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NBAA-The Financial Reporting on Oil and Gas-A reflection.pptx NBAA SEMINAR.pptx 2

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NBAA-The Financial Reporting on Oil and Gas-A reflection.pptx NBAA SEMINAR.pptx 2

  2. 2. 1: NATURAL GAS VALUE CHAIN| BUSINESS MODEL Upstream Downstream Support services Exploration Production Trading Intake Refining Trading Transportation Marketing & Sales Supply chain management Financing Headquarter & back office services Engineering M a f w e n g a H a n d l e y @ 2 0 1 4
  5. 5. 2: SECTOR-SPECIFIC ACCOUNTING ISSUES FOR IFRS CONVERSION Why These Issues are Significant to Oil and Gas They may be pervasive across the sector and will require significant time and cost to evaluate and implement; Conversion may have a significant impact on information systems, accounting processes and systems. 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.
  6. 6. A: UP STREAM ACTIVITIES : 3: RESERVES AND RESOURCES In order to achieve sustainable natural gas supply, upstream activities need to be aligned with mid and downstream activities. Resources are volumes of oil and gas estimated to be present in the ground, which may or may not be economically recoverable. Reserves are resources anticipated to be commercially recovered from known accumulations from a specific date. Entities record reserves at the historical cost of finding and developing reserves or acquiring them from third parties. The cost of finding and developing reserves is not directly related to the quantity of reserves. Natural resources are outside the scope of IAS 16 “Property, Plant and Equipment” and IAS 38 “Intangible Assets”. The IASB considers the accounting for mineral resources and reserves as part of its Extractive Activities project.
  7. 7. 3.1: RESERVES REPORTING [Proved and Unproved Reserves] PROVED RESERCES [estimated quantities of reserves that, based on geological and engineering data, appear reasonably certain to be recoverable in the future from known oil and gas reserves under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made.] and operating conditions, i.e., prices and costs as of the date the estimate is made. PROVED DEVELOPED [Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods] PROVED UNDEVELOPED [Reserves that are expected to be recovered from new wells on undrilled proved acreage or from existing wells where relatively major expenditure is required before the reserves are extracted] UNPROVED RESERVES [Reserves those technical or other uncertainties preclude from being classified as proved] PROBABLE RESERVES [Additional reserves that are less likely to be recovered than proved reserves but more certain to be recovered than possible reserves] POSSIBLE RESERVES [Additional reserves that analysis of geoscience and engineering data suggest are less likely to be recoverable than probable reserves] NOTE: Disclosure of Reserves and Resources In line with the IAS 1 “Presentation of Financial Statements” [IAS 1 para 17] many entities provide supplemental information with the financial statements because of the unique nature of the oil and gas industry and the clear desire of investors and other users of the financial statements to receive information about reserves. The information is usually supplemental to the financial statements, and is not covered by the auditor‟s opinion.
  8. 8. 3.2: CAPITALIZATION AND EXPENSING OF COSTS Exploration costs are incurred to discover hydrocarbon resources. Evaluation costs are incurred to assess the technical feasibility and commercial viability of the resources found. Exploration, as defined in IFRS 6 “Exploration and Evaluation of Mineral Resources”, starts when the legal rights to explore have been obtained. Expenditure incurred before obtaining the legal right to explore is generally expensed in the period in which they are incurred. Once the legal right to explore has been acquired, costs directly associated with an exploration well are capitalised as exploration and evaluation intangible assets until the drilling of the well is complete and the results have been evaluated. These costs include directly attributable employee remuneration, materials and fuel used, rig costs and payments made to contractors. Costs incurred in finding, acquiring and developing reserves are typically capitalised on a field-by-field basis as production occurs. Capitalised costs are allocated to commercially viable hydrocarbon reserves. Failure to discover commercially viable reserves means that the expenditure is charged to expense. Capitalised costs are depleted on a field-by-field basis
  9. 9. FULL COST VS SUCCESSFUL EFFORTS FULL COST SUCCESSFUL EFFORTS In some upstream companies, all costs associated with exploring for and developing oil and gas resources [All costs incurred in searching for, acquiring and developing the reserves in a large geographic cost centre] under local GAAP are capitalized irrespective of the success or failure of specific parts of the overall exploration activity. The costs are accumulated in cost centres [cost pool-A cost centre or pool is typically a country.] The costs in each cost pool are written off against income arising from production of the reserves attributable to that pool Exploration expenditure which are general in nature are charged to the P&L A/c and that which relates to unsuccessful drilling operations though initially capitalized pending determination is subsequently written-off. Costs that relate directly to the discovery and development of specific commercial oil and gas reserves will remain capitalized to the depreciated over the lives of these reserves Exploration activities should be viewed as part of an overall effort in a defined area The Exploration activities should be viewed as separate efforts to locate commercial reserves The total costs of both successful and unsuccessful activities are spread over total production from each pool [If exploration efforts in the country or the geological formation are wholly unsuccessful, the costs are expensed]. Results in a greater deferral of costs during exploration and development and higher subsequent depletion charges. Therefore, does not apply to the discontinued operations due to difference in tracking and allocation of costs. The costs of individually unsuccessful efforts are usually written-off earlier in the F/S but greater reported profits will be shown once production starts. Exploration, evaluation and development expenditure is preferably accounted for using the successful efforts method of accounting. 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 recognized earlier
  10. 10. 3.2: CAPITALIZATION AND EXPENSING OF COSTS Debate continues within the industry on the conceptual merits of both methods although neither is wholly consistent with the IFRS framework. The IASB published IFRS 6 „Exploration for and Evaluation of Mineral Resources‟ to provide an interim solution for E&E costs pending the outcome of the wider extractive activities project. Entities transitioning to IFRS can continue applying their current accounting policy for E&E. IFRS 6 does not apply to costs incurred once E&E is completed. The period of shelter provided by the standard is a relatively narrow one, and the componentisation principles of IAS 16 and impairment rules of IAS 36 prevent the continuation of full cost past the E&E phase. The successful efforts method is seen as more compatible with the Framework. Specific transition relief has been included in IFRS 1 “First-time adoption of IFRSs” to help entities transition from full cost accounting under previous GAAP to successful efforts under IFRS. Can an entity make changes to its policy for capitalising exploration and evaluation expenditures when it first adopts IFRS?
  11. 11. 3.2: CAPITALIZATION AND EXPENSING OF COSTS ANSWER: No ! IFRS 6 restricts changes in accounting policy to those which make the policy more reliable and no less relevant or more relevant and no less reliable. One of the qualities of relevance is prudence. Capitalising more costs than under the previous accounting policy is less prudent and therefore is not more relevant. An entity can change its accounting policy for E&E only if the change results in an accounting policy that is closer to the principles of the Framework [IFRS 6 para 13]. The change must result in a new policy that is more relevant and no less reliable or more reliable and no less relevant than the previous policy. The criteria used to determine if a policy is relevant and reliable are those set out in paragraph 10 of IAS 8. That is, it must be: Relevant to decision making needs of users; Provide a faithful presentation; Reflect the economic substance; Neutral i.e. free from bias; Prudent; and Complete
  12. 12. Initial Recognition of Exploration and Evaluation Under IFRS 6 Exemption and Framework
  13. 13. 3.2: CAPITALIZATION AND EXPENSING OF COSTS Costs incurred after probability of economic feasibility is established are capitalised only if the costs are necessary to bring the resource to commercial production. Subsequent expenditures should not be capitalised after commercial production commences, unless they meet the asset recognition criteria. Tangible/Intangible Classification Exploration and evaluation assets are recognised and classified as either tangible or intangible according to their nature [IFRS 6 para 15]. A Test Well however, is normally considered to be a tangible asset. The revaluation model can only be applied to intangible assets if there is an active market in the relevant intangible assets. Some companies will initially capitalise exploration and evaluation assets as intangible and, when the development decision is taken, reclassify all of these costs to “Oil and gas properties” within PPE. Some capitalise exploration expenditure as an intangible asset and amortise this on a straight line basis over the contractually established period of exploration. Others capitalise exploration costs as “tangible” within “Construction in progress” or PPE from commencement of the exploration.
  14. 14. 3.2: CAPITALIZATION AND EXPENSING OF COSTS Subsequent Measurement of E&E Assets Exploration and evaluation assets can be measured using either the cost model or the revaluation model as described in IAS 16 and IAS 38 after initial recognition [IFRS 6 para 12]. In practice, most companies use the cost model. Depreciation and amortisation of E&E assets usually does not commence until the assets are placed in service. Some entities choose to amortise the cost of the E&E assets over the term of the exploration licence. Reclassification Out of E&E under IFRS 6 E&E assets are reclassified from Exploration and Evaluation when evaluation procedures have been completed [IFRS 6 para 17]. E&E assets for which commercially-viable reserves have been identified are reclassified to development assets. E&E assets are tested for impairment immediately prior to reclassification out of E&E [IFRS 6 para 17].
  15. 15. 3.2: CAPITALIZATION AND EXPENSING OF COSTS M a f w e n g a H a n d l e y @ 2 0 1 4
  16. 16. Reclassification Out of E&E Under IFRS 6
  17. 17. Depreciation Impairments Depletion 4.0: DEPRECIATION, IMPAIRMENTS, DEPLETION AND AMORTIZATION Accounting process of allocating the cost of tangible assets to expense in a systematic and rational manner to those periods expected to benefit from the use of the asset. This is when the carrying amount of an asset is not recoverable, a company records a write-off This is the process of allocating the cost of natural resources which involves four factors of computation: 1. Acquisition cost. 2. Exploration costs 3. Development Costs 4. Restoration costs Events leading to impairment: 1. Significant decrease in the fair value of an asset. 2. Significant change in the manner in which an asset is used. 3. Adverse change in legal factors or in the business climate. 4. An accumulation of costs in excess of the amount originally expected to acquire or construct an asset. 5. A projection or forecast that demonstrates continuing losses associated with an asset. This is where we are allocating costs of long- term intangible assets Amortization
  18. 18. Depreciation, Impairments, Depletion and Amortization
  20. 20. 6.0: JOINT ARRANGEMENT STRUCTURE [IFRS 11] There are only two types of joint arrangements under IFRS 11 – a joint operation or a joint venture. A joint operation is defined as a joint arrangement whereby the parties that have joint control of the arrangement have rights to the assets, and obligations for the liabilities, relating to the arrangement. A joint venture is defined as a joint arrangement whereby the parties that have joint control of the arrangement have rights to the net assets of the arrangement. Production Sharing Agreements [PSA]
  22. 22. 6.0: JOINT ARRANGEMENT STRUCTURE [IFRS 11] Production Sharing Agreements Tanzania's Model PSA serves as the basic document for negotiations between foreign oil companies, the Government and TPDC. It sets out the terms under which exploration and production can take place. Although the terms - which are internationally competitive -mirror closely those incorporated in earlier PSA's concluded in Tanzania, the Government's flexible approach allows for the negotiation of the important issues (such as Area, Work Program and Economic terms etc.) within the framework of production sharing arrangements. The Government's objective is to negotiate terms with the oil industry which are fair and balanced, bearing in mind the usual risks associated with exploration and the State's legitimate desire for revenues as owner of a depleting, non-renewable, natural resource. The Government seeks to encourage the development of small and marginal discoveries; obtain a higher share of profits from the more attractive fields, and satisfy national objectives such as the transfer of petroleum skills and the acquisition of more data.
  23. 23. PRODUCTION SHARING AGREEMENTS Production Sharing is such that, the remaining volume after cost recovery shall be divided between TPDC and the oil company in the progressive proportions which are negotiable: Participation (Joint Operations) There is an option for TPDC to participate in development whereby it will contribute to Contract Expenses. The MPSA provides for TPDC to negotiate a participating interest at 20% of the Contract Expenses, excluding Exploration (and Appraisal) expenses. TPDC's Profit Oil Share will then be increased by the rate of the participating interest, and the Oil Company's Share will be reduced accordingly. PSA falls under Joint Arrangements which are entities. The parties to the PSA should account for their own assets and liabilities and cash flows; measured in accordance with the terms of the PSA. However, the accounting treatment of the assets, liabilities and cash flows arising under PSA should reflect the Agreement‟s commercial effect and not its structure.
  24. 24. Progressive Production Sharing Structure Cont…….. CRUDE OIL SHARE (QUARTERLY AVERAGE) TPDC SHARE OIL COMPANY 0 - 12,500 BOPD 50% 50% 12,501 - 25,000 BOPD 55% 45% 25,001 - 50,000 BOPD 60% 40% 50,001 - 100,000 BOPD 65% 35% >100,000 BOPD 70% 30%
  25. 25. 7.0: Development Expenditures Development expenditures are costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. An entity should develop an accounting policy for development expenditure based on the guidance in IAS 16, IAS 38 and the Framework. Much development expenditure results in assets that meet the recognition criteria in IFRS. Expenditure on the construction, installation or completion of infrastructure facilities such as platforms, pipelines and the drilling of development wells, including unsuccessful development or delineation wells, is capitalised within oil and gas properties. Development expenditures are capitalised to the extent that they are necessary to bring the property to commercial production. Entities should also consider the extent to which “abnormal costs” have been incurred in developing the asset. IAS 16 requires that the cost of abnormal amounts of labour or other resources involved in constructing an asset should not be included in the cost of that asset. Expenditures incurred after the point at which commercial production has commenced should only be capitalised if the expenditures meet the asset recognition criteria in IAS 16 or 38.
  26. 26. Overlift and underlift Pre-production sales Provisional pricing arrangements 9.0: REVENUE RECOGNITION IN UPSTREAM A sale of oil at the point of lifting by the underlifter to the overlifter. When the criteria for revenue recognition in IAS 18 “Para 14 are considered to be met. Overlift is a purchase of oil by the overlifter from the underlifter. The produced “test oil” from a development well prior to entering full production which his test oil may be sold to third parties and Where the test oil is considered necessary to the completion of the asset, the proceeds from sales are usually offset against the asset cost instead of being recognised as revenue within the income statement. This is a provisional pricing - at the date of delivery of the oil or gas, a provisional price may be charged. The final price is generally an average market price for a particular future period.The sale of oil by the underlifter to the overlifter should be recognised at the market price of oil at the date of lifting [IAS 18 para 9]. A Volumetric Production Payment (VPP) arrangement is a structured transaction that involves the owner of oil or gas interests selling a specific volume of future production from specified properties to a third party “investor” for cash. Underlift by a partner is an asset in the balance sheet and overlift is reflected as a liability. An underlift asset is the right to receive additional oil from future production without the obligation to fund the production of that additional oil. An overlift liability is the obligation to deliver oil out of the entity‟s equity share of future production The initial measurement of the overlift liability and underlift asset is at the market price of oil at the date of lifting,. Subsequent measurement depends on the terms of the JV agreement. JV agreements that allow the net settlement of overlift and underlift balances in cash falls scope of IAS 39 unless the „own use‟ exemption applies [IAS 39 para 5]. Forward-selling contracts to finance development Balances that fall within the scope of IAS 39 must be re-measured to the current market price of oil at the balance sheet date. The change arising from this re-measurement is included in the income statement as other income/expense rather than revenue or cost of sales. Overlift and underlift balances that do not fall within the scope of IAS 39 are measured at the lower of carrying amount and current market value. Any re-measurement should be included in other income/ expense rather than revenue or cost of sales
  27. 27. 9.0: REVENUE RECOGNITION IN UPSTREAM “Lifting or offtake arrangements for oil and gas produced in jointly owned operations are frequently such that it is not practicable for each participant to receive or sell its precise share of the overall production during the period. Any resulting short term imbalance between cumulative production entitlement and cumulative sales attributable to each participant at a reporting date represents overlift or underlift.” IFRS 6 does not specifically deal with the issue of accounting for under or overlift. However industry practice is also relevant in selecting accounting policies under IFRS. It is likely to be appropriate for entities adopting IFRS to account for under/overlifts Forward-selling contracts to finance development Oil and gas exploration and development is a capital intensive process and different financing methods have arisen. The buyer in a VPP may assume significant reserve and production risk and all, or substantially all, of the price risk. If future production from the specified properties is inadequate, the seller has no obligation to make up the production volume shortfall. Legally, a VPP arrangement is considered a sale of an oil or gas interest because ownership of the reserves in the ground passes to the buyer.
  28. 28. 9.0: REVENUE RECOGNITION IN UPSTREAM The seller in a VPP arrangement will deem that it has sold an oil and gas interest. Common practice would be to eliminate the related reserves for disclosure purposes. However, typically a gain is not recognised upon entering the arrangement because the seller remains obligated to lift the VPP oil or gas reserves for no future consideration. In these circumstances the seller records deferred revenue for all of the proceeds received and does not reduce the carrying amount of PP&E related to the specified VPP properties. The amount received is recorded as “deferred revenue” rather than a loan as the intention is that the amount due will be settled in the commodity rather than cash or a financial asset. Where no gain is recognised the seller will recognise the deferred revenue and deplete the carrying amount of PP&E related to the specified VPP properties as oil or gas is delivered to the VPP buyer. No production would be shown in the supplemental disclosures in relation to the VPP. The revenue arising from the sale under the VPP contract is recognised over the production life of the VPP.
  29. 29. 9.0: REVENUE RECOGNITION IN UPSTREAM Provisional pricing arrangements Revenue from the sale of provisionally priced commodities is recognised when risks and rewards of ownership are transferred to the customer, which would generally be the date of delivery. At this date, the amount of revenue to be recognised will be estimated based on the forward market price of the commodity being sold. The provisionally priced contracts are marked to market at each reporting date with any adjustments being recognised within revenue.
  30. 30. 10: DEPLETION, DEPRECIATION AND AMORTISATION (“DD&A”) Oil and gas properties are depreciated/amortised on a unit-of- production basis over the total proved developed and undeveloped reserves of the field concerned, except in the case of assets whose useful life is shorter than the lifetime of the field, in which case, the straight-line method is applied. Rights and concessions are depleted on the unit-of-production basis over the total proved developed and undeveloped reserves of the relevant area. The unit-of-production rate calculation for the depreciation/amortisation of field development costs takes into account expenditures incurred to date, together with sanctioned future development expenditure. Basic Depreciation, Depletion & Amortization Formula Production for the Year X book value at year end OR Estimated reserves at the beginning of the year Equivalent DD&A Formula Book Value X Production for the year Estimated reserves at the beginning of the year
  32. 32. B: MIDSTREAM AND DOWNSTREAM ACTIVITIES Cont…. Cost and Freight Vs Free On Board IAS 18 focuses on whether the entity has transferred to the buyer the significant risks and rewards of ownership of the goods as a key determination of when revenue should be recognised. Industry practice has been that the transfer of significant risks and rewards of ownership occurs when the good‟s have passed the ship‟s rail, and accordingly revenue will be recognised at that point even if the seller is still responsible for insuring the goods whilst they are in- transit. However, a full understanding of the terms of trade will be required to ensure that this is the case. Oilfield services Oilfield services companies provide a range of services to other companies within the industry. This can include performing geological and seismic analysis, providing drilling rigs and managing operations.
  33. 33. 2: REVENUE RECOGNITION IN MIDSTREAM AND DOWNSTREAM The contractual terms and obligations are key to determining how revenue from an oilfield services contract is recognised. An entity should define the contract, identify the performance obligations (and whether there are any project milestones) and understand the pricing terms. Where an entity provides drilling rigs, costs of mobilisation and demobilisation are one area where the terms of the contract must be clearly understood in order to conclude on the accounting treatment for costs incurred. Revenue recognition for the rendering of services often uses the percentage of completion method. Entities using this approach should be aware of any potential loss-making contracts and collectability issues – revenue can only be recognised to the extent of costs incurred which are recoverable. Entities providing oilfield services should consider whether their contracts fall within the scope of IAS 17
  34. 34. MIDSTREAM AND DOWNSTREAM ACTIVITIES Cont… Product exchanges Energy companies exchange crude or refined oil products with other energy companies to achieve operational objectives. A common term used to describe this is a “Buy-sell arrangement”. These arrangements are often entered to save transportation costs by exchanging a quantity of product A in location X for a quantity of product A in location Y. Variations on the quality or type of the product can sometimes arise,. Balancing payments are made to reflect differences in the values of the products exchanged where appropriate. The settlement may result in gross or net invoicing and payment. The nature of the exchange will determine if it is a like for-like exchange or an exchange of dissimilar goods. A like-for-like exchange does not give rise to revenue recognition or gains. An exchange of dissimilar goods results in revenue recognition and gains or losses. Crude oil and gas may need to be moved long distances and need to be of a specific type to meet refinery requirements. Entities may exchange product to meet logistical, scheduling or other requirements. The exchange of crude oil, even where the qualities of the crude differ, is usually treated as an exchange of similar products and accounted for at book value. Any balancing payment made or received to reflect minor differences in quality or location is adjusted against the carrying value of the inventory.
  35. 35. 2: REVENUE RECOGNITION IN MIDSTREAM AND DOWNSTREAM Emissions Trading Schemes The emission rights permit an entity to emit pollutants up to a specified level. The emission rights are either given or sold by the government to the emitter for a defined compliance period. The allowances are intangible assets and are recognised at cost if separately acquired. Allowances that are received free of charge from the government are recognised either at fair value with a corresponding deferred income (liability), or at cost (nil) as allowed by IAS 20 “Accounting for Government Grants and Disclosure of Government Assistance” [IAS 20 para 23]. The allowances recognised are not amortised if the residual value is at least equal to carrying value [IAS 38 para 100]. The cost of allowances is recognised in the income statement in line with the profile of the emissions produced. The government grant (if initial recognition at fair value under IAS 20 is chosen) is amortised to the income statement on a straight-line basis over the compliance period. An alternative to the straight-line basis, such as a units of production approach, can be used if it is a better reflection of the consumption of the economic benefits of the government grant.
  36. 36. 2: REVENUE RECOGNITION IN MIDSTREAM AND DOWNSTREAM The entity may choose to apply the revaluation model in IAS 38 Intangible Assets for the subsequent measurement of the emissions allowances. The revaluation model requires that the carrying amount of the allowances is restated to fair value at each balance sheet date, with changes to fair value recognised directly in equity except for impairment, which is recognised in the income statement [IAS 38 para 75 & 85-86]. A provision is recognised for the obligation to deliver allowances or pay a fine to the extent that pollutants have been emitted [IAS 37 para 14]. The allowances reduce the provision when they are used to satisfy the entity‟s obligations through delivery to the government at the end of the scheme year. However, the carrying amount of the allowances cannot reduce the liability balance until the allowances are delivered to the government. The provision recognised is measured at the amount that it is expected to cost the entity to settle the obligation. This will be the market price at the balance sheet date of the allowances required to cover the emissions made to date (the full market value approach) [IAS 37 (revised) para 37].
  37. 37. 2: REVENUE RECOGNITION IN MIDSTREAM AND DOWNSTREAM Depreciation of downstream assets Downstream phase assets are depreciated using a method that reflects the pattern in which the asset‟s future economic benefits are expected to be consumed. The depreciation is allocated on a systematic basis over an asset‟s useful life. The residual value and the useful lives of the assets are reviewed at least at each financial year-end and, if expectations differ from previous estimates the changes are accounted for as a change in an accounting estimate in accordance with IAS 8 Accounting Policies, Changes in Accounting Estimates and Errors. Downstream assets such as refineries are often depreciated on a straight line basis over the expected useful lives of the assets. An alternative approach is using a throughput basis. For example, for pipelines used for transportation depreciation can be calculated based on units transported during the period as a proportion of expected throughput over the life of the pipeline. IFRS has a specific requirement for „component‟ depreciation, as described in IAS 16. Each significant part of an item of property, plant and equipment is depreciated separately [IAS 16 para 43-44].
  38. 38. 2: REVENUE RECOGNITION IN MIDSTREAM AND DOWNSTREAM Cost of turnaround/overhaul The costs of performing a major turnaround/overhaul are capitalised if the turnaround gives access to future economic benefits. Such costs will include the labour and materials costs of performing the turnaround. However, turnaround/overhaul costs that do not relate to the replacement of components or the installation of new assets should be expensed as incurred [IAS16 para 12]. Turnaround/overhaul costs should not be accrued over the period between the turnarounds/overhauls because there is no legal or constructive obligation to perform the turnaround/overhaul – the entity could choose to cease operations at the plant and hence avoid the turnaround/overhaul costs.
  39. 39. 3. FINANCIAL INSTRUMENTS Every Oil and Gas entity is exposed to business risks from its daily operations which have an impact on the cash flows or the value of assets and liabilities, and therefore, ultimately affect profit or loss. In order to manage these risk exposures, companies often enter into derivative contracts (or, less commonly, other financial instruments) to hedge them. Hedging can, therefore, be seen as a risk management activity in order to change an entity‟s risk profile including other exposures such as currency fluctuations. 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 re 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.
  40. 40. 3. FINANCIAL INSTRUMENTS Applying the normal IFRS accounting requirements to those risk management activities can then result in accounting mismatches, when the gains or losses on a hedging instrument are not recognised in the same period(s) and/or in the same place in the financial statements as gains or losses on the hedged exposure. The idea of hedge accounting is to reduce this mismatch by changing either the measurement or (in the case of certain firm commitments) recognition of the hedged exposure, or the accounting for the hedging instrument. IFRS 9 distinguishes between the risk management strategy and the risk management objective: The risk management strategy for example could identify changes in interest rates of loans as a risk and define a specific target range for the fixed to floating rate ratio for those loans. IFRS 7 Financial Instruments: Disclosures that should allow users of the financial statements to understand the risk management activities of an entity and how they affect the financial statements
  41. 41. 3. FINANCIAL INSTRUMENTS The risk management objective, on the contrary, is set at the level of an individual hedging relationship and defines how a particular hedging instrument is designated to hedge a particular hedged item. For example, this would define how a specific interest rate swap is used to „convert‟ a specific fixed rate liability into a floating rate liability. Hence, a risk management strategy would usually be supported by many risk management objectives. As with IAS 39, the item being hedged must still be reliably measurable. Also unchanged from IAS 39, a forecast transaction must be highly probable. However, what has changed in IFRS 9, compared to IAS 39, is how hedged items are designated in a hedging relationship. In particular, the designation of risk and nominal components and the designation of aggregated exposures and groups of items have changed. These changes, which should ultimately lead to more risk management activities qualifying for hedge accounting, all stem from the broader goal of the hedge accounting project, to better align an entity‟s risk management approach with the accounting outcome.
  42. 42. 3. FINANCIAL INSTRUMENTS The effective date of IFRS 9 is periods beginning on or after 1 January 2013 superseded the requirements of IAS 39 Financial Instruments: Recognition and Measurement on the classification and measurement of financial assets. 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.
  43. 43. CHALLENGES Projects under PPP arrangements have been implemented in the petroleum and natural gas-sub sector. However, the Government has experienced challenges in such projects including risks sharing mechanisms and insignificant benefits coupled with Disclosure requirements pertaining to accounting standards Does the prevailing legal and institutional framework support transparency and accountability? What information is published about the complex and lucrative resource sector? What safeguards are in place to promote integrity in its governance? Finally, is the broader institutional environment conducive to accountable resource governance? Changes in one component can affect governance as a whole. [State owned companies; natural resource funds and play crucial role in Governance issues; Lack of skills and knowledge in Oil and gas i.e inadequate professional capacity in geology, law, taxation, accounting and other related expertize.
  44. 44. THANK YOU