognition and measurement criteria.
Principles
The following guidance should be considered in conjunction with recognition and measurement of
E&E expenditures under IFRS:
E&E costs must be
• Costs incurred prior to obtaining a right or licence to explore (the pre-exploration phase) are not
included in E&E costs and may be either:
post-exploration costs,
segregated from both
i.e., those costs incurred
– Expensed, or
in the development or
– Capitalized, in those rare and limited circumstances where the costs meet the definition of an
intangible asset under IAS 381
production phase, and
pre-exploration costs.
• Costs incurred in the E&E phase must be accounted for under IFRS 6 and not under any other
standard
• E&E costs must be segregated from both post-exploration costs, i.e., those costs incurred in the
development or production phase, and pre-exploration costs
• E&E costs may be capitalized according to category or class of expenditure, or expensed,
depending on the entity’s selected accounting policy
Offshore oil rig
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• Capitalized E&E expenditures must initially be measured at cost. After recognition as assets an
entity may apply either the cost model or revaluation model to those costs in accordance with
the entity’s selected accounting policy2
• Capitalized E&E costs should normally be segregated between intangible and tangible asset classes
• When tangible E&E assets are consumed in the development of intangible E&E assets the amount
reflecting the consumption may form part of the cost of the intangible asset.
• Capitalized E&E costs should be reviewed for indicators of impairment at each reporting period;
if such indicators are determined to exist (by reference to IFRS 6) an impairment test is required
by reference to IAS 36 “Impairment of Assets” — see Section 5
• Upon completion of the E&E phase, an IFRS 6 impairment test must be completed by reference
to IAS 36 and successful capitalized E&E costs that have been tracked at a lower level, net of
any impairment charge, must be reclassified to development or production assets, and
• Costs incurred subsequent to completion of the E&E phase are accounted for under IAS 16 and/or
other applicable standards, not IFRS 6.
In conjunction with the selection of an accounting policy for E&E expenditures that must be consistently followed, entities are encouraged to consider the requirements of IAS 8 “Accounting Policies,
Changes in Accounting Estimates and Errors”, IAS 16, IAS 23 “Borrowing Costs”, IAS 36, IAS 37
“Provisions, Contingent Liabilities and Contingent Assets”, and IAS 38.
1
Practice in the UK indicates that reporting companies surveyed by KPMG in its 2007 publication “Assessing the Impact —
Adoption of IFRS 6: Exploration for and Evaluation of Mineral Resources by Oil & Gas Companies” — all wrote off pre-licensing
costs. However, it may be appropriate to capitalize these costs if the conditions set out in IAS 38 can be met. The criteria for
treatment as an intangible asset include identification, control and existence of future economic benefits. Examples might
include field seismic programs, purchased seismic data, geological and geophysical studies or internally-developed innovative
technology, but there could be others that would qualify. For instance, a technical team defining an exploration area could
have developed “knowledge” or “proprietary information” to either use this information itself or sell it to another company,
the proceeds from which would be used to purchase a right to explore. This situation could result from a technical team
starting a new company or a large company technical team starting a new project. The challenge will be, absent precedent to
date, to determine, in what are expected to be rare and limited circumstances, whether the knowledge satisfies the guidance
for recognition as an internally generated intangible asset under IAS 38, is identifiable, has economic value and can be sold.
2 The revaluation model is an "on going" alternative under IAS 16, which is different from the “deemed cost” exemption at
transition under IFRS 1. At transition, an entity may choose the “cost” or “deemed cost” option while after transition the
entity may choose to follow the cost model under IFRS 6 or the cost and revaluation models under IAS 16 and IAS 38.
Matters for Consideration
At the date of
transition to IFRS,
entities currently have
three choices available
for measuring assets.
The following matters will require consideration in conjunction with an entity’s adoption of
accounting policies in respect of E&E expenditures:
• At the date of transition to IFRS, entities currently have three choices available for measuring
assets: (1) the cost model under which retrospective restatement is required to determine cost in
accordance with IFRS 6, IAS 16 and IAS 38; (2) the deemed cost election for individual assets,
which requires fair value measurement with no retrospective treatment; or (3) the revaluation
model under which fair value less accumulated amortization is determined for each class of
assets — see footnote 2 above
• Identification of cost elements to be included in, and excluded from, E&E costs will be required —
see “Elements of E&E Costs” below
• If a capitalization policy for E&E expenditures is chosen, additional policy choices include:
– The method of accounting for directly attributable administrative and overhead costs
– The method and period, if any, for amortizing E&E costs
– The identification of so called E&E cash-generating units, if any, in which to aggregate E&E
assets, and
– The method for assessing and measuring periodic impairment, i.e., expensing, amortizing and
derecognizing considerations.
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Exploration and Evaluation Expenditures
• Consistency of application of accounting policies for E&E costs per category
• Timing of transfer of successful E&E costs including recognition of associated decommissioning
liabilities, if any, to development or production assets, and
• Detailed disclosure requirements.
Section 9 contains a discussion, analysis and illustrative example of the proposed amendment to
IFRS 1, which, if approved by the IASB, would allow entities currently following full cost accounting an
alternative choice for measuring oil and gas assets at transition — it is expected that the majority of
public Canadian full cost entities would choose this option, if available.
IFRS 6 Discussion
The objective of IFRS 6 is limited to specifying the financial reporting for exploration and evaluation
of mineral resources (the E&E phase) and does not deal with activities that precede the legal right to
explore (prospecting, etc.) and with activities incurred after the technical feasibility and commercial
viability of extraction have been ascertained (development, construction, production, closure and
decommissioning, etc. — the development or production phase), the latter being generally recognized
as an entity having demonstrated proved and probable reserves and the assets having achieved
commercial viability.
Appendix A of IFRS 6 specifically states that E&E expenditures are “expenditures incurred by an
entity in connection with the exploration and evaluation of mineral resources before the technical
feasibility and commercial viability of extracting a mineral resources are demonstrable”, while E&E
assets are “exploration and evaluation expenditures recognized as assets in accordance with the
entity’s accounting policy”.
The acquisition of a “legal right to explore” is generally considered as the point at which an entity
obtains control of the economic benefits expected to flow from the area.
Some examples include:
• Acquisition of exploration licences or lease rights
• Farm-in agreements
• Joint Venture Agreements (if non-operated), and
• Production Sharing Contracts, Technical Assistance Contracts and similar host government
contractual arrangements.
Elements of E&E Costs
IFRS 6 requires an entity to determine its accounting policy specifying which expenditures, if any,
are recognized as E&E assets and to apply that policy consistently. It is probable that different
entities will identify and recognize different cost elements.
It is probable that different
The standard does not specify which cost elements are to be included in E&E expenditures, but
rather provides a non-exhaustive list of choices which may be included:
elements.
entities will identify and
recognize different cost
• Acquisition of licences to explore undeveloped mineral rights
• Post acquisition of legal rights to explore in connection with topographical, geological and
geophysical (G&G) and geochemical studies
• Exploratory drilling
• Trenching, sampling, logging and testing procedures, and/or
• Activities in relation to evaluating the technical feasibility and commercial viability of extracting
the mineral resource.
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The application of IFRS 6 is restricted to E&E expenditures and, until an entity has achieved
commercial viability, accumulated costs remain as E&E assets and should continue to be accounted
for under IFRS 6. Entities may choose to capitalize administrative and overhead costs that are
directly attributable to and associated with E&E activities. In addition, provided the assets are
determined to be “qualifying assets” under IAS 23, e.g., an extended multi-well exploratory drilling
program, borrowing costs will require capitalization as part of E&E assets. However, the recognition
hurdle required under IAS 23R that it be “probable that economic benefit will arise” would appear to
rule out interest capitalization on E&E expenditures except in rare situations. Application of this
hurdle ensures that capitalization generally should not commence until the project enters the
post-E&E phase. In addition, interest capitalization may be limited to large infrastructure projects.
IAS 23 — Borrowing Costs
Recognition
Borrowing costs directly attributable to the acquisition, construction, development or production of
a qualifying asset (a qualifying asset is one which takes a substantial period of time to get ready for
use or sale) form part of the cost of that asset and should be capitalized. Other borrowing costs are
recognized as an expense.
Measurement
Where funds are borrowed specifically, costs eligible for capitalization are the actual costs incurred
less any income earned on the temporary investment of such borrowings. Where the borrowed funds
are part of a general pool, the amount eligible for capitalization is determined by applying the
weighted average of the borrowing costs applicable to the general pool to the expenditure on the
qualifying asset.
Capitalized borrowing
costs should be included
with E&E costs subject to
periodic impairment
assessment.
Capitalization of borrowing costs should commence when expenditures are being incurred, when
borrowing costs are being incurred and when activities that are necessary to prepare the asset for
its intended use are in progress. This may include some activities prior to commencement of physical
production, e.g., E&E activities. Capitalization should be suspended during periods in which active
exploration and evaluation is interrupted. Capitalized borrowing costs should be included with E&E
costs subject to periodic impairment assessment. Capitalization would continue subsequent to the
transfer of E&E assets to development or production assets until substantially all of the activities
necessary to prepare the asset for its intended use are complete.
Disclosure
• The amount of borrowing cost capitalized during the period, and
• The capitalization rate used.
Farm-outs
In practice, many oil and gas entities have chosen to apply an accounting policy for farm-out
arrangements based on their previous national GAAP, which is allowed under IFRS 6. Under this
approach, the farmee accounts for E&E expenditures in the same manner as directly incurred
E&E expenditures. The farmor accounts for the farm-out arrangement as follows:
• There is no accounting for expenditures made by the farmee
• No gain or loss is recognized, and
• Any cash consideration received is credited against costs previously capitalized.
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Exploration and Evaluation Expenditures
Asset Swaps
Accounting for E&E asset swaps falls within IFRS 6; however, the standard does not specifically
address swaps. In practice, entities have continued to apply the accounting policies used under their
previous national GAAP, in particular when the fair value of the E&E asset cannot be determined
reliably. Because reliable fair value measurement is usually unavailable given the nature of
exploratory assets, entities have generally selected an accounting policy under which the E&E
assets obtained in the swap transaction are recognized at the carrying amount of the E&E assets
relinquished.
Measurement after Recognition
After transition to IFRS, an entity may choose from the cost model under IFRS 6 and the cost and
revaluation models under IAS 16 and IAS 38. However, IAS 38 allows for the revaluation of intangible
assets (but not in the case of internally generated intangible assets) only if fair value can be
determined by reference to an active market, which is expected to be a rare situation; and, IFRS 6
requires that E&E assets be segregated into intangible and tangible components. The revaluation
model, therefore, would not appear to be appropriate for recognition and measurement of E&E
assets. In addition, since IFRS 6 does not provide specific measurement guidance, entities choosing
to capitalize E&E expenditures under the cost model will also need to choose a related measurement
policy. For example:
• Capitalized E&E costs may be kept whole and intact until it is determined that the property
contains mineral reserves, at which time the costs are reclassified to development or production
assets (subject to an impairment test)
• Capitalized E&E costs may be kept whole and intact until it is determined that no future economic
benefits will result or the outcome is uncertain
• Best practice suggests that when E&E expenditures are determined to have no future economic
benefits they should be expensed and the specific E&E assets derecognized
• Capitalized costs may be amortized using an appropriate method or rate over a relevant and
determinable period
• Regardless of the measurement policy chosen, capitalized E&E costs (including associated
capitalized borrowing costs, if any) must be reviewed for indicators of impairment at each
reporting period and if such indicators are present, i.e., when facts and circumstances suggest
the carrying amount of the E&E assets may exceed its recoverable amount, the E&E assets must
be measured for impairment under IAS 36, and
• Impairment tests for E&E assets are required at IFRS transition — see Section 9.
There is no specific restriction under IFRS 6 regarding the time frame that costs can remain
classified as E&E assets, i.e., when activities on the ground, costs being incurred or active evaluation
and decision-making are continuing, provided there are no indications of impairment — see Section 5.
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The revaluation model,
therefore, would not
appear to be appropriate
for recognition and
measurement of E&E
assets.
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The transfer of E&E costs
may be made on a well by
well basis or at a field or
area level.
The timing of transfer of E&E costs to development or production assets is a function of the
achievement of technical feasibility and commercial viability. The transfer of E&E costs may be made
on a well by well basis or at a field or area level, etc. provided the transfer is not greater than the
identified cash-generating unit (CGU) level, i.e., exclude costs not belonging to that CGU, and the
selected method is applied consistently. Transfers should be performed at a level, after impairment
testing, that promotes the concept of tracking intangible and tangible oil and gas assets, including
componentization, under IAS 16 and IAS 38 — see Section 2. For example, suppose an exploration
project consists of five completed exploration wells of which three wells are dry and two wells are
successful which, in turn, makes the entire area commercially viable. An entity could choose under its
selected IFRS 6 accounting policy to expense the three dry holes when drilled and to reclassify the
costs of the two successful wells to development or production assets subject to completion of an
impairment test. Alternatively, if the entity has made a different choice of accounting policy, it could
reclassify the costs of all five wells to development or production assets, again subject to
impairment testing.
Examples of Amortization Methods for E&E Assets
E&E property acquisition costs
• Amortize over lease term (subject to impairment tests); or
• No amortization (subject to impairment tests)
E&E exploration costs in progress
• Amortize (discretionary basis) or no amortization (subject to
impairment tests)
Unsuccessful E&E costs
• Amortize (discretionary basis) any remaining balance after
impairment (level of impairment test for unsuccessful E&E costs
could be as high as an operating segment level); or
• Expense when determined to be unsuccessful and have no future
economic benefit
Successful E&E costs
• Transfer to development or production assets (subject to
impairment test) and amortize on the unit of production basis
Impairment of E&E Assets
Section 5 provides a detailed discussion of the requirements for impairment testing of E&E assets
and Section 9 includes an illustrative example.
Presentation
E&E assets should be
classified as either
intangible or tangible
assets according to
their nature.
E&E assets should be classified as either intangible or tangible assets according to their nature.
A tangible asset consumed in developing an intangible asset should still be classified as a tangible
asset; however, any depreciation charged on the tangible asset may be capitalized as part of the cost
of the intangible asset being actively explored or evaluated. In practice, the majority of oil and gas
companies reporting under IFRS classify E&E assets as “intangible exploration assets”, with tangible
equipment, if any, being classified separately.
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Disclosures
In order to appropriately identify and explain amounts recognized in financial statements with
respect to E&E assets, an entity should disclose:
Additional disclosures are
• The accounting policies for E&E expenditures including the recognition and measurement criteria
with respect to classes of E&E assets, and
impairments.
required in respect of
• The amounts of assets and liabilities arising from E&E activities, including revenues, expenses and
cash flows, if any.
Additional disclosures are required in respect of impairments — see Section 5. A hypothetical
example of E&E accounting policy note disclosure might be:
Oil and gas exploration
The company accounts for oil and gas exploration expenditures as follows:
Pre-license costs
The Company expenses pre-license costs in the period in which they are incurred.
Exploration and evaluation costs
Exploration and evaluation (E&E) costs are initially capitalized3 by well, field or exploration area,
as appropriate, and include payments to acquire the legal right to explore, technical services and
studies, seismic acquisition, geological and geophysical costs, exploratory drilling and testing,
consumed materials and directly attributable administrative and overhead costs. E&E costs are
classified as intangible and tangible oil and gas assets; however, to the extent a tangible asset is
used in the development of an intangible asset, the amount of amortization reflecting such usage
is recorded as part of the cost of the intangible asset. Borrowing costs are capitalized. E&E costs
are not amortized prior to the completion of exploration and evaluation activities.
Each E&E asset is reviewed for impairment whenever events or changes in circumstances
indicate the carrying value may not be recoverable. When a potential impairment is indicated,
an assessment of the asset is performed in conjunction with the group of operating assets
(representing a cash-generating unit) to which the exploration cost is attributed. To the extent
that the capitalized expenditure is not expected to be recovered through use or disposal, it is
expensed. If no future related activity is planned, the E&E costs are also expensed.
Sample disclosures
Melrose Resources PLC — Exploration Expenditures (extract)
Pre-acquisition expenditures on oil and gas assets are recognized as an expense in the income statement when incurred. In
accordance with IFRS 6, exploration and evaluation costs are capitalized within intangible assets until the success or otherwise
of the well or project has been established and subject to an impairment review. The costs of unsuccessful wells in an area are
written off to the income statement: this is in accordance with the successful efforts accounting policy but is also compatible
with IAS 36 on the basis the asset is impaired.
Eni S.p.A — Intangible Assets (extract)
Intangible assets are assets without physical substance, controlled by the company and able to produce future economic
benefits, and goodwill acquired in business combinations. An asset is classified as intangible when management is able to
distinguish it clearly from goodwill. This condition is normally met when: (i) the intangible asset arises from contractual or
legal rights, or (ii) the asset is separable, i.e., can be sold, transferred, licensed, rented or exchanged, either individually or
as an integral part of other assets. An entity controls an asset if it has the power to obtain the future economic benefits
generated by the underlying asset and to restrict the access of others to those cash flows. Intangible assets are initially stated
at cost as determined by the criteria used for tangible assets and they are not revalued for financial reporting purposes.
3 Underscored terms indicate accounting policy choices are permitted under IFRS 6.
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SECTION 2 — COMPONENTIZATION
OF OIL AND GAS ASSETS
Background
Entities will have to apply
judgment in defining and
identifying PP&E.
Under IAS 16 “Property, Plant and Equipment”, an item of property, plant and equipment (PP&E) is
recognized as an asset in an entity’s balance sheet only when its cost can be measured reliably and
it is probable that future economic benefits associated with the item will accrue to the entity. IAS 16
notes that there are issues regarding what constitutes a single item of PP&E, but does not prescribe
a unit of account for recognition. Entities will have to apply judgment in defining and identifying
PP&E, including the associated components and parts, which align with their specific business
circumstances.
The standard distinguishes between regular servicing of an asset and replacement of a major part or
component of the asset. Regular servicing, i.e., repairs and maintenance, is charged to expense while
expenditure involving replacement of a significant part of an asset is capitalized (provided the
recognition criteria are met). Under the recognition principle, the cost of replacing a major or
significant part of the asset is recognized when the cost is incurred and the carrying amount of the
replaced part is derecognized.
An entity should identify those parts of an asset that it considers will be replaced either sooner or
separately from the rest of the asset, from consumption and/or from other factors used to determine
useful life. These are parts that have a cost that is significant in relation to the total cost of the asset.
Costs do not need to be incremental or external but must be directly attributable, e.g., costs of site
preparation, delivery and handling, installation, related professional fees and the estimated cost of
dismantling and removing (decommissioning) the asset and restoring the site. Entities should identify
significant parts upon acquisition in order to properly depreciate the asset. There is no requirement
to identify all parts; however, IAS 16 requires derecognition of an existing part when it has been
replaced regardless of whether it has been depreciated separately. In addition, the carrying value of
the replaced part may be estimated, if necessary, for derecognition purposes. As a result, an entity
may not have identified the parts of an asset until the replacement expenditure is incurred.
Principles
Borrowing costs directly
incurred to acquire or
construct qualifying PP&E
assets must be capitalized.
The following matters will require consideration in conjunction with an entity’s consideration of
IAS 16 and IAS 23 “Borrowing Costs”:
• The asset recognition criteria apply to the original and all subsequent PP&E expenditures
• Componentization or the breaking out of separate assets is necessary; however, an entity about
to replace a previously unidentified asset may break it out at that time and, if necessary, the
carrying value may be estimated
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Small Explorers and Producers Association of Canada
Componentization of Oil and Gas Asset
• Significant components with similar lives and depreciation methods may be grouped together
as may insignificant components, provided the groupings are maintained in the separate
geographical unit of account with which they are associated, e.g., compressors located within
a single geographic unit of account may be grouped into a single class
• Repairs and maintenance is a driver of componentization since periodic and major repair and
overhaul, turnarounds and work-over expenditures may be an indication of separately identifiable
assets that require a depreciation method and rate different from the larger associated asset
• Significant parts that have specific lives or scheduled replacement are considered separate
components, e.g., a good indicator of a separate component would be when an entity concludes
that it would capitalize the expenditure if it were to replace the component
• Additional components may be identified when significant parts of a larger asset require
replacement
• Borrowing costs directly incurred to acquire or construct qualifying PP&E assets must be
capitalized
• Annual reviews of estimated useful lives and salvage values of component parts of PP&E are
required with changes being accounted for prospectively, and
• Disclosures are required for each class of PP&E.
Associated standards that should be reviewed to assist in the determination of amounts to be
included in the PP&E asset base and subject to componentization include: IFRS 1 “First Time Adoption
of International Financial Reporting Standards”; IFRS 3 “Business Combinations”; IFRS 5 “Assets Held
for Sale”; IFRS 6 “Exploration for and Evaluation of Mineral Resources”; IAS 17 “Leases”; IAS 31
“Interest in Joint Ventures”; IAS 36 “Impairment of Assets”; IAS 37 “Provisions, Contingent Liabilities
and Contingent Assets”; IAS 38 “Intangible Assets”; IAS 40 “Investment Properties”, and IFRIC 1
“Changes in Existing Decommissioning, Restoration and Similar Liabilities”.
Discussion
All Entities
Under IAS 16, a portion of the original total cost of an asset should be apportioned to major or
significant components subject to future turnarounds, overhauls and replacement. This accounting
treatment was developed primarily to address concerns about accruals for major repairs being
recognized before the repair had occurred, but at a time when no obligation had arisen. IAS 16
requires an enterprise to identify those parts of a qualifying asset that it considers will be replaced
much sooner and separately from the rest of the asset, e.g., future expenditures that would be
expected to extend the asset’s useful life. In addition, the cost of these significant apportioned
components (including applicable costs such as labour, engineering and consulting fees) must be
separately identified and depreciated to their residual value over the useful life of the component.
Consistent with derecognition of physical parts on replacement, non physical parts are derecognized
when the required remedial work is completed.
IAS 37 and IFRIC 1 require entities to identify and include in the original cost of an asset future
expenditures to meet constructive or legal obligations (e.g., decommissioning liabilities) — see Section 6.
The determination of what constitutes a component starts with individual assets and should be based
on discussions with operations personnel familiar with the design, construction and maintenance of
the assets. Operations personnel can also assist in identifying material physical and non physical
components, asset classes, types and categories, useful lives, residual values, replacement schedules,
etc. The intent is to focus on items that would make a significant difference in measured amounts of
depreciation or repairs and maintenance, which in turn would impact external financial reporting,
not to individually recognize, track and depreciate insignificant items. Although minute detail may be
possible, it will not likely provide any meaningful information about the asset’s life or future costs to
keep the asset productive. To support a satisfactory answer to this issue, an entity will be required
to expend a certain amount of time and effort.
Canadian Association of Petroleum Producers
19
Consistent with
derecognition of physical
parts on replacement,
non physical parts are
derecognized when the
required remedial work
is completed.
International Financial Reporting Standards
Information Guide
Other key factors in identifying an entity’s significant components include:
• Major repairs and maintenance schedules
• Technical knowledge and expertise
• Replacement policy and practice, e.g., retiring or replacing major components to maintain
productive capacity
• Derecognition policy and practice, e.g., future repairs may result in derecognition of existing
components and recognition of new components, and
• Useful lives that differ from the reserves life or the lives of major components.
Notwithstanding that separate components may not have been initially recognized, an estimate of
the carrying amount of the components should be made and the components derecognized when
they are replaced and the new component should be recognized at that time. Estimates of initially
unrecognized components may be based on time-adjusted current replacement cost.
Entities with Upstream Assets and Major Facilities
Larger oil and gas entities generally have installations containing a significant number of
components or parts, many of which will have different useful lives. Examples would be pipelines,
gas plants, LNG facilities, heavy oil upgraders, offshore platforms, compressor facilities, computer
monitoring and control systems, etc. Identifying the number of components can be a complex and
time consuming exercise for large installations. Some components can be expected to be replaced
one or more times during the life of the installation.
Entities with Upstream Assets and No Major Facilities
An entity may not have
to separately identify
components of PP&E
provided no individual
assets are significant.
Smaller oil and gas entities will frequently be involved in a limited number of extractive properties,
which may be operated or non-operated. For operated properties, an entity may not have to
separately identify components of PP&E provided no individual assets are significant. This situation
could arise when assets belonging to a geographical unit of account are expected, with only minor
replacements, to have an estimated useful life that equates generally with the estimated reserves
life of the geographical unit of account. For non-operated properties, an entity should be able to
obtain component information, if significant, from the operator in conjunction with management
decisions in respect of joint arrangements.
Issues
The following issues will require consideration:
• Whether historical cost information exists for all identified components
• On transition to IFRS, the method of allocation of cost and accumulated amortization to
significant asset components (including any non physical parts)
• The level of groupings of assets and components within a geographical unit of account, e.g.,
one or more fields with similar asset classes or categories in a specifically identified area
• On transition to IFRS an entity should consider whether the effect of depreciating a component
separately would be significant to financial statement users
• Whether upstream tangible assets could be depreciated over the life of the related reserves,
e.g., the useful life of the assets, with proper maintenance, could equal reserves life; little or no
residual value could be evident if assets are highly dependent on commodity prices and location;
or, if assets have no real component value except to produce and process the reserves
• Identification of components should be considered in conjunction with identification of assets
within geographical units of account, and
• Consistency of relationships among components, allocation of cost and accumulated depreciation,
impairment tests, decommissioning liabilities, depreciation calculations, etc.
20
Small Explorers and Producers Association of Canada
Componentization of Oil and Gas Asset
In addition to the foregoing, entities should consider whether computerized accounting systems
and their related chart of accounts will require upgrading or modification to track the information
at the level of detail necessary for component monitoring. Changes in the entity’s internal control
environment should be documented and additional control procedures may be necessary for new
processes.
Farm-outs
For farm-outs outside the E&E phase, the farmee should recognize an asset that represents the
interest acquired, at cost, in accordance with IAS 16 and a liability, if any, that reflects the farmor’s
share of the future investment from which the farmee will not derive future economic benefit. The
farmor should: derecognize the portion of the asset that has been sold in accordance with IAS 16;
recognize the consideration, if any, received or receivable from the farmee, which represents the
farmor’s obligation to fund future capital expenditures in relation to the interest retained by the
farmor; and, recognize a gain or loss on the transaction as the difference between the net disposal
proceeds and the carrying amount of the asset disposed, provided the value of the consideration
can be measured reliably, absent which the consideration received should be accounted for as a
reduction in the carrying amount of the underlying assets.
Asset Swaps
Accounting for asset swaps in respect of property, plant and equipment, intangible and tangible oil
and gas assets and intangible assets falls within the scope of IAS 16. Those standards require the
acquisition of such assets in exchange for non monetary assets, or a combination of monetary and
non monetary assets, to be measured at fair value. The deemed cost of the acquired assets is
measured at fair value unless:
Asset swaps falls within
the scope of IAS 16.
• The swap transaction lacks commercial substance4, or
• The fair value of the assets acquired and the assets relinquished cannot be reliably measured
(in which case the transaction is measured at the carrying amount of the assets relinquished).
Sample disclosure
ENI S.p.A. — Oil and Gas Assets and Components (extract)
Tangible assets are recognized using the cost model and stated at their purchase or self-construction cost
including any costs directly attributable to bringing the asset into operation. In addition, when a substantial
period of time is required to make the asset ready for use, the purchase price or self-construction cost includes
the borrowing costs incurred that could have otherwise been saved had the investment not been made. In the
case of a present obligation for the dismantling and removal of assets and the restoration of sites, the carrying
value includes, with a corresponding entry to a specific provision, the estimated (discounted) costs to be borne at
the moment the asset is retired.
Property, plant and equipment is not revalued for financial reporting purposes.
Expenditures on renewals, improvements and transformations that extend the useful lives of the related asset are
capitalized to property, plant and equipment. Tangible assets, from the moment they begin or should begin to be
used, are depreciated systematically using a straight-line method over their useful life, which is an estimate of the
period over which the assets will be used by the company. When tangible assets are composed of more than one
significant element with different useful lives, each component is depreciated separately. The amount to be
depreciated is represented by the book value reduced by the estimated net realizable value at the end of the
useful life, if it is significant and can be reasonably determined.
Replacement costs of identifiable components in complex assets are capitalized and depreciated over their useful
life; the residual book value of the component that has been substituted is charged to the profit and loss account.
Expenditures for ordinary maintenance and repairs are expensed as incurred.
4
Commercial substance is determined by comparing forecast cash flows expected to be generated from the acquired and
relinquished assets and exists when the risk, timing and amount of forecast cash flows are significantly different or the
entity-specific value of the portion of the entity’s operations affected by the swap changes as a result of the swap
transaction.
Canadian Association of Petroleum Producers
21
International Financial Reporting Standards
Information Guide
SECTION 3 — BASIS AND CALCULATION OF
DEPLETION, DEPRECIATION AND AMORTIZATION
Background
IAS 16 “Property, Plant and Equipment” is the standard under which property, plant and equipment
and development or production assets (collectively, PP&E), and depletion, depreciation and
amortization (collectively, DD&A) are governed. IAS 16 does not prescribe a single method of
determining DD&A but does refer to straight line, diminishing balance and the unit of production
methods.
The cost of an item of PP&E is initially recognized as an asset on an entity’s balance sheet and in
each subsequent period a portion of the cost is amortized as an expense on the income statement.
In a perfect world, at the end of the asset’s working life, the net cost remaining on the balance
sheet should either equal the disposal proceeds or zero if there is no remaining value.
Principles
Useful life is defined in
terms of use to the business
(not economic life).
The following principles are derived from IAS 16:
• At the date of transition to IFRS, entities currently have three choices available for measuring
assets: (1) the cost model under which retrospective restatement is required to determine cost in
accordance with IFRS 6, IAS 16 and IAS 38; (2) the deemed cost election for individual assets,
which requires fair value measurement with no retrospective treatment; or (3) the revaluation
model under which fair value less accumulated amortization is determined for each class of
assets — see Section 9 for a discussion of the IASB’s proposed amendment to IFRS 1 that would
remove the requirement for retrospective restatement of oil and gas assets by full cost entities in
the event the amendment is approved by the IASB and the election is made by the entity
• Following transition to IFRS, subsequent asset acquisitions are initially recognized at cost and
PP&E may be measured using the cost method or the revaluation method
• The cost of an item of PP&E includes:
— The purchase price plus duties and taxes, less discounts and rebates
— An apportionment from the cost of major or significant components of assets that will be
subject to future expenditures expected to extend the asset’s useful life, such as major plant
turnarounds, overhauls and replacement, i.e., those components that the entity considers will
be replaced much sooner and separately from the rest of the asset
— Borrowing costs incurred to acquire qualifying assets
— Costs attributable to ready the asset for the service for which it is intended, excluding
administration and general overhead costs, and
— An initial estimate of the costs of decommissioning, removal, restoration or abandonment
resulting from utilization of the asset over time.
Steam generators.
Image courtesy of
Devon Canada
22
Small Explorers and Producers Association of Canada
Basis and Calculation of Depletion, Depreciation and Amortization
• Each part of an item of PP&E with a cost that is significant in relation to the total cost of the item,
including non physical components such as labour, engineering and consulting fees and similar
costs, must be depreciated separately
• Significant parts of an item that have the same life and depreciation method may be grouped for
the purposes of calculating DD&A
• After separating significant parts of an item, an entity should separately depreciate the remainder,
which would consist of the parts that are not individually significant (if an entity has varying
expectations for these parts, approximation techniques may be necessary to depreciate the
remainder in a manner that faithfully represents the consumption pattern and/or useful life)
• The amount subject to DD&A is determined as the cost of the asset less its residual value and
should be allocated on a systematic basis over the useful life of the assets
• Useful life is defined in terms of use to the business (not economic life) as the period over which
the asset is expected to be available for use or the number of production units expected to be
obtained from the asset
• Useful life, residual value and the DD&A method used for all PP&E should reflect the pattern in
which the asset’s future economic benefits are expected to be consumed by the entity
• The rate and method of DD&A should be reviewed at a minimum at the entity’s financial year-end
and, if changed significantly, the changes should be accounted for prospectively as a change in an
accounting estimate in accordance with IAS 8 “Accounting Policies, Changes in Accounting
Estimates and Errors”
• DD&A should commence once the asset has achieved commercial viability, where commercial
viability is generally recognized as occurring when the asset is in the location and condition
necessary for it to be capable of operating in the manner intended by management
• DD&A should continue until the earlier of the date the item is classified as held for sale and the
date the item is derecognized (an entity does not stop charging DD&A just because the asset is
idle or has been removed from use; however, if the entity is recognizing DD&A on the basis of
units of production, DD&A can temporarily cease in the event of an interruption of production)
• An entity is required to derecognize the carrying value of a part of an item of PP&E that is
replaced, regardless of whether the part has been depreciated separately, if the entity has
included the cost of the replacement item in the original carrying value of the PP&E
• The derecognized carrying value of a replaced part may be estimated, if necessary
• Gains or losses from derecognition of an item of PP&E must be included in income, not revenue,
in the period in which the item is derecognized, and
• All items of PP&E accounted for under IAS 16 are subject to the impairment requirements of
IAS 36 — see Section 5.
Matters for Consideration
The following matters will require management’s consideration in conjunction with adoption of the
preceding principles:
• To determine whether to adopt the cost model or the revaluation model for PP&E after transition to IFRS
• To determine the degree of componentization of assets — see Section 2
• To identify and separate PP&E that will be depreciated on a straight line basis over the useful life
in years (e.g., processing facilities, major pipeline and gathering systems, etc.) from assets that
will be amortized on a unit of production basis over the reserves life (e.g., on-lease development
or production assets, decommissioning costs, etc.)
• To determine the appropriate category of reserves to use in the unit of production DD&A
calculation, e.g., proved (1P) or proved and probable (2P) reserves and the corresponding
associated future development costs to be included, i.e., to ensure consistency between the
numerator and denominator in the DD&A calculation
Canadian Association of Petroleum Producers
23
International Financial Reporting Standards
Information Guide
• To determine the appropriate reserves using current prices or forecast pricing.
• To identify the level at which to perform DD&A calculations and the grouping of assets based
on useful life
• To ensure consistency among inputs and parameters used for DD&A calculations and impairment
tests, and
• Disclosure requirements.
IAS 16 Discussion
PP&E assets having a
different (shorter or longer)
life than the pool, field or
area with which they are
associated should be
amortized separately.
For an upstream oil and gas entity, those PP&E assets having a different (shorter or longer) life than
the pool, field or area with which they are associated should be amortized separately from the pool,
field or area assets. This is also a consideration for pipelines, processing facilities, terminals, etc.
However, if the assets have a useful life that is clearly related to a specific pool, field or area, the unit
of production method would be an appropriate method of calculating DD&A. The method used should
reflect the pattern in which the asset’s future economic benefits are expected to be enjoyed and
consumed by the entity.
Reserves
There is no direct guidance under IAS 16 on the reserve categories (e.g., proved (1P) or proved plus
probable (2P)) and the pricing method (e.g., constant or forecast (future) pricing) to be used in DD&A
calculations. Until guidance is issued by the IASB, an entity is permitted choices in these matters,
provided the choices reflect management’s best estimates of the recoverable reserves expected to
be obtained from the asset and the choices are applied consistently from period to period.
Reserves Categories
With reference to the principle that the DD&A methodology should reflect the pattern in which the
future economic benefits of the assets are expected to be consumed, if an entity following IFRS has
elected to deplete its oil and gas reserves using proved and probable reserves, then in order to
ensure comparability, the depletion base (i.e., the costs to be depleted) should include the future
development costs required to access both classifications of reserves.
Reserves Pricing
Reserve volumes under constant pricing or forecast pricing scenarios can vary (sometimes
significantly) depending on current economic conditions, commodity prices and cost volatility.
Constant price information may be misleading in times of volatile pricing and may not be the most
accurate estimate for purposes of estimating reserves and calculating DD&A. Reserves volumes
based on forecast prices would be expected to be more meaningful as long as they accurately
reflect the production expected to be obtained from the associated oil and gas assets.
Revaluation Model
If the revaluation model is selected, each asset class of PP&E will be carried at fair value less
subsequent amortization charges adjusted for periodic revaluation changes. Additions to PP&E are
initially recognized at cost. Fair value would generally be determined based on market evidence or
appraisals prepared by qualified professionals. Valuation frequency is not directly specified in IAS 16;
however, the standard requires that revaluations be obtained regularly in order to ensure the carrying amount of assets does not differ materially from fair value at the reporting date. In practice for
the commodity based oil and gas industry, annual revaluations would likely be required; in times of
significant economic, industry and/or entity changes, quarterly revaluations might be required.
When an asset is revalued, any accumulated DD&A at the date of the revaluation is either restated
proportionately with the change in the gross carrying amount of the asset or is eliminated against
the gross carrying amount of the asset and the resulting net amount is restated as the carrying
amount of the asset.
24
Small Explorers and Producers Association of Canada
Basis and Calculation of Depletion, Depreciation and Amortization
It is expected that most entities will choose the cost model due to inherent difficulties in applying
the revaluation model. For example, the complexity associated with componentization and the
associated timing, expertise and cost of necessary periodic revaluations would be expected generally
to be prohibitive. Furthermore, IAS 38 allows for the revaluation of intangible assets only if fair value
can be determined by reference to an active market which is expected to be rare in the case of
intangible assets.
Oil Sands Considerations
For an oil sands mining or other extractive industry operation that has significant pre-production
capital expenditures, using a proved plus probable reserve base and forecast pricing will likely result
in the best estimate of recoverable reserves expected to be obtained from the asset. This is because
the capital costs for design, engineering and construction are incurred not only to obtain the proved
reserves but also the probable reserves.
Examples of DD&A methods for PP&E — IAS 16
Class of PP&E5
Method
Proved property acquisition costs
Unit of production
Proved property, drilling, completion and development costs
Unit of production
Support equipment and facilities — not a component and if not
with a shorter useful life
Unit of production
Support equipment and facilities including turnarounds —
major separate component with a different (shorter or longer)
useful life
Useful life
Gas handling facilities and lease oil batteries — not a separate
component and if not with a shorter useful life
Unit of production
Gas processing facilities and oil terminals including
turnarounds — major separate component
Straight line over useful life
Wells or facilities in progress not subject to IFRS 6
No amortization
Presentation and disclosure
• The amortization charge for each period is recognized in profit or loss unless it is included in
the carrying amount of another asset
• Disclosure requirements for each class of PP&E in respect of DD&A are as follows:
— Measurement basis at and following transition, i.e., cost method or revaluation method
— DD&A methods used
— The useful lives of PP&E or the DD&A rates used
— The gross carrying amount of PP&E (aggregated with accumulated impairment losses) and
accumulated DD&A at the beginning and end of the period
— A reconciliation of the carrying amounts of PP&E and DD&A at the beginning and end of the
reporting period disclosing all significant movements in classes, and
— Comparative amounts.
• Changes in the rate and method of amortization should be disclosed, and
• Selection of the DD&A method and estimate of the useful lives of assets are matters of judgment;
therefore, disclosure of the methods adopted and the estimated useful lives or DD&A rates is
deemed to provide users of financial statements with information that allows for a review of the
policies selected by management and enables comparisons to be made with other entities.
5 Each class of PP&E should identify significant components for purposes of disposal measurement.
Canadian Association of Petroleum Producers
25
Most entities will choose
the cost model due to
inherent difficulties in
applying the revaluation
model.
International Financial Reporting Standards
Information Guide
Financial statement note disclosure (comparative data would be required)
Oil and gas assets
Cost at January 1, 2011
$
5,000
Additions:
Transfers of exploration and evaluation assets
200
Property acquisitions
500
Change in decommissioning provision
100
Property disposals
(50)
Properties derecognized
(50)
Cost at December 31, 2011
$
5,700
Accumulated DD&A and impairment at January 1, 2011
$
1,500
Amortization provision for the year
100
Property disposals
(10)
Properties derecognized
(20)
Accumulated DD&A and impairment at December 31, 2011
$
1,570
Net book value at December 31, 2011
$
4,130
Sample disclosure
BP — Depreciation and Amortization (extract)
Property, plant and equipment is stated at cost, less accumulated depreciation and accumulated impairment
losses. Oil and natural gas properties, including related pipelines, are depreciated using a unit-of-production
method. The cost of producing wells is amortized over proved developed reserves. Licence acquisition, field
development and future decommissioning costs are amortized over total proved reserves. The unit-of-production
rate for the amortization of field development costs takes into account expenditures incurred to date, together
with approved future development expenditure required to develop reserves.
Other property, plant and equipment is depreciated on a straight-line basis over its expected useful life.
The useful lives of the group’s other property, plant and equipment are as follows:
Land improvements
15 to 25 years
Buildings
20 to 50 years
Refineries
20 to 30 years
Petrochemicals plants
20 to 30 years
Pipelines
10 to 50 years
Service stations
15 years
Office equipment
3 to 7 years
Fixtures and fittings
5 to 15 years
The expected useful lives of property, plant and equipment are reviewed on an annual basis and, if necessary,
changes in useful lives are accounted for prospectively.
Eni S.p.A. — Depreciation and Amortization (extract)
Tangible assets, from the moment they begin or should begin to be used, are depreciated systematically using a
straight-line method over their useful life which is an estimate of the period over which the assets will be used by
the company. When tangible assets are composed of more than one significant element with different useful
lives, each component is depreciated separately. The amount to be depreciated is represented by the book value
reduced by the estimated net realizable value at the end of the useful life, if it is significant and can be reasonably
determined. Replacement costs of identifiable components in complex assets are capitalized and depreciated over
their useful life; the residual book value of the component that has been substituted is charged to the profit and
loss account. Expenditures for ordinary maintenance and repairs are expensed as incurred.
Development costs are those costs incurred to obtain access to proved reserves and to provide facilities for
extracting, gathering and storing oil and gas. They are then capitalized within property, plant and equipment
and amortized generally on a unit of production basis, as their useful life is closely related to the availability of
feasible reserves. This method provides for residual costs at the end of each quarter to be amortized at a rate
representing the ratio between the volumes extracted during the quarter and the proved developed reserves
existing at the end of the quarter, increased by the volumes extracted during the quarter. This method is applied
with reference to the smallest aggregate representing a direct correlation between investments and proved
developed reserves. Costs related to unsuccessful development wells or damaged wells are expensed immediately
as losses on disposal.
26
Small Explorers and Producers Association of Canada
SECTION 4 — CASH
GENERATING UNIT
Background
The definition of a cash-generating unit (CGU) is defined under IAS 36 “Impairment of Assets” as
“the smallest identifiable group of assets that generates cash inflows that are largely independent
of the cash inflows from other assets or groups of assets”. This definition is broad and requires
judgment and interpretation and IAS 36 provides limited guidance.
The smallest identifiable
A CGU is an important part of the requirements of IAS 36 and IFRS 6 “Exploration for and Evaluation
of Mineral Resources” to test assets for impairment when indicators of impairment exist. In practice,
it is often considered the most complex part of the impairment standard to apply. See Section 5 for
further information on impairment indicators and impairment testing.
of the cash inflows from
group of assets that
generates cash inflows that
are largely independent
other assets or groups
of assets.
The identification of an entity’s CGUs requires assessment of various factors, many of which are
expected to be entity-specific and involve the entity’s particular circumstances and nature of its
operations. As a result, what one entity identifies as a CGU may differ from what another entity
identifies, even though the two entities are of comparable size and operate in the same industry —
in other words, a “one-size fits all” approach will not always be relevant or practical.
There are a number of factors which management of an upstream oil and gas entity should consider
in identifying CGUs in addition to the foremost factor of determining whether cash inflows are largely
independent of one another. Such factors would include but not be limited to:
• Are there wells or fields that operate as a single unit through the use of shared infrastructure?
Are there wells or
fields that operate
interdependently in
a single area?
• Are there wells or fields that operate interdependently in a single area?
• Are there wells or fields within a common regulatory regime or geographic area as defined by a
regulatory authority?
• Is there an active market for intermediate products?
• Are there external users of the infrastructure and processing assets?
• Is there a reasonable basis on which to aggregate assets, e.g., wells, fields, shared infrastructure,
etc., and/or activities?
• Is the individual asset or cash-generating activity largely independent and significant to the
business?
• How does the entity manage the business, e.g., monitoring operations, areas of interest,
investment and divestiture decisions, etc.?
• Have other significant factors been identified and considered?
Natural gas plant
Image courtesy of
Suncor Energy Inc.
Canadian Association of Petroleum Producers
27
International Financial Reporting Standards
Information Guide
Matters for Consideration
The following matters support the IAS 36 definition of a CGU and will require consideration in conjunction with an entity’s identification of CGUs:
• Cash inflows are inflows of cash and cash equivalents received from parties external to the entity
• When an active market exists for the output produced by an asset or group of assets, that asset
should be identified as a CGU even if some or all of the output is utilized internally (IAS 36.70
deals with internal transfer pricing)
• CGUs should be identified consistently from period to period for the same asset or types of assets
unless a change is justified, e.g., due to a change in facts (absent a change in facts, any change
would be a change in accounting policy subject to IAS 8 “Accounting Policies, Changes in
Accounting Estimates and Errors”)
• Factors supporting the identification of a CGU should be determined independently of factors
supporting asset amortization requirements
• Each CGU or group of CGUs to which exploration and evaluation assets are allocated under IFRS 6
cannot be larger than an operating segment determined in accordance with IFRS 8 “Operating
Segments”; however, E&E CGUs may be identified at a higher level than that defined under IAS 36
• Each CGU or group of CGUs to which development or production assets are allocated under IAS 16
cannot be larger than an operating segment
• The carrying amount of a CGU is limited to an amount that is consistent with the impairment test
associated with the CGU, and
• Corporate assets and goodwill require allocation to one or more CGUs or operating segments.
General Comments to Consider in Identifying CGUs
In conjunction with the foregoing, the following comments should be considered in identifying CGUs.
General
The identification of CGUs
is an entity-dependent
assessment.
• The identification of CGUs is an entity-dependent assessment and different entities will invariably
identify CGUs that align with their individual businesses.
• The primary consideration in identifying CGUs is independent cash inflows and not net cash flows;
accordingly, cash outflows are not the primary consideration for purposes of identifying an entity’s
CGUs. In this context, the identification of a CGU must meet the definitional requirements of
IFRS 6 and/or IAS 36, depending on the phase of the entity’s operations, and the factors
supporting identification are generally expected to be considered in parallel, not in sequence.
• The IAS definition of a CGU is the foremost factor in identifying whether cash inflows are
independent. How management monitors the entity’s operations or makes decisions regarding
the continuation or disposition of the entity’s assets / operations are secondary considerations
and, therefore, CGU identification may be required at a level below that at which an income
stream is being separately monitored.
• An inability to accurately allocate certain assets to independent cash-generating streams would
indicate that a CGU has most likely been identified at too low a level. For example, two wells
sharing a common battery and pipeline might be indicative of assets that do not generate
independent cash inflows.
• The marketability of output and impact of by-products requires consideration. If an active market
exists for the intermediate product output from a group of assets that generates independent
cash flows, then it is likely this group of assets should be considered a separate CGU. This would
be the case even if the output is sold entirely to other divisions within the same entity, e.g., the
natural gas assets used in conjunction with the production from oil sands and heavy in-situ oil
projects would likely be considered a separate CGU from the oil producing assets. The issue is
not whether a CGU actually generates independent cash flows but whether it is capable of doing
so and an active market exists for the intermediate product.
28
Small Explorers and Producers Association of Canada
Cash Generating Unit
• Another consideration in identifying CGUs is aggregation of similar or interdependent cash
generating inflows into a single CGU. For example, if an area in which an entity conducts operating
activities contains several fields, some of which are contiguous and share common infrastructure,
the contiguous fields in the area might be identified as a single CGU. Another example could be
fields or an area having common distribution networks or customers and a management view to
develop associated interdependent cash inflows. Some practical considerations in identifying
whether a single CGU exists include:
— The common infrastructure is relatively insignificant
— The fields / areas are capable of selling production without using the common infrastructure, or
— The shared infrastructure is classified as a corporate asset.
Integrated Facilities — Upgraders, Oil Sands Facilities, etc.
• Secondary factors to consider include whether the facility produces marketable products at an
intermediate stage, whether third-party processing is performed, how the facility is managed, how
results are monitored, and how output is sold.
• Identification of whether there is an “active market” for the intermediate product is evident and
available. An active market is one in which the items traded within the market are homogeneous,
the market is accessible, there are willing buyers and sellers at all times, and prices are available
to the public. If these conditions do not exist, there is generally no requirement to consider the
production of the intermediate product as a separate CGU.
• Realities of the business, the degree of operational integration and how products are marketed
should be considered in identifying CGUs, e.g., there may be an active market for bitumen
produced from an in-situ oil sands plant but project economics may not be sustainable for the
bitumen production as a stand alone operation. In such a situation, the upgrader that was
designed to refine the bitumen production into a lighter and higher quality grade of oil in order
to capture higher prices would be considered an integral part of the project, and the project
would be identified as a single CGU, i.e., without the higher prices generated from sale of the
upgrader’s refined product the project would not be economically viable.
• Many facility operators do not currently allocate operating revenues and costs to the components
of the facility but instead accumulate revenues and costs for the facility as a whole. Under IAS 36,
this practice would be inconsistent with the basic principle that a CGU must be identified as “the
smallest identifiable group of assets that generates cash inflows that are largely independent of
the cash inflows from other assets or groups of assets”. Thus, a facility could theoretically be
identified as a single stand alone CGU (or two CGUs if the facility is used to perform third-party
processing and the assets dedicated to such processing are identifiable and capable of generating
independent cash inflows) but under IAS 36 each asset in the facility that is capable of generating
independent cash inflows must be identified as a separate CGU. Identifying CGUs based on
management’s reporting structure is not consistent with the definition of a CGU and is not
appropriate.
Goodwill
Goodwill is allocated, as at the date of acquisition, to the acquirer’s CGUs or operating segments
expected to benefit from the synergies of the business combination to which the goodwill relates
regardless of whether other assets or liabilities of the acquiree are assigned to those units or
segments. Each CGU (or group of CGUs) or operating segment for which goodwill information is
available and allocated should represent the level within the entity at which goodwill is managed
and monitored.
Canadian Association of Petroleum Producers
Goodwill is allocated
to the acquirer’s CGUs
expected to benefit from
the business combination.
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EU Experience — Guidance Less Relevant to the Canadian Industry (“Field” as a CGU)
A field could be
too low a level for
CGU definition.
The European Union (EU) experience with transition to IFRS is not fully reflective of the current oil
and gas business environment in Canada. As a result, while much of the IFRS transitional guidance
published to date in Canada has focused around EU experience, Canadian upstream oil and gas
entities should exercise caution in accepting this guidance without further consideration. For example,
some guidance has been published in Canada indicating that a CGU for oil and gas financial reporting
purposes would likely be interpreted as being a “field.” While this may be an acceptable interpretation
for certain smaller companies, it may not always be appropriate for larger companies. This is
because a field could be construed as too low a level for CGU definition and could result in undue or
too much disaggregation. In addition, from a Canadian perspective, there are a number of different
acceptable definitions of the term “field”, which generally refer to a smaller geographic region.
For larger Canadian upstream oil and gas companies, use of a “field” as a basis for identifying CGUs
may not always be appropriate, e.g., a natural gas area might contain one or more contiguous fields
with several hundred wells feeding a single plant or extraction facility. In such a situation, a more
acceptable CGU identification may be the “area” encompassing the fields, which may be defined
either for regulatory purposes or in technical engineering terms as discrete accumulations of
hydrocarbons. These considerations, however, must be secondary to the primary consideration
of the IAS 36 definition of a CGU.
Accounting Policy and Disclosure
IAS 36 and IFRS 6 require an entity to consistently identify its CGUs from period to period for the
same assets or types of assets (unless a change is justified) and, accordingly, identifying the entity’s
CGUs will generally be expected to be a complex, but critical, management process. In addition,
entities will need to consider the long-term implications of identifying CGUs, not just the immediate
impact arising on transition to IFRS.
EU and Australian
companies have been
generic and provide users
with limited information.
There are few disclosure requirements related to CGU identification. For the most part, disclosures
emanating for EU and Australian companies have been generic and provide users with limited
information. Disclosures refer to the IAS definition of a CGU and a statement that CGUs are used
for purposes of impairment testing. If changes are made to an entity’s identification or aggregation
of CGUs, IAS 36 requires disclosure of the current and former way of aggregating CGUs and the
reasons for changing the way the CGUs are identified.
Most companies do not disclose how exploration and evaluation assets are allocated to CGUs, except
when a company has had an impairment loss the disclosure of CGUs is provided in greater detail,
generally in the “Impairment Indicators” section of the accounting policies summary and in the
“Impairment Losses” portion of the oil and gas assets financial statement note — see Section 5.
Examples
The following examples are illustrative of CGUs that have been identified by businesses reporting
under IFRS. It should be noted that the list is not exhaustive and each entity must identify CGUs
based on its own facts and circumstances.
Development or production assets
• Field6 when cash inflows are independent
• Number of fields grouped together where:
— Cash inflows of each field are interdependent
— Fields have similar characteristics (sometimes referred to as resource or depletion plays)
— Fields with similar reserves7 lives and amortization rates
• Any one of the foregoing together with associated facilities when cash inflows are interdependent.
A field or a specifically defined area of interest would appear to be a reasonable approach to
identifying a CGU subject to management’s consideration of the IAS 36 definition of a CGU.
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Small Explorers and Producers Association of Canada
Cash Generating Unit
Individually large asset(s)
• Facility
• Refinery
• Upgrader
• Plant
• Pipeline
• Offshore platform
Nature of activity or type of product
• Concession
• License block
• Product type (e.g., Heavy Oil, Oil Sands, Coal-bed Methane)
• Development area
• Development project
• Production Sharing Agreements
• Royalty / tax regime
• Onshore / offshore operations
• Third party processing
• Marketing arrangements
Geographical location
• Broader categories:
• Region
• District
• Directional (NE, SW, etc.) segments of above
• Specific areas:
— Gulf of Mexico
— North Sea, etc.
The potential CGUs listed above are in reference only to the IAS 16 standard or post-E&E phase and
are for illustration purposes only. Other CGUs may be identified.
6 The term "field" has various definitions and the manner in which upstream oil and gas entities define fields can differ.
7
Consultation with reservoir engineers is an important consideration in CGU identification due to different methodologies
used by engineering firms, which could result in inconsistent and unintended impacts on amortization calculations and
impairment testing.
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Conclusion
A continuum exists for
identification of CGUs
from the lowest level
within an upstream oil
and gas entity (individual
wells) to the highest
level (geographical or
operating segments).
Identification of an entity’s CGUs requires careful judgment. A continuum exists for identification of
CGUs from the lowest level within an upstream oil and gas entity (individual wells) to the highest
level (geographical or operating segments).
While it is theoretically possible for an individual well to generate cash inflows which are independent
of other wells, it is unlikely that an entity would choose to identify an individual well as a single
CGU. This is due to the necessity of making a large number of arbitrary allocations in order to
determine cash inflows from individual wells, thereby indicating that the cash inflows are not really
independent.
It is also unlikely that an entity would identify a geographical or operating segment as a single
CGU because it is virtually certain that at least some of the assets within the segment would be capable of generating cash inflows independently of other assets included in the segment (unless,
for example, the segment consisted of a single country Production Sharing Agreement (PSA) or a
single property in one country, in which case the CGU is not really the country, it is the PSA or the
single property; if there were two PSAs or two properties there would be two CGUs).
Within the continuum from individual wells to operating segments, an entity must consider primarily
the IAS 36 definition in identifying its CGUs and only secondarily how its operating activities are
managed and the degree to which its assets are interrelated. If there is a high degree of interrelation
among assets in a particular area, such as shared production facilities or a common sales point,
those facts argue for and support identification of CGUs at a relatively higher level. Conversely, if
an entity’s assets consist primarily of properties which operate independently of each other with
separate facilities and sales points, those facts support identification of CGUs at a lower level.
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Small Explorers and Producers Association of Canada
SECTION 5 — BASIS AND APPLICATION
OF IMPAIRMENT TESTS
Background
IAS 36 “Impairment of Assets” applies to most assets held by an entity, including its oil and gas
assets, regardless of whether the cost model or the revaluation model of accounting is followed. It is
a complex standard and there is little definitive guidance as to how to apply the standard in practice.
As a result, entities and their professional advisors may interpret the standard’s requirements in
differing ways. The Sponsors recommend timely consultation between an entity’s management and
their professional advisors in conjunction with IAS 36 principles and related interpretations in order
to facilitate introduction of impairment testing policies and assurances about how to proceed.
Under the IFRS Framework an asset is recognized when it is “probable that future economic benefits
will flow to the entity and the asset has a cost or value that can be measured reliably”. An asset is
considered impaired when it is unlikely the entity will recover the carrying value of the asset on its
balance sheet either through use or sale. Under IAS 36, when circumstances arise that indicate an
asset might be impaired, a review must be undertaken of the asset’s cash generating ability either
through its continuing use or disposition.
The purpose of the impairment review, which applies to all intangible and tangible oil and gas assets,
indefinite life assets and goodwill, is to ascertain that the carrying value of the assets does not
exceed their recoverable amount. Under IAS 36, “recoverable amount” is defined as the higher of
fair value less costs to sell (FVLCTS) and value in use (VIU). If either recoverable amount exceeds
the asset’s carrying value, no impairment exists and no write-down is necessary.
FVLCTS is generally recognized as a valuation based on the potential sale of an asset, i.e., the
amount that would be obtained from the sale of the asset in an arm’s length transaction between
knowledgeable willing parties less disposal costs. It is predicated on current observable market
values, which is a market-specific value and implies that an active marketplace exists. An active
market, as defined in IAS 36, is one in which all the following conditions are met: the items traded
within the market are homogeneous; willing buyers and sellers can normally be found at any time;
and, prices are available to the public.
VIU is defined in terms of discounted cash flow, i.e., the present value of the future cash flows to
the entity generated through utilization of an asset throughout its life plus proceeds from eventual
disposition. Selection of an appropriate discount rate under IAS 36 definitions is an important
consideration in completing a VIU impairment test. VIU is an entity-specific value that permits
consideration of synergies; however, IAS 36 is restrictive in the cash flows and other inputs that
may be used in the valuation.
Principles
There are two standards that address impairment within the upstream oil and gas industry:
• IFRS 6 “Exploration for and Evaluation of Mineral Resources”, which is applicable only in respect
of exploration and evaluation (E&E) assets — see Section 1, and
• IAS 36, which is applicable to intangible and tangible oil and gas assets (except E&E assets),
intangible assets with an indefinite life and goodwill.
The impairment criteria for each of IFRS 6 and IAS 36 are discussed below.
Canadian Association of Petroleum Producers
33
The purpose of the
impairment review is to
ascertain that the carrying
value of the assets does not
exceed their recoverable
amount.
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Determining Whether an Impairment Test is Required
The proposed IFRS 1 Amendment is discussed in Section 9. If approved, the amendment would
allow an entity currently following the full cost method of accounting to elect to measure E&E and
development or production assets (i.e., intangible and tangible oil and gas assets) on transition to
IFRS at the amount determined under its previous GAAP, subject to measurement and recognition,
if any, of impairment losses for those assets, which together with any adjustment (plus or minus)
for decommissioning, restoration and similar liabilities as determined under IAS 37 “Provisions,
Contingent Liabilities and Contingent Assets” would be charged to retained earnings. Disclosure of
any loss and/or adjustment will be required.
IFRS 6
There are distinct criteria that must be considered in conjunction with IFRS 6 impairment indicators
and test criteria:
• Under IFRS 6, the assessment of impairment of E&E assets is “triggered” by changes in facts and
circumstances and the assets require testing for impairment when either of the following
conditions are present:
— Facts and circumstances suggest that the carrying amount may exceed the recoverable
amount, or
— The entity has sufficient information to reach a conclusion on the technical feasibility and
commercial viability of minerals extraction.
The IASB has confirmed that once an entity determines an E&E asset to be impaired, IAS 36 should
be used to measure, present and disclose that impairment. However, IFRS 6 makes two important
modifications:
• It defines separate impairment indicators or testing triggers for E&E assets, and
• It allows a cash-generating unit (CGU) or groups of CGUs to be used in impairment testing of
E&E assets.
In summary, E&E assets must be tested for impairment at transition, at a reporting period when
indicators of impairment are present, and in conjunction with their transfer to development or
production assets.
IAS 36
The IAS 36 standard also includes distinct criteria that must be considered in conjunction with
impairment indicators and assessment and test criteria in respect of assets:
• For assets falling within the scope of IAS 36 (excluding intangible assets with an indefinite life and
goodwill), the standard requires an assessment at each reporting date as to whether there are
indicators of impairment and, only in the event such indicators exist, will the entity be required
to complete an impairment test, and
• For intangible assets with an indefinite life and goodwill, IAS 36 requires that an annual
impairment test be performed, and for goodwill the test is to be performed at the same time
each year.
A decision to sell an asset is a trigger point for an impairment review and if an impairment test
indicates an impairment loss should be recognized, the loss is recognized at the time of classification
as an asset held for sale and not included with the gain or loss on eventual disposal. For assets held
for sale, the impairment test would normally be done using the FVLCTS method since an impairment
test done on a VIU basis would be expected to produce a lower valuation.
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Small Explorers and Producers Association of Canada
Basis and Application of Impairment Tests
Impairment of E&E Assets
Indicators of Impairment
The first step in the E&E assets impairment assessment process is to ascertain whether indicators
of impairment exist. IFRS 6 lists the following examples, as modifications from IAS 36 assessment
criteria, of “facts and circumstances” that may indicate impairment:
The first step in the
E&E assets impairment
assessment process is
• The time frame under which an entity had the right to explore in the specific area expired during
the reporting period, or will expire in the near future and is not expected to be renewed
to ascertain whether
• Substantive expenditure on further exploration and evaluation of mineral resources is not
budgeted or planned
impairment exist.
indicators of
• E&E activities in a specific area have not led to the discovery of commercially viable quantities of
mineral resources and the entity has decided to discontinue such activities in the specific area, or
• Sufficient data exist to indicate that, although development in a specific area is planned to
proceed, the carrying amount of the E&E asset is unlikely to be recovered in full in either a
development or a sale scenario.
This list is not intended to be exhaustive. There could be other factors such as adverse changes in
commodity prices or the regulatory environment that may indicate impairment testing is necessary.
There is no specific restriction under IFRS 6 regarding the time frame that costs can remain
classified as E&E assets provided there are no indicators of impairment. However, best practice
suggests that when E&E expenditures are determined to have no future economic benefits they
should be expensed and the specific E&E assets derecognized. E&E assets must be tested for
impairment at each reporting period when indicators of impairment are present, at transition to
IFRS, and in conjunction with their transfer to development or production assets.
Impairment Considerations
In the E&E phase, entities are restricted in the application of capitalization of E&E costs under
IFRS 6 because:
Practice in Europe has
• When impairment indicators are present an impairment test under IAS 36 must be performed
oil and gas entities classify
• E&E assets should be recognized as intangible and tangible oil and gas assets (although practice in
Europe has shown that the majority of oil and gas entities reporting under IFRS classify E&E
assets as “Intangible exploration assets”, with the exception of significant tangible equipment
that is generally classified separately, e.g., a drilling rig), and
E&E assets as “Intangible
shown that the majority of
• Once the commercial viability of reserves is demonstrable, E&E assets must be tested for
impairment, reclassified (intangible and tangible) to development or production assets and
accounted for under IAS 16.
In effect, this means that it is generally not possible to account for successful and unsuccessful
E&E projects within a single E&E cost centre or pool.
Level of Impairment Assessment
The allocation of E&E assets to, and their aggregation within, an E&E CGU or group of E&E CGUs
is specifically allowed under IFRS 6 and may be used for assessing E&E assets for impairment.
Therefore, an entity must determine an accounting policy for allocation and aggregation of E&E
assets, as well as for transfers to development or production assets, and the policy must be applied
consistently and disclosed. A change in accounting policy would be permitted only if certain criteria
set out in IFRS 8 “Operating Segments” are met.
Canadian Association of Petroleum Producers
35
exploration assets”.
International Financial Reporting Standards
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There is no specified order
of testing for impairment of
E&E assets under IFRS 6.
Although there is no specified order of testing for impairment of E&E assets under IFRS 6, an entity
would normally first test an individual E&E asset for impairment and, if a recoverable amount is
undeterminable, the test would be completed at the level of the E&E CGU or group of E&E CGUs. An
E&E CGU or group of E&E CGUs cannot be larger than the entity’s applicable operating segment
determined in accordance with IFRS 8. This means that impairment testing may be completed at the
E&E CGU level, but must not be performed at a level that results in the aggregation of E&E assets or
E&E CGU’s belonging to different segments, e.g., geographical or operating segments. However, if
there are corporate assets or goodwill associated with the E&E assets, there is a specified order of
impairment testing and recognition as discussed below and in Section 9.
In summary, an entity must determine an accounting policy for the purpose of assessing E&E assets
for impairment, including where applicable, the allocation of E&E assets to an E&E CGU or group of
E&E CGUs. In the rare situation that an entity identifies only one business or geographical segment
under IFRS 8, the entity would be permitted to use a single aggregated approach to impairment
testing of E&E assets. However, such an approach could potentially result in impaired assets being
aggregated with non impaired assets in satisfaction of the recoverable amount test and, as
previously indicated, best practice suggests that when E&E assets are determined to have no future
economic benefits they should be expensed and derecognized.
Impairment Test
For entities following the cost model, E&E activities (assets and CGUs) would appear to be capable
of reliable measurement at the outset. However, it is expected that impairment writedowns (and
derecognition) will be a frequent occurrence given the high degree of risk and uncertainty associated
with E&E activities. Consequently, careful consideration will be required when performing the
impairment test with respect to recoverable amounts, if any, for E&E assets.
Impairment testing for E&E assets should be completed in accordance with criteria established in
IAS 36 subject to the modifications permitted under IFRS 6 as discussed above. When measuring
impairment, the carrying amount of the asset or CGU is compared to its recoverable amount and
any excess should be recognized as an impairment charge in the income statement. Future
amortization rates for E&E assets, if any, should reflect the lower carrying amount of the asset.
Under IAS 36, the recoverable amount is defined as the higher of:
• FVLCTS, and
• VIU.
Upon completion of the E&E
phase capitalized E&E costs
must be transferred to
development or production
assets or expensed.
E&E assets would normally be expected to be tested for impairment by reference to FVLCTS provided reliable fair value estimates (if any) can be obtained, e.g., independent valuations or reserve
reports.
Upon completion of the E&E phase (which may be an individual asset, a single CGU, group of CGUs or
operating segment that the company has selected for its measurement policy) capitalized E&E costs,
net of any impairment charge determined under IFRS 6 and measured in accordance with IAS 36,
must be transferred to development or production assets or expensed.
Impairment Examples
Horizontal Impairment — smaller entities
When an entity applies IFRS 6 and has selected an accounting policy to initially capitalize E&E
expenditures, it would be acceptable for such expenditures to be recognized as assets and expensed
when it is determined they will not lead to future economic benefits. Measurement of capitalized
costs would normally be on a project-by-project basis. For example:
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Small Explorers and Producers Association of Canada
Basis and Application of Impairment Tests
Projects
Pre-E&E
Phase
E&E
Phase
Post-E&E
Phase
1
2
3
In this example, none of the Projects is associated with an E&E CGU, i.e., each is a new stand-alone
project.
Project 1 consists only of pre-exploration expenditures, such as prospecting, and is expensed.
Project 2 expenditures are incurred subsequent to the acquisition of exploration rights, are
capitalized under the entity’s chosen IFRS 6 policy, and include the costs of drilling and abandoning
an exploratory well. Since no further activity is planned or budgeted for Project 2, it is deemed to
be impaired and the costs are expensed.
Project 3 expenditures consist of exploratory drilling, completion and equipping costs that are
capitalized under the entity’s chosen IFRS 6 policy and result in a commercially viable oil discovery.
It is tested for impairment under IAS 36 and, when no impairment is determined, it is reclassified
to development or production assets in the post E&E phase as a new and identifiable CGU and
accounted for under IAS 16.
There are variances to the foregoing example (not illustrated) depending on the entity’s chosen
accounting policies in respect of E&E expenditures. For example:
• If the unsuccessful Project 2 had been associated with, i.e., belonged to, a development or
production CGU (say, CGU-2), the impaired E&E assets could possibly be sheltered by an excess
of value (headroom) following the impairment test at the CGU-2 level. In such a situation, Project 2
costs would be reclassified to CGU-2 and no impairment loss would be recognized. In CGU-2,
Project 2 costs would be included with the CGU development or production assets subject to
depletion.
• If the successful Project 3 had been associated with, i.e. belonged to, a development or production
CGU (say, CGU-3) and the E&E asset impairment test prior to reclassification of the E&E assets to
CGU-3 indicated a partial impairment loss was required, e.g., the carrying amount of the costs of
the oil discovery was not fully supported by the associated newly-discovered reserves belonging
to CGU-3, a portion or the impairment loss could be sheltered by headroom following the
impairment test at the CGU-3 level and only the impaired portion would be expensed.
• Other scenarios could result depending on the entities chosen IFRS 6 policies.
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Vertical Impairment — larger entities
Larger entities may prefer to choose a vertical approach to E&E impairment testing. For example:
Projects
Pre-E&E
Phase
E&E
Phase
Post-E&E
Phase
1
2—4
CGU—A
5
CGU—B
CGU—X
6—9
Project 1 is not associated with either E&E phase CGU-A or CGU-B and consists only of a preexploration expenditure, such as prospecting, and is expensed.
Projects 2 — 4 are associated with and belong to E&E phase CGU-A, which is identified as an area in
which three separate exploratory projects (2, 3 and 4) are being undertaken. Project 2 expenditures
are incurred subsequent to the acquisition of exploration rights in the area, are capitalized under the
entity’s chosen IFRS 6 policy, and include the costs of drilling and abandoning an exploratory well.
No further activity is planned for Project 2; however, continuing exploration and evaluation activity in
the area for Projects 3 and 4 are planned and budgeted. Although Project 2 is impaired, it may not be
necessary to recognize an impairment loss provided the impairment test at the E&E phase CGU-A
level has sufficient headroom or shelter available.
Projects 5 — 9 are separate projects associated with and belonging to E&E phase CGU-B, which is
further identified as belonging to development or production CGU-X, i.e., E&E Projects 5 - 9, if
successful, will be reclassified to CGU-X. Project 5 expenditures consist of exploratory drilling,
completion and equipping costs that are recognized as assets under the entity’s chosen IFRS 6
policy and result in a commercially viable oil discovery. It is tested for impairment under IAS 36 and,
when no impairment is determined, the costs are reclassified into development or production assets
in CGU-X and accounted for under IAS 16. Projects 6 - 9 are planned and budgeted but have not
been started.
There are variances to the foregoing example (not illustrated) depending on the entity’s chosen
accounting policies in respect of E&E expenditures. For example:
• The unsuccessful Project 2 exploratory well could have been expensed following the impairment
test.
• If the lack of success of Project 2 resulted in a management decision to abandon all E&E activity
in the area, all capitalized costs in CGU-A would be impaired and expensed.
• If Project 5 was a new multi-well E&E project that required drilling several successful wells before
commercial viability could be ascertained, the costs of drilling the initial successful well could be
retained in CGU-B pending the completion of the full project, with the associated net revenues
(provided such net revenues were incidental) generated from the initial successful well being
credited to CGU-B.
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Small Explorers and Producers Association of Canada
Basis and Application of Impairment Tests
• Alternatively, if Project 5 had been unsuccessful and was determined to be impaired, the impaired
assets could possibly be sheltered by an excess of value (headroom) following the impairment test
at the CGU-B level and remain capitalized pending completion of Projects 6 — 9.
• Other scenarios could result depending on the entities chosen IFRS 6 policies.
Reversals of Impairment
An impairment loss on an E&E asset or CGU that has been recognized in accordance with IFRS 6 will
need to be reversed if there are indications that the previously recognized loss has been recovered
or reduced. In the event of such indications, the entity will need to recalculate the recoverable
amount and reinstate the carrying value up to, but not exceeding, the value at the current date as if
the impairment had never been recognized. Both cost and accumulated amortization, if any, of the
previously recognized impairment must be reversed. This means that, if the entity’s policy is to
amortize E&E assets, it will be required to recalculate amortization on the basis that the previously
recognized impairment loss had not occurred in order to determine the ceiling amount of the
reversal.
Derecognition
Entities recognizing impairment losses on E&E assets will need to decide whether or not to
derecognize the E&E assets if the entity has no plans to undertake further exploration and
evaluation activities and no future economic benefits are expected.
Issues
Impairment testing in the E&E phase is a complex process and requires careful management
consideration and judgment. Entities adopting either a horizontal approach or a vertical approach
to impairment testing of E&E assets will need to exercise caution in the selection of an IFRS 6 policy
and method of application. The following issues will require consideration:
• Whether to test for impairment at the individual E&E asset or CGU level
horizontal approach or
a vertical approach
to impairment testing
of E&E assets will need
• Whether to amortize E&E assets and the rate of amortization
to exercise caution.
• Accuracy of values as impairment indicators for E&E assets in times of extreme market volatility
• Use of current, historical average or forecast values as impairment indicators for E&E assets,
e.g., land
• Whether unsuccessful drilling costs in the E&E phase should ever be capitalized
• Whether to continue to aggregate E&E assets within a CGU when no future economic benefits
are expected
• The number of E&E phase dry holes necessary to reach an impairment conclusion in a multi-well
project
• Systems and methodologies to track intangible and tangible asset reclassifications through the
E&E phase to the development or production phase
• Systems and methodologies to track costs, amortization and impairments for potential
impairment reversal, and
• Criteria necessary to support reversals of impairment.
A further issue that must be addressed within the development or production phase is whether to
capitalize or expense development dry holes.
Canadian Association of Petroleum Producers
Entities adopting either a
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Sample disclosure
Melrose Resources PLC — E&E Impairment (extract)
In accordance with IFRS 6, exploration and evaluation costs are capitalized within intangible assets until the success or otherwise of the well or project has been established and is subject to an impairment review. Exploration
and evaluation expenditures are reviewed at each reporting date for indicators of impairment. If such indicators
exist then the assets are tested for impairment by allocating the relevant item to a cash-generating unit or group
of cash-generating units. An impairment test is also carried out before the transfer of costs related to assets
which are being transferred to development and production assets following a declaration of commercial reserves.
This impairment test is carried out in accordance with IAS 36, which requires that the impairment be calculated
on the basis of a cash-generating unit which is a field or a concession, as appropriate.
Impairment of Oil and Gas Assets
The purpose of this section is to provide further detail of impairment testing under the requirements
of IAS 36 in respect of oil and gas assets and assets capitalized under IAS 38. Oil and gas assets
comprise those assets in upstream oil and gas operations that are utilized to produce oil and gas and
encompass the costs to find associated reserves and develop infrastructure, i.e., the development or
production phase.
Indicators of Impairment
The first step in the impairment assessment process is to ascertain whether indicators of impairment
exist. The frequency of this impairment assessment, as well as the actual indicators of impairment,
will vary depending on the type of asset.
Oil and gas assets are
to be assessed for
impairment indicators at
each reporting date.
Under IAS 36, oil and gas assets are to be assessed for impairment indicators at each reporting date.
If there are indicators of impairment from this assessment then the entity is required to complete an
impairment test. As previously indicated, impairment tests must be performed at IFRS transition and
assessing for impairment indicators is different from actually performing the impairment tests.
IAS 36 provides the following indicators that a company should consider, at a minimum, when
assessing whether indications of impairment of oil and gas assets exist:
External sources of information
• During the period an asset’s market value has declined significantly, more than would be expected
as a result of the passage of time or normal use
• Significant changes with an adverse effect on the entity have taken place during the period, or will
take place in the near future, in the technological, market, economic or legal environment in which
the entity operates or in the market to which an asset is dedicated
• Market interest rates or other market rates of return on investments have increased during the
period, and those increases are likely to affect the discount rate used in calculating an asset’s
value in use and materially decrease the asset’s recoverable amount, or
• The carrying amount of the net assets of the entity is more than its market capitalization.
Internal sources of information
• Evidence is available to indicate obsolescence or physical damage of an asset
• Significant changes with an adverse effect on the entity have taken place during the period, or are
expected to take place in the near future, in respect of the extent or manner that an asset is used
or is expected to be used
• Evidence is available from internal reporting that indicates the economic performance of an asset
is, or will be, worse than expected
• Cash flows for acquiring an asset or subsequent cash needs for operating or maintaining the asset
are significantly higher than originally budgeted or are projected to decline significantly, or
• Operating losses or net cash outflows are evident when current period amounts are aggregated
with future budgeted amounts.
40
Small Explorers and Producers Association of Canada
Basis and Application of Impairment Tests
Level of Impairment Assessment and Impairment Test
Some of the indicators included in the internal sources of information listed above are aimed at
individual assets while others relate to CGUs or the entity as a whole. Under IAS 36, individual assets
are tested for impairment when both fair value and value in use are determinable for that asset.
However, in certain instances, the fair value of an asset might be determinable but its VIU on a
stand alone basis may not be. For example, the fair value of an individual asset might indicate that a
write-down is necessary; however, when the asset is part of a CGU, the CGU must also be tested for
impairment. If the CGU containing the asset is not impaired, then the asset’s VIU exceeds its carrying
amount and no impairment is recorded. Thus, it may be irrelevant to the recoverable amount of the
CGU that it contains an asset whose market value has deteriorated. However, an individual asset that
has suffered impairment and been written down (because the greater of the fair value and the VIU
for that asset is less than the carrying amount) is not written back up as a result of a positive CGU
impairment test for a CGU containing the asset.
The standard requires the carrying amount of an asset to be compared with its recoverable amount
where the recoverable amount is the higher of FVLCTS and VIU. If either FVLCTS or VIU is higher
than carrying value, no further action is required since the asset is not impaired. In addition, if
FVLCTS is greater than carrying value, no VIU calculation is necessary. It is noted, however, that
there is certain interplay between FVLCTS and VIU, i.e., if FVLCTS drops, then VIU may not be
far behind.
Although the determination of FVLCTS is predicated on the existence of an active market from which
to estimate current fair value, IAS 36.20 indicates that it may be possible to determine FVLCTS even
if an asset is not traded in an active market. However, it may be difficult to obtain reliable third party
estimates of fair value for these assets. Under such circumstances and for purposes of impairment
testing, it would be acceptable for entities to determine FVLCTS on a discounted cash flow (DCF)
basis. Alternatively, with certain adjustments, a VIU approach to impairment testing would also be
acceptable. Either a FVLCTS or VIU approach with modifications could be used to underly or support
impairment testing, however, neither will be accomplished by way of a straightforward process.
At the CGU level in an oil and gas entity, impairment testing would normally be supported by
information extracted from current reserve reports. Reserve reports are expected to be the
cornerstone for determining FVLCTS on a DCF basis or VIU on an adjusted basis:
• When determining FVLCTS using a DCF basis — understanding all the market inputs used to
generate the reserves report, e.g., current economic conditions, observable transactions, market
based data, risk parameters and sensitivities, future commodity pricing, production rates, royalty
rates, market discount rate, time period covered, and treatment and assumptions with respect to
future development costs, decommissioning liabilities, etc. Entity-specific synergies are not taken
into account under this valuation approach.
• When determining VIU — understanding the market inputs referred to above and estimating
future cash inflows and outflows from usage and eventual disposition and discounting the results
at an appropriate rate. In addition, there are limitations that must be considered and overcome in
the determination of VIU under IAS 36. Among them: the test is limited to the future five-year
growth period unless a longer period can be justified, e.g., the entity is confident that longer term
projections are reliable based on the accuracy of its past projection experience; the calculation
must be pre-tax; and future development costs are limited to those actually approved at the time
of the test, e.g., only approved costs to develop 2P reserves. Entity-specific synergies may be
taken into account under this valuation approach.
Canadian Association of Petroleum Producers
41
IAS 36.20 indicates that
it may be possible to
determine FVLCTS even if
an asset is not traded in
an active market.
International Financial Reporting Standards
Information Guide
Reversals of Impairment
IAS 36 is the applicable standard in respect of the impairment test and reversals of impairment for
development or production assets. As such, the same guidance as prescribed for E&E assets, as set
out above under the caption “Reversals of Impairment”, should be followed.
It should be noted that FVLCTS on a DCF basis for oil and gas assets may increase simply because
the present value of future cash flows increases as the time value discount is reduced. A past
impairment loss is not reversed due to the passage of time even if the recoverable amount is
higher than the carrying amount.
Other Considerations
Reserves
As previously indicated neither the AcSB nor the IASB has established reserves classifications for
the oil and gas industry.
Both FVLCTS on a DCF basis
and VIU determinations are
expected to be supported
by the entity’s reserves
report.
For an upstream oil and gas entity, both FVLCTS on a DCF basis and VIU determinations are
expected to be supported by the entity’s reserves report provided the report has been prepared by
reputable independent reservoir engineers who may use their own assumptions with respect to
pricing and other inputs to their economic forecasting models. The reserves report should be based
on reasonable and supportable assumptions that represent management’s best estimate, predicated
on market assumptions of economic conditions that will exist over the remaining life of the assets.
As reserve reporting involves significant judgment, expertise and management estimates, the
following best practices should be considered:
Which Reserves
• Use Proved plus Probable (2P) reserves in accordance with NI 51-101.
Pricing
• Use Forecast pricing.
Time Period
• In the oil and gas industry, independent reserve reports are prepared that span the economic
life of the oil and gas assets. These reserve reports are used by management in resource
allocation and operating and investment decisions as well as by the marketplace and
investment community for analysis and evaluation. It is reasonable that these cash flow
projections should be used in conjunction with impairment assessments.
Future Development Expenditures
• In the oil and gas industry, reserve reports typically include future development costs in the
cash flow projections, in particular those costs necessary to develop and reclassify risked
probable reserves into proved reserves. Those costs are generally required to maintain the
level of economic benefits expected to arise from existing reserves and to gain access to
probable reserves. It is reasonable that these future capital expenditures should be used in
conjunction with impairment assessments.
Decommissioning Liabilities
• Cash outflows that relate to obligations that have already been recognized as liabilities on the
balance sheet are to be excluded from the cash flow projections to avoid double counting.
Decommissioning liabilities should be allocated among CGUs and decommissioning assets are
not excluded from impairment testing.
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Small Explorers and Producers Association of Canada
Basis and Application of Impairment Tests
Discount Rate
The discount rate or rates should reflect current market assessments of the time value of money
and the risks specific to the asset for which the future cash flow estimates have not been adjusted.
In some cases additional
With regard to the time value of money, the standard states the current market risk-free rate of interest should be used. With regard to risk, the entity’s reserve report would normally be expected to
address “technical” and “economic” risks in respect of the reserves; however, in some cases
additional risks such as political risk should be considered in establishing an appropriate
discount rate.
should be considered in
risks such as political risk
establishing an appropriate
discount rate.
Goodwill
Under IFRS, goodwill is normally recognized only in business combinations. Since goodwill is
incapable of generating independent cash flows, it must be allocated to one or more CGUs or
operating segments expected to achieve synergies from the combination, not just to the assets
acquired. Goodwill that is allocated must represent the lowest level within the entity at which the
goodwill is monitored for internal management purposes, which cannot be larger than an operating
segment. Goodwill is not amortized but must be tested annually for impairment. IAS 36 sets out a
specific order for impairment testing of a CGU to which goodwill has been allocated.
Any asset for which an impairment indicator exists is first tested separately for impairment if its
recoverable amount can be estimated reliably. If goodwill has been allocated to a CGU, impairment
at the CGU level is then tested excluding the goodwill. An impairment loss at the CGU level must be
recognized immediately as an expense in the income statement and the loss must first be applied to
reduce the carrying value of any goodwill allocated to the CGU and then to reduce other assets in the
CGU pro rata with the carrying amount of each asset.
Since the impairment test at the CGU level containing the goodwill is only carried out after the
individual asset test, the effect of this sequencing is that where goodwill is allocated to only one CGU,
no amount of assets will be written down until all the goodwill has been written off. Goodwill must be
written down first and cannot be reversed under any circumstances.
The standard requires impairment testing for goodwill as follows:
• All CGUs or groups of CGUs containing goodwill must be tested for impairment at least annually
and at the same time each year, and
• If goodwill has been allocated during the current period, the CGU or group of CGUs must be tested
for impairment before the end of the period.
A CGU having goodwill allocated to it may need to be tested twice during a year, e.g., if the test for
goodwill supersedes the identification of impairment indicators for oil and gas assets, the goodwill
will need to be tested again in conjunction with the impairment test of the oil and gas assets. An
example would be receipt of a reserves report setting out substantial reductions of reserves
subsequent to completion of the initial goodwill impairment test.
A CGU having goodwill
allocated to it may need to
be tested twice during
a year.
The Proposed IFRS 1 Amendment
The proposed IFRS 1 Amendment will require impairment tests for oil and gas assets to be
completed at the date of transition to IFRS. Disclosure of any resulting impairment losses
will be required.
Disclosures
IAS 36 requires disclosure of the following with respect to impairments:
• The amount of any actual impairment losses or reversals made during the period including the
line item in the income statement in which such losses or reversals are included, and
• Information concerning the annual impairment tests for goodwill and intangible assets having
an indefinite useful life regardless of whether or not any impairment adjustment has been
recognized, including the line item in the income statement in which such losses are included.
Canadian Association of Petroleum Producers
43
International Financial Reporting Standards
Information Guide
IAS 36 requires the following disclosures with respect to CGUs:
• For each material impairment loss recognized or reversed during the period for a CGU, a
description of the CGU is required, and
• Detailed information about the estimates used to measure recoverable amounts of CGUs
containing goodwill or intangible assets with indefinite useful lives is required.
IFRS 3 “Business Combinations” has a specific requirement that an entity must disclose sufficient
information about goodwill to enable users of its financial statements to evaluate changes in the
carrying amount of goodwill during the period.
Financial statement note disclosure — Oil and Gas Assets
E&E
Assets
Cost
$
Accumulated impairments
5,000
Development or
Production Assets
$
(2,500)
25,000
(1,000)
Balance sheet disclosed amounts:
Cost
2,500
Accumulated DD&A
Net assets
24,000
(500)
$
2,000
(6,000)
$
18,000
Although accumulated impairments are not shown separately on the balance sheet, they should be
disclosed in the notes accompanying the financial statements. Alternatively, only the net assets could
be disclosed and the supporting details included in the notes — see example in Section 3.
Sample disclosure
Eni S.p.A — Oil and Gas Asset Impairment (extract)
The carrying value of property, plant and equipment is reviewed for impairment whenever events indicate that
the carrying amounts for those assets may not be recoverable. The recoverability of an asset is assessed by
comparing its carrying value with the recoverable amount represented by the higher of fair value less costs to
sell and value in use.
If there is no binding sales agreement, fair value is estimated on the basis of market values, recent transactions,
or the best available information that shows the proceeds that the company could reasonably expect to collect
from the disposal of the asset.
Value in use is the present value of the future cash flows expected to be derived from the use of the asset and,
if significant and reasonably determinable, the cash flows deriving from its disposal at the end of its useful life,
net of disposal costs. Cash flows are determined on the basis of reasonable and documented assumptions that
represent the best estimate of the future economic conditions during the remaining useful life of the asset, giving
more importance to independent assumptions. Oil, natural gas and petroleum products prices used to quantify the
expected future cash flows are estimated based on forward prices prevailing in the marketplace for the first four
years and management’s long-term planning assumptions thereafter. Discounting is carried out at a rate that
takes into account the implicit risk in the sectors where the entity operates.
Valuation is carried out for each single asset or, if the realizable value of a single asset cannot be determined, for
the smallest identifiable group of assets that generates independent cash inflows from their continuous use, the
so called “cash generating unit”. When the reasons for their impairment cease to exist, Eni makes a reversal that
is recognized in profit or loss account as income from asset revaluation. This reversed amount cannot exceed the
carrying amount that would have been determined, net of depreciation, had no impairment loss been recognized
for the asset in prior years.
44
Small Explorers and Producers Association of Canada
Basis and Application of Impairment Tests
Goodwill and other intangible assets with an indefinite useful life are not amortized. The recoverability of their
carrying value is reviewed at least annually and whenever events or changes in circumstances indicate that the
carrying value may not be recoverable. Goodwill is tested for impairment at the level of the smallest aggregate on
which the company, directly or indirectly, evaluates the return on the capital expenditure to which goodwill relates.
When the carrying amount of the cash generating unit, including goodwill allocated thereto, exceeds the cash
generating unit’s recoverable amount, the excess is recognized as impairment. The impairment loss is first
allocated to reduce the carrying amount of goodwill; any remaining excess to be allocated to the assets of the
unit is applied pro-rata on the basis of the carrying amount of each asset in the unit. Impairment charges against
goodwill are not reversed3. Negative goodwill is recognized in the profit and loss account.
BP — Oil and Gas Asset Impairment (extract)
The group assesses assets or groups of assets for impairment whenever events or changes in circumstances
indicate that the carrying value of an asset may not be recoverable. If any such indication of impairment exists,
the group makes an estimate of its recoverable amount. Individual assets are grouped for impairment assessment
purposes at the lowest level at which there are identifiable cash flows that are largely independent of the cash
flows of other groups of assets. An asset’s group recoverable amount is the higher of its fair value less costs to
sell and its value in use. Where the carrying amount of an asset group exceeds its recoverable amount, the
asset group is considered impaired and is written down to its recoverable amount. In assessing value in use, the
estimated future cash flows are adjusted for the risks specific to the asset group and are discounted to their
present value using a pre-tax discount rate that reflects current market assessments of the time value of money.
An assessment is made at each reporting date as to whether there is any indication that previously recognized
impairment may no longer exist or may have decreased. If such indication exists, the recoverable amount is
estimated. Any previously recognized loss is reversed only if there has been a change in the estimates used to
determine the asset’s recoverable amount since the last impairment loss was recognized. If that is the case, the
carrying amount of the asset is increased to its recoverable amount. That increased amount cannot exceed the
carrying amount that would have been determined, net of depreciation, had no impairment loss been recognized
for the asset in prior years. Such reversal is recognized in profit or loss. After such reversal, the depreciation
charge is adjusted in future periods to allocate the asset’s revised carrying amount, less any residual value,
on a systematic basis over its remaining useful life.
Repsol YPF Group — Oil and Gas Asset Impairment (extract)
In order to ascertain whether its assets have become impaired, the Group compares their carrying amount
with their recoverable amount at the balance sheet date or more frequently if there are indications that the assets
might have become impaired. For that purpose, assets are grouped into cash-generating units as they
generate cash flows which are independent from other units. To perform this test, goodwill acquired on a business
combination is allocated among the cash-generating units or groups of cash-generating units that benefit from
the synergies of the business combination and the recoverable amount thereof is estimated by discounting the
estimated future cash flows of each unit.
Recoverable amount is the higher of fair value less costs to sell and value in use. In assessing value in use, the
estimated future cash flows are discounted to their present value using a rate that reflects the weighted average
cost of capital employed, which is different for each country and business. If the recoverable amount of an asset
(or a cash-generating unit) is estimated to be less than its carrying amount, the carrying amount of the asset (or
the cash-generating unit) is reduced to its recoverable amount, and an impairment loss is recognized as an
expense under “Other Expenses” in the consolidated income statement.
The basis for future depreciation or amortization will take into account the reduction in the value of the asset
as a result of any accumulated impairment losses. When an impairment loss subsequently reverses, the carrying
amount of the asset (or the cash-generating unit) is increased to the revised estimate of its recoverable amount,
so that the increased carrying amount does not exceed the carrying amount that would have been determined in
case no impairment loss had been recognized for the asset (or the cash-generating unit) in prior years. A reversal
of an impairment loss is recognized under “Other Income” in the consolidated income statement. An impairment
loss recognized for goodwill cannot be reversed in a subsequent period.
Canadian Association of Petroleum Producers
45
International Financial Reporting Standards
Information Guide
Summary Chart
The following summary chart describes an approach to impairment testing for E&E assets, oil and
gas assets, indefinite life intangible assets and goodwill and the level and frequency of impairment
assessment. Note that under the proposed IFRS 1 amendment impairment testing is also required
on transition.
E&E Assets
Aggregation / Tests
No Aggregation / Tests
Level at which E&E assets
are assessed for impairment
(IFRS 6)
Individual asset or groups of assets,
CGU or group of CGUs including
development or production CGUs,
if any, to which the E&E assets
belong. The group of CGUs cannot
be larger than an operating segment.
Lowest level (selected policy
for unit of account
measurement).
Frequency of impairment
assessment
(IFRS 6)
a) When facts and circumstances
suggest the carrying amount
exceeds the recoverable amount.
a) When facts and circumstances
suggest the carrying amount
exceeds the recoverable amount.
b) On transition to IFRS
b) On transition to IFRS
c) On reclassification to
development or production assets.
c) On reclassification to
development or production assets.
Type of impairment test
(IAS 36)
Compare the carrying amount to
the recoverable amount. The
recoverable amount will
generally be FVLCTS.
Compare the carrying amount to
the recoverable amount. The
recoverable amount will
generally be FVLCTS.
Oil and Gas Assets
Approach
Level at which development
or production assets are
assessed for impairment
(IAS 36)
Individual assets and CGU.
Frequency of impairment
assessment (IAS 36)
Assess for impairment at each reporting date; test for impairment at transition
and test subsequently only when indicators of impairment are present.
Type of impairment test
(IAS 36)
Compare the carrying amount to the recoverable amount. The recoverable
amount could be determined on either a FVLCTS or a VIU basis; each
approach will require modifications from a strict interpretation of the
related IFRS definitions.
Indefinite Life Intangible
Assets and Goodwill
Approach
Level at which development
assets are assessed for
impairment (IAS 36)
CGU or group of CGUs up to an operating segment.
Frequency of impairment
assessment subsequent to
the required impairment test
at transition (IAS 36)
Assess for impairment at each reporting date; an impairment test for
indefinite life intangible assets is required annually; an impairment test
for goodwill is required on an annual basis and at the same time each year.
Type of impairment test
(IAS 36)
Compare the carrying amount to the recoverable amount. The recoverable
amount will be the higher of the VIU and FVLCTS.
46
Small Explorers and Producers Association of Canada
SECTION 6 — DECOMMISSIONING
LIABILITIES
Background
IAS 37 “Provisions, Contingent Liabilities and Contingent Assets” deals with provisions that are
included as liabilities on an entity’s balance sheet, where a “provision” is defined as a liability of
uncertain timing and amount. Thus, the scope of IAS 37 covers decommissioning liabilities (asset
retirement obligations or ARO is the term commonly understood and practiced by the Canadian oil
and gas industry) and management will need to apply care and judgment in applying this IAS standard.
IFRIC 1 “Changes in Existing Decommissioning, Restoration and Similar Liabilities” provides additional
guidance on accounting for the effects of changes in the measurement of existing provisions to
dismantle, remove or restore items of property, plant and equipment (PP&E).
The IASB has indicated that major modifications to IAS 37 are forthcoming, including recognition
and measurement changes; however, the timing of the revised standard is uncertain.
Matters for Consideration
The objective of IAS 37 “is to ensure that appropriate recognition criteria and measurement bases
are applied to provisions, contingent liabilities and contingent assets and to ensure that sufficient
information is disclosed in the notes to enable users to understand their nature, timing and amount”.
The following matters will require consideration in conjunction with an entity’s adoption of an
accounting policy in respect of decommissioning liabilities:
No provision should
• A provision is a liability of uncertain timing or amount, which should be recognized when,
and only when:
of future operations.
— An entity has a present obligation (legal or constructive) as a result of a past event
— It is probable, i.e., more likely than not, that an outflow of resources embodying economic
benefits will be required to settle the obligation, and
— A reliable estimate can be made of the amount of the obligation (the standard notes a
sufficiently reliable estimate can almost always be made for a provision since an entity is
generally capable of determining a range of possible outcomes).
• Conversely, no provision should be recognized for costs that will need to be incurred as a result
of future operations, i.e., liabilities to be recognized are those that exist at the reporting date and
are not the result of normal operating activities
• In the extremely rare cases when an entity cannot determine a range of possible outcomes, no
provision should be recognized and the matter should be disclosed as a contingent liability
• A past event is deemed to give rise to a present obligation if, taking account of all available
evidence, it is more likely than not that a present obligation exists at the reporting date, i.e.,
the probability is greater than 50%
• The amount to be recognized as a provision should be management’s best estimate of the
present value of the expenditure required to settle the obligation at the reporting date
• In measuring a provision, an entity should:
— Take risks and uncertainties into account; however, there is no justification for creating
excessive provisions or deliberately overstating liabilities
— Discount the provisions when the effect of the time value of money is material using a pre-tax
discount rate (or rates) that reflect(s) current market assessments of the time value of money
and those risks specific to the liability that have not been reflected in the best estimate of
the expenditure
— Ensure that when discounting is used the increase in the provision due to the passage of time
is recognized as a financing cost
— Take future events such as changes in law and technological changes into account only when
there is sufficient objective evidence that the events will occur, and
— Not take gains from the expected disposal of assets into account even if the expected disposal
is closely linked to the event giving rise to the provision.
Canadian Association of Petroleum Producers
47
be recognized for costs
that will need to be
incurred as a result
International Financial Reporting Standards
Information Guide
• Provisions should be reviewed at each balance sheet date and adjusted to reflect the current
best estimate. If it is no longer probable that an outflow of resources embodying economic
benefits will be required to settle the obligation, the provision should be reversed, and
• A provision should be used only for expenditures for which the provision was originally
recognized, i.e., charging costs against a provision for which it was not originally intended is
not permitted.
Additional standards related to provisions for decommissioning liabilities can be found in IFRS 1
“First-time Adoption of International Financial Reporting Standards”; IFRIC 1; and, IFRIC 5 “Rights to
Interests Arising from Decommissioning, Restoration and Environmental Rehabilitation Funds”. See
also Section 9 for a discussion of the proposed amendment to IFRS 1 that, if approved by the IASB,
may have an impact on the measurement of decommissioning liabilities as determined under an
entity’s current GAAP and at transition to IFRS under IAS 37.
IAS 37 Discussion
The following table sets out the expected treatment of decommissioning liabilities under IAS 37:
Likelihood of outcome
Accounting treatment
Disclosure
Virtual certainty
Recognize the liability
Yes
Probable
Recognize the liability
Yes
Possible, but not probable
No recognition
Yes
Remote
No recognition
No
Practical issues must be considered and careful judgment applied in support of the criteria
underlying the range of probabilities that could be used in applying percentages to the “Likelihood
of outcome” column.
Recognition of a liability
IAS 37, as set out above, requires recognition of a provision when all of the following conditions
are met:
• An entity has a present obligation (legal or constructive) as a result of a past event
• It is probable that an outflow of resources will be required to settle the obligation, and
• A reliable estimate can be made of the amount of the obligation.
For an event to be an
obligating event, it is
necessary that the entity
has no realistic alternative
to settling the obligation
created by the event.
For an event to be an obligating event, it is necessary that the entity has no realistic alternative to
settling the obligation created by the event. This is the case only when:
• The settlement of the obligation can be enforced by law, or
• In the case of a constructive obligation where the event creates valid expectations in other
parties that the entity will discharge the obligation.
Legal obligation
A legal obligation derives from a contract, legislation or other operation of law. Changes in law
should not be recognized until it is virtually certain that the legislation will be enacted as drafted,
which is often not until it is enacted. Changes in legislation can result from instances where a
provision was not initially required when the obligating event occurred, but is later required
when it becomes virtually certain new legislation will pass. Changes in contracts become
effective when the contract is executed.
48
Small Explorers and Producers Association of Canada
Decommissioning Liabilities
Constructive obligation
A constructive obligation derives from an entity’s actions under which, by an established pattern
of past practice, published policies or by a sufficiently specific current statement, the entity has
indicated to other parties that it will accept certain responsibilities and, as a result, the entity
has created a valid expectation on the part of those other parties that it will discharge those
responsibilities.
The existence of a constructive obligation is subjective and can be difficult to discern. For example,
a management or board decision would not be expected to give rise to a constructive obligation
unless it is communicated in sufficient detail to those affected by it. Therefore, management can
impact the financial reporting by the timing of an announcement. A public announcement may
create a constructive obligation, but the announcement must carry sufficient weight that it leaves
the company little alternative but to carry out the remedial work. An example of what normally
would be expected to create a constructive obligation is a widely publicized environmental policy
or a contamination clean-up policy. In practice there may be situations where it appears a
constructive obligation exists, but because it can be avoided, no obligating event has occurred.
Said another way, there is no need to recognize a constructive obligation when actions are taken
to avoid creating the obligation in the first place. Examples might be a planned future change in
the method of operations, future staff training or refurbishment plans, all of which are to be
designed to avoid the expenditure.
Initial recognition
With respect to the initial recognition of decommissioning liabilities:
• Provisions should only be recognized if the obligation arises from past events existing
independently of an entity’s future actions; thus, if an entity can avoid an obligation by its
future actions, no provision is required (see preceding examples)
• The cost of dismantling and removing an asset associated with the construction of the
asset should be apportioned in the original cost of the asset
• Obligations to decommission an asset should be recognized during the exploration and
evaluation and development or production phases, as appropriate, rather than at the time
the asset begins commercial production. This is an important consideration for an asset that
takes a substantial period of time to prepare for its intended use. An example would be an oil
sands extraction project involving long lead times for development and eventual production.
During the initial phase of the project, the company may have to provide for reclamation of
disturbances, although no contamination from production will have occurred. Once production
commences, however, the provision will have to be adjusted to recognize anticipated clean up
expenditures for contamination
• An obligation always involves another party to whom the obligation is owed. It is not necessary
to know the identity of the other party - it could be the public at large, e.g., an environmental
clean-up obligation could be owed to the public but the liability will be settled by payment to
the clean-up contractor, and
• An entity must make a provision for environmental remediation and reclamation for all long
lived assets.
Canadian Association of Petroleum Producers
49
International Financial Reporting Standards
Information Guide
Discount rates
The standard requires that, in the event the time value of money is significant, the amount of a
provision should be the present value of the expected expenditures necessary to discharge the
obligation.
It will be important for entities to be consistent in the choice and application of a discount rate, not
only from period to period but also to situations in which discounting is required, e.g., impairment
tests, cash flows from reserves, etc. The standard notes:
• The amount of the provision is the present value of the expenditure expected to be required to
settle the obligation;
• The discount rate applied is a pre-tax rate that reflects current market assessments of the time
value of money and the risks specific to the liability; and
• The discount rate should not reflect risks for which future cash flow estimates have been adjusted.
IAS 37 includes reference to real discount rates in Appendix D, Example 2.
Following is a brief discussion of choices that entities might consider in selecting a discount rate:
Real vs. nominal rate
• If future cash flows are expressed in current dollars, a real discount rate is used. If future cash
flows are expressed in forecast dollars, a nominal discount rate is used. The initial present value
of the obligation will be the same under each method, but the unwinding of the discount will
be different.
• If cash flows are expressed using forecast prices and are discounted at a nominal rate, the
entire unwinding of the discount in future years will be included as a financing cost in the
income statement. Future costs may be derived from current costs adjusted for inflation and
may take into account enacted changes in laws and expected changes in technology.
• If cash flows are expressed in current dollars and a real discount rate is used, the annual
financing cost will be lower but management will have to revise cost estimates each year to
take inflation into account, which may result in recognition of an incremental cost and a
higher annual amortization expense.
Risk free vs. risk adjusted rate
The risk free rate would likely be a government bond rate for the same term, not the yield on a
high quality corporate bond as suggested by IAS 19 “Employee Benefits”. There are a number of
practical issues for entities to consider in selecting a risk free rate or a risk adjusted rate:
• It is more difficult to risk adjust the discount rate and less difficult to risk adjust the cash flows.
• One method to risk adjust the cash outflows is to estimate cash outflows using a deck of
different possible outcomes. A risk adjustment would be made to the single point best estimate
of the liability. Using a weighted average of estimates on a portfolio of properties, wells and
facilities may also yield a reliable estimate of risk adjusted cash flows.
• The use of proved plus probable reserves (2P) as the basis for the timing of well abandonment
and the trigger for decommissioning and restoration expenditures should not require further
risk adjustment since risk has already been factored into the reserves determination.
• Under IFRS, the risk adjusted rate will always be less than the risk free rate, which would result
in a higher liability on the balance sheet. The recognition of a higher liability is to offset the
inherent uncertainty in the estimate. (This is different from current North American practice
where the credit adjusted risk free rate represents a company’s estimated costs of borrowing to
finance its future expenditures and is always higher than the risk free rate.)
Single rate or multiple rates
A single rate would be appropriate when there is a single cash flow, but if cash outflows are
generated at different points in time or in different geographies, the discount rate should reflect
this distinction.
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Small Explorers and Producers Association of Canada
Decommissioning Liabilities
Summary of discount rate/cost choices
The following table summarizes the alternatives for discount rates and cost bases:
Rate
Real interest rate
Nominal interest rate
Risk free interest rate
Current risk adjusted costs
Future risk adjusted costs
Risk adjusted interest rate
Current unrisked costs
Future unrisked costs
Use of a risk free nominal interest rate simplifies the calculations of liability and accretion and is
the closest method to current North American practice. However, companies may choose other
options after analyzing the implicit financial impacts.
Future periods and changes
The decommissioning provision must be reviewed at each reporting date and adjusted to reflect
management’s current best estimates. In addition, at each reporting date the decommissioning
provision is to be recalculated for changes in the estimated timing or amount of future cash
outflows.
Accounting for changes in provisions is outlined in IFRIC 1 and is applicable to decommissioning
liabilities that have been both included in PP&E as part of an asset measured under IAS 16 and
measured as a liability under IAS 37. It deals with the effect of the following three changes:
1. A change in the estimated timing of outflow of resources necessary to discharge the obligation
2. A change in the current market based discount rate (changes in the time value of money and
risks specific to the liability), and
3. An increase that reflects the passage of time (also referred to as the unwinding of the discount
or accretion of the discount).
For changes caused by items 1 and 2, the change is added to or deducted from the cost of the asset
to which it relates and the adjusted amount is amortized prospectively over the estimated life of the
asset. A downward adjustment to the decommissioning and restoration asset cannot exceed the
current carrying amount of the asset. Any excess should be recognized in the income statement
in the current period.
The unwinding of the discount (item 3) arising from the passage of time is recognized as a financing
cost in the income statement. It is not a borrowing cost as defined in IAS 23 “Borrowing Costs” and
cannot be capitalized.
A change in decommissioning liabilities is reflected as a change in the liability at the time the revised
estimate is made; similarly, a change in the discount rate would be expected to be applied only at
that time, i.e., the new estimate is discounted at the new discount rate.
Expenditures incurred for dismantling or removing damaged equipment or restoring a site should
be expensed when they result from operating activities, e.g., an environmental or other operational
accident, and capitalized when they are associated with drilling, construction or other capital
activities.
Canadian Association of Petroleum Producers
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A change in decommissioning
liabilities is reflected as
a change in the liability
at the time the revised
estimate is made.
International Financial Reporting Standards
Information Guide
Indefinite life assets
• IAS 37 states that in rare cases only will an entity be unable to determine a range of possible
outcomes of decommissioning liabilities associated with indefinite life assets and can, therefore,
make an estimate of the obligation that is sufficiently reliable to use in recognizing a provision.
• In the rare case where no reliable estimate can be made, a liability exists that cannot be
recognized and should be disclosed as a contingent liability.
• Management must exercise judgment in determining the best estimate of the amount and
timing of future cash flows to settle decommissioning liabilities on indefinite life assets.
Revaluation model
For entities accounting for PP&E using the revaluation model, a change in decommissioning liabilities
does not affect the valuation of the item for accounting purposes. Instead, it alters the revaluation
surplus or deficit related to the item and the effect of the change is treated consistently with other
revaluation surpluses or deficits, i.e., any cumulative deficit is recognized immediately in income,
but any cumulative surplus is credited to equity.
Issues
The following issues will require management’s consideration in conjunction with adoption of IFRS
and IAS 37:
• Identification of all legal and constructive obligations for decommissioning liabilities
• Determination of whether new decommissioning liabilities will need to be recognized at transition
and subsequently based on the “greater than 50%” probability threshold for recognizing such
liabilities (current Canadian standards are rigorous and the change to IFRS would not generally
be expected to have a significant recognition impact on the upstream oil and gas industry)
• Measurement of amounts and timing, including accounting for changes, of decommissioning
cash flows
• Selection of an appropriate discount rate and cost basis on which to calculate the
decommissioning liabilities, which will require a choice between:
• Using a risk free interest rate and risk adjusting the decommissioning cash flows or using a risk
adjusted interest rate and unrisked decommissioning cash flows, and
• Using a nominal interest rate and inflation adjusted (future dollar) decommissioning cash flows
or using a real interest rate and current dollar decommissioning cash flows.
• Determination of decommissioning liabilities, if any, for indefinite life assets based on
management’s best estimates of amounts and timing.
Disclosures
The IAS 37 standard requires that, for each class of provision, an entity must disclose:
• The carrying amount at the beginning and end of the period
• Additional provisions made in the period, including increases to the existing provision
• Amounts used during the period, i.e., incurred and charged against the provision
• Unused amounts reversed during the period, and
• The increase during the period in the discounted amount arising from the passage of time and
the effect of any change in the discount rate.
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Small Explorers and Producers Association of Canada
Decommissioning Liabilities
In addition, an entity must disclose the following for each class of provision:
• A brief description of the nature of the obligation and the expected timing of any resulting
outflows of economic benefits
• An indication of the uncertainties about the amount or timing of those outflows, including
where necessary, adequate disclosure of the major assumptions made concerning future
events, and
• The amount of any expected reimbursement stating the amount of any asset that has been
recognized for that expected reimbursement.
Illustrative Example — Decommissioning and Restoration
The Company provides for future decommissioning and restoration liabilities related to its oil and
gas operating activities based on current legislation, constructive obligations and industry operating
practices. Decommissioning and restoration obligations are recognized as a liability in the period
in which they are incurred. When the liability is initially recognized, an amount equivalent to the
provision is capitalized as a cost of the related oil and gas asset. This cost is amortized to expense
through depletion and depreciation over the life of the related asset. The provision recognized is
the estimated future cost of decommissioning and restoration, discounted to its net present value
using the nominal risk free interest rate (or “real risk-free interest rate” or “nominal risk adjusted
interest rate” or “real risk adjusted interest rate”). Changes in the estimated amount or timing of
decommissioning and restoration costs are dealt with prospectively by recording an adjustment to
the provision and a corresponding adjustment to the related asset. The unwinding of the present
value discount on the provision is recognized as a finance cost.
Decommissioning and restoration liabilities — balance sheet
Balance, beginning of year
2012
$
New provisions
1,270
2011
$
345
Changes in estimates
Liabilities settled
Unwinding of discount
250
50
45
(125)
(60)
40
35
Balance, end of year
$
1,580
$
Current
$
380
$
Non current
1,200
$
1,000
1,580
1,270
270
1,000
$
1,270
The provision for decommissioning and restoration is based on the estimated net present value of
future costs for abandoning wells, removing facilities and restoring the affected areas. The provision
has been estimated based on existing technology, at current prices and discounted using a real
discount rate of x percent (2011 — x percent) (or “at future prices and discounted using a nominal
discount rate of y percent”). While these assumptions are reviewed regularly to take into account
changes in technology, prices and other factors, there still remains uncertainty regarding both the
amount and timing of these costs. The majority of these costs are expected to be incurred over
the next xx years.
Decommissioning and restoration liabilities — income statement
Interest on bank overdrafts and loans
2012
$
540
2011
$
450
Interest on obligations under finance leases
75
70
Other interest and borrowing costs
25
45
Unwinding of discount on decommissioning and restoration liabilities
Interest capitalized
$
Canadian Association of Petroleum Producers
40
35
(120)
(95)
560
$
505
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Sample disclosure
BP - Provisions (extract)
Provisions and Contingencies
Provisions are recognized when the group has a present obligation (legal or constructive) as a result of a past
event, it is probable that an outflow of resources embodying economic benefits will be required to settle the
obligation and a reliable estimate can be made of the amount of the obligation. Where appropriate, the future
cash flow estimates are adjusted to reflect risks specific to the liability. Where the group expects some or all of
a provision to be reimbursed, for example, under an insurance contract, the reimbursement is recognized as a
separate asset, but only when the reimbursement is virtually certain. The expense relating to any provision is
presented in the income statement net of any reimbursement. If the effect of the time value of money is material,
provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current
market assessments of the time value of money. Where discounting is used, the increase in the provision due to
the passage of time is recognized as other finance expense. A contingent liability is disclosed where the existence
of an obligation will only be confirmed by future events or where the amount of the obligation cannot be
measured with reasonable reliability. Contingent assets are not recognized, but are disclosed where an inflow
of economic benefits is probable.
Environmental Expenditures and Liabilities
Environmental expenditures that relate to current or future revenues are expensed or capitalized as appropriate.
Expenditures that relate to an existing condition caused by past operations and do not contribute to current or
future earnings are expensed. Liabilities for environmental costs are recognized when environmental assessments
or clean-ups are probable and the associated costs can be reliably estimated. Generally, the timing of recognition
of these provisions coincides with the commitment to a formal plan of action or, if earlier, on divestment or on
closure of inactive sites. The amount recognized is the best estimate of the expenditure required. Where the
liability will not be settled for a number of years, the amount recognized is the present value of the estimated
future expenditure.
Decommissioning
Liabilities for decommissioning costs are recognized when the group has an obligation to dismantle and remove
a facility or an item of plant and to restore the site on which it is located, and when a reliable estimate of that
liability can be made. Where an obligation exists for a new facility, such as oil and natural gas production or
transportation facilities, this will be on construction or installation. An obligation for decommissioning may also
crystallize during the period of operation of a facility through a change in legislation or through a decision to
terminate operations. The amount recognized is the present value of the estimated future expenditure determined
in accordance with local conditions and requirements. A corresponding item of property, plant and equipment of
an amount equivalent to the provision is also created. This is subsequently depreciated as part of the asset. Other
than the unwinding discount on the provision, any change in the present value of the estimated expenditure is
reflected as an adjustment to the provision and the corresponding item of property, plant and equipment.
54
Small Explorers and Producers Association of Canada
SECTION 7 — ISSUES SPECIFIC TO
IN-SITU HEAVY OIL AND OIL SANDS
Background
All public companies in Canada involved in in-situ heavy oil or oil sands exploration, development and
extraction will be required to adopt IFRS for interim and annual financial statements for fiscal years
beginning on or after January 1, 2011. As a result, the information contained in this Guide can be
expected to impact public companies involved in in-situ heavy oil sands exploration and production
in a similar manner as conventional upstream oil and gas companies, with limited exceptions.
One exception is that only oil and gas companies currently following full cost accounting under
Canadian GAAP will be permitted to elect to take advantage of the proposed amendment to IFRS 1
outlined in Section 9. The election will not be available to entities that have been following the
successful efforts method of accounting for oil and gas activities.
Until the IASB completes its Extractive Industries Research Project and issues further guidance, it is
expected that public companies involved in in-situ heavy oil or oil sands extraction will continue to
apply their current capitalization policies, subject only to changes necessary to conform with IFRS.
The principal standards that will require review and consideration by these entities are: IFRS 1 “First
Time Adoption of International Financial Reporting Standards”; IFRS 6 “Exploration and Evaluation of
Mineral Resources”; IAS 16 “Property, Plant and Equipment”; IAS 23 “Borrowing Costs”; IAS 36
“Impairment of Assets”; IAS 37 “Provisions, Contingent Liabilities and Contingent Assets”; and,
IAS 38 “Intangible Assets”.
Methods of in-situ heavy oil or oil sands extraction
There are currently several methods of in-situ heavy oil or oil sands extraction, but, as the industry
is still predominantly in its formative stages, there is no single standard of extraction, one that is
both low cost and efficient that can be applied across most reserve deposits. There are five principal
technologies used in the development and extraction of in-situ heavy oil or oil sands (other
technologies are also emerging):
There is no single
standard of extraction.
• Cold Heavy Oil Production with Sand — this technique utilizes a submersible pump which lifts
oil, sand, minerals and sediment from the producing horizon into a wellbore. Hydrocarbons
extracted this way are usually produced without additional heating or chemicals and the method
is considered the most simple extraction process for heavy oil that is deep below the surface.
• Steam Assisted Gravity Drainage — this method of heavy oil extraction involves heating the heavy
oil with steam, then collecting the less viscous oil by gravity drainage through horizontal well
bores. It works well when the heavy oil is capable of easy uplifting and depends on the subsurface
geological conditions of the heavy oil resource.
Image courtesy of
Imperial Oil Limited
Canadian Association of Petroleum Producers
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International Financial Reporting Standards
Information Guide
• Cyclical Steam Stimulation — this technology involves a multi-step process in a single vertical,
deviated or horizontal well, beginning with steam injection, followed by a brief shut-in or heat
soaking period, and finally extraction of the liquefied heavy oil and water. This cycle is repeated
until the cost of injecting steam becomes greater than the value of oil recovered.
• Solvent Extraction — involves injecting chemicals or other hydrocarbons into the formation in
order to reduce the bitumen viscosity. It is a new technology that is expected to reduce water,
energy usage and greenhouse gas emissions, and possibly improve total oil recovery rates.
• Fireflood Combustion — this new technology involves “burning” an advance portion of the heavy
oil underground and using the resulting heat and force of the combustion to move both oil and
gas up through collection wellbores. It has yet to be demonstrated as commercially viable on a
large scale.
Issues
The in-situ oil production business has a number of issues to be considered.
Capitalization policy relative to vertical wells — E&E related
In-situ oil producers utilize vertical wells for a number of different purposes, including resource
appraisal, horizontal well control, water source and reservoir observation. The issue relates to the
capitalization policy relative to these wells since there is typically a long lead time required to define
an economic project, which means that assessment of the ultimate success or failure of resource
appraisal wells can be delayed. In many respects, there are similarities with the extractive oil sands
and mining industries. In addition, the useful life of vertical wells can vary. Some wells are abandoned
immediately and have no further useful life. Some have an ongoing role to play such as for
observation and other purposes.
There is a wide variety of
acceptable capitalization
methods currently followed.
There is a wide variety of acceptable capitalization methods currently followed by entities extracting
oil from in-situ activities, which results in inconsistencies and lack of comparability. Among the
current methods are: expensing vertical wells upon abandonment; capitalizing vertical wells initially
and expensing them if the associated project does not become economic; and, capitalizing the costs
for a set period of time while commercial viability is determined.
Reserve and pricing determinations — IAS 16 related
Reserves definitions for oil sands projects are evolving. An appropriate standard of reserves
determination is crucial to improving comparability among companies. The approaches by which
recovery factors and other parameters are developed for areas between and around the full
complement of existing wells, as well as for projected wells, are unique and fundamental issues
to be considered by in-situ producers.
There are no definitions or measurement criteria for oil sands reserves under IFRS. The United
States and Canadian Securities Administrators, however, have different requirements for
acceptable and reportable reserves disclosure. The issue is that if the IASB does not specify reserves
measurement in conjunction with its Extractive Industries Research Project, each country may be
obliged to determine (or continue with) its own reserves measurement definition. Any future
determinations would be expected to influence the degree to which oil sands reserves can
be recognized.
Currently, only the U.S. Securities and Exchange Commission recognizes bitumen reserves while
Canadian Securities Administrators recognize non-bitumen or upgraded product as reserves. Since
reserves measurement criteria impact asset recognition, depreciation, depletion and amortization
and impairment, standards need to be developed and introduced for in-situ oil reserves. To date,
the unique characteristics of in-situ oil reserves have not been recognized and many third party
engineering firms have developed different approaches to estimating reserves resulting in an
inability to make meaningful comparisons among industry participants.
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Small Explorers and Producers Association of Canada
Issues Specific to In-Situ Heavy Oil and Oil Sands
For Canadian public companies, it is expected that in-situ oil reserves will continue be determined in
accordance with NI 51-101 until such time as the IASB accepts or requires development of expanded
reserve definitions. Consistent with pricing for conventional oil and gas reserves, it is expected that
forecast prices will continue to be used by industry for in-situ oil reserves.
Only the U.S. Securities
Pre-approval development and emerging technology costs — IAS 38 related
Administrators recognize
The two areas for consideration are:
non-bitumen or upgraded
• Pre-approval project development costs, e.g., costs of environmental impact statements and
preliminary design engineering before confirmation of the project’s commercial viability and
prior to internal project approval, and
product as reserves.
and Exchange Commission
recognizes bitumen reserves
while Canadian Securities
• Emerging unproven technologies in respect of in-situ heavy oil or oil sands extraction.
For pre-approval project development costs and emerging unproven technologies, an entity would
need to consider IAS 38 and IAS 23 in respect of selecting capitalization policies and assessing
whether the expenditures on the technology qualify for recognition as an asset.
Impairment tests
Price volatility in the bitumen production business is extreme and often uncorrelated with other oil
prices. Selecting a representative price deck to be used in impairment testing can avoid unexpected
writedowns during times when prices are depressed only for short periods. Therefore, use of forecast
prices would be expected to avoid short-term market fluctuations and would be consistent with
prices used by conventional upstream oil and gas producers.
Asset componentization and identification of cash-generating units by in-situ heavy oil or oil sands
entities will be important considerations — see Sections 2 and 4.
Impairment testing must be completed at transition to IFRS and indicators of impairment must be
assessed at each subsequent reporting period in accordance with IFRS 6 or IAS 36, as appropriate —
see Section 5.
Bitumen blending operations
Most stand alone oil sands producers blend bitumen prior to transportation in order to meet pipeline
specifications. Trucking raw bitumen is only feasible in small volumes. The blending stock can be a
variety of lighter hydrocarbons including synthetic oil or condensate. The issue that arises is the
accounting treatment and valuation of blending material which often has to be purchased from
third parties and stored before use.
IAS 2 “Inventories” is the standard under which inventories are recognized and measured under
IFRS. Inventories are defined in IAS 2 as:
• Assets held for sale in the ordinary course of business
• Assets used in the process of production for such sale, or
• Materials or supplies to be consumed in the production process or in the rendering of services.
The standard’s basic rule is that inventories must be measured at the lower of cost and net realizable
value. Net realizable value is the estimated selling price in the ordinary course of business less the
estimated costs of completion plus the estimated costs to make the sale. Net realizable value is market driven, i.e., the amount the entity actually expects to make from selling that particular inventory.
The accounting standard notes that “supplies held for use in the production of inventories are not
written down below cost if the finished products in which they will be incorporated are expected to
be sold at or above cost”. However, when a decline in the price of the supplies indicates that the
cost of the finished product will exceed net realizable value, the supplies are written down to net
realizable value. Estimates of net realizable value must be based on the most reliable evidence
available and take into account fluctuations of price after the end of the period if this is evidence
Canadian Association of Petroleum Producers
57
Estimates of net
realizable value must
be based on the most
reliable evidence
available.
International Financial Reporting Standards
Information Guide
of conditions existing at the end of the period. In the case of blending stock used by in-situ oil
producers, replacement cost may be the best available measure of net realizable value in a declining
oil price environment.
Reversals of previous writedowns should be recognized as a reduction of supplies expense and an
increase in inventory carrying value on the balance sheet in the period in which the reversal occurs.
The amount of reversals, if material, should be separately disclosed.
Identification of cash-generating units
The level of aggregation at which to identify a cash-generating unit (CGU), “the smallest identifiable
group of assets that generates cash inflows that are largely independent of the cash inflows from
other assets or groups of assets”, is not unique to in-situ oil producers but nonetheless important.
The following factors should be taken into consideration:
• Whether the facility is capable of producing marketable products at an intermediate stage and an
active market for the products exist, whether third party processing is performed, how the facility
is managed, how results are monitored, how output is sold, and how costs of operating the facility
are allocated
• How products are marketed, e.g., raw bitumen may be sold from an upgrader but, if the upgrader
is designed to produce and market a lighter and higher quality grade of oil in order to capture
higher prices (in the absence of which it would not be a commercially viable investment), this
could indicate that the entire upgrader might be considered a single CGU
• Determination of whether there is an active market for the intermediate product is evident (an
active market is one in which the items traded within the market are homogeneous, there are
willing buyers and sellers at all times, and prices are available to the public); if these conditions
do not exist, there is no requirement to consider the assets producing the intermediate product
as a separate CGU, and
• Practical considerations, e.g., a facility, or a part of one, that is used to perform significant third
party processing, and the assets dedicated to such processing are capable of generating cash
inflows independent of the entity’s own operations and an active market exists, would suggest a
CGU separate from the facility itself be identified.
Application of componentization to assets
There are no unique types of asset classes that would make in-situ heavy oil or oil sands facilities
different from other oil and gas facilities and plants. The major processing effort is focused on water
treatment and recycling as well as control of greenhouse gas emissions. Control of greenhouse gas
emissions is not a major processing effort, rather an outcome of being more effective and efficient
with the other processes.
See Section 2 for a discussion and review of components and parts of assets and the requirements
of IAS 16.
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Small Explorers and Producers Association of Canada
Issues Specific to In-Situ Heavy Oil and Oil Sands
Self-produced fuel
Natural gas represents almost two thirds of the operating costs of an in-situ heavy oil or oil sands
project and many producers supply their own fuel. The accounting treatment for self-produced fuel
is varied at present. There is no standardized practice and there is no specific guidance under IFRS.
Note, however, that Section 4 includes the following statement: “If an active market exists for the
intermediate product output from a group of assets that generates independent cash flows, then it
is likely this group of assets should be considered a separate CGU”.
Until the IASB completes its Extractive Industries Research Project and issues further guidance, it is
expected that public companies involved in in-situ oil sands operations will continue to apply their
current policies in respect of self-produced fuel, provided those policies conform with current IFRS
standards.
Transfer pricing for integrated projects
Moving bitumen to integrated upgraders from an in-situ heavy oil or oil sands operation raises the
issue of the appropriate price to set in the event the in-situ operation and upgrader are allocated
to separate CGUs. However, unless the in-situ operation and upgrader are in different business
segments or CGUs, there is no standard that specifies a required method of transfer pricing. If
different segments are involved, IAS 14 “Segment Reporting” is the standard to be followed.
Until the IASB completes its Extractive Industries Research Project and issues further guidance, it is
expected that public companies involved in in-situ heavy oil or oil sands operations will continue to
apply their existing policies in respect of transfer pricing, provided those policies conform with
current IFRS standards.
Decommissioning liabilities
IAS 37 is the standard under which decommissioning liabilities are recognized and measured —
see Section 6.
Canadian Association of Petroleum Producers
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International Financial Reporting Standards
Information Guide
SECTION 8 — ISSUES SPECIFIC TO
OIL SANDS MINING OPERATIONS
Background
All public companies in Canada involved in oil sands exploration, development and extraction will
be required to adopt IFRS on or before January 1, 2011. As a result, the information contained in this
Guide can be expected to impact public oil sands companies in a similar manner as conventional
upstream oil and gas companies, with limited exceptions.
One exception is that only oil and gas companies currently following full cost accounting under
Canadian GAAP will be permitted to elect to take advantage of the proposed amendment to IFRS 1
outlined in Section 9. The election will not be available to oil sands entities that have been following
mining or successful efforts accounting principles and methods.
(It is beyond the scope of this Guide to provide further information on accounting issues specific to
the mining industry, which may include among other things: functional currency issues, stripping
costs and overburden removal, inventories, impairment issues, and revenue recognition.)
Until the IASB completes its Extractive Industries Research Project and issues further guidance,
it is expected that public companies involved in oil sands operations will continue to apply their
current capitalization policies, subject only to changes necessary to conform with IFRS. The
principal standards that will require review and consideration by these entities are: IFRS1 “First Time
Adoption of International Financial Reporting Standards”; IFRS 6 “Exploration and Evaluation of
Mineral Resources”; IAS 16 “Property, Plant and Equipment”; IAS 23 “Borrowing Costs”; IAS 36
“Impairment of Assets”; IAS 37 “Provisions, Contingent Liabilities and Contingent Assets”; and,
IAS 38 “Intangible Assets”.
Cash Generating Units
The aggregation of oil sands assets into cash-generating units (CGUs) is expected to follow an
approach similar to that used for conventional upstream oil and gas operations. A cash-generating
unit is defined as “the smallest identifiable group of assets that generates cash inflows that are
largely independent of the cash inflows from other assets or groups of assets”. Companies obtain
the legal rights to explore for and mine oil sands reserves discovered within an acquired lease area.
Costs incurred during the exploration and evaluation (E&E) phase will be capitalized or expensed as
required by IFRS 6. Any capitalized E&E costs, which by definition would not be expected to generate
independent cash inflows, should be allocated to a CGU until the determination of commercially
viable reserves is made and the costs are either reclassified to development or production assets
or expensed.
A single mine may cover one or more leases, along with the necessary facilities to mine the oil
sands and to process the extracted product into bitumen. The bitumen can then be sold or upgraded
Oil sands mining
60
Small Explorers and Producers Association of Canada
Issues Specific to Oil Sands Mining Operation
into synthetic crude oil, either through company-owned or third party upgrading facilities. Support
facilities such as power generation should also be allocated to CGUs (a separate CGU may be
necessary in the event power generation facilities are used additionally to provide electricity to third
parties). Management’s decisions regarding the mining, extraction of bitumen and upgrading of
the oil sands reserves are a secondary consideration in the identification of an appropriate CGU
structure for the oil sands assets.
Management’s decisions
regarding the mining,
extraction of bitumen and
upgrading of the oil sands
reserves are a secondary
consideration in the
For a vertically integrated oil sands operation, a single CGU would likely be appropriate since the
mine, extraction and upgrading assets are all dedicated to the production of the lease reserves.
Asset impairment testing would be based on those underlying reserves. Examples of other CGU
choices would be:
identification of an
appropriate CGU structure
for the oil sands assets.
• At the individual mine level — this would be appropriate where the bitumen is sold without further
upgrading using company owned facilities or where a company-owned upgrader is used to process
bitumen from two or more company leases. In the latter situation, the upgrader would be a shared
facility cost and would be allocated to the mine level CGU’s.
• Separately at both the individual mine and at the upgrader levels — this would be appropriate
where the bitumen is further processed into synthetic crude, but the upgrading facilities are also
used or capable of being used to process substantial amounts of third party bitumen.
The ability to sell intermediate product, not whether the choice is to use it internally, is a key
consideration in identifying a separate CGU. In addition, there should be consideration of whether
there is an active market for the intermediate product - see Section 4. Recent changes to bitumen
based royalties, including the Alberta government proposal to take bitumen “in kind” may require
further consideration.
Over time a company’s operating plan for its assets may change, necessitating a change to the CGU
structure. (If changes were to be made, IAS 36 requires disclosure of the current and former way of
aggregating CGUs and the reasons for the change.) Consideration should be given when designing
the underlying asset accounting records, to the possible need of realigning the assets within existing
CGU’s. As an example, although all the assets within a vertically integrated operation may be initially
grouped into a single CGU, the assets should also be identifiable with individual mines and upgrading
facilities to allow for the possible future need for a multiple CGU structure. The following example
illustrates the possible CGU structure for an upstream oil and gas company that has oil sands,
conventional and offshore operations:
Notes:
1. Oil Sands Project # 1 — a single CGU since current plans are for all bitumen to be processed
through the upgrader (subject to capability and active market considerations).
2. Oil Sands Project # 2 — each mine will be a separate CGU since there are no upgrading facilities
nor any significant shared facilities.
3. Conventional Operated Properties — each major field or area will be a separate CGU. Smaller items
may be grouped into geographical CGUs.
4. Offshore Property — generally large single fields and each will be a separate CGU. Shared facilities
are allocated to each CGU.
5. Oil Sands Refinery — a separate CGU since majority of bitumen processed is third party.
Section 4 notes limited disclosure requirements related to CGU identification and, for the most part,
disclosures emanating from European Union and Australian companies have been generic and do
not provide users with meaningful information. Disclosures have generally been limited to the IFRS
definition of a CGU and a statement that CGUs are used for purposes of testing impairment of
long-lived assets.
Canadian Association of Petroleum Producers
61
The ability to sell
intermediate product,
not whether the choice is
to use it internally, is a
key consideration in
identifying a
separate CGU.
International Financial Reporting Standards
Information Guide
Company
Oil Sands
Project #1
Oil Sands
Project #2
Note 1
Note 2
Mine
#1
Mine
#2
UOP
Assets
Mine
#1
Refinery
Conventional
Operated
Properties
Note 3
Mine
#2
Offshore
Property
Oil Sands
Refinery
Note 4
Note 5
Major
Field
#1
Straight
Line
Assets
Minor
Fields
UOP
Assets
Straight
Line
Assets
=CGU
Sample disclosure
Royal Dutch Shell
In the second quarter of 2007, Royal Dutch Shell plc (Shell) announced that as from the fourth quarter 2007
the Oil Sands operations in Canada will be disclosed separately from the Exploration and Production segment in
the quarterly results announcements. The Canadian in-situ activities will continue to be reported under the
Exploration and Production segment. Prior period financial statements have been reclassified accordingly.
Until the third quarter of 2007 the Oil Sands financial results were included in the Exploration and Production
segment of Shell’s financial statements.
The Oil Sands segment includes Canadian bitumen mining activities at the Muskeg River Mine, processing and
transportation of bitumen to Scotford, and the upgrading activities at Scotford to produce synthetic crude and
other by-products.
Repsol YPF Group
In its 2007 Filing with the SEC Repsol noted that its oil and gas producing activities do not include:
• The transporting, refining and marketing of oil and gas;
• Activities relating to the production of natural resources other than oil and gas;
• The production of geothermal steam or the extraction of hydrocarbons as a by-product of the production of
geothermal steam or associated geothermal resources as defined in the Geothermal Steam Act of 1970; or
•
The extraction of hydrocarbons from shale, tar sands or coal.
BHP Billiton
In its June 2007 Annual Report BHP Billiton disclosed that its financial statements had been prepared in
accordance with “International Financial Reporting Standards and interpretations as issued by the International
Accounting Standards Board and interpretations effective as of 30 June 2007 and International Financial
Reporting Standards and interpretations as adopted by the European Union (EU) as of 30 June 2007”. It also
indicated that in 2006 it had early adopted IFRS 6 “Exploration for and Evaluation of Mineral Resources”.
BHP Billiton disclosed that it operated in nine business segments, six of them directly related to its mining
activities, e.g., aluminum, base metals, iron ore, etc., two for coal (Energy Coal and Metallurgical Coal (exploration
for and mining, processing and marketing of energy and metallurgical coal, respectively) and one for Petroleum
(exploration for and production, processing and marketing of hydrocarbons including oil, gas and LNG).
62
Small Explorers and Producers Association of Canada
SECTION 9 — OIL AND GAS ASSETS —
TRANSITIONAL ISSUES
Background
Under IFRS, full cost
As indicated in the introductory section of this Guide, in North America either the successful
efforts or full cost method of accounting for oil and gas activities has been traditionally utilized.
The standard for full cost accounting under Canadian generally accepted accounting principles
(GAAP) is Accounting Guideline 16 (AcG 16), while under United States GAAP full cost accounting
is prescribed by the Securities Exchange Commission’s S-X Regulations.
accounting is not permitted
except that accounting
or exploration and
Under full cost accounting, costs associated with property acquisition and exploration and
development activities, including asset decommissioning and restoration costs, are generally
capitalized within a cost centre and only one cost centre is allowed for each country. Depletion,
depreciation and amortization (DD&A) and impairments are generally recognized at the country level.
Costs of acquiring and evaluating unproved properties may be excluded from the full cost pool
and DD&A calculation until it is determined whether or not commercially viable reserves are
attributable to the properties or impairment occurs, whichever comes first. Additionally, a portion
of the costs of major developments may be excluded from the DD&A calculation until certain
criteria are met.
Under IFRS, full cost accounting is not permitted except that accounting for exploration and
evaluation (E&E) costs, which are governed by IFRS 6 “Exploration for and Evaluation of Mineral
Resources”, may utilize a modified method of full cost accounting. However, if an entity chooses
to use such a modified method in developing its accounting policy for E&E costs, it would be
inappropriate to describe the policy as “full cost” because certain key elements are not permitted
under IFRS. As such, entities are required to adopt policies as prescribed under IFRS 6 for E&E
costs as well as under IAS 16 “Property, Plant and Equipment” (PP&E) for development or
production costs and (collectively, for purposes of this Section — oil and gas assets)
At the date of transition to IFRS, entities currently have three choices available for measuring
assets: (1) the cost model under which retrospective restatement is required to determine cost in
accordance with IFRS 6, IAS 16 and IAS 38; (2) the deemed cost election for individual assets, which
requires fair value measurement with no retrospective treatment; or (3) the revaluation model under
which fair value less accumulated amortization is determined for each class of assets. Each of these
choices pose significant challenges to the upstream Canadian oil and gas industry, e.g., under the
cost model the necessary data to effect retroactive restatement may not be available, costs to
prepare and present the transition balance sheet may be prohibitive and few, if any, full cost
companies would be expected to select the revaluation model due to the complexity and costs
associated with subsequent regular revaluation updates (although the cost method could be
chosen to measure revalued assets subsequent to transition).
As a result of these challenges and in order to provide full cost companies with a practical and cost
effective method of transition to IFRS, the Canadian Accounting Standards Board (AcSB) submitted a
proposed amendment to IFRS 1 “First Time Adoption of International Financial Reporting Standards”
to the International Accounting Standards Board (IASB) for consideration. The amendment proposes
to modify the “deemed cost” election referred to above by permitting a voluntary elective method
under which only companies currently utilizing the full cost method of accounting would segregate
the net carrying value oil and gas assets between:
• Exploration and evaluation assets, and
• Assets in the development or production phases.
The net carrying value of the two divided asset classes would equal the net book value of the
entity’s oil and gas assets as determined under its previous GAAP, less any impairment charges.
An adjustment (plus or minus), if any, for decommissioning, restoration and similar liabilities as
measured under IAS 37 “Provisions, Contingent Liabilities and Contingent Assets” would be charged
directly to retained earnings. (Note that in completing this latter assessment, the entity would be
exempt from applying IFRS 1 paragraph 25E or IFRIC 1.)
Canadian Association of Petroleum Producers
63
evaluation (E&E) costs
may utilize a modified
method of full cost
accounting.
International Financial Reporting Standards
Information Guide
The objectives of this Section are to provide a framework for application of the IFRS 1 Amendment on
the basis that the IASB will approve the Exposure Draft summarized in the following paragraph and
to set out an illustrative example of a full cost company electing to apply the proposed amendment
with respect to its oil and gas assets when adopting IFRS for the first time.
If the Exposure Draft is not approved by the IASB or if additional amendments are introduced, this
Section will require revisions.
The Proposed IFRS 1 Amendment
In September 2008, the IASB issued an Exposure Draft proposing amendments to IFRS 1 that would
amend the IFRS 1 “deemed cost” election. Relevant portions of the proposed amendment are as
follows (the complete Exposure Draft is available on the IASB website):
Deemed cost
“19A A first-time adopter using full cost accounting8 under previous GAAP may elect to measure
oil and gas assets at the date of transition to IFRS9 on the following basis:
a) Exploration and evaluation assets at the amount determined under the entity’s previous GAAP,
and
b) Assets in the development or production phases at the amount determined under the entity’s
previous GAAP. The entity shall allocate this amount to the underlying assets pro rata using
reserve volumes or reserve values as of that date.
The entity shall test exploration and evaluation assets and assets in the development or production
phases for impairment at the date of transition to IFRS in accordance with IFRS 6 ”Exploration for
and Evaluation of Mineral Resources“ or IAS 36 “Impairment of Assets” respectively and, if
necessary, reduce the amount determined in accordance with (a) or (b) above. For the purposes of
this paragraph, oil and gas assets comprise only those assets used in the exploration, evaluation,
development or production of oil and gas.”
“25EA An entity that uses the exemption in paragraph 19A(b) (for oil and gas assets in the
development or production phases accounted for using full cost accounting under previous GAAP)
shall, instead of applying paragraph 25E or IFRIC 1:
a) Measure decommissioning, restoration and similar liabilities as at the date of transition to IFRS in
accordance with IAS 37, and
b) Recognize directly in retained earnings any difference between that amount and the carrying
amount of those liabilities at the date of transition to IFRS determined under the entity’s previous
GAAP.”
Presentation and disclosure — explanation of transition to IFRS
Use of deemed cost for oil and gas assets
“44B If an entity uses the exemption in paragraph 19A(b) for oil and gas assets, it shall disclose
that fact and the basis on which carrying amounts determined under previous GAAP were
allocated.”
Effective date
“47M An entity shall apply the amendments in paragraphs 13(b), 19A, 19B, 25E, 25F and 44B for
annual periods beginning on or after [date to be inserted after exposure]. Earlier application is
permitted. If an entity applies the amendments for an earlier period it shall disclose that fact.”
8 Under full cost accounting, exploration and development costs for properties in development or in production are accounted
for in cost centres that include all properties in a large geographical area.
9 Note for Exposure Draft readers: Appendix A of IFRS 1 defines the "date of transition to IFRS" as: "The beginning of the
earliest period for which an entity presents full comparative information under IFRS in its first IFRS financial statements".
64
Small Explorers and Producers Association of Canada
Oil and Gas Assets — Transitional Issues
Year of Application
IFRS 1 includes the following statement: “An entity shall use the same accounting policies in its
opening IFRS balance sheet and throughout all periods presented in its first IFRS financial
statements. Those accounting policies shall comply with each IFRS effective at the reporting date
for its first IFRS financial statements, except as specified in…”
Although all Canadian public entities will be required to report under IFRS commencing in 2011,
the date of transition under IFRS 1 will, in effect, be the date on which an entity first prepares and
presents an opening IFRS balance sheet. Since the Q1 2011 interim financial statements of a public
entity must be issued under IFRS, the statements will need to contain Q1 2010 comparative
information. For a public entity having a calendar year end, in order to obtain the Q1 2010
comparative balance sheet, the deemed cost of oil and gas assets must be IFRS compliant as at
January 1, 2010. This will enable transactions for 2010 to be recognized as if IFRS policies were
being fully applied throughout 2010 in order that comparative quarterly information will be available
in 2011 (even though the entity will continue external reporting for 2010 in accordance with its
previous GAAP).
To illustrate, for a company with a calendar year end, disclosing only one year of comparative
financial information, the adoption timeline would be as follows:
Jan 1
2010
Q1
Q2
Q3
Dec 31
2010
Q1
Q2
Q3
Dec 31
2011
1 Canadian GAAP
2 IFRS Reporting
2A Apply Amendment
2B Capture Transactions under IFRS
Canadian GAAP
For the year ended December 31, 2010, the company would continue to report under its current
GAAP. This could be accomplished in one of three ways: by recording all transactions through existing
systems in accordance with current practice and, through analysis and working paper adjustments
tracking the necessary IFRS accounting, or vice versa, or by running both systems in parallel. For
entities that have completed the assessment of IFRS reporting systems requirements, recording
transactions under IFRS and through analysis and working paper adjustments tracking the necessary
GAAP accounting for external reporting purposes, would appear to be the preferable approach.
IFRS reporting
For the year ended December 31, 2011, the company would report under IFRS:
• All 2011 transactions (including quarterly information), and
• All transactions during 2010 (initially externally reported under the entity’s previous GAAP), but
captured under IFRS in order to provide comparative information necessary for presentation in
the 2011 financial statements, including the IFRS 1 amendments applied to the balance sheet as at
January 1, 2010 and in the 2010 interim quarterly information.
Canadian Association of Petroleum Producers
65
For the year ended
December 31, 2010, the
company would continue
to report under its
current GAAP.
International Financial Reporting Standards
Information Guide
The net book value of oil
and gas assets is first
reduced by the identified
and measured E&E assets.
Application of the IFRS 1 Amendment
The net book value of oil and gas assets is first reduced by the identified and measured E&E assets.
The remaining net book value of the full cost pool becomes the net cost associated with development
or production assets. E&E assets and development or production assets and/or associated CGUs must
be separately tested for impairment.
Any necessary adjustment for differences (plus or minus) arising from the application of IAS 37 and
the decommissioning liabilities as measured under the entity’s previous GAAP is charged directly to
retained earnings.
1. Develop IFRS 6 policy
• An entity must develop and describe its accounting policies for E&E assets in accordance
with IFRS 6.
2. Separate E&E assets from total development or production assets
• The entity should apply its IFRS 6 accounting policies to separate the cost of E&E assets from
total oil and gas assets. (Since E&E assets under full cost accounting would not, in all likelihood,
have been included in the full cost pool subject to DD&A, these costs should be readily
determinable for most entities.) After separating E&E assets, the remaining net book value
relates to development or production assets (intangible and tangible) and both cost and
accumulated DD&A should be identified for allocation purposes.
3. Allocate adjusted development or production assets using reserves volumes
or reserves values
• Both costs and accumulated DD&A related to development or production assets require
allocation to units of account (including CGUs for impairment testing purposes) on a pro rata
basis using reserve volumes or related values as at the date of transition to IFRS. The level to
which the development or production assets are allocated should be aligned with the level (unit
of account) at which the entity intends to calculate DD&A subsequent to the transition to IFRS
since IAS 16 requires that each component with a cost that is significant in relation to the total
cost of the asset should be depreciated separately.
• The allocation to the selected unit of account level is done on the basis of reserves volumes or
reserves values. This allocation will require an assessment of the most appropriate basis,
depending on the entity’s facts and circumstances, i.e., use of reserves volumes or reserves
values will generally produce different allocations, and take into account the following elements:
• The category of reserves to be used, e.g., proved or proved plus probable.
• If allocating on the basis of reserves values based on future net revenues:
— Pricing assumptions, and
— The appropriate discount rate to be applied.
In making the determination of the basis for allocation, the entity should consider the methods,
assumptions and estimates it will be applying in its DD&A calculations and impairment testing.
For example, reserves volumes might be appropriate when product quality and production costs
are similar and reserves values might be appropriate when those criteria are different. It will be
important that an entity’s use of reserves be consistent in all instances in which reserves are an
integral part of the calculations being undertaken.
66
Small Explorers and Producers Association of Canada
Oil and Gas Assets — Transitional Issues
4. Group E&E assets for impairment testing
• E&E assets, subsequent to separation as set out in 2 above, are to be assessed for impairment
in accordance with the requirements of IFRS 6. IFRS 6 requires that an accounting policy be
established under which the E&E assets may be allocated to one or more CGUs for impairment
testing purposes. The allocated unit cannot be larger than an operating segment determined in
accordance with IFRS 8 “Operating Segments”. The general IFRS impairment standard is set
out in IAS 36 “Impairment of Assets”; however, IFRS 6 modifies IAS 36 specifically in regards
to identifying impairment indicators for E&E assets - see Section 5 of the Guide.
5. Group development or production assets for impairment testing
• Each identified development or production asset, as established under 4 above, is separately
tested for impairment prior to testing individual CGUs or groups of CGUs. Consistent with
grouping for E&E assets, development or production assets belonging to the same CGU and
having the same life and DD&A method may be aggregated within that CGU or included in a
group of CGUs comprising a level no higher than an operating segment, whichever is in
accordance with the entity’s selected accounting policy. Note that prior to testing development
or production assets for impairment, corporate assets, if any, should be allocated to and
included with the assets to be tested. The allocation of corporate assets would generally be
expected to be made on the same basis as the allocation of development or production assets.
6. Complete impairment tests
• Separate impairment tests are required for E&E assets or CGUs and for development or
production assets and CGUs.
• Impairment tests must be completed in accordance with IAS 36 to determine if there are
impairment losses that require recognition.
• IAS 36 makes it clear that if an impairment test is required for a CGU or one that is part of a
group to which goodwill has been allocated, the impairment test on the CGU or CGU group
containing the goodwill must be performed only after the individual test. The premise is that
impairment is tested first at the asset or CGU level, excluding goodwill.
• Notwithstanding the foregoing, it would seem appropriate to allocate corporate assets to the
development or production CGUs, exclusive of goodwill, before completing the first
impairment test.
7. Does impairment exist?
• Impairment losses are recognized as an adjustment to retained earnings at the IFRS transition
date. Impairment losses for both E&E assets and development or production assets are required
to be allocated to units of account and CGUs.
• Fully impaired assets may also need to be derecognized from an entity’s accounting records.
8. Allocate impairment in accordance with IAS 36
• Impairment losses for E&E assets are allocated in accordance with the entity’s selected IFRS 6
policy, e.g., an individually impaired asset may be expensed or the impairment charge may be
allocated to the CGU to which the asset belongs; a CGU level impairment charge may be
recognized at the CGU level or allocated to the group of CGUs to which the CGU belongs.
• Impairment losses for development or production assets are allocated pro rata among the
entity’s impaired unit of account levels, e.g., individual assets or CGUs.
Canadian Association of Petroleum Producers
67
International Financial Reporting Standards
Information Guide
9. Determine the deemed cost of E&E assets and Development or Production assets
• The net book value (costs and, if any, accumulated amortization) of E&E assets after recognition
of any impairment losses becomes the deemed cost of E&E assets at the IFRS transition date.
• The net book value of the allocated development or production assets (both costs and
accumulated DD&A) after recognition of any asset or CGU impairment losses becomes the
deemed cost of oil and gas assets at the IFRS transition date.
• Decommissioning, restoration and similar liabilities are measured at the IFRS transition date in
accordance with IAS 37 and any difference between that amount and the carrying amount of
those liabilities at the transition date, as determined under the entity’s previous GAAP, is
recognized directly in retained earnings.
Process
Flowchart
Develop IFRS 6 Policy
Separate E&E assets from
total development or
production assets
Allocate adjusted
development or production
assets using reserves
volumes or reserves values
Group E&E assets for
impairment testing
Group development or
production assets for
impairment testing
Complete impairment tests
Does impairment exist?
YES
NO
Allocate impairment in
accordance with IAS 36
Deemed cost of
E&E assets
68
Deemed cost of development
or production costs
Small Explorers and Producers Association of Canada
Oil and Gas Assets — Transitional Issues
Illustrative Example
The following example may require modification if the proposed IFRS 1 amendment is
changed by the IASB as a result of comments received during the comment period.
Assume the company is required to provide comparative information for 2010 starting with its first
quarter in 2011 and presents the following information as at January 1, 2010:
• A full cost pool with a pre-transition net book value of $36,000,000, comprising $46,000,000 of
development or production assets and $10,000,000 of accumulated DD&A.
• Three exploration and evaluation projects, comprising total costs of $6,000,000, which have been
excluded from the full cost pool and identified as follows:
• Exploration X — $1,000,000 is a new project within Area A and is not related to any existing
reserves or facilities within the area
• Exploration Y — $2,000,000 is a project not associated with any of the company’s producing area
CGUs and on which no reserves have been found and no further exploration is planned or
budgeted, and
• Exploration B — $3,000,000 is a planned future project in Area B that if successful will share the
production and pipeline facilities with Area B.
• In a prior year the company purchased Company B having Area B and Area E as its principal
assets. The purchase price resulted in recognition of goodwill in the amount of $15,000,000,
which was allocated $14,000,000 to Area B and $1,000,000 to Area E. Due to declining production
and technical issues, Area E, comprising only a few marginal wells, has been shut in and is not
expected to be restarted.
• Corporate assets of $4,000,000, which had not previously been associated with the company’s
producing areas, have been allocated pro rata to development or production assets on the basis of
reserves values determined after recognition of the impairment for Area E — this is illustrated in
Step 6 below.
• Management’s analysis of the level at which DD&A is determined has identified that an area level
is an appropriate unit of account level. The entity has five such areas with reserves (developed
using an appropriate methodology) and each area has been identified as a separate CGU
as follows:
Area / CGU
Reserves
Volumes (BOE)
Reserves Values
(Discounted Future Cash Flows)
A
1,000,000
$25,000,000
B
1,500,000
30,000,000
C
100,000
1,600,000
D
500,000
8,400,000
E
—
–
3,100,000
$65,000,000
Total
• A current measurement of decommissioning liabilities in accordance with IAS 37 indicates an
additional $900,000 is necessary and this amount is charged to retained earnings at transition.
Canadian Association of Petroleum Producers
69
International Financial Reporting Standards
Information Guide
Application of IFRS 1 Amendment
Step 1. Develop IFRS 6 accounting policies
• The adoption of accounting policies under IFRS 6 should include management’s identification of
the level of groupings (CGUs, componentization and DD&A calculations, and E&E and development
or production assets) that the entity will use for purposes of impairment testing.
Apply the Amendment to Balances on January 1, 2010 as follows:
Step 2. Separate E&E assets from total development or production assets
• The E&E assets, which have been excluded from the full cost pool and not subject to DD&A,
are Exploration X, Exploration Y and Exploration B projects having an aggregate cost of $6.0M.
Step 3. Allocate adjusted development or production assets using reserves volumes or
reserves values
The following allocation makes no attempt to separately identify intangible and tangible oil and gas
assets, assets with different estimated useful lives and major components of assets, e.g., gas plants
and processing facilities, in respect of the development or production assets. In practice, an industrywide norm of 80% intangible assets and 20% tangible assets may be an acceptable allocation
approach.
NBV allocation based on reserves volumes
NBV allocation based on reserves values
Area
Calculation
Result
Calculation
Result
A
1.0M/3.1Mx$36.0M
$11.6M
$25.0M/$65.0Mx$36.0M
$13.8M
B
1.5M/3.1Mx$36.0M
17.4M
$30.0M/$65.0Mx$36.0M
16.6M
C
0.1M/3.1Mx$36.0M
1.2M
$1.6M/$65.0Mx$36.0M
0.9M
D
0.5M/3.1Mx$36.0M
5.8M
$8.4M/$65.0Mx$36.0M
4.7M
E
0.0M/3.1X$36.0M
0.0M
$0.0/$65.0MX$36.0M
Total
$36.0M
0.0M
$36.0M
Step 4. Test E&E assets for impairment
Under the company’s chosen IFRS 6 policy, E&E projects are initially tested for impairment on an
individual asset basis:
• Exploration X is a separate project within Area A
• Exploration Y is a separate project not associated with any of the company’s development or
production CGUs on which no further exploration is planned or budgeted, and
• Exploration B is a planned future project located within Area B.
E&E Asset
Cost
Are there indications of impairment?
X
$1.0M
No — active exploration is continuing within Area A
Y
$2.0M
Yes — no further exploration planned or budgeted
B
$3.0M
No — the project is planned, but not currently budgeted
Impairment
—
$2.0M (Note)
—
Note: Exploration project Y is deemed to be impaired and $2.0M is charged to retained earnings.
70
Small Explorers and Producers Association of Canada
Oil and Gas Assets — Transitional Issues
Step 5. Test development or production assets for impairment
(before corporate assets and goodwill allocation)
Development
or Production
Assets
Deemed Cost
Reserves
Volumes
Deemed Cost
Reserves
Values
Discounted
Future Cash
Flows (DCF)
A
$11.6M
$13.8M
$25.0M
Yes
None
B
17.4M
16.6M
30.0M
Yes
None
C
1.2M
0.9M
1.6M
Yes
None
D
5.8M
4.7M
8.4M
Yes
None
E
0.0M
0.0M
0.0M
(Note)
(Note)
$36.0M
$36.0M
$65.0M
—
—
Total
Is DCF >
Deemed
Cost?
Impairment
Note: Although Area E is impaired (see assumptions), the mechanics of the allocation calculation of
deemed cost results in an anomalous situation. This is remedied in the calculation at Step 6a, which
includes the allocated corporate assets and goodwill.
Step 6. Test individual development or production assets for impairment
including corporate assets allocation (before goodwill)
Development
or Production
Assets
Deemed Cost
Reserves
Values
Allocate
Corporate
Assets
Total
Asset
Costs
Discounted
Cash
Flow
DCF>
Total Asset
Cost
Impairment
A
$13.8M
$1.5M
$15.3M
$25.0M
Yes
None
B
16.6M
1.8M
18.4M
30.0M
Yes
None
C
0.9M
0.1M
1.0M
1.6M
Yes
None
D
4.7M
0.6M
5.3M
8.4M
Yes
None
E
Total
0.0M
—
—
—
n/a
n/a
$36.0M
$4.0M
$40.0M
$65.0M
n/a
n/a
Step 6a. Test goodwill for impairment at the CGU level
Development
or Production
CGU
Deemed Cost
Reserves
Values
Allocate
Corporate
Assets
Allocate
Goodwill
(Note)
Add
E&E
Assets
Total
CGU
Assets
Discounted
Future Cash
Flows (DCF)
DCF>
Total CGU
Assets
A
$13.8M
B
16.6M
C
$1.5M
—
$1.0M
$16.3M
$25.0M
Yes
—
1.8M
$14.0M
3.0M
35.4M
30.0M
No
$5.4M
0.9M
0.1M
—
—
1.0M
1.6M
Yes
—
D
4.7M
0.6M
—
—
5.3M
8.4M
Yes
—
E
0.0M
—
1.0M
—
1.0M
—
No
1.0M
$36.0M
$4.0M
$15.0M
$4.0M
$59.0M
$65.0M
n/a
$6.4M
Total
$
Amount
(Note)
Note: Under IAS 36, goodwill is written down first; therefore, the required impairment charge for goodwill associated with CGU B
and CGU E are $5.4M and $1.0M respectively.
Step 7. Determine deemed cost of E&E assets and development or production assets
Canadian Association of Petroleum Producers
71
International Financial Reporting Standards
Information Guide
Subsequent to IFRS transition the Company’s deemed cost of oil and gas assets is $40.0M
as follows:
Deemed cost of E&E assets
$4.0M
(X —$1.0M plus B — $3.0M)
Development or production assets:
A
13.8M
B
16.6M
C
0.9M
D
4.7M
E
0.0M
Deemed cost of development or production assets
36.0M
Deemed cost of oil and gas assets
40.0M
Add:
Corporate assets
4.0M
Goodwill
8.6M
Total assets
$52.6M
($15.0M — $5.4M — $1.0M)
The total assets cost of $52.6M under IFRS can be reconciled from the company’s previous GAAP as
follows: full cost pool of $46.0M less accumulated DD&A of $10.0M plus exploration and evaluation
projects excluded from the full cost pool of $6.0M plus corporate assets of $4.0M plus goodwill of
$15.0M less IFRS transitional goodwill impairments of $6.4M less Exploration Y project asset
impairment of $2.0M.
The basic requirement of IAS 36 is that impairment testing be done initially at the individual
identified asset level unless that asset does not generate cash inflows that are largely independent
of those from other assets or groups of assets. Subsequent impairment tests, as indicated in the
preceding example, require the inclusion of corporate assets and goodwill. If impairment is indicated
in the initial tests, then further tests need to be carried out at the CGU level under review. IAS 36
sets out a three-step procedure, which includes a fully worked example of the allocation and
calculation processes.
Step 7a. Modification to illustrative example facts
If, in Step 6a above, the facts in respect of development or production assets A and B had been
different and the assets had been identified, together with their associated exploration projects X
and B, as properly forming a single CGU, there would have been a different impairment result
as follows:
Note: When the goodwill impairment test is carried out at the single CGU level, there is no impair-
Development
or Production
Assets
Deemed Cost
Reserves
Values
Allocate
Corporate
Assets
Allocate
Goodwill
Add
E&E
Assets
Total
CGU
Assets
Discounted
Future Cash
Flows (DCF)
DCF>
Total CGU
Assets
$
Amount
(Note)
A
$13.8M
$ 1.5M
$ 0.0M
$1.0M
$16.3M
$25.0M
n/a
n/a
B
16.6M
1.8M
$14.0M
3.0M
35.4M
30.0M
n/a
n/a
$30.4M
$ 3.3M
$14.0M
$4.0M
$51.7M
$55.0M
Yes
None
CGU
ment that requires recognition.
72
Small Explorers and Producers Association of Canada
Oil and Gas Assets — Transitional Issues
Step 8. Post application of amendment on January 1, 2010
• Commence tracking costs by Areas A, B, C, D and Exploration X and Exploration B in accordance
with IFRS policies for purposes of preparing and presenting the 2010 comparative quarterly
financial reports that will be published in conjunction with the 2011 interim quarterly reports.
Disclosure of Application of IFRS 1 Amendment
Under the proposed IFRS 1 Amendment, an entity that uses the permitted election will be required
to disclose that fact and the basis on which carrying amounts under previous GAAP were allocated.
Disclosure example
Note disclosure in respect of the transition to IFRS from full cost accounting, only in respect of oil
and gas assets, for the illustrative example set out above might include:
On January 1, 2011, the Company adopted International Financial Reporting Standards (IFRS) for the
first time. For all years up to and including December 31, 2010 the Company prepared its financial
statements in accordance with Canadian generally accepted accounting principles (GAAP).
The Company has prepared and presented its opening balance sheet at January 1, 2010, its date of
transition to IFRS.
The Company has elected to measure its oil and gas assets at January 1, 2010, in accordance with
an exemption in IFRS 1 as follows:
• Exploration and evaluation assets of $4.0 million have been carried forward at the amount
previously recognized under Canadian GAAP after deduction of $2.0 million in respect of an
exploration and evaluation project determined by the Company to be impaired
• Net development or production assets in the amount of $36.0 million have been carried forward
at the amount previously recognized under Canadian GAAP and allocated among the underlying
development or production assets pro rata using reserves values as at January 1, 2010
• Corporate assets associated with development or production activities in the amount of
$4.0 million have been carried forward at the amount previously recognized under Canadian
GAAP and allocated among the underlying development or production assets pro rata using
reserve values as of January 1, 2010
• Goodwill allocated to development or production assets in the amount of $8.6 million has been
carried forward at the amount previously recognized under Canadian GAAP after deduction of
$6.4 million determined by the Company to be impaired, and
• Decommissioning liabilities have been increased by $0.9 million with a corresponding amount
charged directly to retained earnings.
The financial impact on the Company’s balance sheet from adopting IFRS has been to reduce oil and
gas assets and retained earnings as at January 1, 2010 by $9.3 million, comprised of impairment of
exploration and evaluation assets of $2.0 million, impairment of goodwill of $6.4 million, and an
increase in decommissioning liabilities of $0.9 million.
Note that disclosures with respect to an entity’s overall transition to IFRS will be far more extensive
than the preceding disclosure, which relates solely to oil and gas assets. IFRS 1 requires an entity to
explain how the transition from its previous GAAP to IFRS affected its reported financial position,
financial performance and cash flows and to provide reconciliations in sufficient detail to enable
readers to understand the material changes to its balance sheet, income statement and cash flows.
Canadian Association of Petroleum Producers
73
APPENDICES
Appendix A — Sources of Information
International Financial Reporting Standards (IFRS) 1 — 8
International Accounting Standards (IAS) 1 — 41
International Financial Reporting Interpretations Committee Interpretations (IFRIC) 1 — 14
Ernst & Young International GAAP 2008 — Generally Accepted Accounting Practice
under International Financial Reporting Standards
Ernst & Young International GAAP 2008 - Good Petroleum (International) Limited,
Illustrative Financial Statements
KPMG 2007 — Assessing the Impact — Adoption of IFRS 6: Exploration for and Evaluation
of Mineral Resources by Oil & Gas companies
KPMG 2008 — Insights into IFRS
Canadian Institute of Chartered Accountants (CICA) — Adopting IFRS in Canada
Deloitte & Touche LLP, Ernst & Young LLP, KPMG LLP and PricewaterhouseCoopers LLP —
various IFRS publications and seminar materials
74
Small Explorers and Producers Association of Canada
Appendix B — Contributors
The following individuals contributed to the development of this Guide:
Group Leaders
Dave Connolly CA (Section 1), Jeff Dashkin CA (Section 2), Rick Schiller CA (Section 3),
Kyla DaCosta CA (Section 4), Bill Cromb CA (Section 5), Kevin Hamm CA (Section 6),
Bruce Watson CGA (Section 7), Sherri Rogers CA (Section 8), Jim Wilson CA (Section 9)
and Charlena Arsenault CA10
Group Participants
Hughes Alamargot, Travis Beatty CA CFA, Jason Berting CA, Sue-Ann Bibby CA, Philip Birkby CA,
Kerry Blue CA CFA, Stephanie Bunch CA, Corine Bushfield CA, Ross Campbell CA, Karen Cheema CA,
Anna Cheong CA, Joan Collins CA, Yasmin Dhanani CA, Rod Gray CA, Scott Greenshields CA,
Murray Harris CA, Todd Hirtle, Jodi Jenson Labrie CA CBV, Jeremy Kalanuk CA CPA, Andrew Low CA,
Wayne Macinnis CA, Janet Ranger CA, Ian Robinson FCA, Corey Ruttan CA, Peter Scott MBA,
Peter Skirving CA, Rick Smith CA, Ian Staveley CA, Kelly Tomyn CA, and Mitch White CA
Oversight Committee
Doug Baker FCA (Chair), Matt Bootle FCA, Steve Glover FCA, Jim Screaton CA, Jim Wilson CA,
and Fred Snell FCA (Observer)
Guide Preparation Coordinator
Chris LeGeyt FCA
The Sponsors gratefully acknowledge the contribution of the professional advisors from
Calgary’s public accounting firms involved in this project, the support of the Oversight
Committee and the Chartered Accountants’ Education Foundation (CAEF) of Alberta11
and the leadership contributions of Jim Wilson, CA, Chair of CAPP’s IFRS Task Group
and David Daly, Manager, CAPP Fiscal Policy.
10 Charlena Arsenault is the Group Leader for Joint Arrangements. Since the IASB is currently preparing a new standard
in respect of joint arrangements, the Sponsors have decided to delay preparation of this Section pending release of the
new IASB standard, which is expected in the second quarter of 2009.
11 CAEF contributions were limited to financial support.
Canadian Association of Petroleum Producers
75
The Canadian Association of Petroleum Producers (CAPP) represents
130 companies that explore for, develop and produce natural gas, natural
gas liquids, crude oil, oil sands, and elemental sulphur throughout Canada.
CAPP member companies produce more than 95 per cent of Canada’s
natural gas and crude oil. CAPP also has 150 associate members that
provide a wide range of services that support the upstream crude oil and
natural gas industry. Together, these members and associate members are
an important part of a $100-billion-a-year national industry that affects
the livelihoods of more than half a million Canadians.
2100, 350 — 7 Avenue SW
Calgary, Alberta
Canada T2P 3N9
Telephone: (403) 267-1100
Fax: (403) 261-4622
403, 235 Water Street
St. John’s, Newfoundland and Labrador
Canada A1C 1B6
Telephone: (709) 724-4200
Fax: (709) 724-4225
communications@capp.ca
www.capp.ca
SEPAC, Canada’s Oil and Gas Entrepreneurs™, represents the interests
of hundreds of emerging and junior companies in Canada’s oil and gas
industry to government and the public.
This segment of the industry is a leader in the exploration and
development of the energy resources Canadians rely on.
1060, 717 — 7 Avenue SW
Calgary, Alberta
Canada T2P 0Z3
Telephone: (403) 269-3454
Fax: (403) 269-3636
info@sepac.ca
www.sepac.ca
February 2009 • 2009-0004