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SORP. Statement of Recommended Practice. Accounting for Oil and Gas Exploration, Development, Production and Decommissioning Activities - PDF
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1 SORP Statement of Recommended Practice Accounting for Oil and Gas Exploration, Development, Production and Decommissioning Activities Updated 7 th June 2001 A SORP issued by the Oil Industry Accounting Committee incorporating and updating guidance set out in the SORP issued January 2000 and any subsequent Guidance Notes
2 Statement by the Accounting Standards Board (ASB) The aims of the Accounting Standards Board (the ASB) are to establish and improve standards of financial accounting and reporting, for the benefit of users, preparers, and auditors of financial information. To this end, the ASB issues accounting standards that are primarily applicable to general purpose company statements. In particular industries or sectors, further guidance may be required in order to implement accounting standards effectively. This guidance is issued, in the form of Statements of Recommended Practice (SORPs), by bodies recognised for the purpose by the ASB. The Oil Industry Accounting Committee (OIAC) has confirmed that it shares the ASB s aim of advancing and maintaining standards of financial reporting in the public interest and has been recognised by the ASB for the purpose of issuing SORPs. As a condition of recognition, OIAC has agreed to follow the ASB s code of practice for bodies recognised for issuing SORPs. The code of practice sets out procedures to be followed in the development of SORPs. These procedures do not include a comprehensive review of the proposed SORP by the ASB, but a review of limited scope is performed. On the basis of its review, the ASB has concluded that the SORP has been developed in accordance with the ASB s code of practice and does not appear to contain any fundamental points of principle that are unacceptable in the context of present accounting practice or to conflict with any accounting standard or the ASB s plans for future standards. The Accounting Standards Board Holborn Hall 100 Gray s Inn Road London WC1X 8AL 7 th June 2001 OIAC, All rights reserved ISBN Published by the Institute of Petroleum, London. A charitable company limited by guarantee. Registered No England This document, together with any future updates that may apply, can be viewed on OIAC s website:
3 CONTENTS... Paragraphs Part 1 : Explanatory note Part 2 : Definition of terms Part 3 : Recommended practice Pre-production activities & decommissioning Full cost and successful efforts principles Initial treatment of costs pending determination Subsequent expenditure Finance costs Bottom hole contributions Capitalisation of future decommissioning costs provided Depreciation Impairment tests Decommissioning Consolidation adjustments Oil & gas production activities Introduction Turnover, indirect taxes and excise duties Royalties Overlift and underlift Crude oil trading Production testing revenue Tariff income Gas sales contracts CONTENTS... Paragraphs Risk sharing arrangements Introduction Consortia Carried interests Production sharing agreements Production loans, forward sales & other similar arrangements Project finance Tariffed and shared assets Disposals, acquisitions & other changes of interests Disposal of interests Unitisations and redeterminations Farm ins Financial statement presentation & disclosures Accounting policies Capitalised costs Decommissioning Pre-production costs incurred or provided Results of operations Results of acquired operations Results of discontinued operations Exceptional items Analysis of tax charge Foreign exchange Commercial reserve quantities Presentation formats Appendices: 1 Capitalised Costs 2 Pre-production Costs Incurred or Provided 3 Results of Operations
4 4 Net Commercial Oil and Gas Reserve Quantities
5 Part 1 : Explanatory note INTRODUCTION 1. The Oil Industry Accounting Committee ( OIAC ) was established in 1984 to develop and promulgate guidance for the UK upstream oil and gas industry with the aim of advancing and maintaining standards of financial accounting and reporting. 2. The OIAC was authorised, initially, by the Accounting Standards Committee and subsequently by its successor, the Accounting Standards Board (ASB) to develop Statements of Recommended Practice (SORPs) and Guidance Notes for the preparation of financial statements for shareholders. This arrangement requires OIAC to follow the ASB s code of practice for the production and issuing of SORPs. This code of practice provides a framework to be followed by the OIAC for the development of SORPs, but does not entail a detailed examination of the proposed SORP by the ASB. However, a review of limited scope is performed. This SORP has been seen by The Financial Sector and Other Special Industries Committee of the ASB which has raised no objection to its publication. The OIAC issued four SORPs and two guidance notes between 1986 and In January 2000, following a period of substantial increase in the numbers of Financial Reporting Standards (FRSs), issued by the ASB, OIAC rationalised its previous pronouncements into a single combined SORP, superseding all earlier statements 3. The ASB code of practice on the development of SORPs requires, inter alia, that SORP-making bodies keep under review all SORPs for which they are responsible. In particular, the SORPs must comply with new accounting standards as they are introduced and reflect any new developments in the industry on which guidance may be needed. 4. This new SORP incorporates the FRS 15 Tangible Fixed Assets guidance issued by OIAC in September It also reflects other changes identified by the ASB, OIAC or its oil and gas industry
6 constituency as appropriate for further guidance. No industry specific issues were identified in FRS 16 Current Tax, the last FRS to be issued at the time this statement was prepared. PART 2: DEFINITION OF TERMS companies legislation. In the event of conflict accounting standards and companies legislation take precedence over this SORP. 5. Readers attention is particularly drawn to paragraphs 78 and 82, relating to impairment test discounting of revenues and costs, to paragraph 121 Underlift and Overlift, to paragraph 124, relating to the disclosure of oil trading sales and costs, to paragraphs 157 to 161 relating to production sharing agreements and to paragraphs 183 to 188, relating to redeterminations, where new recommended practices have been incorporated. Once this SORP comes into effect, the January 2000 SORP will be formally withdrawn. OBJECTIVE 6. The objective of this SORP is to promote consistency amongst companies reporting under UK Accounting and Financial Reporting Standards as regards the effective application of these standards to their oil and gas exploration and production activities. SCOPE AND APPLICATION 7. This statement of recommended practice applies to the financial statements of all companies reporting under UK generally accepted accounting principles with oil and gas exploration, development and/or production activities whether or not these activities take place in the UK. The recommendations only apply to material items. 8. This statement does not seek to set out all of the reporting requirements which apply to companies reporting under UK financial reporting standards with oil and gas exploration, development and/or production activities and is intended to complement, not replace, accounting standards 1 and companies legislation. This statement should not be used on a standalone basis, but rather should be referred to in conjunction with accounting standards and 1 Comprising Financial Reporting Standards (FRSs), Statements of Standard Accounting Practice and Urgent Issues Task Force Abstracts
7 PART 2: DEFINITION OF TERMS Part 2 : Definition of terms 9. ALLOCABLE TAXES. Taxes which can be specifically identified with oil and gas production activities. 10. CARRIED INTEREST. An arrangement whereby one or more members of a consortium are financed by other members during the exploration and/or development phase, with repayment only being required out of future production (if any). 11. CEILING TEST. See impairment test. 12. COMMERCIAL RESERVES. Commercial reserves may, at a company s option, be taken as either: (a) Proven and probable oil and gas reserves; or (b) Proved developed and undeveloped oil and gas reserves; both of which are defined below. These alternative definitions are mutually exclusive and the option chosen should be applied consistently in respect of all exploration, development and production activities. (a) Proven and probable oil and gas reserves Proven and probable reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty (see below) to be recoverable in future years from known reservoirs and which are considered commercially producible. There should be a 50 per cent statistical probability that the actual quantity of recoverable reserves will be more than the amount estimated as proven and probable and a 50 per cent statistical probability that it will be less. The equivalent statistical
8 PART 2: DEFINITION OF TERMS probabilities for the proven component of proven and probable reserves are 90 per cent and 10 percent respectively. Such reserves may be considered commercially producible if management has the intention of developing and producing them and such intention is based upon: - a reasonable assessment of the future economics of such production; - a reasonable expectation that there is a market for all or substantially all the expected hydrocarbon production; and - evidence that the necessary production, transmission and transportation facilities are available or can be made available. Furthermore (i) Reserves may only be considered proven and probable if producibility is supported by either actual production or conclusive formation test. The area of reservoir considered proven includes (a) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, or both, and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geophysical, geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. (ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are only included in the proven and probable classification when successful testing by a pilot project, the operation of an installed programme in the reservoir, or other reasonable evidence (such as, experience of the same techniques on similar reservoirs or reservoir simulation studies) provides support for the engineering analysis on which the project or programme was based. (b) Proved developed and undeveloped oil and gas reserves The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, that is, prices and costs as at the date the estimate is made. (i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of reservoir considered proved includes (a) that portion delineated by drilling and defined by gas-oil or oilwater contacts, if any, or both, and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. (ii) Reserves that can be produced economically through the application of improved recovery techniques (such as fluid injection) are generally only included in the proved classification if successful testing by a pilot project, or the operation of an installed programme in the reservoir, provides support for the engineering analysis on which the project or programme was based. (iii) Estimates of proved reserves do not include the following: (a) crude oil, natural gas and natural gas liquids that may become available from known reservoirs but are classified separately as indicated additional reserves; (b) crude oil, natural gas and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (c) crude oil, natural gas and natural gas liquids that may occur in undrilled prospects; and (d) crude oil, natural gas and natural gas
9 PART 2: DEFINITION OF TERMS liquids that may be recovered from oil shales, coal, gilsonite and other such sources. Proved reserves may be sub-divided into proved developed and proved undeveloped : (i) Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should generally be included as proved developed reserves only after testing by a pilot project or after the operation of an installed programme has confirmed through production response that increased recovery will be achieved. (ii) All other proved reserves which do not meet this definition are proved undeveloped. 13. COST POOL. A cost centre used under the full cost method of accounting as a basis for accumulating depreciable capitalised exploration, appraisal and development expenditure and for performing an impairment test. The cash flows from fields within a pool must be affected by the same factors and therefore the fields within a pool will possess to a significant degree common characteristics in at least one of the following factors: geological area, interdependence of infrastructure, common economic environment or common development of markets. 14. COSTS. (a) Pre-licence costs Cost incurred in the period prior to the acquisition of a legal right to explore for oil and gas in a particular location. Such costs include the acquisition of speculative seismic data and expenditure on the subsequent geological and geophysical analysis of this data. (b) Licence acquisition costs Costs incurred to purchase, lease or otherwise acquire a property including the costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to petroleum when land including petroleum rights is purchased, including brokers fees and legal and other related costs. (c) Exploration and appraisal costs Costs incurred after obtaining a licence or concession but before a decision is taken to develop a field or reservoir, including the costs of: - geological and geophysical studies; - holding undeveloped properties; and - drilling, equipping and testing exploration and appraisal wells. Appraisal costs are those incurred in determining the size and characteristics of a reservoir discovered during the exploration stage and then assessing its commercial potential. (d) Development costs Costs incurred after a decision has been taken to develop a reservoir, including the costs of: - drilling, equipping and testing development and production wells; - production platforms, downhole and wellhead equipment, pipelines, production and initial treatment and storage facilities and utility and waste disposal systems; and - improved recovery systems and equipment. (e) Operating costs
10 PART 2: DEFINITION OF TERMS Operating costs are the costs of producing oil and gas, including: - costs of personnel engaged in the operation of wells and related equipment and facilities; - repairs and maintenance of producing facilities; and - materials, supplies and fuel consumed and services utilised in such operations. 15. DECOMMISSIONING. The process of plugging and abandoning wells, dismantlement of wellhead, production and transport facilities and restoration of producing areas in accordance with licence requirements and/or relevant legislation. 16. FARM IN. The transfer of part of an oil and gas interest in consideration for an agreement by the transferee ( farmee ) to meet, absolutely, certain expenditure which would otherwise have to be undertaken by the owner ( farmor ). 17. FIELD. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. 18. FULL COST ACCOUNTING. A method of accounting for oil and gas exploration and development activities whereby all costs associated with exploring for and developing oil and gas reserves are capitalised, irrespective of the success or failure of specific parts of the overall exploration activity. Costs are accumulated in cost centres known as cost pools and the costs in each cost pool are written off against income arising from production of the reserves attributable to that pool. 19. IMPAIRMENT. (a) Of capitalised development costs; a change in circumstances leading to a conclusion that the recoverable amount from reserves associated with capitalised development costs is likely to be less than the amount at which those costs are carried in the books assessed by means of an impairment test, see below. (b) Of costs capitalised pending determination, ie costs capitalised whilst a field is still being appraised; a change in circumstances leading to a conclusion that there is no longer a reasonable prospect that commercial reserves will result and will be developed reached in accordance with the guidance in this statement. 20. IMPAIRMENT TEST. A test in accordance with FRS 11 to assess the recoverability of the amounts at which capitalised exploration, appraisal and development expenditure associated with an income generating unit are recorded in the books by comparing that amount with the recoverable amount generally being the present value of future cash flows obtainable as a result of the continued use of that income generating unit, often referred to as a ceiling test by the industry. 21. INCOME GENERATING UNIT. The group of assets, liabilities and associated goodwill that generates income that is largely independent of a reporting entity s other income streams, as defined in FRS 11. Under successful efforts accounting policies, the income generating unit will generally be the assets, liabilities and associated goodwill associated with a particular field, or under some circumstances a group of fields that are to a significant degree economically interdependent. Under full cost accounting policies, the income generating unit will generally be the cost pool. 22. JOINT ARRANGEMENT (equivalent to a joint venture in common oil and gas industry terminology). A contractual arrangement by which a number of participants agree to conduct oil and gas exploration and production activities jointly, as a consortium. The terms of the joint arrangement are generally set out in a joint operating agreement such that all significant matters of operating
11 PART 2: DEFINITION OF TERMS and financial policy are predetermined. Under the joint operating agreement, the operator is elected to manage the assets and is generally empowered to enter into contracts and incur costs which are rechargeable to the other participants. Such an upstream oil and gas industry joint venture will typically fall within the FRS 9 definition of a joint arrangement which is not an entity (FRS 9 paragraph 4 and paragraphs 8 and 9), and not within the FRS 9 definition of a joint venture (FRS 9 paragraph 4 and paragraph 10) which is used to describe a significantly different type of business structure. 23. LICENCE. The right to explore for and exploit hydrocarbon reserves within a defined area. For the purposes of this statement, this term should be taken to include leases, concessions and other similar means by which this right may be granted or acquired. 24. LIFE-OF-FIELD METHOD. One of the methods of computing provisions for oil taxation, e.g. Petroleum Revenue Tax, by estimating the total tax payable over the life of a field and providing for the liability on a unit-of-production or similar basis. 25. OIL AND GAS EXPLORATION AND DEVELOPMENT ACTIVITIES. Those activities that involve the acquisition of interests in petroleum licences and properties, exploration, appraisal and development of crude oil reserves, including condensate and natural gas liquids, and natural gas. 26. PROVED PROPERTIES. Licences, concessions or leases which have proved reserves. 27. PRT. UK Petroleum Revenue Tax. 28. REDETERMINATION. A retroactive adjustment to the relative percentage interests of the participants in a field. 29. RESERVOIR. A porous and permeable underground formation containing a natural accumulation of producible oil or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. 30. SUCCESSFUL EFFORTS ACCOUNTING. A method of accounting for oil and gas exploration and development activities whereby exploration expenditure which is either general in nature or relates to unsuccessful drilling operations is written off. Only costs which relate directly to the discovery and development of specific commercial oil and gas reserves are capitalised and are depreciated over the lives of these reserves. The success or failure of each exploration effort is judged on a well-by-well basis as each potentially hydrocarbonbearing structure is identified and tested. 31. UNIT-OF-PRODUCTION. A method of computing charges by reference to the ratio that quantities of production in a period bear to the quantities of reserves remaining at the end of that period plus production in the period. 32. UNPROVED PROPERTIES. Licences, concessions or leases which do not have proved reserves. 33. WELLS. (a) Exploration well; A well drilled to discover whether oil or gas exists in a previously unproved geological structure. (b) Appraisal well; A well drilled to determine the size, characteristics and commercial potential of a reservoir discovered by the drilling of an exploration well. (c) Development well; A well drilled within the area of a proved reservoir to facilitate the production of reserves. Such wells may either be intended to produce oil and gas directly or to facilitate such production by, for example, the injection of gas or water. All wells drilled after a
12 PART 2: DEFINITION OF TERMS decision to develop a field has been made will ordinarily constitute development wells.
13 Part 3 : Recommended practice PRE-PRODUCTION ACTIVITIES & DECOMMISSIONING Full cost and successful efforts principles 34. Oil and gas exploration and development activities have several distinctive features: - the risks of exploration are high and there is often a low probability of discovering commercial reserves in any individual location; - the elapsed time between initial exploration, the assessment of whether commercial reserves exist and the bringing of such reserves, if any, into production may be several years, particularly in offshore environments; - there is no necessary correlation between exploration and development expenditure incurred, whether capitalised or otherwise, and the value of oil and gas reserves discovered as a result of those activities; and - the major economic value lies in the underlying oil and gas reserves which typically are not recorded in company balance sheets. 35. These and other factors historically resulted in the development of a wide range of practices as companies sought to provide a proper accounting presentation of the underlying activities. These practices have been narrowed into two categories full cost and successful efforts. 36. Under successful efforts accounting, exploration expenditure which is general in nature is charged directly to the profit and loss account and
14 that which relates to unsuccessful drilling operations, though initially capitalised pending determination, is subsequently written off. Only costs which relate directly to the discovery and development of specific commercial oil and gas reserves will remain capitalised to be depreciated over the lives of these reserves. The success or failure of each exploration effort will be judged on a well-by-well basis as each potentially hydrocarbon-bearing structure is identified and tested. 37. Under full cost accounting, all costs associated with exploring for and developing oil and gas reserves are capitalised, irrespective of the success or failure of specific parts of the overall exploration activity. Costs are accumulated in cost centres (known as cost pools ). The costs in each cost pool are generally written off against income arising from production of the reserves attributable to that pool. 38. The differences between the two methods outlined above reflect the differing perceptions which may be taken by companies of their exploration activities, in particular the issue of whether distinct exploration activities should be viewed as separate efforts to locate commercial reserves - the successful efforts method - or as part of an overall effort in a defined area - the full cost method. 39. The consequence is that there is a difference in the timing of income recognition. Under the successful efforts method, the costs of individually unsuccessful efforts are usually written off earlier in the financial statements but greater reported profits will be shown once production starts. Under the full cost method, the total costs of both successful and unsuccessful activities are spread over total production from each pool. Over the life of the entity aggregate reported profits under each method will be the same, but profits under full cost would tend to be recognised earlier. 40. Both full cost and successful efforts are considered to be acceptable accounting methods and companies should adopt that policy which they consider to be most suitable to their operations. The accounting practice under each of these methods is recommended in this statement based on the research of the OIAC into actual practices followed and the various alternatives considered acceptable to the UK PART 3: RECOMMENDED PRACTICE industry. Practices followed in other countries have also been taken into account. Initial treatment of costs pending determination Full cost companies 41. Expenditure on pre-licence, licence acquisition, exploration, appraisal and development activities including enhanced oil recovery and extended life projects should be capitalised. 42. In accordance with FRS 15, Tangible Fixed Assets, all other costs should be expensed as incurred including operating and productionrelated costs, such as tariffs and royalties, and also administrative and other general overhead costs not directly attributable to the activities referred to in paragraph All capitalised exploration and development expenditure should be recorded within an appropriate cost pool when incurred, except that certain exploration and appraisal costs may be held outside cost pools pending determination. 44. Pre-licence acquisition, exploration and appraisal costs of individual licence interests may be held outside cost pools until the existence or otherwise of commercial reserves is established. These costs will therefore remain undepreciated pending determination, subject to there being no evidence of impairment. 45. Costs initially held outside cost pools must be transferred to the relevant pool, and depreciated, in the following circumstances: - when there are indications of impairment; all expenditure must be subjected to a test for impairment at least annually. Costs capitalised pending determination of whether or not they have found commercial reserves are, where accounted for in accordance with this statement, specifically exempt from the detailed rules for assessing impairment set out in FRS 11;
15 - at the conclusion of an appraisal programme whether or not commercial reserves are discovered. The possibility of impairment must be considered if in the case of licence acquisition costs there is no drilling after one year or, in the case of successful exploration wells requiring further appraisal, such appraisal does not take place within two years of the discovery being made. The determination of drilling costs should be on a well-by-well basis except that all appraisal wells in respect of a discovery may be determined together. 46. The basis under which cost pools are established, for example geographic area, region or country, should be disclosed as an accounting policy. Cost pools should not normally be smaller in size than a country (except where significant interests are subject to widely differing geological, infrastructure, economic or market factors, for example onshore and offshore interests) and should be restricted in size so as to encompass a geographical area which shares a significant degree of common characteristics in at least one of the following factors: geological area, interdependence of infrastructure, common economic environment or common development of markets. The following are examples of what may be acceptable full cost pools: (a) Northern South America contains effectively one geological province: the so-called Sub-Andean Province. Although the area covers a number of different countries, it is significantly affected by similar geological risks throughout. (b) Similarly the NW European Continental Shelf has common geological characteristics extending beyond national boundaries, as well as having an increasing amount of shared infrastructure. (c) Although Russia contains a number of geological basins, these are linked by common political, economic, legal and fiscal systems as well as shared infrastructure. (d) The Caspian region comprises a number of separate countries, but they are closely linked commercially by a common export system, PART 3: RECOMMENDED PRACTICE shared exploration resources and by the parallel development of new markets. In each of these and in other similar cases where an area is managed as a single unit with its own dedicated team and internal reporting requirements, it may be appropriate to treat the area as a single income generating unit and therefore a single cost pool. A worldwide pool containing areas with very different characteristics, would not qualify as a single income generating unit, and a world-wide pool of this kind would therefore be inappropriate. 47. Changes in either the physical size or number of pools within an established policy must be warranted by business developments or changes in infrastructure, economic or market factors affecting the business. The reasons for any changes should be reported and the consequent effect on the company s earnings should be disclosed in the financial statements of the current period. 48. The aggregate net book value of full cost pools should be disclosed, together with the aggregate of costs held outside cost pools. 49. Full cost pools should be classified in the balance sheet as tangible assets. Expenditure held outside full cost pools should be classified as intangible assets - exploration expenditure. Successful efforts companies 50. All pre-licence, licence acquisition, exploration and appraisal costs should initially be capitalised (including those costs which may fall to be written off in the same period such as those costs referred to in paragraph 51) in well, field or general exploration cost centres as appropriate, pending determination. Expenditure incurred during the various exploration and development phases should then be written off unless commercial reserves have been established or the determination process has not been completed. 51. Expenditure incurred prior to the acquisition of a licence and the costs of other exploration activities which are not specifically directed to an identified structure should be written off in the period.
16 PART 3: RECOMMENDED PRACTICE 52. Expenditure incurred on the acquisition of a licence interest should initially be capitalised on a property-by-property basis. 53. Exploration and appraisal costs should be accumulated on a well-bywell basis pending evaluation. Capitalised costs should be considered abortive and written off on completion of a well unless the results of drilling indicate that hydrocarbon reserves exist and there is a reasonable prospect that these reserves are commercial. Where such reserves exist, the costs of unsuccessful appraisal wells may remain capitalised where further appraisal of the discovery is planned. If this further appraisal does not lead to the discovery of commercial reserves, all these costs should be written off. 54. After appraisal, if commercial reserves are found then the net capitalised costs incurred in discovering the field should be transferred into a single field cost centre. Any subsequent development costs, including, if desired, the costs of dry delineation and other dry development wells, should be capitalised in this cost centre. 55. All other costs should be expensed as incurred including operating and production-related costs, such as tariffs and royalties, and also administrative and other general overhead costs not directly attributable to the activities referred to in paragraph Unless further appraisal of the prospect is firmly planned or underway, expenditure incurred on exploration and appraisal activities may be carried forward pending determination for a maximum of three years following completion of drilling in an offshore or frontier environment where major development costs may need to be incurred or for a maximum of two years in other areas. In exceptional circumstances, these time limits may be inappropriate but, having regard to the intent of successful efforts accounting, any undetermined costs carried forward beyond these limits should be disclosed. Costs capitalised pending determination of whether or not they have found commercial reserves are, where accounted for in accordance with this statement, specifically exempt from the detailed rules for assessing impairment set out in FRS Subsequent to the appraisal of a field, expenditure incurred in establishing commercial reserves may be carried forward only as long as there exists a clear intention to develop the field. The inclusion of a field development plan within the company s overall business plan would be evidence of such intention. 58. All exploration and development expenditure should be capitalised as additions to fixed assets in the period in which it is incurred. This includes expenditure which is subsequently written off during that period. 59. Exploration and appraisal expenditure on a property should be classified in the financial statements as intangible assets-exploration expenditure, pending evaluation. When the existence of commercial reserves is established, directly related exploration and appraisal expenditure should be reclassified in the financial statements under the heading tangible assets. Subsequent field development costs should be classified as tangible assets. Subsequent expenditure 60. FRS 15 states, in paragraph 34 that subsequent expenditure to ensure the tangible fixed asset maintains its previously assessed standard of performance should be recognised in the profit and loss account as it is incurred. Subsequent expenditure should be capitalised where it enhances the economic benefits of the tangible fixed assets. An example in the oil and gas industry is where expenditure is associated with additional oil and gas reserves or allows accelerated production. Expenditure relating to workovers should be reviewed on a case by case basis and capitalised only if it enhances the original performance of the tangible fixed asset. Finance costs 61. Finance costs may be capitalised in accordance with the rules set out in FRS 15 Tangible Fixed Assets.
17 Bottom hole contributions 62. Bottom hole contributions involve a payment to an operator as a contribution to the cost of drilling a well on a licence in which the contributor has no property interest, in exchange for information on the results of the well. The contributions are normally payable when the well reaches a predetermined depth, irrespective of whether it is successful or otherwise. 63. The contributor should account for the cost as it would for other preproduction costs. The company receiving the contribution should credit the receipt against the cost of the well. Capitalisation of future decommissioning costs provided 64. The future cost of decommissioning an installation, provided for in accordance with paragraphs 89 to 99 of this statement, should be regarded as part of the total investment to gain access to future economic benefit. Thus a decommissioning asset should be established and should be included as part of the overall cost pool or field cost centre. 65. The decommissioning asset should be recognised and capitalised as the related facilities are installed, simultaneously with the recognition of the provision, and in the phased manner described in paragraph 94 of this statement where appropriate. The incremental amount capitalised on each phase of installation should equal the incremental amount provided in respect of each phase. 66. Where a decommissioning asset has previously been recognised, a change in provision due to a change in the estimate or the assumptions underlying it should be treated as an adjustment to the decommissioning asset included within the overall cost pool or field cost centre. 67. In exceptional circumstances, an adjustment to the decommissioning provision for a facility may reduce the overall net book value of the cost pool or field cost centre to below zero. In such cases, the amount of the adjustment which would otherwise have given rise to a PART 3: RECOMMENDED PRACTICE negative net book value should be taken to the profit and loss account. Depreciation Full cost companies 68. All expenditure carried within each cost pool should be depreciated on a unit-of-production basis by reference to quantities. 69. The depreciation charge should be calculated on a pool-by-pool basis, using the ratio of oil and gas production in the period to the estimated quantity of commercial reserves at the end of the period plus the production in the period. Where both oil or gas or other hydrocarbons exist in material quantities it is necessary to use an appropriate conversion factor so that aggregate reserves and production can each be expressed in a common unit. The figures both for production and commercial reserves should consistently either include or exclude any quantities of oil or gas consumed in operations. 70. The cost element of the unit-of-production calculation should be the costs incurred to date together with the estimated future development costs of obtaining access to all the reserves included in the unit-ofproduction calculation. Thus it should represent the net book amount of capitalised costs incurred to date, plus the anticipated future field development costs which should be stated at current period-end unescalated prices. 71. Future decommissioning costs capitalised as part of the cost of the related installation should be depreciated on a unit-of production basis in the same way as other costs capitalised within the pool. 72. Changes in cost and reserve estimates do not give rise to prior year adjustments. Where estimates are revised, the carrying amount should be depreciated using the revised estimates from the date of the revision.
18 PART 3: RECOMMENDED PRACTICE Successful efforts companies 73. Licence acquisition costs which have not been allocated should be depreciated over a maximum period of the licence. The net book amount of undepreciated licence acquisition costs should be reviewed annually for impairment on a property-by-property basis. Any impairment identified should be written off. Costs capitalised pending determination of whether or not they have found commercial reserves are, where accounted for in accordance with this statement, specifically exempt from the detailed rules for assessing impairment set out in FRS All expenditure carried within each field should be depreciated on a unit-of-production basis by reference to quantities. The basis should be the ratio of oil and gas production in the period to the estimated quantity of commercial reserves on a field-by-field basis at the end of the period plus the production in the period. Where both oil and gas or other hydrocarbons exist in material quantities it is necessary to use an appropriate conversion factor so that aggregate reserves and production can each be expressed in a common unit. The figures both for production and commercial reserves should consistently either include or exclude any quantities of oil or gas consumed in operations. 75. The cost element of the unit-of-production calculation should be the costs incurred to date together with the estimated future development costs of obtaining access to all the reserves included in the unit-ofproduction calculation. Thus it should represent the net book amount of capitalised costs incurred to date, plus the anticipated future field development costs which should be stated at current period-end unescalated prices. 76. Future decommissioning costs capitalised as part of the cost of the related installation should be depreciated on a unit-of-production basis in the same way as other capitalised costs. 77. Changes in cost and reserve estimates do not give rise to prior year adjustments. Where estimates are revised, the carrying amount should be depreciated using the revised estimates from the date of the revision. Impairment tests Full cost companies 78. An impairment test should be carried out if events or changes in circumstances indicate that the net book amount of expenditure within each cost pool, less any provisions for decommissioning costs and deferred production or revenue-related taxes 2, may not be recoverable from the anticipated future net revenue from oil and gas reserves attributable to the company s interest in that pool. Since, under the full cost method, the pool is the recorded asset for Companies Act purposes and should be defined so as to qualify as an income generating unit for the purposes of FRS 11, the test should be carried out on a pool-by-pool basis. Costs held outside the cost pools are subject to a separate review for impairment, as set out in paragraph 45above. 79. In undertaking calculations for the purposes of impairment tests, the following rules shall apply: (a) cash flow projections should be prepared showing the estimated revenues from production of reserves together with future operating costs, future production or revenue-related taxes (including PRT), future insurance and royalties, future development costs and decommissioning costs. See paragraph 184 if a future redetermination of field interests is anticipated. A deduction should be made to reflect any quantities included as reserves which are expected to be consumed in operations. General financing costs and taxation on profits (including UK corporation tax) should not be included in the projections; 2 Provisions for deferred income taxes attributable to the field should not be deducted.
19 PART 3: RECOMMENDED PRACTICE (b) prices and cost levels used should be those expected to apply in future periods, rather than those ruling at the date the impairment test is applied; and (iv) if cash flows are estimated using prices expected to apply in future periods, the discount rate should be a nominal one (i.e. also reflecting price increases). (c) either the estimates of future cash flows should be directly adjusted to reflect the risks, or appropriately risk adjusted discount rates should be applied to the cash flows. Where risk is reflected in the discount rate, estimates of future revenues and costs should each be discounted at a rate appropriate to that cash stream. In particular: (i) (ii) (iii) FRS 11 does not preclude the use of discount rates commonly used within the industry to value similar assets. However, the discount rates should be consistent with the other assumptions reflected in the impairment test; where specific cash flows within the projections are affected significantly by a specific risk or uncertainty unique to those cash flows, then it will generally be inappropriate to reflect this risk by adjusting the discount rate applied to net cash flows. To the extent that probable reserves are included in projected revenues and a risk adjustment to the discount rate is to be used to reflect uncertainty, it is inappropriate to apply this same risk adjusted rate to costs in the projections which are not expected to be affected by whether or not probable reserves are ultimately recovered; the discount rate applied for impairment test purposes in calculating the present value of future cash flows relating to decommissioning should be consistent with the rate used in the measurement of the decommissioning provision under paragraphs 92 and 93 of this statement. This rate may differ from the rate used to discount future net revenues, reflecting the differing risk profiles of those cash flows. Alternatively, the decommissioning cash flows and the related balance sheet provision may be removed from the impairment test; and (d) paragraph 38 of FRS 11 requires the costs and benefits of future capital expenditure to be excluded only to the extent that the expenditure will improve the fields which comprise the pool in excess of their originally assessed standard of performance. This requirement does not prevent oil and gas exploration companies from taking account of future capital expenditure required to fully exploit the reserves estimated to be present at the time of developing a new field, or in developing an identified field extension. There must be clear evidence that the development plan pre existed the indication of impairment. 80. A deficiency identified as the result of an impairment test must be provided and charged in the current period as additional depreciation and taxation provisions should be adjusted as appropriate. In certain circumstances the additional depreciation may need to be disclosed as an exceptional item. The disclosure requirements associated with an impairment are set out in paragraphs of FRS 11 'Impairment of Fixed Assets and Goodwill'. 81. If there is a change in economic conditions or in the expected use of an asset that reverses a previous impairment, the asset s value should be restored in the balance sheet in accordance with the FRS. The asset s value should not be restored if the increase in value arises simply because of the passage of time or the occurrence of previously forecast cash outflows. Successful efforts companies 82. An impairment test should be carried out if events or changes in circumstances indicate that the net book amount of expenditure within each cost centre, less any provisions for decommissioning costs and deferred production or revenue-related taxes 3, may not be 3 Provisions for deferred income taxes attributable to the field should not be deducted.
20 recoverable from the anticipated future net revenue from oil and gas reserves attributable to the company s interest in that field. Since, under successful efforts accounting, the field is the recorded asset for Companies Act purposes, the test should generally be carried out on a field-by-field basis. In certain circumstances, for example where two or more fields use common production and transportation facilities, those fields may be sufficiently economically interdependent to constitute a single income generating unit for the purposes of FRS 11, in which case impairment test should be performed in aggregate for those fields. Costs held pending determination are subject to a separate review for impairment, as set out in paragraph 56 above. 83. In undertaking calculations for the purposes of impairment tests, the following rules shall apply: (a) cash flow projections should be prepared showing the estimated revenues from production of reserves together with future operating costs, future production or revenue-related taxes (including PRT), future insurance and royalties, future development costs and decommissioning costs. See paragraph 184 if a future redetermination of field interests is anticipated. A deduction should be made to reflect any quantities included as reserves which are expected to be consumed in operations. General financing costs and taxation on profits (including UK corporation tax) should not be included in the projections; (b) prices and cost levels used should be those expected to apply in future periods, rather than those ruling at the date the impairment test is applied; and (c) either the estimates of future cash flows should be directly adjusted to reflect the risks, or appropriately risk adjusted discount rates should be applied to the cash flows. Where risk is reflected in the discount rate, estimates of future revenues and costs should each be discounted at a rate appropriate to that cash stream. In particular: (i) FRS 11 does not preclude the use of discount rates commonly used within the industry to value similar (ii) (iii) (iv) PART 3: RECOMMENDED PRACTICE assets. However, the discount rate should be consistent with the other assumptions reflected in the impairment test; where specific cash flows within the projections are affected significantly by a specific risk or uncertainty unique to those cash flows, then it will generally be inappropriate to reflect this risk by adjusting the discount rate applied to net cash flows. To the extent that probable reserves are included in projected revenues and a risk adjustment to the discount rate is to be used to reflect uncertainty, it is inappropriate to apply this same risk adjusted rate to costs in the projections which are not expected to be affected by whether or not probable reserves are ultimately recovered; the discount rate applied for impairment test purposes in calculating the present value of future cash flows relating to decommissioning should be consistent with the rate used in the measurement of the decommissioning provision under paragraphs 92 and 93 of this statement. This rate may differ from the rate used to discount future net revenues, reflecting the differing risk profiles of those cash flows. Alternatively, the decommissioning cash flows and the related balance sheet provision may be removed from the impairment test; and if cash flows are estimated using prices expected to apply in future periods, the discount rate should be a nominal one (i.e. also reflecting price increases). (d) paragraph 38 of FRS 11 requires the costs and benefits of future capital expenditure to be excluded only to the extent that the expenditure will improve the fields which comprise the pool in excess of their originally assessed standard of performance. This requirement does not prevent oil and gas exploration companies from taking account of future capital expenditure required to fully exploit the reserves estimated to be present at the time of developing a new field, or in developing an identified field extension. There must be clear evidence that the development plan pre existed the indication of impairment.
CONSOLIDATED AND COMPANY INCOME STATEMENTS FOR THE YEAR ENDED 31 MARCH (IN THOUSANDS OF US$) Year ended 31 March Company Year ended 31 March Note Revenue 5 93,303 50,243 1,584 2,122 Cost of sales 6 (70,147)