ENERGY & NATURAL RESOURCES. Impact of IFRS: Oil and Gas. kpmg.com/ifrs. KPMG International

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1 ENERGY & NATURAL RESOURCES Impact of IFRS: Oil and Gas kpmg.com/ifrs KPMG International

2 Contents Overview of the IFRS conversion process 2 Accounting and reporting issues 3 1. Exploration and evaluation (E&E) assets 5 2. Depletion, depreciation and amortisation (DD&A) 8 3. Impairment of non-financial assets Decommissioning and environmental provisions Joint arrangements Revenue recognition Reserves reporting Financial instruments 20 Information technology and systems considerations 22 From accounting gaps to information sources 22 How to identify the impact on information systems 23 Oil and gas accounting differences and respective system issues 24 Parallel reporting: Timing the changeover from local GAAP to IFRS reporting 26 Harmonisation of internal and external reporting 28 People: Knowledge transfer and change management 29 Business and reporting 30 Stakeholder analysis and communications 30 Audit Committee and Board of Directors considerations 30 Monitoring peer group 30 Other areas of IFRS risks to mitigate 30 Benefits of IFRS 31 KPMG: An Experienced Team, a Global Network 32 Contact us IBC

3 Impact of IFRS: Oil and Gas 1 Foreword Accounting for oil and gas activities presents many difficulties. Significant upfront investment, uncertainty over prospects and long project lives have led to a variety of approaches being developed by companies, and a range of country-specific guidance for the sector. As countries around the world adopt IFRS, accounting approaches for affected companies may need to be reassessed. Many countries converted to IFRS in 2005 and conversions are imminent for other countries such as Canada and South Korea in 2011 and Mexico in Japan has permitted the early adoption of IFRS by listed companies from years ending on or after 31 March 2010 and is expected to announce a final decision on whether to mandate adoption in The US will likely announce later in 2011 or 2012 its plan as to how IFRS might be incorporated into the financial reporting requirements for US domestic issuers. As countries adopt a single set of high quality, global accounting and financial reporting standards, there should be greater global consistency and transparency. However, it is recognised that extractive activities is an area in which there is little IFRS guidance. There is also variation in practice between companies applying IFRS, which was highlighted in KPMG s survey The Application of IFRS: Oil and Gas published in October This publication looks at some of the main accounting issues across oil and gas companies. It considers currently effective standards and notes future developments that could impact accounting in the sector. The long-term future of accounting for extractive activities is as yet unclear. The IASB issued the discussion paper Extractive Activities in April 2010, and the main proposals of the project team and the responses to this discussion paper are discussed in this publication. A decision on whether the Extractive Activities project should be added to the IASB s active agenda is expected when the IASB considers responses to its Agenda Consultation 2011, which are due by 30 November This publication also discusses the IFRS conversion project as a whole, including the importance of the conversion management process, and considers the impact of IFRS conversion across an organisation. Any conversion project will be significantly more detailed than merely addressing the issues discussed in this publication. However, making a head start in identifying the accounting and business related issues on conversion can avoid accounting challenges in the years to come. While the main audience of this publication are those contemplating IFRS conversion, we hope that there is something stimulating and thought provoking for all those already dealing with IFRS in the oil and gas sector. Jimmy Daboo Global Energy & Natural Resources Auditing and Accounting Leader KPMG in the UK

4 2 Impact of IFRS: Oil and Gas Overview of the IFRS conversion process Addressing challenges and opportunities of conversion for all aspects of your business All IFRS conversions have consistent themes and milestones to them. The key is to tailor the conversion specifically to your own issues, your internal policies and procedures, the structure of your group reporting, the engagement of your stakeholders and the requirements of your corporate governance. Oil and gas companies can be broadly grouped into the majors and the juniors, and there may be similarities among these organisations, particularly within each group. However, there always will be differences in the corporate DNA that makes one conversion project different from the next. The IFRS Conversion Management Overview diagram below presents a holistic approach to planning and implementing an IFRS conversion by helping ensure that all linkages and dependencies are established between accounting and reporting, systems and processes, people and the business. The conversion should address proactively the challenges and opportunities of adopting IFRS for all aspects of your business. This includes, for example, consideration of the impact of IFRS transition on the regulatory aspect of your operations, which may vary depending on state, federal, international, product, reporting and competitive requirements.

5 Impact of IFRS: Oil and Gas 3 Accounting and reporting issues Early identification of differences is critical to a successful conversion project The first and fundamental area to tackle is accounting and reporting. Getting a timely and accurate assessment of the impact of IFRS and ensuring that the gap analysis is correct are critical steps to a successful transition. Based on our experience of IFRS conversions, we outline below the main sector-specific accounting issues for oil and gas companies to consider when converting to IFRS, and provide a glimpse of the questions to be considered. This is not meant to be a comprehensive list; indeed it does not cover many areas that oil and gas companies need to consider. Owing to their generic nature, there are material accounting topics (such as defined benefit pension scheme accounting, share-based payments, presentation of financial statements and business combinations) that we have not considered in this publication. 1 Exploration and evaluation (E&E) assets 2 Depletion, depreciation and amortisation (DD&A) 3 Impairment of non-financial assets 4 Decommissioning and environmental provisions 5 Joint arrangements 6 Revenue recognition 7 Reserves reporting 8 Financial instruments In our experience, these issues are significant to oil and gas companies for the following reasons. Issues may be pervasive across the sector and will require significant time and cost to evaluate and implement; for example, accounting for E&E expenditure and assets. Conversion may have a significant impact on information systems, accounting processes and systems. For example, the impact of different depreciation and amortisation policies may lead to adjustments in the asset sub-ledger. Accounting requirements may require careful consideration of contract terms, for example those terms outlined in joint arrangements. Judgement may be required in selecting significant accounting policies that impact future results. Accounting and reporting requirements may be subject to future change for which organisations need to be prepared. We recommend KPMG s publication The Application of IFRS: Oil and Gas for greater detail on the issues raised in this document, and examples of disclosures from existing IFRS oil and gas companies.

6 4 Impact of IFRS: Oil and Gas Discussion Paper Extractive Activities IFRS 6 Exploration for and Evaluation of Mineral Resources was intended only as a temporary measure. The future of accounting for E&E expenditure is not yet clear. The International Accounting Standards Board (IASB) issued a discussion paper Extractive Activities in April The discussion paper outlines a revised framework for accounting for extractive activities. A decision on whether the Extractive Activities project should be added to the IASB s active agenda is expected when the IASB considers responses to its Agenda Consultation 2011, which are due by 30 November If the IASB adds a project on extractive activities to its active agenda, then it will take the discussion paper and the 141 comment letters received as the basis for its initial deliberations. The discussion paper and responses are discussed throughout this section of the publication. It is clear that there is currently variation in accounting and opinions between companies in the extractive industries, and the discussion paper generated significant interest in the oil and gas sector. Respondents were supportive of a project to address the accounting for extractive activities, although many respondents did not agree with the project team s specific proposals. The responses to the discussion paper highlight the range of opinions on the future of accounting for oil and gas operations under IFRS.

7 Impact of IFRS: Oil and Gas 5 1 Exploration and evaluation (E&E) assets IFRS does not define either successful efforts or modified full cost accounting, despite these being the two most common accounting approaches applied by IFRS companies The costs involved in E&E and development activities are considerable, and often there are years between the start of exploration and the commencement of production. Even with today s advanced technology, exploration is a risky and complex activity. These factors create specific challenges in accounting for E&E expenditure. There was no IFRS that specifically addressed E&E activities until IFRS 6 became effective in IFRS 6 was intended to be a temporary standard while the IASB undertook an in-depth project on extractive activities. With that in mind, the standard was written with a view to allowing companies to carry over to IFRS their previous GAAP practices to a large extent. Traditionally under national GAAPs, oil and gas companies have accounted for E&E costs using one of two broadly defined methods: the successful efforts method or the full cost method. However, as there is no single accepted definition of either method under IFRS, the application of these approaches can vary. Capitalisation of E&E expenditure IFRS 6 relaxes asset recognition requirements for E&E expenditure Without the benefit of IFRS 6, expenditure would not be recognised as an asset unless it is probable that it will give rise to future economic benefits. This would mean that expenditure on an exploration activity likely would be expensed until the earlier of the time at which: the estimated fair value less costs to sell of the exploration prospect is positive; and it is determined that commercial reserves are present. Applying this test, it would be rare for expenditure other than licence acquisition costs to be capitalised prior to the determination of commercial reserves. IFRS 6 relaxes this approach for E&E assets, allowing capitalisation of E&E costs by expenditure class if the company elects that accounting policy. Definition of E&E expenditure The stage of a project is important in determining the accounting standards to be applied IFRS 6 applies only to E&E expenditure. Outside of the scope of IFRS 6 the usual IFRS accounting requirements apply, including in respect of impairment testing. The standard provides a non-exhaustive list of E&E expenditure that may be capitalised, including the cost of geological and geophysical studies, the acquisition of rights to explore, exploratory drilling, trenching and sampling. The stage of projects needs to be monitored to ensure that accounting policies are applied appropriately. IFRS 6 excludes pre-licence expenditure from the scope of E&E costs, implying that E&E activities commence on acquisition of the legal rights to explore an area. Also, IFRS 6 does not apply to expenditure incurred after the technical feasibility and commercial viability of extracting the oil and gas are demonstrable. Determining when this is demonstrable, and the level of detail at which this assessment should be made, can involve considerable judgement and requires close communication between finance and technical specialists. Classification Classification of expenditure forms the basis of presentation and subsequent measurement of assets E&E assets are a separate class of asset that is measured initially at cost. E&E assets are classified as tangible or intangible assets depending on their nature. Tangible E&E assets may include the items of plant and equipment used for exploration activity, such as vehicles and drilling rigs. Intangible E&E assets may include costs of exploration permits and licences as well as depreciation of tangible assets consumed in developing intangible assets such as exploratory wells. First-time adoption Oil and gas deemed cost election There is an oil and gas industry-specific exemption in IFRS 1 First-time Adoption of IFRS. Oil and gas companies can elect to measure E&E assets at the amount determined under previous GAAP at the date of transition to IFRS. Development and production assets can be measured at the amount determined for the cost centre under previous GAAP, with an allocation to the underlying assets on a pro rata basis using reserve volumes or reserve values at transition date. This exemption can assist oil and gas companies in preparing their first IFRS financial statements without having to revisit all previous accounting for these items. For more information on the reliefs available on the adoption of IFRS, we recommend that you refer to KPMG s publication IFRS Handbook: First-time Adoption of IFRS.

8 6 Impact of IFRS: Oil and Gas

9 Impact of IFRS: Oil and Gas 7 Discussion Paper Extractive Activities The Discussion Paper supported a separate accounting model for E&E costs in extractive industries. The views of respondents varied significantly on the approach that the IASB should take, and on the asset recognition model. The project team s proposals relating to E&E assets included the following. A single accounting approach for both minerals and oil and gas extractive activities. Recognition of an asset on the acquisition of legal rights and capitalisation of all subsequent expenditure as part of that asset. This includes expenditure that may be expensed currently. Three possible measurement bases for assets arising from extractive activities: historical cost, current value, and a mixture of historical cost and current value. The project team recommended historical cost as the preferred measurement basis. Single and separate approach for mining and oil and gas activities The project team proposed to limit the scope of a future IFRS to extractive activities for minerals, oil and natural gas. A single accounting and disclosure model was proposed. The responses highlighted the broad range of views on this subject. Of respondents who addressed this question, 62% agreed with the single model approach. A small minority of respondents didn t believe that a separate accounting standard is required, but supported a disclosure standard that applied a single approach to oil and gas and mining companies. Some respondents who disagreed with a separate single model approach supported including extractive activities in a broader project to reconsider intangible assets accounting. The case for a broader project on intangible assets relates to the question of whether extractive activities are sufficiently different from other industries to justify a separate accounting model. For example, the uncertainty and long project lives inherent in E&E activities are similar to issues in the technology and pharmaceutical industries. Some respondents commented that separate standards should be developed for each of mining and oil and gas. Asset recognition proposals problematic Most respondents expressed at least some concern with the asset recognition model proposed by the project team. While the majority (63%) agreed with the proposal to recognise an asset when the legal right is acquired, a significant majority of respondents (88%) disagreed with the project team s view that the subsequent E&E activity would always represent an enhancement of the asset. Many of those respondents suggested that the project team s analysis of the treatment of E&E assets was inconsistent with the asset recognition criteria and the IFRS conceptual framework because the information obtained may not have any future economic benefit due to uncertainty in the exploration process. Respondents urged the IASB to consider asset recognition further. Respondents who disagreed with the asset recognition model made the following suggestions of alternative approaches. Recognise a mining/oil and gas property asset on the same basis as other assets (e.g. in accordance with IAS 38 Intangible Assets, IAS 16 Property, Plant and Equipment and/or the IFRS conceptual framework) (42%). Respondents who supported this approach to asset recognition typically also recommended that the scope of a future project should extend beyond extractive activities. Use existing accounting methods such as successful efforts accounting (19%). The range of responses and the concerns raised underline the difficulties in accounting for E&E assets and the divergence of practice. Measurement at historical cost preferred Almost all respondents agreed with the proposal to measure assets at historical cost because it is a measure that is verifiable, can be prepared in a timely manner and can be used to assess financial performance and stewardship. These respondents explained that they did not support fair value because it would introduce excessive subjectivity and short-term volatility to the financial statements. It was also thought that the use of fair value would impose significant preparation and audit costs that are not justified because users are not interested in that information. The research conducted by the project team indicated that analysts, lenders and venture capitalists would make only limited use of an estimate of fair value due to the subjectivity and degree of estimation involved.

10 8 Impact of IFRS: Oil and Gas 2 Depletion, depreciation and amortisation (DD&A) A move from group depreciation methods or depreciation pools under previous GAAP to component depreciation under IFRS could require significant effort Component accounting Significant judgement may be required in determining components, and systems needs to be capable of tracking components separately Companies need to allocate the cost of an item of property, plant and equipment into its significant parts, or components, and depreciate each part separately. For each component the appropriate depreciation method, rate and period needs to be considered. This process may involve significant judgement. An item of property, plant and equipment should be separated into components when those parts are significant in relation to the total cost of the item. This does not mean that a company should split its assets into an infinite number of components if the effect on the financial statements would be immaterial. Some oil and gas companies that have been applying full cost accounting under previous GAAP may have been calculating DD&A at a cost centre (typically a country) level. While there is no cost-pool concept under IFRS, the standard does allow companies to group and depreciate components within the same asset class together, provided they have the same useful life and depreciation method. However, it is unlikely that development or production oil and gas assets will be able to be grouped at a level greater than a field; this is because each field may be significant and the lives of the fields, and therefore depreciation rates, will vary. Companies need to consider the impact, including on accounting systems, of depleting assets on a much more detailed level than previous GAAP. Depreciation method Companies need to choose the most appropriate depreciation method IFRS do not specify one particular method of depreciation as preferable. Oil and gas companies have the option to use the straight-line method, the reducing balance method or the unit-ofproduction method, as long as it reflects the pattern in which the economic benefits associated with the asset are consumed. The unit-of-production method is most commonly used to deplete upstream oil and gas assets, using a ratio that reflects the annual production of a field in proportion to the estimate of reserves within that field. IFRS provides no specific guidance on how the assumptions within the reserve estimates should be calculated or approximated. Consequently, practice varies as to which reserves base is used in the calculation of DD&A. Commencement of depreciation/amortisation Available for use Depreciation or amortisation starts when an asset is available for use. For assets in the development stage there may be pilot testing phases prior to the start of full production. Whether incidental production arising during any such phases triggers depreciation depends on the assessment of whether the asset is available for use. Some E&E assets (e.g. a drilling rig) may be available for use immediately and so could be depreciated/amortised during the E&E phase. Other assets will not be available for use until the whole field is ready to commence operations. In our view, there are two reasonable approaches to determining when depreciation/amortisation of E&E assets should commence. Commence depreciation/amortisation when the whole field is ready to commence operations, since, in effect, it is from this point that economic benefits will be realised. Commence depreciation/ amortisation during the E&E phase as the assets are available for use when considered on a stand-alone basis; however such depreciation/ amortisation is capitalised to the extent that the assets are used in the development of other assets.

11 Impact of IFRS: Oil and Gas 9 Discussion Paper Extractive Activities The scope of the discussion paper did not specifically include DD&A The discussion paper did not propose to change the basis for calculating depreciation, although it highlighted some issues related to the application of the unit-of-production method. One issue is whether such a method should be based on revenues or physical units. Another issue is whether the unit-ofproduction method should be based on proved reserves, proved and probable reserves or another unit basis. The project team proposed that these issues be addressed in any future standard. Some respondents noted that they would like additional issues such as depreciation/depletion to be addressed if this project is added to the active agenda of the IASB.

12 10 Impact of IFRS: Oil and Gas 3 Impairment of non-financial assets Annual impairment testing for intangible assets that are not yet available for use is relaxed for E&E assets E&E assets E&E assets are exempt from certain impairment testing requirements IFRS 6 requires E&E assets to be assessed for impairment in two circumstances. When facts and circumstances suggest that the carrying amount of an E&E asset may exceed its recoverable amount. When E&E activities have been completed, i.e. when the commercial viability and technical feasibility of that asset have been determined and prior to reclassification to development assets. The standard provides the following examples of trigger events that indicate that an E&E asset should be tested for impairment: expiration of the right to explore; substantive expenditure on further exploration for and evaluation of mineral resources in the specific area is neither budgeted nor planned; commercially viable reserves have not been discovered and the company plans to discontinue activities in the specific area; and data exists to show that while development activity will proceed, the carrying amount of the E&E asset will not be recovered in full through such activity. This provides relief from the general requirements of IFRS, which require annual impairment testing for intangible assets that are not yet available for use. Impairment testing calculations are performed in line with general impairment requirements and take into account the time value of money. Development and production assets Reporting date consideration of impairment indicators For non-current assets (other than goodwill and E&E assets) IAS 36 Impairment of Assets requires companies to assess at the end of each reporting period whether there are any indicators that an asset is impaired. If there is such an indication, then recoverable amount needs to be assessed. An impairment loss is recognised for any excess of carrying amount over recoverable amount. If recoverable amount cannot be determined for the individual asset, because the asset does not generate independent cash inflows separate from those of other assets, then the impairment loss is recognised and measured based on the cash-generating unit to which the asset belongs. Cash-generating units (CGUs) Identification of appropriate CGUs can be complex A CGU is the smallest group of assets that generates cash inflows from continuing use that are largely independent of the cash inflows from other assets or group of assets of the oil and gas company. In our experience, many companies in the oil and gas sector base the identification of CGUs on licence, field or core areas. For some companies that operate a number of areas or fields that have shared infrastructure and E&E assets, the identification of CGUs can be more complex. An accounting policy is also needed for allocating E&E assets to CGUs when an impairment test is to be performed. For assets during the E&E phase, CGUs can be aggregated to form a group of units for impairment testing purposes. Allocation of assets to CGUs and impairment groups requires judgement and the interaction with indicators of impairment will require consideration. Indicators of impairment Some examples of indicators of impairment are outlined below. Market value has declined significantly or the company has operating or cash losses. For example, a significant downward movement in the oil price may result in operating cash losses and represent a trigger for impairment. Technological obsolescence. Competition. Market capitalisation. For example, the carrying amount of the oil and gas company s net assets exceeds its market capitalisation. This may be a particular risk for companies with large E&E assets. Significant regulatory changes. For example, increased regulation of environmental rehabilitation processes. Physical damage to the asset. For example, damage to a drilling rig caused by an explosion. Significant adverse effect on the company that will change the way in which the asset is used/ expected to be used. For example, the re-nationalisation requirements of some governments may lead to some projects being diluted to accommodate a government interest. Goodwill Impairment testing at least annually Under IFRS, oil and gas companies are required to test goodwill (and intangible assets with indefinite useful lives) for impairment at least annually,

13 Impact of IFRS: Oil and Gas 11 irrespective of whether indicators of impairment exist. Additional testing at interim reporting dates is required if impairment indicators are present. Goodwill by itself does not generate cash inflows independently of other assets or group of assets and therefore is not tested for impairment separately. Instead, it should be allocated to the acquirer s CGUs that are expected to benefit from the synergies of the related business combination. Goodwill is allocated to a CGU that represents the lowest level within the company at which the goodwill is monitored for internal management purposes. The CGU cannot be larger than an operating segment as defined in IFRS 8 Operating Segments, before aggregation. An impairment loss is recognised and measured at the amount by which the CGU s carrying amount, including goodwill, exceeds its recoverable amount. Impairment reversals Reversal of impairment losses restricted Impairment losses related to goodwill cannot be reversed. However, for other assets companies assess whether there is an indication that a previously recognised impairment loss has reversed. If there is such an indication, then impairment losses are reversed if the recoverable amount has increased, subject to certain restrictions. Discussion Paper Extractive Activities Proposals maintain the exemption from applying all requirements of IAS 36 to E&E assets The project team s proposals relating to impairment included the following. l The indicators of impairment for E&E assets differ from those in IAS 36. l When management determines that there is a high likelihood that the carrying amount of the asset will not be recovered, then the E&E asset should be tested for impairment. l The proposals concluded that IAS 36 should not be applied to E&E assets. The basis for this proposal was a view that it is not possible to make a reliable judgement of whether the carrying amount is less than the recoverable amount until sufficient information is available. Of respondents who commented on impairment, most (73%) opposed the proposals. Some respondents suggested that the IASB include a review of IAS 36 in any future project to alleviate difficulties in applying IAS 36 to E&E assets. The potential of the proposed approach to delay recognition of any impairment loss and the reliance on management judgement were noted by some respondents. Some respondents remarked that the fact that the IAS 36 impairment test approach is not considered to work for E&E assets may imply that the project team has proposed the wrong asset recognition model.

14 12 Impact of IFRS: Oil and Gas 4 Decommissioning and environmental provisions IFRS may result in the earlier recognition of provisions than many national GAAPs Oil and gas companies often are exposed to legal, contractual and constructive obligations to meet the costs of decommissioning and dismantling assets at the end of their production life and to restore the site. These costs are likely to be a significant item of expenditure for most oil and gas companies. Timing of recognition A present obligation that is more likely than not Decommissioning and environmental provisions are covered by IAS 37 Provisions, Contingent Liabilities and Contingent Assets. Recognition of a provision is required when there is a present obligation and an outflow of resources is probable. Probable is defined as more likely than not. A present obligation can be legal or constructive in nature. For oil and gas companies a legal obligation for decommissioning and remediation often is contained in the licence agreement and related contracts, or in legislation. However, in some countries environmental legislation may be less developed and it may be difficult to determine the extent of the obligation. A constructive obligation may arise from a company s published policies about environmental clean-up or from past practices. An obligation to make good damage or dismantle equipment is provided for in full when the damage is caused or the asset installed. This may result in the recognition of additional amounts or earlier recognition of such amounts in IFRS financial statements compared to previous GAAP. When the provision arises on initial recognition of an asset, the corresponding debit is treated as part of the cost of the related asset and is not recognised immediately in profit or loss. Measurement Judgement is required to arrive at the best estimate The provision is measured at the best estimate of costs to be incurred. This takes the time value of money into account, if material. The best estimate may be based on the single most likely cost of decommissioning and takes uncertainties into account in either the cash flows or discount rate used in measuring the provision. The discount rate should reflect the risks specific to the liability and adjusting the discount rate for risk often is complex and involves a high degree of judgement. There are many complexities in calculating an estimate of expenditure to be incurred. Technological advances may reduce the ultimate cost of decommissioning and may also affect the timing by extending the expected recoveries from reservoirs. The estimate is updated at each reporting date. For midstream and downstream assets with indefinite useful lives, the timing of decommissioning may be so distant that the present value of liabilities is not significant. When there is uncertainty about the useful life of the asset, this uncertainty needs to be taken into account in the measurement of the provision. In such cases, it may be that the provision is not significant until the expected date at which the facilities will be decommissioned is less distant. Significant judgement may be required in measuring the provision. Future developments The IASB is reviewing accounting for provisions In 2005 the IASB began reviewing the accounting for provisions and an exposure draft was issued, which would have resulted in changes to both the timing of recognition and the measurement of provisions. In 2010 the IASB issued a limited reexposure of the 2005 proposals, which included a focus on the measurement of provisions involving services, e.g. decommissioning. The project currently is inactive, and the IASB will decide whether or how to progress the project when it considers responses to its Agenda Consultation 2011, which are due by 30 November 2011.

15 Impact of IFRS: Oil and Gas 13

16 14 Impact of IFRS: Oil and Gas 5 Joint arrangements The term joint venture is a widely used operational term, although not all such arrangements are joint ventures for accounting purposes. A recently issued standard could significantly impact the accounting Determining whether an arrangement is a joint arrangement Companies need to review their arrangements to determine whether they should be accounted for as a joint arrangement Joint arrangements are a common way for oil and gas companies to share the risks and costs of exploration and production activities, and come in a variety of forms. Within the sector, the term joint venture is used widely as an all-encompassing operational expression to describe shared working arrangements. However, under IFRS there are strict criteria that must be met in order for joint arrangement accounting to be applied. For an arrangement to be a joint arrangement for accounting purposes there must be a contractual arrangement that gives joint control. Joint control is not determined by economic interest. Control is based on the contractual arrangements and exists when decisions about the relevant activities require the unanimous consent of more than one party to the arrangement. Companies must review their arrangements to determine whether joint control exists. When the company does not have joint control, the arrangement likely will be accounted for as an investment, subsidiary or associate. Accounting for joint ventures prior to adoption of IFRS 11 Accounting is based on whether there is a separate legal entity. An accounting policy choice is available for jointly controlled entities Accounting for joint arrangements (currently referred to as joint ventures) before the adoption of IFRS 11 Joint Arrangements is governed by IAS 31 Interests in Joint Ventures. There are three classifications of joint venture under IAS 31: jointly controlled entity, jointly controlled asset and jointly controlled operation. Jointly controlled entities A jointly controlled entity is a joint arrangement that is carried out through a separate legal entity. Currently there is an accounting policy choice that applied when accounting for jointly controlled entities. A venturer accounts for its interest using either proportionate consolidation or the equity method. In KPMG s 2008 survey The Application of IFRS: Oil and Gas there was an almost even split between companies applying the equity method and those using proportionate consolidation. Jointly controlled assets and jointly controlled operations Jointly controlled assets and jointly controlled operations are joint ventures that are not separate legal entities. Venturers in jointly controlled assets and jointly controlled operations recognise the assets and liabilities, or share of assets and liabilities, that they control, as well as the costs incurred and income received in relation to that arrangement. Accounting for joint arrangements from 2013 A new standard issued in 2011 significantly impacts the accounting for joint arrangements The IASB issued IFRS 11 in May The standard is effective for periods beginning on or after 1 January 2013, with early adoption permitted subject to some conditions. There are two classifications of joint arrangements under IFRS 11: Joint ventures and joint operations. The definitions of each category differ from those in IAS 31. The classification of arrangements under IFRS 11 is more judgemental and the terms of arrangements and the nature of any related agreements must be considered to determine the classification of the arrangement for accounting purposes. Joint venture A joint venture is a joint arrangement in which the jointly controlling parties have rights to the net assets of the arrangement. Joint ventures include only arrangements that are structured through a separate vehicle (such as a separate company). However, not all joint arrangements that are companies will necessarily be joint ventures. The nature and terms of arrangements need to be reviewed to determine the appropriate classification of the arrangement. The legal form is only one factor to be considered. When the contractual arrangements and other facts and circumstances indicate that the joint venturers have rights to assets or obligations for liabilities of the arrangement, the arrangement will be a joint operation. One circumstance that could indicate that an arrangement is a joint operation is if the arrangement is designed so that the jointly controlled company cannot undertake its own trade, and can only trade with the parties to the joint arrangement. Related agreements and other facts and circumstances also need to be considered. A joint venturer will account for its involvement in the joint venture using the equity method in accordance with IAS 28 (2011) Investments in Associates and Joint Ventures. Joint operation A joint operation is an arrangement in which the jointly controlling parties have rights to assets and obligations for

17 Impact of IFRS: Oil and Gas 15 liabilities relating to the arrangement. An arrangement that is not structured through a separate vehicle will be a joint operation; however, other arrangements may also fall into this classification depending on the rights and obligations of the parties to the arrangement. A joint operator recognises its own assets, liabilities and transactions, including its share of those incurred jointly. Discussion Paper Extractive Activities Joint arrangements were not in the scope of the discussion paper In commenting on the proposed scope of any future project by the IASB, some respondents requested that the IASB consider other issues that were not specifically covered in the discussion paper. These included risk-sharing agreements such as farm-in/ farm-outs, productionsharing agreements and carried interests. These issues are routinely encountered in the oil and gas sector. Some respondents indicated that they considered addressing these, and other additional areas, to be a high priority in the absence of specific guidance in IFRS. These comments underline the importance and accounting complexities of risk-sharing arrangements in the extractive industries.

18 16 Impact of IFRS: Oil and Gas 6 Revenue recognition Oil and gas companies face challenges when applying the revenue recognition requirements under IFRS due to common industry arrangements that can give rise to complex revenue issues Oil and gas companies reporting under IFRS need to assess whether the risks and rewards of ownership have been transferred in order to determine when to recognise revenue. The determination of when this occurs can present challenges for oil and gas companies. The individual facts and circumstances will need careful consideration as they may vary between contracts. Timing of revenue recognition There is no industry standard as to the timing of the transfer of ownership in oil and gas transactions. The revenue arising from each transaction is recognised based on the terms of the underlying sales agreement. For most transactions involving the sale of physical oil and gas, the contractual terms for the transfer of ownership will be based on the delivery or lifting of production. For example, for crude oil sales generally there are two points at which title could pass from seller to buyer: when the crude oil is lifted from the site of production; or when the crude oil is delivered to the refinery/ storage depot. For petroleum products sold to retail distribution networks, generally revenue is recognised on delivery to service stations. Physical exchange of products The physical exchange of products is common within the oil and gas industry. For example, under crude oil buy/sell arrangements a company agrees to buy a specified quantity and grade of oil to be delivered at a specified location, while simultaneously agreeing to sell a specified quantity and grade of oil at a different location with the same counterparty, generally to facilitate operational requirements. In accordance with IAS 18 Revenue, the swapping of goods or services that are of a similar nature and value is a transaction that does not generate revenue. The nature of the exchange will determine if it is a like-for-like exchange accounted for at book value, or an exchange of dissimilar goods within the scope of IAS 18. The quantum of the balancing payment is one important factor in deciding whether the transaction is a sale and a purchase or a swap of similar products. The more significant the balancing payment is compared to the value of the products being exchanged, the more likely the transaction is to be a swap of dissimilar products. Overlift and underlift In many joint arrangements the timing of revenue recognition will coincide with a fixed schedule of lifting, which stipulates when each participant lifts its share of crude oil or gas from the production facility. The practicalities of loading an oil tanker mean that any single lifting can be more or less than a company s entitlement, resulting in an overlift (a lifting in excess of the company s contractual allocation of production) or an underlift (a lifting less than the company s contractual allocation of production). Oil and gas companies need to consider how they account for any overlift or underlift balances, including what measurement base to apply to any resulting asset or liability. Future developments A new standard on revenue recognition is expected The IASB and the US Financial Accounting Standards Board are working on a joint project to develop a comprehensive set of principles for revenue recognition. An exposure draft published in 2010 proposed a single revenue recognition model in which an entity would recognise revenue as it satisfies a performance obligation by transferring control of promised goods or services to a customer. The model was proposed to be applied to all contracts with customers except leases, financial instruments, insurance contracts and non-monetary exchanges between entities in the same line of business to facilitate sales to customers other than the parties to the exchange. The Boards redeliberated the proposals contained in the exposure draft during the first half of 2011 and agreed tentatively to revise a number of aspects of the proposals, including the criteria for identifying separate performance obligations, the guidance on transfer of control, and the measurement of the transaction price, particularly for arrangements including uncertain consideration. The Boards concluded that, although there was no formal due process requirement to reexpose the proposals, it was appropriate to go beyond established due process given the importance of this topic to all entities. A revised exposure draft is expected in the second half of 2011.

19 Impact of IFRS: Oil and Gas 17

20 18 Impact of IFRS: Oil and Gas 7 Reserves reporting There is no specific IFRS reporting requirement on reserves, although many oil and gas companies include an accounting policy for reserves or a commentary in the critical estimates and judgements note, or in the management discussion and analysis section of the annual report Oil and gas reserve estimates are critical information in the evaluation of oil and gas companies, and reserves disclosure is an important component of annual reports in the sector. The purpose of reserves reporting is to make available information about the oil and gas reserves controlled by companies in the sector. This is vital in assessing their current performance and future prospects. Despite their importance to both the company and the financial statements, there are no explicit requirements for the disclosure of reserve information in IFRS. Disclosures In the absence of specific guidance, oil and gas companies tend to refer to other requirements, such as those in the US, Canada, Australia and the UK. The nature of reserves estimates is such that, even if all companies provided disclosure based on a single classification, meaningful comparison between companies would be difficult without in-depth analysis of the many assumptions inherent in the core disclosures. The US Securities and Exchange Commission s rules require any issuer providing disclosure under ASC Extractive Activities Oil and Gas Notes to Financial Statements to continue to provide that disclosure even if the issuer is preparing financial statements in accordance with IFRS. Impact of reserve estimates on financial statement balances While the reporting of reserves data is important in its own right, reserves measures are also used in deriving a number of accounting estimates. In our experience, DD&A calculations usually are based on the unit-ofproduction method and the volume of reserves used in the calculation affects the calculation of the associated DD&A charge. Reserves estimates are a key factor in determining the economic life of an oil field and therefore impact on the calculation of decommissioning and environmental rehabilitation provisions. Impairment calculations include assumptions for reserves. Downward revisions in reserve estimates often represent an indicator of impairment. Reserves are a key input to fair value calculations in accounting for a business combination. Assumptions about future profit potential based on reserves estimates may be the basis for the recognition of deferred tax assets arising from unused tax losses. Because of the impact of reserves information in the financial statements, oil and gas companies typically include some information about reserves in the critical estimates and judgements note to the financial statements.

21 Impact of IFRS: Oil and Gas 19 Discussion Paper Extractive Activities Significant disclosure requirements proposed The project team s proposals relating to reserves reporting included the following. Use of Petroleum Resource Management System (PRMS) definitions for reserves and resources. The discussion paper noted that the PRMS is used by many oil and gas companies for internal resource management and it also corresponds closely to market regulator disclosure requirements in most jurisdictions that have formalised reserve disclosure requirements. Significant disclosure requirements relating to reserves and resources, including: quantities of proved reserves and proved plus probable reserves, with reserve quantities presented separately by commodity and by material geographical area; the main assumptions used in estimating reserve quantities, and a sensitivity analysis; and a current value measurement of reserves by major geographical region if historical cost is used to measure E&E assets. Reserve definition respondents views Most respondents agreed with recommendations that industry-based definitions of reserves and resources be used in any future IFRS to set disclosures and complement the accounting requirements. Most also agreed with the PRMS definition. Concerns raised related to the approach for incorporating the definition into any future IFRS. Also, respondents suggested that application guidance may be required to ensure PRMS is applied consistently. Concern was also raised over the project team s proposal that reserves estimates be prepared using a market participant s assumption of commodity price. Respondents who commented expressed a preference for a historical price assumption to remove subjectivity. Disclosure proposals respondents views While a majority (63%) of respondents generally agreed with the disclosure objectives, almost all respondents expressed significant concern about the level of granularity of the disclosures proposed. Concern was also raised as to whether the disclosure of reserve quantities should be subject to audit. Some of the proposed disclosures differ from those currently required by some market regulators. Also, additional information may be required in the future if such disclosures are mandated. Therefore, this area is likely to require significant management focus as practice and requirements develop. The importance of reserves reporting and the lack of current guidance led some respondents to support development of disclosure requirements separately, and more urgently, than accounting requirements.

22 20 Impact of IFRS: Oil and Gas 8 Financial instruments The conversion process must include a review of the existence, classification and accounting for financial instruments, including derivatives. Future changes in the accounting are expected Oil and gas companies generally have financial instrument accounting issues owing to the significant commodity price risk that they face and the structures in place to manage this and other exposures such as currency fluctuations. A thorough review of the existence, classification and accounting for financial instruments will be required on conversion. Current requirements Accounting and disclosure requirements may be significantly different from national GAAP Contracts to buy and sell oil and gas and other non-financial items may be included in the scope of the financial instruments standards. There is an exemption for contracts that are held for physical delivery or receipt for the company s expected purchase, sale or usage requirements (the own use exemption ). However, specific conditions must be met to apply this exemption, and its applicability should be reviewed carefully. Specific types of oil and gas contracts also commonly contain embedded derivatives that may need to be accounted for separately. For example, gas contracts that are not derivatives themselves may contain embedded derivatives as a result of a pricing mechanism linked to an index other than a gas pricing index. As it currently stands, IAS 39 Financial Instruments: Recognition and Measurement requires financial assets to be classified into one of four categories: at fair value through profit or loss; loans and receivables; held to maturity; and available for sale. Financial liabilities are categorised as either financial liabilities at fair value through profit or loss or other liabilities. Financial assets and financial liabilities are measured initially at fair value. After initial recognition, loans and receivables and held-to-maturity investments are measured at amortised cost. All derivative instruments are measured at fair value with gains and losses recognised in profit or loss except when they qualify as hedging instruments in a cash flow or net investment hedge. A financial asset is derecognised only when the contractual rights to cash flows from that particular asset expire or when substantially all risks and rewards of ownership of the asset are transferred. A financial liability is derecognised when it is extinguished or when the terms are modified substantially. Forthcoming requirements/ Future developments Simplified classifications In November 2009 the IASB published the first chapters of IFRS 9 Financial Instruments, which will supersede the requirements of IAS 39 Financial Instruments: Recognition and Measurement on the classification and measurement of financial assets. In October 2010 requirements with respect to the classification and measurement of financial liabilities and the derecognition of financial assets and financial liabilities were added to IFRS 9. Most of these requirements have been carried forward without substantive amendment from IAS 39. However, to address the issue of own credit risk some changes were made to the fair value option for financial liabilities. The effective date of IFRS 9 is periods beginning on or after 1 January 2013 but an exposure draft, open for comment until 21 October 2011, requests views on whether the effective date should be pushed back to 1 January IFRS 9 includes two primary measurement categories for financial assets: amortised cost and fair value. Other classifications, such as held to maturity and available for sale, have been eliminated. The classification and measurement requirements for financial liabilities are generally unchanged other than a change to the treatment of changes in fair value as a result of own credit risk.

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