1.1 Basis of preparation

The group consolidated and the company’s financial statements have been prepared in accordance with the Norwegian Accounting Act and International Financial Reporting Standards (IFRS) as adopted by the EU.

The financial statements have been prepared on a historical cost basis with the exception of the following accounting items:

• Financial instruments at fair value through profit or loss.
• Loans, receivables and other financial liabilities, which are recognized at amortized cost.

The financial statements have been prepared using uniform accounting principles for equivalent transactions and events taking place on otherwise equal terms.

There have been certain changes in the presentation of the line items in the Income statement since 2015. Accretion expenses is now included in the line item other financial expenses, while it has been presented as interest expenses prior to 2016. In addition, following the change from defined benefit to defined contribution scheme, pension is no longer presented on a separate line in the Statement of financial position. Comparable figures have been restated accordingly.

All amounts have been rounded to the nearest thousand unless otherwise stated. As a result of rounding adjustments, the figures in one or more rows or columns included in the financial statements and notes may not add up to the total of that row or column.

1.2 Functional currency and presentation currency

The functional currency of Aker BP ASA and the presentation currency of the group is USD.

1.3 Important accounting judgments, estimates and assumptions

The preparation of financial statements in accordance with IFRS requires management to make judgments, estimates and assumptions that have an effect on the application of accounting principles and on recognized amounts relating to assets and liabilities, to provide information relating to contingent assets and liabilities on the date of the Statement of financial position, and to report revenues and expenses in the course of the accounting period.

The important judgments management has made on the application of accounting principles relate to the following:

Goodwill allocation and methodology for impairment testing: For the purpose of impairment testing, goodwill is allocated to cash-generating unit (CGU), or groups of cash-generating units, that are expected to benefit from the synergies of the business combination from which it arose. The appropriate allocation of goodwill requires management's judgment and may impact the subsequent impairment charge significantly. Technical goodwill is a category of goodwill arising as an offsetting account to deferred tax in business combinations, as described in Section 1.8 below. There are no specific IFRS guidelines pertaining the allocation of technical goodwill, and management has therefore applied the general guidelines for allocating goodwill for the purpose of impairment testing. In general, technical goodwill is allocated to CGU level for impairment testing purposes, while residual goodwill may be allocated across all CGUs based on facts and circumstances in the business combination.

When performing the impairment test for technical goodwill, deferred tax recognized in relation to the acquired licences reduces the net carrying value prior to the impairment charges. This is done to avoid an immediate impairment of all technical goodwill. When deferred tax from the initial recognition decreases, more goodwill is as such exposed for impairment. Going forward, depreciation of values calculated in the purchase price allocation will result in decreased deferred tax liability.

On selling a licence where the company historically has recognized deferred tax and goodwill in a business combination, both goodwill and deferred taxes from the acquisition are included when calculating gain/loss. When recording impairment of such licences as a result of impairment testing, the same assumptions are applied when measuring the impairment. This avoids a gross up of the impairment with tax, in that the impairment charged to the Income statement will not be higher than the original post-tax amount paid in the business combination.

Accounting estimates are used to determine reported amounts, including the possibility of realizing certain assets, the expected useful life of tangible and intangible assets, the tax expense, etc. Even though these estimates are based on management’s best judgment and assessment of previous and current events and actions, the actual results may deviate from the estimates. The estimates and underlying assumptions are reviewed regularly. Changes to the estimates are recognized when new estimates can be determined with sufficient certainty. Changes to accounting estimates are recognized in the period when they arise. The main sources of uncertainty when using estimates for the company relate to the following:

Proven and probable oil and gas reserves: Oil and gas reserves are estimated by the company’s experts in accordance with industry standards. The estimates are based on Aker BP’s own assessment of internal information and information received from the operators. In addition, reserves are certified by an independent third party. Proven and probable oil and gas reserves consist of the estimated quantities of crude oil, natural gas and condensates shown by geological and technical data to be recoverable with reasonable certainty from known reservoirs under existing economic and operational conditions, i.e. on the date that the estimates are prepared. Current market prices are used in the estimates, except for existing contractual future price changes.

Proven and probable reserves and production volumes are used to calculate the depreciation of oil and gas fields by applying the unit-ofproduction methodology. Reserve estimates are also used as basis for impairment testing of licence-related assets. Changes in petroleum prices and cost estimates may change reserve estimates and accordingly economic cut-off, which may impact the timing of assumed decommissioning and removal activities. Changes to reserve estimates can also be caused by updated production and reservoir information. Future changes to proven and probable oil and gas reserves can have a material effect on depreciation, life of field, impairment of licence-related assets, and operating results.

Successful Effort Method - exploration: Aker BP’s accounting policy is to temporarily recognize expenses relating to the drilling of exploration wells in the Statement of financial position as capitalized exploration expenditures, pending an evaluation of potential oil and gas discoveries. If resources are not discovered, or if recovery of the resources is considered technically or commercially unviable, the costs of exploration wells are expensed. Decisions as to whether this expenditure should remain capitalized or be expensed during the period, may materially affect the operating result for the period.

Acquisition costs: Expenses relating to the acquisition of exploration licences are capitalized and assessed for impairment if there are indications of impairment. See Items 1.11 and 1.12 for further details.

Fair value measurement: From time to time, the fair values of non-financial assets and liabilities are required to be determined, e.g. when the entity acquires a business, determines allocation of purchase price in an asset deal or where an entity measures the recoverable amount of an asset or CGU at fair value less cost to sell. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value of an asset or a liability is measured using the assumptions that market participants would use when pricing the asset or liability, assuming that market participants act in their economic best interest.

A fair value measurement of a non-financial asset takes into account a market participant's ability to generate economic benefits by using the asset in its highest and best use or by selling it to another market participant that would use the asset in its highest and best use. The group uses valuation techniques that are appropriate in the circumstances and for which sufficient data are available to measure fair value, maximizing the use of relevant observable inputs and minimizing the use of unobservable inputs. The fair value of oil fields in production and development phase is normally based on discounted cash flow models, where the determination of the different input in the model requires significant judgment from management, as described in the section below regarding impairment.

Impairment/reversal of impairment: Aker BP has significant investments in long-lived assets. Changes in the expected future value/cash flow of individual assets can result in the book value of some assets being impaired to estimated recoverable value. Impairment losses other than those relating to goodwill must be reversed if the conditions for the impairment are no longer present. Considerations regarding whether an asset is actually impaired or whether the impairment losses should be reversed can be complicated and are based on judgement and assumptions. The complexity of the issue can, for example, relate to the modelling of relevant future cash flows to determine the asset’s value in use, decide on measurement units and establish the asset’s net sales value.

The evaluation of impairment requires long-term assumptions concerning a number of often volatile economic factors, including future oil prices, oil production, currency exchange rates and discount rates. Such assumptions require the estimation of relevant factors such as forward price curves (oil), long-term price assumptions, the level of capex and opex, production estimates and residual asset values. Likewise, establishing an asset’s net sales value requires careful assessment unless information about net sales value can be obtained from an actual observable market. See Note 14 ’Property, plant and equipment and intangible assets’ and Note 15 ’Impairment of goodwill and other assets’ for details about impairment.

Decommissioning and removal obligations: The company has considerable obligations relating to decommissioning and removal of offshore installations at the end of the production period. Obligations associated with decommissioning and removal of long-term assets are recognized at present value of future expenditures on the date they are incurred. At the initial recognition of an obligation, the estimated cost is capitalized as production plant and depreciated over the useful life of the asset (typically by unit-of-production). It is difficult to estimate the costs for decommissioning and removal at initial recognition as these estimates are based on currently applicable laws and regulations, and are dependent on technological developments. Many decommissioning and removal activities will take place in the distant future, and the technology and related costs are constantly changing. The estimates include costs based on expected removal concepts based on known technology and estimated costs of maritime operations, hiring of heavy-lift barges and drilling rig. As a result, the initial recognition of the obligation in the accounts, the related costs capitalized in the Statement of financial position for decommissioning and removal and subsequent adjustment of these items, involve careful consideration. Based on the described uncertainty, there may be significant adjustments in estimates of liabilities that can affect future financial results. See Note 22 for further details about decommissioning and removal obligations.

Income tax: The company may incur significant amounts of income tax payable or receivable, and recognizes significant changes to deferred tax or deferred tax assets. These figures are based on management’s interpretation of applicable laws and regulations, and on relevant court decisions. The quality of these estimates is highly dependent on management’s ability to properly apply a complex set of rules and identify changes to the existing legal framework. See Note 12 for details about the deferred tax and taxes payable.

1.4 Foreign currency transaction

Transactions and balances

Transactions in foreign currencies are translated using the exchange rate on the transaction date. Monetary items in foreign currencies in the Statement of financial position are translated using the exchange rates at the end of the period. Foreign exchange gains and losses are recognized on an ongoing basis in the accounting period. Non-monetary items that are measured in terms of historical costs in a foreign currency are translated using the exchange rates on the dates of the initial transactions. Non-monetary items measured at fair value in a foreign currency are translated using the exchange rates on the date when the fair value is determined.

Group Companies

The results and financial position of group companies that have a functional currency different from the presentation currency are translated into the presentation currency as follows:

• Assets and liabilities for each balance sheet presented are translated based on the exchange rates at the balance sheet date.
• Revenues and expenses for each Income statement presented are translated at average exchange rate for the period. However, if this average is not a reasonable approximation of the cumulative effect on the prevailing rates on the actual transaction dates, revenues and expenses are translated using the foreign exchange rates on the specific transaction date.
• Equity transactions are translated at the exchange rate on the transaction date.

All resulting exchange differences are recognized in other comprehensive income. The same method has been used for translating the parent company financial statements to USD as presentation currency for periods prior to the change in functional currency to USD.

1.5 Revenue recognition

Revenues from petroleum products in which the company has an interest with other producers are recognized on the basis of the company’s ideal share of production during the period, regardless of actual sales (entitlement method).

This is achieved by applying the following approach in dealing with imbalances between actual sales and entitlements:

The excess of product sold during the period over the participant’s ownership share of production from the property is recognized by the overlift party as a liability (deferred revenue) and not as revenue. Conversely, the underlift party would recognize an underlift asset (receivable) and report corresponding revenue.

Differences between oil lifted and sold: petroleum overlifts are presented as current liabilities, while petroleum underlifts are presented as short-term receivables. The value of overlift/underlift is set at the estimated sales value, minus estimated sales costs.

Other revenues are recognized when the goods or services are delivered and material risk and control are transferred. Gain on asset disposals as described in Section 1.9 is included in other operating income.

Tariff revenue from processing of oil and gas is recognized as earned in line with underlying agreements.

Revenue is presented net of customs and excise taxes on petroleum products.

Dividends are recognized when the shareholders’ dividend rights are approved by the Annual General Meeting.

Interest is taken to income based on the effective interest method as it is earned.

1.6 Interests in joint arrangements

IFRS defines a joint arrangement as an arrangement over which two or more parties have joint control. Joint control is the contractually agreed sharing of control of an arrangement, which exists only when decisions about the relevant activities (being those that significantly affect the returns of the arrangement) require unanimous consent of the parties sharing control.

The company has interests in licences on the Norwegian Continental Shelf. Under IFRS 11 Joint arrangements, a joint operation is 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. The company recognizes investments in joint operations (oil and gas licences) by reporting its share of related revenues, expenses, assets, liabilities and cash flows under the respective items in the company's financial statements.

For those licences that are not deemed to be joint arrangements pursuant to the definition in IFRS 11 as there is no joint control, the company recognizes its share of related expenses, assets, liabilities and cash flows on a line-by-line basis in the financial statements in accordance with applicable IFRSs.

1.7 Classification in statement of financial position

Current assets and current liabilities include items that fall due for payment less than a year from the end of the reporting period and items relating to the business cycle. Next year’s instalments on long-term liabilities are classified as current liabilities. Financial investments in shares are classified as current assets, while strategic investments are classified as non-current assets.

1.8 Business combinations and goodwill

In order to consider an acquisition as a business combination, the acquired asset or groups of assets must constitute a business (an integrated set of operations and assets conducted and managed for the purpose of providing a return to the investors). The combination consists of inputs and processes applied to these inputs that have the ability to create output.

Acquired businesses are included in the financial statements from the transaction date. The transaction date is defined as the date on which the company achieves control over the financial and operating assets. This date may differ from the actual date on which the assets are transferred.

Comparative figures are not adjusted for acquired, sold or liquidated businesses.

For accounting purposes, the acquisition method is used in connection with the purchase of businesses. Acquisition cost equals the fair value of the assets used as consideration, including contingent consideration, equity instruments issued and liabilities assumed in connection with the transfer of control. Acquisition cost is measured against the fair value of the acquired assets and liabilities. Identifiable intangible assets are included in connection with acquisitions if they can be separated from other assets or meet the legal contractual criteria. If the acquisition cost at the time of the acquisition exceeds the fair value of the acquired net assets (when the acquiring entity achieves control of the transferring entity), goodwill arises.

If the fair value of the net identifiable assets acquired exceeds the acquisition cost on the acquisition date, the excess amount is taken to the Income statement immediatley.

Goodwill is allocated to the CGUs or groups of CGUs that are expected to benefit from synergy effects of the acquisition. The allocation of goodwill may vary depending on the basis for its initial recognition.

The main part of the company's goodwill is related to the requirement to recognize deferred tax for the difference between the assigned fair values and the related tax base ("technical goodwill"). The fair value of licences is based on cash flows after tax. This is because these licences are only sold in an after-tax market based on decisions made by the Norwegian Ministry of Finance pursuant to the Petroleum Taxation Act Section 10. The purchaser is therefore not entitled to a tax deduction for the consideration paid over and above the seller’s tax values. In accordance with IAS 12 paragraphs 15 and 24, a provision is made for deferred tax corresponding to the difference between the acquisition cost and the transferred tax depreciation basis. The offsetting entry to this deferred tax is goodwill. Hence, goodwill arises as a technical effect of deferred tax. Technical goodwill is tested for impairment separately for each CGU which give rise to the technical goodwill. A CGU may be individual oil fields, or a group of oil fields that are connected to the same infrastructure/production facilities.

The estimation of fair value and goodwill may be adjusted up to 12 months after the takeover date if new information has emerged about facts and circumstances that existed at the time of the takeover and which, had they been known, would have affected the calculation of the amounts that were included from that date.

Acquisition-related costs, except costs to issue debt or equity securities, are expensed as incurred.

1.9 Acquisitions, sales and licence swaps

On acquisition of a licence that involves the right to explore for and produce petroleum resources, it is considered in each case whether the acquisition should be treated as a business combination (see Item 1.8) or an asset purchase. Generally, purchases of licences in a development or production phase will be regarded as a business combination. Other licence purchases regarded as asset purchases are described below.

Oil and gas production licences

For licences in the development phase, the acquisition cost is allocated between capitalized exploration expenses, licence rights and production plant.

When entering into agreements regarding the purchase/swap of assets, the parties agree on an effective date for the takeover of the net cash flow (usually 1 January in the calendar year which would also normally be the effective date for tax purposes). In the period between the effective date and the completion date, the seller will include its sold share of the licence in the financial statements. In accordance with the purchase agreement, there is a settlement with the seller of the net cash flow from the asset in the period from the effective date to the completion date (pro & contra settlement). The pro & contra settlement will be adjusted to the seller’s losses/gains and to the assets for the purchaser, in that the settlement (after a tax reduction) is deemed to be part of the consideration in the transaction. Revenues and expenses from the relevant licence are included in the purchaser’s Income statement from the completion date, as defined in 1.8 above.

For tax purposes, the purchaser will include the net cash flow (pro & contra) and any other income and costs as from the effective date.

When acquiring licences that are defined as asset acquisitions, no provision is made for deferred tax.

Farm-in agreements

Farm-in agreements are usually entered into in the exploration phase and are characterised by the transferor waiving future financial benefits in the form of reserves, in exchange for reduced future financing obligations. For example, a licence interest is taken over in return for a share of the transferor’s expenses relating to the drilling of a well. In the exploration phase, the company normally accounts for farm-in agreements on a historical cost basis, as the fair value is often difficult to determine.

Swaps

Swaps of assets are calculated at the fair value of the asset being surrendered, unless the transaction lacks commercial substance, or neither the fair value of the asset received, nor the fair value of the asset surrendered, can be effectively measured. In the exploration phase, the company normally recognizes swaps based on historical cost, as the fair value often is difficult to measure.

1.10 Unitizations

According to Norwegian law, a unitization is required if a petroleum deposit extends over several production licences and these production licences have a different ownership representation. Consensus must be achieved with regard to the most rational coordination of the joint development and ownership distribution of the petroleum deposit. A unitization agreement shall be approved by the Ministry of Petroleum and Energy.

The company recognizes unitizations in the exploration phase based on historical cost, as the fair value often is difficult to measure. For unitizations involving licences outside the exploration phase, it has to be considered whether the transaction has commercial substance. If so, the unitization is recognized at fair value.

1.11 Tangible fixed assets and intangible assets

General

Tangible fixed assets are recognized on a historical cost basis. Depreciation of assets other than oil and gas fields is calculated using the straight-line method over estimated useful lives and adjusted for any impairment or change in residual value, if applicable.

The book value of tangible fixed assets consists of acquisition cost after deduction of accumulated depreciation and impairment losses. Expenses relating to leased premises are capitalized and depreciated over the remaining lease period if the recognition criteria for an asset have been met.

The expected useful lives of tangible fixed assets are reviewed annually, and in cases where these differ significantly from previous estimates, the depreciation period is changed accordingly. Changes to estimates are included prospectively in that the change is recognized in the period in which it occurs, and in future periods if the change affects both.

The residual value of an asset is the estimated amount that the company would obtain from disposal of the asset, after deduction of the estimated costs of disposal, if the asset was already of the age and in the condition expected at the end of its useful life.

Ordinary repair and maintenance costs relating to day-to-day operations are charged to the Income statement in the period in which they are incurred. The costs of major repairs and maintenance are included in the asset’s book value.

Gains and losses relating to the disposal of assets are determined by comparing the selling price with the book value, and are included in other operating expenses. Assets held for sale are reported at the lower of the book value and the fair value less cost to sell.

Operating assets related to petroleum activities

Exploration and development costs relating to oil and gas fields

Capitalized exploration expenditures are classified as intangible assets and reclassified to tangible assets at the start of the development. For accounting purposes, the field is considered to enter the development phase when the technical feasibility and commercial viability of extracting hydrocarbons from the field are demonstrable, normally at the time of concept selection. All costs relating to the development of commercial oil and/or gas fields are recognized as tangible assets. Pre-operational costs are expensed as they are incurred.

The company employs the ’successful efforts’ method to account for exploration and development costs. All exploration costs (including seismic shooting, seismic studies and 'own time’), with the exception of acquisition costs of licences and drilling costs for exploration wells, are expensed as incurred. When exploration drilling is ongoing in a period after a reporting date and the result of the drilling is subsequently not successful, the capitalized exploration cost as of the reporting date is expensed if the evaluation of the well is completed before the date when the financial statement are authorized for issue.

Drilling cost for exploration wells are temporarily capitalized pending the evaluation of potential discoveries of oil and gas resources. Such costs can remain capitalized for more than one year. The main criteria are that there must be plans for future drilling in the licence or that a development decision is expected in the near future. If no resources are discovered, or if recovery of the resources is considered technically or commercially unviable, expenses relating to the drilling of exploration wells are charged to expense.

Acquired licence rights are recognized as intangible assets at the time of acquisition. Acquired licence rights related to fields in the exploration phase remain as intangible assets also when the related fields enter the development or production phase.

Depreciation of oil and gas fields

Capitalized exploration and evaluation expenditures, development expenditures from construction, installation or completion of infrastructure facilities such as platforms, pipelines and production wells, and field-dedicated transport systems for oil and gas are capitalized as production facilities and are depreciated using the unit-of-production method based on proven and probable developed reserves expected to be recovered from the area during the concession or contract period. Acquired assets used for the recovery and production of petroleum deposits, including licence rights, are depreciated using the unit-of-production method based on proven and probable reserves. The reserve basis used for depreciation purposes is updated at least once a year. Any changes in the reserves affecting unit-of-production calculations are reflected prospectively.

1.12 Impairment

Tangible fixed assets and intangible assets

Tangible fixed assets and intangible assets (including licence rights, exclusive of goodwill) with a finite useful life will be assessed for potential loss in value when events or changes in the circumstances indicate that the book value of the assets is higher than the recoverable amount.

The valuation unit used for assessment of impairment will depend on the lowest level at which it is possible to identify cash inflows that are independent of cash inflows from other groups of fixed assets. For oil and gas assets, this is carried out at the field or licence level. The loss in value for capitalized exploration costs is assessed for each well. Impairment is recognized when the book value of an asset or a CGU exceeds the recoverable amount. The recoverable amount is the higher of the asset’s fair value less cost of disposal and value in use. When assessing the value in use, the expected future cash flow is discounted to the net present value by applying a discount rate after tax that reflects the current market valuation of the time value of money and the specific risk related to the asset. The discount rate is derived from the Weighted Average Cost of Capital (WACC).

For producing licences and licences in a development phase, the recoverable amount is calculated by discounting future cash flows after tax. Future cash flows are determined in the various licences based on the production profile compared to estimated proven and probable remaining reserves. The lifetime of the field for the purpose of impairment testing, is normally determined by the point in time when the operating cash flow from the field becomes negative.

For acquired exploration licences, an initial assessment as described in Section 1.11 above is performed – an assessment of whether plans for further activities have been established or, if applicable, an evaluation of whether development will be decided on in the near future.

A previously recognized impairment can only be reversed if changes have occurred in the estimates used for the calculation of the recoverable amount. However, the reversal cannot be to an amount that is higher than it would have been if the impairment had not previously been recognized. Such reversals are recognized in the Income statement. After a reversal, the depreciation amount is adjusted in future periods in order to distribute the asset’s revised book value, minus any residual value, on a systematic basis over the asset’s expected remaining life.

Goodwill

Goodwill is tested for impairment annually or more frequently if events or changes in circumstances indicate that the value may be impaired. Impairment is recognized if the recoverable amount of the CGU (or group of CGUs) to which the goodwill is related is less than the book value, including associated goodwill and deferred tax as described in Section 1.8. Losses relating to impairment of goodwill cannot be reversed in future periods. The company performs its annual impairment test of goodwill in the fourth quarter. On selling a licence where the company historically has recognized deferred tax and goodwill in a business combination, both goodwill and deferred taxes from the acquisition are included when calculating gain/loss. When recording impairment of such licences as a result of impairment testing, the same assumptions are applied when measuring the impairment. This avoids gross up of the impairment with tax, in that the impairment charged to the Income statement will not be higher than the original post tax amount paid in the business combination.

1.13 Financial instruments

The company has classified the financial instruments into the following categories of financial assets and liabilities:

• Financial assets at fair value through profit and loss (primarily derivatives)
• Loans and receivables
• Financial liabilities at fair value through profit and loss (derivatives)
• Other financial liabilities

Financial assets with fixed or determinable cash flows that are not quoted in an active market are classified as loans and receivables.

Financial liabilities that do not form part of the “held for trading purposes” category and which have not been designated as being at fair value with changes in value through profit or loss are classified as other financial liabilities

For financial instruments not traded in an active market, the fair value is determined using appropriate valuation techniques. Such techniques may include using recent arm’s length market transaction; reference to the current fair value of other instruments that is substantially the same; discounted cash flow analysis or other valuation models.

An analysis of fair values of financial instruments and further details as to how they are measured are provided in Note 28.

1.14 Impairment of financial assets

Financial assets that are assessed at amortized cost are impaired when, based on objective evidence, it is likely that the instrument’s cash flows have been negatively affected by one or more events that have occurred after the initial recognition of the instrument. In addition, the loss event must have an impact on estimated future cash flows that can be reliably estimated. The impairment is recognized in the Income statement. Should the reason for the impairment subsequently cease to exist, and this can be objectively linked to an event taking place after the impairment of the asset, the previous impairment shall be reversed. The reversal shall not cause the book value of the financial asset to exceed the amount that the amortized cost would have been if the impairment had not been recognized at the time when the impairment was reversed. Reversals of previous impairments are presented on the same line item as the impairment.

1.15 Research and development

Research consists of original, planned studies carried out with a view to achieving new scientific or technical knowledge or understanding. Development consists of the application of information gained through research, or of other knowledge, to a plan or design for the production of new or significantly improved materials, facilities, products, processes, systems or services before commercial production or use commences.

The licence system on the Norwegian Continental Shelf stimulates research and development activities. The company is only involved in research and development through projects financed by participants in the licences. It is the company’s own share of the licence-financed research and development that is assessed with a view to capitalization. Development costs that are expected to generate future financial benefits are capitalized when the following criteria are met:

• The company can demonstrate that the technical premises exist for the completion of the intangible asset with the aim of making it available for use or sale – the demo version;
• The company intends to complete the intangible asset and then use or sell it;
• The company has the ability to use or sell the asset;
• The intangible asset will generate future economic benefits;
• The company has available adequate technical, financial and other resources to complete the development and to put to use or sell the intangible asset, and;
• The company has the ability to measure the costs incurred in connection with the development of the intangible asset in a reliable manner.

All other research and development costs are expensed as incurred.

Costs that are capitalized include cost of materials, direct payroll expenses and a share of directly related joint expenses. Capitalized development costs are recognized in the Statement of financial position at acquisition cost minus accumulated depreciation.

Capitalized development costs are amortized over the asset’s estimated useful life.

1.16 Presentation of payroll and administration costs

The company presents its payroll and operating costs based on the functions in development, operational and exploration activities respectively, based on allocation of registered hours worked. As a basis, the company uses gross payroll and operating expenses reduced by the amounts already invoiced to operated licences.

1.17 Lease agreements

Financial lease agreements

Lease agreements in which the company accepts the main risk and returns incidental to ownership of the assets are financial lease agreements. At the start of the lease period, financial lease agreements are calculated at an amount corresponding to the lowest of the fair value and the minimum present value of the lease. When calculating the lease agreement's net present value, the implicit interest rate in the lease agreement is used provided that it can be calculated; otherwise, the company’s incremental borrowing rate is used. Direct costs in connection with the establishment of the lease agreement are included in the asset’s cost price.

Financial lease agreements are treated as tangible fixed assets in the Statement of financial position and have the same depreciation period as the company’s other depreciable assets. If it cannot be assumed with reasonable certainty that the company will take over ownership of the asset after the expiry of the lease, the asset is depreciated over whichever is the shorter of the contract period of the lease agreements and the asset’s expected useful life.

Operating lease agreements

Lease agreements in which the main risk and returns associated with the ownership of the asset are not transferred, are classified as operating lease agreements. Rental payments are classified as operating expenses and are recognized on a straight-line basis over the contract period.

1.18 Trade debtors

Trade debtors are recognized in the Statement of financial position at nominal value after a deduction for the provision for bad debt. The provision for bad debt is calculated on the basis of an individual valuation of each trade debtor. Known losses on receivables are expensed as incurred.

1.19 Borrowing costs

Borrowing costs that can be directly ascribed to procurement, processing or production of a qualifying asset shall be capitalized as part of the asset’s acquisition cost. Borrowing cost is only capitalized during the development phase. Other borrowing costs are expensed in the period in which they are incurred.

A qualifying asset is one that necessarily takes a substantial period of time to be made ready for its intended use or sale. Qualifying assets are generally those that are subject to major development or construction projects.

1.20 Inventories

Spare parts
Spare parts are valued at the lower of cost price and net realizable value on the basis of the first-in/first-out (FIFO) principle. Costs include raw materials, freight and direct production costs in addition to some indirect costs.

1.21 Cash and cash equivalents

Cash and cash equivalents include cash, bank deposits, and other short-term highly liquid investments with an original due date of three months or less. Bank overdrafts are included in the Statement of financial position as short-term loans.

1.22 Interest-bearing debt

All borrowings are initially recognized at transaction price, which equals the fair value of the amount received minus issuing costs relating to the loan.

Subsequently, interest-bearing borrowings are valued at amortized cost using the effective interest method; the difference between the transaction price (after transaction costs) and the face value is recognized in the Income statement during the period until the loan falls due. Amortized costs are calculated by considering all issue costs and any discount or premium on the settlement date.

1.23 Tax

General

Tax payable/tax receivable for the current and previous periods is based on the amounts receivable from or payable to the tax authorities.

Tax consists of tax payable and changes in deferred tax. Deferred tax/tax benefits are calculated on the basis of the differences between book value and tax basis values of assets and liabilities, with the exception of temporary differences on acquisition of licences that is defined as asset purchase.

The book value of deferred tax benefits is assessed and reduced insofar as it is no longer probable that future earnings or current tax regulations will make it possible to utilise the benefit. Deferred tax benefits that are not capitalized will be re-evaluated on each date of Statement of financial position and capitalized insofar as it is probable that future earnings or current tax regulations will make it possible to utilise the benefit.

Deferred tax and tax benefits are measured using the expected tax rate when the tax benefit is realised or the tax liability is met, based on tax rates and tax regulations that have been enacted or substantively enacted by the end of the reporting period.

Tax payable and deferred tax is recognized directly against equity or other comprehensive income insofar as the tax items are related to equity transactions or items of other comprehensive income.

Deferred tax and tax benefits are presented net, where netting is legally permitted and the deferred tax benefit and liability are related to the same tax subject and are payable to the same tax authorities.

Petroleum taxation

As a production company, Aker BP is subject to the special provisions of the Petroleum Taxation Act. Revenues from activities on the Norwegian Continental Shelf are liable to ordinary company tax and special tax. The tax rate for general corporate tax was 27 per cent until 1 January 2016, when it was changed to 25 per cent. The rate for special tax was 51 per cent until the same date, when it was changed to 53 per cent. From 1 January 2017, the rates are changed to correspondingly 24 and 54 per cent, which will impact the deferred tax calculation in 2016.

Tax depreciation

Pipelines and production facilities can be depreciated by up to 16 2/3 per cent annually, i.e., using the straight-line method over six years. Depreciation can be started when the expenses are incurred. When the field stops producing, the remaining cost price can be included as a deduction in the final year.

Uplift Uplift is a special income deduction in the basis for calculation of special tax. The uplift is calculated on the basis of investments in pipelines and production facilities, and can be regarded as an extra depreciation deduction in the special tax basis. The uplift constituted until 5 May 2013, 7.5 per cent per year over a period of four years, totalling 30 per cent of the investment. From 5 May 2013, the rate is 5.5 per cent per year (5.4 per cent from 2017) over a period of four years, totalling 22 per cent of the investment (21.6 per cent from 2017). Transition rules apply for some of the company's fields in development phase, which allows for the old 7.5 per cent rate until the year of production start. Uplift is recognized in the year in which it is deducted in the companies' tax returns, and thus has a similar effect on the tax for the period as a permanent difference.

Financial items

Interest on debt with associated currency losses/gains (net financial expenses on interest-bearing debt) is distributed between the offshore and onshore tax jurisdictions. The offshore interest deduction is calculated as the net financial costs of interest-bearing debt multiplied by 50 per cent of the ratio between net asset value for tax purposes allocated to the offshore tax jurisdictions as of 31 December in the income year and the average interest-bearing debt through the income year.

Remaining financial expenses, currency losses and all interest income as well as currency gains are allocated to the onshore jurisdiction.

Uncovered losses in the onshore tax jurisdictions resulting from the distribution of net financial items can be allocated to the offshore tax jurisdictions and deducted from regular income.

Only 50 per cent of other losses in the onshore tax jurisdictions are permitted to be reallocated to the offshore tax jurisdictions as deductions in regular income.

Exploration expenses Companies may claim a refund from the State for the tax value of exploration expenses incurred insofar as these do not exceed the year’s tax-related loss allocated to the offshore activities. The refund is included under ‘Tax receivable’ in the Statement of financial position.

Tax loss

Companies subject to special tax may, without time limitations, carry forward losses with the addition of interest. A corresponding rule also applies to unused uplift. The tax position can be transferred on realisation of the company or merger. Alternatively, disbursement of the tax value can be claimed from the State if the company ceases petroleum activities. The tax loss will thus be reclassified from deferred tax to current tax at the time the petroleum activity ceases, or is transferred to another company.

1.24 Employee benefits

Pension schemes

Gains and losses on curtailment or settlement of a defined-benefit pension scheme are included in the Income statement when the curtailment or settlement occurs. The settlement of the defined-benefit pension scheme for employees in BP Norge AS during 2016 was recognized in accordance with these principles. A defined contribution plan replaced the benefit plan, and the company is making contributions to the pension plan for full-time employees equal to 7 per cent for salary up to 7.1 G and 25.1 per cent between 7.1 and 12 G. The pension premiums are charged to expenses as they are incurred.

An early retirement scheme (AFP) has been introduced for all employees. The scheme is a multi-employer defined benefit plan, but is accounted for as a defined contribution pension, and premiums are expensed as incurred.

1.25 Provisions

A provision is recognized in the accounts when the company incurs a commitment (legal or self-imposed) as a result of a past event and it is probable that financial settlement will take place as a result of this commitment, and the amount can be reliably calculated. Provisions are evaluated at each period end and are adjusted to reflect the best estimate

If the time effect is considerable, the provisions are discounted using a discount rate before tax that reflects the market’s pricing of the time value of the amount and the risk specifically associated with the commitment. On discounting, the book value of the provisions is increased in each period to reflect the change in time relative to the due date of the commitment. The increase is expensed as an accretion expense.

Decommissioning and removal costs:

In accordance with the licence terms and conditions for the licences in which the company participates, the Norwegian State can require licence owners to remove the installation in whole or in part when production ceases or the licence period expires.

In the initial recognition of the decommissioning and removal obligations, the company provides for the net present value of future costs related to decommissioning and removal. A corresponding asset is capitalized as a tangible fixed asset and depreciated using the unit-ofproduction method. Changes in the time value (net present value) of the obligation related to decommissioning and removal accretion are charged to income as financial expenses and increase the balance-sheet liability related to future decommissioning and removal expenses. Changes in the best estimate for expenses related to decommissioning and removal are recognized in the Statement of financial position. The discount rate used in the calculation of the fair value of the decommissioning and removal obligation is the risk-free rate with the addition of a credit risk element.

1.26 Segment

Since its formation, the company has conducted its entire business in one and the same segment, defined as exploration for and production of petroleum in Norway. The company conducts its activities on the Norwegian Continental Shelf, and management follows up the company at this level. The financial information relating to geographical distribution and large customers is presented in Note 5.

1.27 Earnings per share

Earnings per share are calculated by dividing the ordinary profit/loss attributable to ordinary equity holders of the parent entity by the weighted average number of the total outstanding shares. Shares issued during the year are weighted in relation to the period in which they have been outstanding. Diluted earnings per share is calculated as the profit/loss for the year divided by the weighted average number of outstanding shares during the period, adjusted for the dilution effect of any share options.

1.28 Contingent liabilities and assets

Except for in the event of a business combination, neither contingent liabilities nor contingent assets are recognized.

A contingent liability is a possible obligation that arises from past events and whose existence will be confirmed only by the occurrence or non-occurrence of one or more uncertain future events not wholly within the control of the entity; or a present obligation that arises from past events but is not recognized because it is not probable that an outflow of resources embodying economic benefits will be required to settle the obligation or the amount of the obligation cannot be measured with sufficient reliability.

Contingent liabilities are disclosed with the exception of contingent liabilities where the probability of the liability having to be settled is remote.

Contingent assets are possible asset that arises from past events and whose existence will be confirmed only by the occurrence or nonoccurrence of one or more uncertain future events not wholly within the control of the entity. Information about such contingent assets is provided if inflow of economic benefits is probable.

1.29 Changes to accounting standards and interpretations that:

Have entered into force:

The accounting policies applied are consistent with those of the previous financial year, and none of the new and amended standards and interpretations effective as of 1 January 2016 had significant impact for the group.

Have been issued but have not entered into force:

A number of standards and interpretations are issued, but not yet effective, up to the date of issuance of the company’s financial statements. Those that are expected to impact the group are disclosed below. The company intends to adopt these standards when they become effective, provided that the standards are endorsed by the EU before publication of the annual report.

IFRS 9 Financial instruments

IFRS 9 Financial Instruments, which replaces IAS 39 Financial Instruments: Recognition and Measurement, was issued in July 2014. The standard introduces new requirements for classification and measurement, impairment, and hedge accounting. IFRS 9 is effective for annual periods beginning on or after 1 January 2018, with early application permitted. Except for hedge accounting, retrospective application is required, but comparative information is not compulsory. For hedge accounting, the requirements are generally applied prospectively, with some limited exceptions. The adoption of IFRS 9 is not expected to have a material impact on the group financial statements.

IFRS 15 Revenue from contracts with customers

IFRS 15 Revenue from Contracts with Customers was issued in May 2014 and establishes a new five-step model that will apply to revenue arising from contracts with customers. Under IFRS 15, revenue is recognized at an amount that reflects the consideration to which an entity expects to be entitled in exchange for transferring goods or services to a customer.

The principles in IFRS 15 provide a more structured approach to measuring and recognising revenue. The new revenue standard will supersede all current revenue recognition requirements under IFRS. Either a full or modified retrospective application is required for annual periods beginning on or after 1 January 2018 with early adoption permitted. During 2016, the company performed a preliminary assessment of IFRS 15, which is subject to changes arising from a more detailed ongoing analysis. Furthermore, the company is considering the clarifications issued by the IASB in April 2016 and will monitor any further developments. The entitlement method currently applied by the company is not prescribed in the guidelines in IFRS 15. We are, however, assessing whether the method could still be used, based on provisions in other standards, e.g. IFRS 9, but this has not yet been concluded upon. The company is still assessing the impact of IFRS 15, and plans to adopt the new standard on the required effective date (1 January 2018).

IFRS 16 Leases

IFRS 16 Leases was issued in January 2016 and replaces the current lease accounting standard, IAS 17 Leases, including related interpretations. The new standard changes the accounting treatment of leases, which are currently treated as operating leases. It requires that all leases, regardless of type and with few exceptions, must be recognized on the lessee's balance sheet as an asset with a related liability. The standard is effective from 1 January 2019, but has not yet been endorsed by the EU. The company is in the process of assessing the impact of IFRS 16, but has not yet performed any quantitative assessments. The impact may be significant, and will depend on the number and materiality of contracts active at the date of implementation and which are classified as operating leases under the current lease accounting standard.

2016 was an eventful year for the company. Through the acquisition of BP Norge AS, the company strengthed its position as the leading independent offshore E&P company on the NCS. The company is on track with the integration process and reiterates the ambition of a quarterly dividend from the fourth quarter of 2016.

Oil production from the Aker BP operated field Ivar Aasen started on 24 December 2016. The project had a total cost of NOK 27.4 billion and the development was completed on time and within budget – and with no serious incidents.

On 30 September 2016, Aker BP finalized the acquisition of 100 per cent of the shares in BP Norge AS. The transaction was announced on 10 June 2016, and Aker BP issued 135.1 million new shares to BP Group as compensation for the shares in BP Norge AS. In addition, the group paid a cash consideration of USD 251 million. The main reasons for the acquisition were to create a company with a strong platform through industrial capabilities, a world class asset base and financial robustness to take advantage of the attractive growth potential on the NCS. The portfolio of licences from BP Norge AS comes with limited capital expenditure commitments and high near-term production that complement the production start of Aker BP's Ivar Aasen and Johan Sverdrup developments.

The acquisition date for accounting purposes corresponds to the finalization of the transaction on 30 September 2016. For tax purposes, the effective date was 1 January 2016. The acquisition is regarded as a business combination and has been accounted for using the acquisition method of accounting in accordance with IFRS 3. A purchase price allocation (PPA) has been performed to allocate the consideration to fair value of assets and liabilities of BP Norge AS. The PPA is performed as of the acquisition date, 30 September 2016. The closing share price at Oslo Børs (NOK 127) was used as a basis for measuring the value of the shares consideration.

Each identifiable asset and liability is measured at its acquisition date fair value based on guidance in IFRS 13. The standard defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. This definition emphasizes that fair value is a market-based measurement, not an entity-specific measurement. When measuring fair value, the group uses the assumptions that market participants would use when pricing the asset or liability under current market conditions, including assumptions about risk. Acquired property, plant and equipment have been valued using the cost approach (replacement cost), while intangible assets (value of licences) have been valued using the income approach.

Accounts receivable are recognized at gross contractual amounts due, as they relate to large and credit-worthy customers. Historically, there has been no significant uncollectible accounts receivable in BP Norge AS.

The recognized amounts of assets and liabilities assumed as at the date of the acquisition were as follows

(USD 1 000)	30.09.2016
Other intagible assets	759 962
Deferred tax asset	941 221
Property, plant and equipment	921 081
Long-term recievables*	41 546
Long-term tax receivable	5 860
Inventories	20 860
Accounts receivable	14 053
Other short-term receivables	66 618
Tax receivables	4 881
Cash and cash equivalents	674 543
Total assets	3 450 626
Long-term abandonment provision	1 607 683
Provisions for other liabilities**	357 307
Trade creditors	16 001
Accrued public charges and indirect taxes	13 209
Short-term abandonment provision	72 537
Other current liabilities	154 521
Total liabilities	2 221 257
Total identifiable net assets at fair value	1 229 368
Consideration paid on acquisition	2 388 322
Goodwill arising on acquisition***	1 158 954

* This is a receivable towards BP Group related to certain obligations that will be covered by the sellers according to the transaction agreement.

** The main part of the provision is related to negative contract values related to rig contracts entered into by BP Norge AS, which was different from current market terms at the time of acquisition at 30 September 2016. The fair value is based on the difference between market price and contract price

*** No part of the goodwill will be deductible for tax purposes.

The goodwill of USD 1 159 million arises principally because of the following factors:

1. The ability to capture synergies that can be realized from managing a portfolio of both acquired and existing fields on the NCS (residual goodwill)

2. The requirement to recognize deferred tax assets and liabilities for the difference between the assigned fair values and the tax bases of assets acquired and liabilities assumed in a business combination. Licences on the NCS can only be sold in a market after tax, based on a decision made by the Norwegian Ministry of Finance pursuant to the Petroleum Taxation Act Section 10. The assessment of fair value of such licences is therefore based on cash flows after tax. Nevertheless, in accordance with IAS 12 Sections 15 and 19, a provision is made for deferred tax corresponding to the tax rate multiplied with the difference between the acquisition cost and the tax base. The offsetting entry to this deferred tax is goodwill. Hence, goodwill arises as a technical effect of deferred tax (technical goodwill).

Reconciliation of goodwill from the acquisition of BP Norge AS (USD 1 000)	30.09.2016
Goodwill as a result of deferred tax - technical goodwill	944 903
Goodwill related to synergies - residual goodwill	214 051
Total goodwill from the acquisition of BP Norge AS	1 158 954
Impairment charges, see Note 15	51 366
Net goodwill from the acquisition of BP Norge AS as of 31 December 2016	1 107 588

The above valuation is based on currently available information about fair values as of the acquisition date. If new information becomes available within 12 months from the acquisition date, the group may change the fair value assessment in the PPA, in accordance with guidance in IFRS 3.

If the acquisition had taken place at the beginning of 2016, year to date revenue would have increased by USD 514 million while net profit would have decreased by USD 3 million. The acquisition has no impact on other comprehensive income for 2016.

Parent company
On 1 December 2016 all assets and liabilities previously held in BP Norge AS were transferred to Aker BP. The distribution was based on group continuity based on booked values in the group based on the PPA from 30 September 2016. The only remaining asset in BP Norge AS subsequent to the transfer, except for the receivable against Aker BP as a result of transferring the activity, is tax loss carried forward as of 1 January 2016. The tax loss carried forward is classified as a tax receivable in the Group financial statements as it is expected to be refunded by the Norwegian tax authorities.

Upon transferring the activity as described above, the assets and liabilities of BP Norge AS replaced the value of the shares in that company in the separate financial statements of Aker BP ASA. However, the booked valued of the transferred net assets in BP Norge AS was USD 11.3 million lower at the time of the transfer on 1 December 2016 compared to the PPA date. This amount relates to the BP Norge related net profit in the group financial statements in the period between the PPA and the transfer of activity, and is booked as other financial expense in the separate financial statement of Aker BP ASA.

BP Norge AS was acquired 30 September 2016 and is consolidated in the group accounts as described in Note 3. In addition, the company has three subsidiaries which is not consolidated in the group accounts in 2016 due to materiality considerations:

Det norske oljeselskap AS (100 per cent)

Det norske oljeselskap AS, previously Marathon Oil Norge AS, was acquired by Aker BP in October 2014. All activity was transferred to Aker BP on 31 October 2014. As of year-end 2016, the only remaining asset in this company is cash equivalents reflecting the share capital amounting to USD 1.0 million.

Alvheim AS (65 per cent)

The sole purpose of Alvheim AS is to act as legal owner of MST Alvheim, the floating production facility which is used to produce oil and gas from the Alvheim fields. The costs of and benefits from operating the MST Alvheim will be carried by the partners in the Alvheim field. Hence, Alvheim AS only has the formal ownership rather than the actual value of the production facilities. Aker BP has a 65 per cent share in Alvheim AS, which corresponds to the ownership in the Alvheim field.

Sandvika Fjellstue AS (100 per cent)

Sandvika Fjellstue AS owns a conference centre used by Aker BP, located in Sandvika in Verdal.

The subsidiary Det norske oil AS (previously Premier Oil Norge AS) transferred its activity to Aker BP as of 28 February 2016 and was subsequently liquidated. The activity for January and February has thus been consolidated in the group accounts. The activity in Det norske exploration AS (previously Svenska Petroleum Exploration AS) was transferred to Aker BP in 2015, and Det norske exploration AS has been liquidated during 2016.

For additional information regarding subsidiaries, see Note 18.

The company's business is entirely related to exploration for and production of petroleum in Norway. The company's activities are considered to have a homogeneous risk and retur profile before tax, and the business is located in the geographical area Norway. The company operates within a single operating segment which matches the internal reporting to the company's executive management. The revenue in 2016 relates in all material respect to five main customers, which accounted for sales of USD 441 million, USD 276 million, USD 272, USD 157 and USD 107 million for the group and USD 317 million, USD 276 million, USD 272 million, USD 157 million and USD 107 million for the parent. The revenue in 2015 relates in all material respect to three main customers, which accounted for sales of USD 785 million, USD 279 million and USD 107 million (group and parent).

	Group		Parent company
Breakdown of exploration expenses (USD 1 000)	2016	2015	2016	2015
Seismic	29 321	12 530	29 304	12 530
Area fee	13 291	8 634	13 076	8 634
Expensed capitalized wells this year	41 284	10 390	41 284	10 390
Expensed capitalized wells previous years	10 385	1 292	10 385	1 292
Other exploration expenses	53 171	43 559	44 828	43 559
Total exploration expenses	147 453	76 404	138 878	76 404

During 2016 the group made changes in the subcategories within exploration expenses presented above. Comparable figures have been restated accordingly

The inventory mainly consists of equipment for the drilling of exploration wells or spare parts for development and production licences.

	Group		Parent company
Breakdown of petroleum revenues (USD 1 000)	2016	2015	2016	2015
Recognized income liquids	1 120 094	1 044 548	1 021 551	1 044 548
Recognized income gas	128 436	110 909	96 879	110 909
Tariff income	12 274	3 227	11 509	3 227
Total petroleum revenues	1 260 803	1 158 683	1 129 939	1 158 683
Breakdown of produced volumes (barrels of oil equivalent)
Liquids	23 830 388	19 307 898	21 645 073	19 307 898
Gas	4 512 648	2 593 733	3 343 534	2 593 733
Total produced volumes	28 343 036	21 901 630	24 988 607	21 901 630
Other income (USD 1000)
Realized gain/loss (-) on oil derivatives	30 199	14 962	30 199	14 962
Unrealized gain/loss (-) on oil derivatives	-46 399	45 217	-46 399	45 217
Gain on licence transactions	20	856	20	856
Other income*	119 506	2 084	3 938	2 084
Total other income	103 326	63 119	-12 242	63 119

* Other income is mainly related to change in pension scheme for employees in BP Norge AS. As of 30 September 2016 there was a defined benefit scheme in BP Norge AS, which has been replaced by a defined contribution scheme. The accounting consequence of the settlement is that previous gross pension liability is reset to zero and pension funds are used to issue a paid-up policy to each employee.

See Note 23 and 28 for further details regarding commodity derivatives.

	Group		Parent company
Breakdown of payroll expenses (USD 1 000)	2016	2015	2016	2015
Payroll expenses	142 383	116 519	117 835	116 519
Pension*	-79 648	7 904	8 654	7 904
Social security tax	22 645	16 708	17 739	16 708
Other personnel costs	3 541	1 928	2 310	1 928
Total payroll expenses	88 920	143 059	146 538	143 059

* The negative pension cost is related to the change in pension scheme described in Note 8

	Group		Parent company
Number of full time equivalents employed during the year	2016	2015	2016	2015
Europe	742	479	602	479
Southeast Asia	15	29	15	29
Total	757	508	616	508

As of 31 December 2016, the number of employees in the group was 1 371. As of 31 December 2015 the number of employees in the group was 534 of which 523 were employed in the parent company and 11 in the subsidiary, Det norske oil AS.

Remuneration of senior executives in 2016* (USD 1 000)	Salary	Bonus 9)	Payments in kind	Other	Total remuneration	Pension costs	Total number of shares (in 1 000)**	Owning interest
Karl Johnny Hersvik (Chief Executive Officer)	575	880	2	-	1 457	17	-	-
Øyvind Bratsberg (Special Advisor) 1)	450	249	2	4	704	17	49	0.0 %
Alexander Krane (Chief Financial Officer)	383	254	8	1	647	17	12	0.0 %
Gro G. Haatvedt (SVP Exploration)	409	387	2	6	804	72	8	0.0 %
Olav Henriksen (SVP Projects)	390	393	2	-	785	72	-	-
Geir Solli (SVP Operations ) 2)	386	229	6	50	670	17	25	0.0 %
Leif G. Hestholm (SVP HSE) 3)	270	76	2	16	364	17	-	-
Per Harald Kongelf (SVP Improvement) 4)	125	57	1	120	302	6	-	-
Arne Tommy Sigmundstad (SVP D&W) 5)	136	51	1	185	373	7	-	-
Ole-Johan Molvig (SVP Reservoir Development) 6)	285	41	2	19	347	17	-	-
Jorunn Kvåle (SVP HSE) oct-dec 7)	52	8		-	60	-	-	-
Eldar Larsen (SVP Operations) oct-dec 8)	84	13	1	1	99	-	-	-
Total remuneration of senior executives in 2016	3 546	2 637	26	401	6 610	261	94	0.0 %

¹⁾ Acting SVP D&W until 31 July 16.
²⁾ SVP Operations until 30 November 16.
³⁾ SVP HSE until 30 November 16.
⁴⁾ Joined the Company 5 September 16. Other includes sign-on fee.
⁵⁾ Joined the Company 1 August 16. Other includes sign-on fee.
⁶⁾ New position in EMT from 1 December 16.
⁷⁾ Payroll amounts from 30 September 2016, SVP HSE from 1 December 2016.
⁸⁾ Payroll amounts from 30 September 2016, SVP Operations from 1 December 16.
⁹⁾ Numbers represent estimated bonus for 2016, not actual bonus payment. From the total amount in this column, USD 980 thousand relates to a long term incentive program.

* All remuneration to senior executives is paid in NOK and converted to USD using a yearly average USD/NOK-rate at 8.399.
** Number of shares as of year end, and have been purchased by the individuals and are not part of the remuneration.

Remuneration of senior executives in 2015* (USD 1 000)	Salary	Bonus 4)	Payments in kind	Other	Total remuneration	Pension costs	Total number of shares (in 1 000)**	Owning interest
Karl Johnny Hersvik (Chief Executive Officer)	537	436	2	0	975	20	-	-
Øyvind Bratsberg (Acting SVP Drilling and Well)	447	138	2	4	591	20	49	0.0 %
Alexander Krane (Chief Financial Officer)	366	248	8	1	623	20	12	0.0 %
Gro G. Haatvedt (VP Exploration)	390	317	2	8	717	143	8	0.0 %
Gudmund Evju (Acting SVP Technology & Field Development) 1)	209	27	2	48	287	20	89	0.0 %
Olav Henriksen (SVP Projects) 2)	349	322	2	683	1 355	111	-	-
Kjetil Kristiansen (SVP HR)	295	93	5	3	396	20	-	-
Rolf J. Brøske (SVP Comm.)	195	62	2	4	263	20	3	0.0 %
Geir Solli (SVP Operations )	427	173	5	56	661	21	25	0.0 %
Kjetil Ween (SVP Drilling and Wells) 3)	178	-	2	604	784	15	-	-
Elke R. Njaa (SVP Company Development/Special Projects)	316	83	2	27	428	19	-	-
Leif G. Hestholm (SVP HSE & Q)	315	82	2	18	417	20	-	-
Total remuneration of senior executives in 2015	4 024	1 982	37	1 455	7 498	449	186	0.0 %

¹⁾ Joined executive management 12 June 2015.
²⁾ Joined 19 January 2015. The amount included in "other" relates to sign-on fee.
³⁾ Resigned from executive management 12 June 2015. The amount included in "other" relates to severance pay.
⁴⁾ Earned in 2015, paid in 2016.

* All remuneration to senior executives is paid in NOK and converted to USD using a yearly average USD/NOK-rate at 8.074.
** Number of shares as of year end, and have been purchased by the individuals and are not part of the remuneration

The tables below include regular fees to the Board and fees for participation in the Board's subcommittees. The fees to the nomination committee are also included. Fees to Board members employed in Aker or BP Group will be paid to the companies, not to the Board member in person. Some Board members have shares in the company. The table also includes the number of shares and owning interest in Aker BP ASA held directly or indirectly through related parties. Indirect ownership through other companies is included as a whole where the owning interest is 50 per cent or more.

Fees in 2016 Name	Comments	Fee (USD 1 000)	Total number of shares (in 1000)	Owning interest
Øyvind Eriksen	Chairman of the Board from 11 March 2016. Chair of the Compensation committee.	89	-	-
Anne Marie Cannon	Deputy Chair from 17 April 2013, member of the Audit committee	76	6	0.0 %
Gro Kielland	Board member from 20 March 2014. Member of the Audit and Risk committee/Compensation committee	57	-	-
Kjell Inge Røkke 1)	Board member from 17 April 2013	45	-	-
Trond Brandsrud	Board member from 11 March 2016. Chair of the Audit and Risk committee from 28 April 2016	45	-	-
Emil Brustad-Nilsen	Deputy Board member from 11 March 2016	4	-	-
Terje Solheim	Employee representative from 20 March 2014. Member of the Compensation committee from 28 April 2016.	24	1	0.0 %
Bjørn Thore Ribesen	Employee representative from 11 March 2016.	15	20	0.0 %
Lone Margrethe Olstad	Employee representative from 11 March 2016.	15	-	-
Aage Ertsgaard (1.deputy)	Deputy employee representative from 11 March 2016.	2	7	0.0 %
Kristin Gjertsen (2.deputy)	Deputy employee representative from 11 March 2016.	2	6	0.0 %
Ifor Sellevoll Roberts (3.deputy	Deputy employee representative from 11 March 2016.	4	8	0.0 %
Bernard Looney	Board member from 30 September 2016.	-	-	-
Kate Thomson	Board member from 30 September 2016, member of the Audit and Risk committee from 4 October 2016.	-	-	-
Arild Støren Frick	Chair of the nomination committee from 13 April 2015	4	-	-
Finn Haugan	Member of the nomination committee	2	-	-
Hilde Myrberg	Member of the nomination committee	2	-	-
Members until 11 March 2016
Kristin Gjertsen	Employee representative until 11 March 2016.	9	6	0.0 %
Sverre Skogen	Chairman of the Board from 17 April 2013 to 11 March 2016. Chair of the compensation committee until 11 March 2016.	41	-	-
Jørgen C Arentz Rostrup	Board member from 17 April 2013 to 11 March 2016. Chair of the Audit and Risk committee until 11 March 2016.	37	4	0.0%
Gudmund Evju	Employee representative from 20 March 2014 to 11 March 2016.	7	89	0.0 %
Camilla Oftebro	Deputy employee representative from 20 March 2014 to 11 March 2016	1	-	-
Tormod Førland	Deputy employee representative from 20 March 2014 to 11 March 2016	1	36	0.0 %
Kristin Alne	Deputy employee representative from 18 April 2015 to 11 March 2016	1	-	-
Members until 30 September 2016
Kitty Hall (Kat. J. Martin)	Board member from 17 April 2013 to 30 September 2016.	45	-	-
Kjell Pedersen	Board member from 18 April 2015 to 30 September 2016. Member of the Organizational Development and Compensation committee.	38	1	0.0 %
Total fee		566	185	0.1 %

¹⁾ Mr. Røkke and wife own and control TRG, which owns 68.2 per cent of Aker ASA, which through a subsidiary owns 40.0 per cent of Aker BP.

Fees in 2015 Name	Comments	Fee (USD 1 000)	Total number of shares (in 1000)	Owning interest
Sverre Skogen	Chair of the Board from 17 April 2013. Chair of the compensation committee.	117	-	-
Anne Marie Cannon	Deputy Chair from 17 April 2013. Member of the audit committee.	82	4	0.0 %
Jørgen C. Arentz Rostrup	Board member from 17 April 2013. Chair of the audit committee.	83	4	0.0 %
Kitty Hall (Kat J. Martin)	Board member from 17 April 2013.	61	-	-
Kjell Inge Røkke	Board member from 17 April 2013.	19	-	-
Gro Kielland	Board member from 20 March 2014. Member of the audit committee from 18 April 2015.	74	-	-
Kjell Pedersen	Board member from 18 April 2015. Member of the compensation committee.	31	-	-
Gudmund Evju	Employee representative from 20 March 2014.	26	89	0.0 %
Kristin Gjertsen	Employee representative from 20 March 2014. Member of the compensation committee.	31	6	0.0 %
Terje Solheim	Employee representative from 20 March 2014.	20	1	0.0 %
Kristin Alne (1. deputy)	Employee rep. Deputy board member from 18 April 2015.	2	-	-
Tormod Førland (2. deputy)	Employee rep. Deputy board member from 20 March 2014.	5	36	0.0 %
Camilla Oftebro (3. deputy)	Employee rep. Deputy board member from 20 March 2014.	3	-	-
Arild Støren Frick	Chair of the nomination commitee from 13 April 2015	2	-	-
Finn Haugan	Member of the nomination committee.	4	-	-
Hilde Myrberg	Member of the nomination committee.	4	-	-
Members before Annual General Meeting in April 2015:
Tom Røtjer	Board member from 19 April 2012. Member of the compen. committee. Resigned 18 April 2015.	25	7	0.0 %
Inge Sundet	Employee representative from 8 August 2012 to 18 April 2015.	12	15	0.0 %
Kjetil Kristiansen	Chair of the nomination committee to 13 April 2015.	3	-	-
Total Fee		602	163	0.0 %

Guidelines and adherence to the guidelines in 2016

In 2016, the company's remuneration policy has been in accordance with the guidelines described in the Board of Directors' Report for 2015 and submitted to the annual general meeting for an advisory vote in April 2016.

Guidelines for 2017

The Board has established guidelines for 2017 for salaries and other remuneration to the Chief Executive Officer and other senior executives. The guidelines will be reviewed at the company's annual general meeting in 2017.

Senior executives receive a basic salary, adjusted annually. The company's senior executives participate in the general arrangements applicable to all the company's employees as regards bonus programme (see below), pension plans and other payments in kind such as free internet connection at home and subsidized fitness centre fees. In special cases, the company may offer other benefits in order to recruit personnel, including to compensate for bonus rights earned in previous employment.

For bonus arrangements for executive management, reference is made to the section Executive Remuneration in the Board of Directors Report. Estimated amount incurred in 2016 for the different bonus arrangement, including the three year incentive program, is included in the bonus column in the table above.

Adjustment of the CEO's base salary is decided by the Board. Adjustment of the base salaries for other senior executives is decided by the CEO within the wage settlement framework adopted by the Board.

It is up to the Board to decide whether to pay bonuses, based on the previous year’s performance. For 2016, the bonus will be disbursed in April 2017.

A borrowing facility was established for the company's employees, whereby all permanent employees can borrow up to 30 per cent of their gross annual salary at an interest rate corresponding to the taxable norm interest rate. The lender is one selected bank, and the company guarantees for the employees' loans. Guarantees furnished by the company for employee loans in 2016 amounted to USD 1.3 million. The corresponding figure for 2015 was USD 1.6 million. The company covers the difference between the market interest rate and the norm interest rate for tax purposes at any time. As security for such loans, the company signs additional contracts with the employees, entitling it to make deductions for defaulting payment from holiday pay and pay during notice periods. The bank manages the facility, collects interest payments/instalments and follows up any default. The company pays a small annual fee for this work. This borrowing facility was closed for new members following the acquisition of BP Norge AS with no new loans being offered since 1 December 2016. Existing loans will follow set payment plan with no refinancing opportunities for the employee.

	Group		Parent company
(USD 1 000)	2016	2015	2016	2015
Fees for statutory audit services - KPMG	788	568	718	568
Fees for other statutory attestations - KPMG	80	294	80	294
Total auditor's fees	868	862	798	862

	Group		Parent company
(USD 1 000)	2016	2015	2016	2015
Interest income	5 795	3 098	5 516	3 098
Realised gains on derivatives	3 138	2 679	3 138	2 679
Return on financial investments	-	39	-	39
Change in fair value of derivatives	35 991	18 250	35 991	18 250
Currency gains	3 742	44 416	24 939	44 416
Total other financial income	42 871	65 385	64 068	65 385
Interest expenses	160 808	127 620	168 084	127 620
Capitalized interest cost, development projects	-96 562	-62 326	-96 562	-62 326
Amortized loan costs	17 915	17 480	17 915	17 480
Total interest expenses	82 161	82 774	89 438	82 774
Realised loss on derivatives	7 675	51 584	7 675	51 584
Change in fair value of derivatives	-	62 739	-	62 739
Accretion expenses	47 977	26 351	33 473	26 351
Other financial expenses*	7 864	6	39 953	6
Total other financial expenses	63 515	140 679	81 101	140 679
Net financial items	-97 011	-154 971	-100 955	-154 971

* The parent company number includes the group continuity adjustment described in Note 3, as well as other adjustments to the value of the shares in BP Norge AS.

The group changed the presentation of accretion expenses in 2016. It is now included in the line item other financial expenses, while it was presented as interest expenses prior to 2016. Comparable figures have been restated accordingly.

The rate (weighted average interest rate) used to determine the amount of borrowing cost eligible for capitalization for 2016 is 6.33 per cent. The corresponding rate for 2015 was 6.0 per cent.

	Group		Parent company
Breakdown of the current year's tax income (-)/tax expense (+) (USD 1 000)	2016	2015	2016	2015
Calculated current year tax/exploration tax refund	-131 488	49 776	-130 663	49 776
Prior periods' adjustments to current tax	-2 747	-11 580	-1 519	-11 580
Current tax income (-)/expense (+)	-134 235	38 196	-132 182	38 196
Prior periods' adjustments to deferred tax	15 100	6 921	5 226	6 921
Change in deferred tax	374 617	153 927	211 830	153 927
Deferred tax income (-)/expense (+)	389 717	160 849	217 055	160 849
Net tax income (-)/tax expense (+)	255 482	199 045	84 874	199 045
Effective tax rate in %	88%	-175 %	71%	-175 %

		Group		Parent company
Reconciliation of tax income (-)/tax expense (+) (USD 1 000)	Tax rate	2016	2015	2016	2015
25% / 27% company tax on result before tax	25%	72 613	-30 674	29 961	-30 674
53% / 51% special tax on result before tax	53%	153 940	-57 940	63 518	-57 940
Tax effect on uplift	53%	-103 313	-93 513	-99 890	-93 513
Change in tax rate *		-2 888	265	-2 888	265
Permanent difference - impairment of goodwill	78%	62 053	332 631	62 053	332 631
Foreign currency translation of NOK monetary items	78%	2 163	-59 857	-594	-59 857
Foreign currency translation of USD monetary items	78%	55 692	-243 175	51 381	-243 175
Tax effect of financial items - 25% / 27% only	53%	-21 335	185 202	-19 729	185 202
Revaluation of tax balances**	78%	28 901	164 348	-9 730	164 348
Utilization of acquired loss carried forward***		-	-5 524	-	-5 524
Other items (other permanent differences and previous period adjustment)	78%	7 656	7 282	10 791	7 282
Total tax income (-)/tax expense (+) for the year		255 482	199 045	84 874	199 045

* The tax rate for general corporation tax changed from 25 to 24 per cent from 1 January 2017. The rate for special tax changed from the same date from 53 to 54 per cent.

** Tax balances are in NOK and converted to USD using the period end currency rate. When the NOK weakens against USD, the tax rate increases as there is less remaining tax depreciation measured in USD.

*** In the acquisition of Svenska Petroleum Exploration AS the acquired loss carried forward was initially recognized to fair value. The amount of USD 5 524 thousand represents the difference between the proportional share of fair value and the nominal value.

In accordance with statutory requirements, the calculation of current tax is required to be based on NOK currency. This may impact the tax rate when the functional currency is different from NOK.

The revaluation of tax payable is presented as foreign exchange loss/gain in the Income statement, while the impact on deferred tax from revaluation of tax balances is presented as tax.

Breakdown of tax effect of temporary differences and	Group		Parent company
tax losses carry forward (USD 1 000)	2016	2015	2016	2015
Tangible fixed assets	-1 775 189	-1 138 666	-1 775 189	-1 138 666
Capitalized exploration cost	-308 303	-236 191	-308 303	-236 191
Other intangible assets	-932 700	-368 911	-932 700	-396 804
Abandonment provision	1 674 332	330 193	1 674 332	330 193
Financial instruments	9 776	7 637	9 776	7 637
Other provisions	157 183	-18 251	157 183	-18 251
Tax losses carry forward 24% / 25%	9 542	23 786	9 542	7 696
Tax losses carry forward 54% / 53%	119 815	44 289	119 815	-
Total deferred tax liability (-)/deferred tax asset (+)	-1 045 542	-1 356 114	-1 045 542	-1 444 386

	Group		Parent company
Reconciliation of change in deferred tax (-)/deferred tax asset (+) (USD 1 000)	2016	2015	2016	2015
Deferred tax/ deferred tax assets as of 1.1	-1 356 114	-1 286 357	-1 444 386	-1 286 357
Change in deferred taxes in Income statement	-374 617	-153 927	-211 830	-153 927
Reclassification of loss carry forward	-238 866	-	84 368
Deferred tax related to acquisitions*	942 611	91 151	535 893	2 879
Prior period adjustments	-18 555	-6 921	-9 587	-6 921
Deferred tax charged to OCI and equity	-1	-59	-1	-59
Total deferred tax liability (-)/deferred tax asset (+)	-1 045 542	-1 356 114	-1 045 542	-1 444 386

* Deferred tax asset from BP Norge AS has been netted against deferred tax liability in Aker BP as the activity in BP Norge AS was transferred to Aker BP during Q4 2016.

	Group		Parent company
Reconciliation of change in tax receivable (+)/tax payable (-) (USD 1 000)	2016	2015	2016	2015
Tax receivable/payable at 1.1	126 391	-189 098	108 393	-189 098
Current year tax in Income statement	131 488	-49 776	130 663	-49 776
Tax receivable/payable related to acquisitions	255 873	108 047	-71 071	90 049
Tax payment/tax refund	-211 525	232 956	-123 102	232 956
Prior period adjustments	-1 681	11 580	-1 545	11 580
Revaluation of tax payable	7 430	12 682	3 444	12 682
Tax receivable (+)/tax payable (-)	307 977	126 391	46 783	108 393
Tax receivable	400 638	126 391	139 443	108 393
Tax payable	-92 661	-	-92 661	-

Earnings per share is calculated by dividing teh year's profit/loss attributable to ordinary equity holders of the parent entity, which was 236.6 million (202.6 million in 2015). There are no option schemes or convertible bonds in the company. This means that there is no difference between the ordinary and diluted earnings per share.

	Group
(USD 1 000)	2016	2015
Profit/loss for the year attributable to ordinary equity holders of the parent entity	34 971	-312 652
The year's average number of ordinary shares (in thousands)	236 583	202 619
Earning per share in USD	0.15	-1.54

TANGIBLE FIXED ASSETS - GROUP*
2016 - Group (USD 1 000)	Assets under development	Production facilities including wells	Fixtures and fittings, office machinery	Total
Book value 31.12.2015	1 493 795	1 470 881	14 758	2 979 434
Acquisition cost 31.12.2015	1 505 779	2 514 487	35 506	4 055 772
Acquisition of BP Norge AS	-	921 081	-	921 081
Additions	752 795	177 144	12 603	942 542
Disposals	-	.	4 001	4 001
Reclassification**	-1 349 900	1 337 853	12 028	-19
Acquisition cost 31.12.2016	908 674	4 950 566	56 137	5 915 377
Accumulated depreciation and impairments 31.12. 2015	11 984	1 043 606	20 748	1 076 338
Depreciation	-	411 400	6 491	417 891
Impairment	-10 418	-6 191	-	-16 609
Retirement/transfer depreciations	-	-156	-3 882	-4 038
Accumulated depreciation and impairments 31.12.2016	1 566	1 448 659	23 357	1 473 582
Book value 31.12.2016	907 108	3 501 908	32 779	4 441 796

2015 - Group (USD 1 000)	Assets under development	Production facilities including wells	Fixtures and fittings, office machinery	Total
Acquisition cost 31.12.2014	1 324 556	1 856 371	35 684	3 216 612
Additions	743 328	77 933	-178	821 084
Reclassification	-562 106	580 182	-	18 077
Acquisition cost 31.12.2015	1 505 779	2 514 487	35 506	4 055 772
Acc. depreciations & impairment losses 31.12.2015	11 984	1 043 606	20 748	1 076 338
Book value 31.12.2015	1 493 795	1 470 881	14 758	2 979 434

* Fixed assets of the parent company have not been presented separately as the ending balances are identical for the two, following the transfer of activity from BP Norge AS to Aker BP ASA at 1 December 2016 as described in Note 3.

** The reclassification is mainly related to the Ivar Aasen field which entered into production phase in Q4 2016.

Capitalized exploration expenditures are reclassified to 'Fields under development' when the field enters into the development phase. If development plans are subsequently reevaluated, the associated costs remain in assets under development and are not reclassified back to exploration assets. Fields under development are reclassified to 'Production facilities' from the start of production. Production facilities, including wells, are depreciated in accordance with the Unit of Production Method. Office machinery, fixtures and fittings etc. are depreciated using the straight-line method over their useful life, i.e. 3-5 years. Removal and decommissioning costs are included as production facilities or fields under development.

See Note 15 for information regarding impairment charges.

INTANGIBLE ASSETS - GROUP*
	Other intangible assets
2016-Group (USD 1 000)	Licences etc.	Software	Total	Exploration wells	Goodwill
Book value 31.12.2015	646 487	1 543	648 030	289 980	767 571
Acquisition cost 31.12.2015	789 316	9 149	798 465	289 980	1 561 880
Acquisition of BP Norge AS	759 962	-	759 962	-	1 158 954
Additions*	25 519	-1 383	24 137	157 337	-
Disposals/expensed dry wells	-	265	265	51 669	-
Reclassification	406	-	406	-388
Acquisition cost 31.12.2016	1 575 203	7 501	1 582 705	395 260	2 720 835
Accumulated depreciation and impairments 31.12. 2015	142 829	7 606	150 435	-	794 309
Depreciation	91 254	-118	91 136	-	-
Impairment	8 429	-	8 429	-	79 555
Retirement/transfer depreciations	157	-265	-108	-	-
Accumulated depreciation and impairments 31.12.2016	242 670	7 223	249 892	-	873 864
Book value 31.12.2016	1 332 534	279	1 332 813	395 260	1 846 971

	Other intangible assets
2015-Group (USD 1 000)	Licences etc.	Software	Total	Exploration wells	Goodwill
Acquisition cost 31.12.2014	712 237	9 064	721 301	291 619	1 556 498
Additions	73 185	85	73 269	32 014	5 412
Disposals/expensed dry wells	-	-	-	11 682	-
Reclassification	3 895	-	3 895	-21 971	-
Acquisition cost 31.12.2015	789 316	9 149	798 465	289 980	1 561 880
Acc. depreciations & impairment losses 31.12.2015	142 829	7 606	150 435	-	794 309
Book value 31.12.2015	646 487	1 543	648 030	289 980	767 571

* Intangible assets of the parent company have not been presented separately as the ending balances are identical for the two, following the transfer of activity from BP Norge AS to Aker BP ASA at 1 December 2016 as described in Note 3.

The lenders have security in the form of pledge in all licences (development and producing assets), insurance policies, floating charge and accounts receivables

Software is depreciated over its usefull life (three years), using a stright-line method. Licences related to fields in production is depreciated using the Unit of Production method

	Group		Parent company
Depreciation in the Income statement (USD 1 000)	2016	2015	2016	2015
Depreciation of tangible fixed assets	417 891	405 869	404 740	405 869
Depreciation of intangible assets	91 136	75 090	91 136	75 090
Total depreciation in the Income statement	509 027	480 959	495 876	480 959
Impairment in the Income statement (USD 1 000)
Impairment/reversal of tangible fixed assets	-16 609	3 092	-16 609	3 092
Impairment/reversal of intangible fixed assets	8 429	2 832	8 429	2 832
Impairment of goodwill	79 555	424 544	79 555	424 544
Total impairment in the Income statement	71 375	430 468	71 375	430 468

See Note 15 for information regarding impairment charges.

Impairment testing

Impairment tests of individual CGUs are performed when impairment triggers are identified. As of 31 December 2016 there has been a decrease in long term price assumptions compared to 31 December 2015, which is considered as an impairment trigger. Two categories of impairment tests have been performed:

• Impairment test of fixed assets and related intangible assets, other than goodwill
• Impairment test of goodwill

Impairment is recognized when the book value of an asset or a CGU, including associated goodwill, exceeds the recoverable amount. The recoverable amount is the higher of the asset's fair value less cost to sell and value in use. For assets and goodwill in the group prior to the acquisition of BP Norge AS, the impairment testing has been based on value in use, consistent with the impairment testing in Q1 - Q3 2016. For assets and goodwill recognized in relation to the acquisition of BP Norge AS, the impairment testing has been based on fair value. For both value in use and fair value, the impairment testing is done based on discounted cash flows. The expected future cash flow is discounted to the net present value by applying a discount rate after tax that reflects the current market valuation of the time value of money, and the specific risk related to the asset. The discount rate is derived from the WACC for a market participant. Cash flows are projected for the estimated lifetime of the fields, which may exceed periods greater than five years. If not specifically stated otherwise, the same assumptions have been applied for value in use and fair value testing.

For producing licences and licences in the development phase, recoverable amount is estimated based on discounted future after tax cash flows. Below is an overview of the key assumptions applied for impairment testing purposes as of 31 December 2016.

Oil and gas prices

Future price level is a key assumption and has significant impact on the net present value. Forecasted oil and gas prices are based on the management's estimates and available market data. Information about market prices in the near future can be derived from the futures contract market. The information about future prices is less reliable on a long-term basis, as there are fewer observable market transactions going forward. In the impairment test, the oil price is therefore based on the forward curve from the beginning of 2017 to the end of 2019. From 2020, the oil price is based on the company's long-term price assumptions.

The nominal oil price based on the forward curve applied in the impairment test is as follows:

Year	USD/BOE
2017	58.5
2018	58.5
2019	58.0
From 2020 (in real terms) - fair value testing*	65.0
From 2020 (in real terms) - value in use testing	75.0

* In line with the fair value requirements in IAS 36, as defined by IFRS 13 definition of fair value, the long-term fair value oil price assumption reflects the view of market participants at the measurement date under current market conditions.

Oil and gas reserves

Future cash flows are calculated on the basis of expected production profiles and estimated proven and probable remaining reserves. The recoverable amount is sensitive to changes in reserves. For more information about the determination of the reserves, reference is made to Note 1, section 1.3 about important accounting assessments, estimates and assumptions.

Discount rate

The discount rate is derived from the company's WACC. The capital structure considered in the WACC calculation is derived from the capital structures of an identified peer group and market participants with consideration given to optimal structures. The cost of equity is derived from the expected return on investment by the company's investors. The cost of debt is based on the interest-bearing borrowings on debt specific to the assets acquired. The beta factors are evaluated annually based on publicly available market data about the identified peer group.

Based on the above, the post tax nominal discount rate is set to 7.5 per cent, which is a change from 8.5 per cent from the previous quarters in 2016.

Currency rate

Aker BP's functional currency is USD. In line with the methodology used for future oil price, the forward period for currency rates are from 2017 until end 2019. The company's long term assumptions are used from 2020 and onwards. This results in the following currency rates being applied for USD/NOK in the impairment test at year-end 2016:

Year	USD/NOK
2017	8.59
2018	8.53
2019	8.46
From 2020	7.50

Inflation

The long-term inflation rate is assumed to be 2.5 per cent.

Impairment testing of assets other than goodwill

The impairment test of assets other than goodwill has been performed prior to the annual goodwill impairment test. If these assets are found to be impaired, its carrying value will be written down before the impairment test of goodwill. The carrying value of the assets is the sum of tangible assets and intangible assets as of the valuation date.

In the PPA in relation to the acquisition of Marathon Oil Norge AS in 2014, some values were allocated to certain exploration prospects. During 2016 the group has concluded to cease the activity on some of these exploration assets, and the related value is thus impaired. Additionally, the removal estimates on several fields were reduced in 2016. Some of these fields had previously been written down to zero, and a reduction in the removal asset therefore leads to an immediate impact in the Income statement presented as reversed impairment. The impact from the decreased removal estimates is partly offset by decreased prices and other changes in assumptions from previous impairment calculations. Finally, the Gina Krog impairment from 2015 has been reversed in 2016 mainly due to increased prices in the forward period.

Below is an overview of the impairment charge and the carrying value per cash generating unit where impairment has been recognized or reversed at year-end 2016:

	Impairment charged/reversal
CGU (USD 1 000)	Intangible	Tangible	Recoverable amount/ carrying value
Gina Krog	-	-10 418	127 411
CGU's with no remaining carrying value	8 429	-6 191	-
Total	8 429	-16 609	127 411

Impairment testing of goodwill

For the purpose of impairment testing, goodwill acquired through business combinations have, before any impairment charges in 2016, been allocated as follows:

Goodwill allocation (USD 1 000)
Remaining technical goodwill from the acquisition of Marathon Oil Norge AS as of 1 January 2016	431 320
Technical goodwill from the acquisition of BP Norge AS	944 903
Residual goodwill	505 768
Remaining technical goodwill from other business combinations	42 399

Technical goodwill has been allocated to individual CGUs for the purpose of impairment testing. The residual goodwill is allocated to group of CGUs including all fields acquired together with all existing Aker BP's fields, as this mainly relates to tax and workforce synergies and the ability to capture synergies from managing a portfolio of both acquired and existing fields on the NCS. The technical goodwill from other business combinations are mainly allocated to Johan Sverdrup (USD 23 million) and Ivar Aasen (USD 8 million). The remaining technical goodwill from prior year business combinations is not significant in comparison to the total carrying amount of goodwill.

Impairment testing of residual goodwill

As mentioned above, residual goodwill is allocated across all CGUs for impairment testing. The combined recoverable amount exceeds the carrying amount by a substantial margin. Based on this, no impairment of residual goodwill has been recognized.

Impairment testing of technical goodwill from the acquisition of Marathon Oil Norge AS and BP Norge AS

The carrying value of the CGUs consists of the carrying values of the oilfield assets plus associated technical goodwill. In the impairment test performed, carrying value is adjusted by the remaining part of deferred tax from which the technical goodwill arose, to avoid an immediate impairment of all technical goodwill.

The total carrying value of the CGU's with technical goodwill impairment charges in 2016, is calculated as follows:

(USD 1 000)
Carrying value of oilfield licences and fixed assets	3 232 433
+ Technical goodwill	1 216 550
- Deferred tax related to technical goodwill	-1 860 547
Net carrying value pre-impairment of goodwill	2 588 437

The impairment charge is the difference between the recoverable amount and the carrying value

(USD 1 000)	Ula/Tambar	Valhall/Hod	Alvheim*
Net carrying value	264 960	1 112 465	1 211 012
Recoverable amount (including tax amortization benefit)	235 551	1 090 508	1 182 823
Impairment charge 2016	29 409	21 957	28 189

* Alvheim CGU was impaired in Q1 applying the assumptions described in the Q1 2016 financial report.

As depicted in the table showing carrying value above, deferred tax (from the date of acquisitions) reduces the net carrying value prior to the impairment charges. When deferred tax from the acquisitions decreases, more goodwill is as such exposed for impairment. This may lead to future impairment charges even though other assumptions remain stable. In 2016, the main reason for the impairment is the decreased long term price assumptions, together with an overall update of the other assumptions.

Sensitivity analysis

The table below shows how the impairment of goodwill allocated to the CGUs Ula/Tambar, Valhall/Hod and Alvheim would be affected by changes in the various assumptions, given that the remainders of the assumptions are constant.

		Change in goodwill impairment after
Assumption (USD 1 000)	Change	Increase in assumption	Decrease in assumption
Oil and gas price	+/- 20%	-51 366	407 227
Production profiles (reserves)	+/- 5%	-51 366	103 151
Discount rate	+/- 1% point	60 010	-25 170
Currency rate USD/NOK	+/- 1.0 NOK	-51 366	92 536
Inflation	+/- 1.0% point	-39 489	83 553

Impairment testing in 2015

Similar to 2016, the impairment charge in 2015 was in all material respect related to technical goodwill from acquisitions. The methodology for impairment testing was the same as in 2016 as described in this Note.

In 2015, all impairment testing was based on value in use assesments and the following assumptions were applied:

• discount rate of 8.5 per cent nominal after tax (WACC)
• a long-term inflation of 2.5 per cent
• a long-term exchange rate of NOK/USD 7.00 (forward curve first five years)
• a long-term oil price assumption of 85 USD/barrel (forward curve first five years)

Summary of impairment/reversal of impairments

The following impairments/(reversals) have been recorded:

	Group and parent
(USD 1 000)	2016	2015
Impairment of other intangible assets/licence rights	8 429	2 832
Impairment of tangible fixed assets	-16 608	3 092
Impairment of technical goodwill	79 555	424 544
Total impairments	71 376	430 468

The company's customers are large, financially sound oil companies. Accounts receivable consist of receivables related to the sale of oil and gas.

	Group		Parent company
(USD 1 000)	31.12.2016	31.12.2015	31.12.2016	31.12.2015
Receivables related to the sale of petroleum	170 000	85 546	170 000	85 546
Total accounts receivable	170 000	85 546	170 000	85 546

Age distribution of accounts receivable as of 31 December for the group was as follows:

Year (USD 1 000)	Total	Not due	<30d	30-90d	>90d
2015	85 546	84 453	764	-	329
2016	170 000	134 928	34 413	659	-

	Group		Parent company
(USD 1 000)	31.12.2016	31.12.2015	31.12.2016	31.12.2015
Prepayments	40 730	21 634	40 730	21 634
VAT receivable	7 913	6 121	7 913	5 429
Underlift of petroleum	70 003	3 696	70 003	3 696
Accrued income from sale of petroleum products	86 429	1 866	86 429	1 866
Other receivables, mainly from licences	217 857	71 873	217 857	66 595
Total other short-term receivables	422 932	105 190	422 932	99 221

	Group		Parent company
(USD 1 000)	31.12.2016	31.12.2015	31.12.2016	31.12.2015
Shares in Alvheim AS	10	10	10	10
Shares in Det norske oljeselskap AS	1 021	1 021	1 021	1 021
Shares in BP Norge AS	-	-	1 919 120	-
Shares in Det norske Exploration AS	-	-	-	93 804
Shares in Det norske oil AS	-	-	-	123 885
Shares in Sandvika Fjellstue AS	1 814	1 814	1 814	1 814
Investment in subsidiaries	2 845	2 845	1 921 965	220 534
Tenancy deposit	1 553	1 512	1 553	1 512
Other non-current assets	8 496	8 272	8 496	8 272
Total other non-current assets	12 894	12 628	1 932 014	230 317

Alvheim AS, Det norske oljeselskap AS (previously Marathon Oil Norge AS) and Sandvika Fjellstue AS have been deemed immaterial for consolidation purposes. For more information regarding shares in subsidiaries, see Note 4.

The acquisition of BP Norge AS was completed at 30 September 2016 and the company is consolidated in the group numbers as outlined in Note 3. Det norske oil AS and Det norske exploration AS were liquidated during Q2 2016.

The item 'Cash and cash equivalents' consists of bank accounts and short-term investments that constitute parts of the group`s transaction liquidity.

	Group		Parent company
Breakdown of cash and cash equivalents (USD 1 000)	31.12.2016	31.12.2015	31.12.2016	31.12.2015
Bank deposits	106 369	86 201	106 369	75 156
Restricted funds (tax withholdings)	8 917	4 398	8 917	4 143
Cash and cash equivalents	115 286	90 599	115 286	79 299
Unused revolving credit facility (see Note 24)	550 000	550 000	550 000	550 000
Unused reserve-based lending facility (see Note 24)	1 805 000	731 370	1 805 000	731 370

	Parent company
(USD 1 000)	31.12.2016	31.12.2015
Share capital	54 349	37 530
Total number of shares (in 1 000)	337 737	202 619
Nominal value per share in NOK	1.00	1.00

The group completed a private placement in Q3 2016, increasing the number of outstanding shares with 135.1 million to 337.7 million shares. The additional shares have a nominal value of NOK 1 and a share premium value of NOK 126 per share. There is only one single class of shares in the company and all shares carry a single voting right.

Overview of the 20 largest shareholders registered as of 31 December 2016	No. of shares (in 1 000)	Owning interest
AKER CAPITAL AS	135 098	40.00 %
BP GLOBAL INVESTMENTS LIMITED	101 309	30.00 %
FOLKETRYGDFONDET	15 271	4.52 %
STATE STREET BANK AND TRUST COMP	2 697	0.80 %
VERDIPAPIRFONDET DNB NORGE (IV)	2 685	0.79 %
STATE STREET BANK AND TRUST COMP	1 925	0.57 %
VPF NORDEA KAPITAL	1 847	0.55 %
VPF NORDEA AVKASTNING	1799	0.53 %
KLP AKSJENORGE	1 770	0.52 %
VERDIPAPIRFONDET ALFRED BERG GAMBA	1 688	0.50 %
STATE STREET BANK AND TRUST COMP	1 671	0.49 %
DANSKE INVEST NORSKE INSTIT. II.	1 561	0.46 %
DNB LIVSFORSIKRING ASA	1 405	0.42 %
JPMORGAN CHASE BANK, N.A., LONDON	1 381	0.41 %
VERDIPAPIRFONDET DNB NORGE SELEKTI	1 295	0.38 %
JPMORGAN CHASE BANK, N.A., LONDON	1 290	0.38 %
MORGAN STANLEY & CO. INTERNATIONAL	1 265	0.37 %
JPMORGAN CHASE BANK, N.A., LONDON	1 169	0.35 %
J.P. MORGAN BANK LUXEMBOURG S.A.	1 072	0.32 %
STATE STREET BANK AND TRUST COMP	1 065	0.32 %
OTHER	58 474	17.31 %
Total	337 737	100 %

	Group		Parent company
(USD 1 000)	31.12.2016	31.12.2015	31.12.2016	31.12.2015
DETNOR02 Senior unsecured bond 1)	214 827	208 744	214 827	208 744
DETNOR03 Subordinated PIK toggle bond 2)	295 510	294 696	295 510	294 696
Total bond	510 337	503 440	510 337	503 440

¹⁾ The NOK denominated bond runs from July 2013 to July 2020 and carries an interest rate of 3 month NIBOR +6.5 per cent. The principal falls due on July 2020 and interest is paid on a quarterly basis. The loan is unsecured. The loan has been swapped into USD using a cross currency interest rate swap whereby the group pays LIBOR +6.81 per cent quarterly.

In May 2016 the bondholders of DETNOR02 accepted the same covenant amendment package as for the RBL and RCF loans, as described in Note 24 below. As compensation, it was agreed that the DETNOR02 bonds would be repaid at 104 per cent of par at maturity in 2020.

In October 2016 the group removed the dividend restriction, subject to a leverage incurrence test at 4.5x (net interest-bearing debt / EBITDAX). In addition, the bondholders received a put option for an amount corresponding to any dividend payment from Aker BP at put price of 107. As compensation, the DETNOR02 bonds will be repaid at 107 per cent of par at maturity in 2020, up from the previous 104 per cent resulting from the covenant amendment described above.

²⁾ In May 2015, the group completed an issue of USD 300 million subordinated seven year PIK Toggle bonds with a fixed rate coupon of 10.25 per cent. The bonds are callable and includes an option to defer interest payments, and there is no financial covenants.

	Group and parent
(USD 1 000)	31.12.2016	31.12.2015
Provisions as of 1 January	423 325	489 051
Abandonment liabilities from acquisition of BP Norge AS	1 680 206	-
Incurred cost removal	-12 237	-12 508
Accretion expense - present value calculation	47 977	26 351
Change in estimates and incurred liabilities on new fields	17 650	-79 569
Total provision for abandonment liabilities	2 156 921	423 325
Break down of the provision to short-term and long-term liabilities
Short-term	75 981	10 520
Long-term	2 080 940	412 805
Total provision for abandonment liabilities	2 156 921	423 325

Abandonment liabilities of the parent company have not been presented separately as the ending balances are identical for the two, following the transfer of activity from BP Norge AS to Aker BP ASA at 1 December 2016 as described in Note 3.

The group's removal and decommissioning liabilities relate mainly to the producing fields

The estimate is based on executing a concept for abandonment in accordance with the Petroleum Activities Act and international regulations and guidelines. The calculations assume an inflation rate of 2.5 per cent and a nominal discount rate before tax of between 4.14 per cent and 6.35 per cent.

	Group		Parent company
(USD 1 000)	31.12.2016	31.12.2015	31.12.2016	31.12.2015
Unrealized gain commodity derivatives	-	45 217	-	45 217
Short-term derivatives included in assets	-	45 217	-	45 217
Total derivatives included in assets	-	45 217	-	45 217
Unrealized losses currency contracts	5 073	7 840	5 073	7 840
Unrealized losses interest rate swaps	30 586	54 172	30 586	54 172
Long-term derivatives included in liabilities	35 659	62 012	35 659	62 012
Unrealized losses currency contracts	3 868	13 506	3 868	13 506
Unrealized losses commodity derivatives	1 181	-	1 181	-
Short-term derivatives included in liabilities	5 049	13 506	5 049	13 506
Total derivatives included in liabilities	40 708	75 518	40 708	75 518

The group has different types of hedging instruments. The commodity derivatives are used to hedge the risk of oil price reduction. The group manages its interest rate exposure using interest rate derivatives, including a cross currency interest rate swap. Foreign currency exchange contracts are used to manage the company's exposure to currency risks, mainly NOK, EUR and GBP. These derivatives are marked to market with changes in market value recognized in the Income statement. In the Income statement, impacts from the commodity derivatives are presented as other operating income, while impacts from other derivatives are presented as financial items.

	Group		Parent company
(USD 1 000)	31.12.2016	31.12.2015	31.12.2016	31.12.2015
Reserve-based lending facility	2 030 209	2 118 935	2 030 209	2 118 935
Total other interest-bearing debt	2 030 209	2 118 935	2 030 209	2 118 935

The RBL facility was established in 2014 and is a senior secured seven-year facility. The facility was originally USD 3.0 billion, with an additional uncommitted accordion option of USD 1.0 billion. In connection with the acquisition of BP Norge AS, the facility size was increased to USD 4.0 billion. In addition a new, uncommitted, accordion option of USD 1.0 billion was added to the facility.

The interest rate is from 1 - 6 months LIBOR plus a margin of 2.75 per cent, with a utilization fee of 0.5 per cent on outstanding loan. In addition, a commitment fee of 1.1 per cent is paid on unused credit.

The borrowing base availability in the second half of 2016 was reset to USD 2.9 billion (up from USD 2.8 billion in the first half of 2016). After the inclusion of the BP Norge assets into the RBL facility and the semi-annual re-determination in December 2016, the borrowing base was increased to USD 3.9 billion as of 31 December 2016.

A revolving credit facility (RCF) of USD 550 million was completed with a consortium of banks in June 2015. The loan has a tenor of four years with extension options of one plus one year at the lenders discretion. The loan carries a margin of 4 per cent, stepping up by 0.5 per cent annually after 3, 4 and 5 years, plus a utilization fee of 1.5 per cent. In addition, a commitment fee of 2.0 per cent is paid on unused credit. This facility is undrawn as of 31 December 2016.

In April 2016 the company obtained acceptance for a covenant amendment package from its bank consortium, and as a result the covenants levels in the RBL and RCF were updated as follows: Leverage Ratio shall be maximum 6 in the quarters starting from 30 June 2016 and ending 31 December 2017, thereafter maximum 5.5 between 31 March 2018 up to and including 31 December 2018, further maximum 6 between 31 March 2019 up to and including 31 December 2019, and thereafter maximum 3.5. The Interest Coverage Ratio shall be minimum 2 in the quarters starting from 30 June 2016 and ending 30 September 2017, thereafter minimum 2.3 from 31 December 2017 up to and including 30 September 2018, further minimum 2 from 31 December 2018 up to and including 31 December 2019, and thereafter minimum 3.5.

In October 2016, the group completed a process with its bank consortium in order to amend certain provisions of the RBL and RCF, including removal of the dividend restrictions, subject to a leverage incurrence test of 4.5x (net interest-bearing debt / EBITDAX).

The lenders have security in the form of pledge in all licences (development and producing assets), insurance policies, floating charge and accounts receivables.

	Group		Parent company
Breakdown of other current liabilities (USD 1 000)	31.12.2016	31.12.2015	31.12.2016	31.12.2015
Current liabilities related to overcall in licences	81 686	33 444	81 686	31 212
Share of other current liabilities in licences	360 222	184 010	360 222	177 643
Overlift of petroleum	20 000	17 088	20 000	17 088
Fair value of contracts assumed in acquisition of Marathon Oil / BP Norge AS*	36 199	12 009	36 199	12 009
Other current liabilities**	85 737	64 125	1 743 662	61 120
Total other current liabilities	583 844	310 675	2 241 770	299 072

* The negative contracts value are related to rig contracts entered into by Marathon Oil Norge AS and BP Norge AS, which was different from current market terms at the time of acquisition. The fair value was based on the difference between market price and contract price. The balance is split between current and non-current liabilities based on the cash flow in the contracts, and amortized over the lifetime of the contracts.

** Other current liabilities consist of unpaid wages, vacation pay, accrued interest and other provisions. For the parent company, the additional part of other current liabilities consist of intra group seller credit from BP Norge AS.

The company has entered into different operating leases for rig contracts and other lease commitments related to licences, office premises and IT services. Most of the leases contain an option for extension. The leases do not contain any restrictions on the company's dividend policy or financing.

Lease obligation pertaining to ownership interests in licences:

Rig contracts

The company had a lease agreement until 2016 for Transocean Winner, for activity in the Greater Alvheim area. The company has entered into a new lease agreement for Transocean Artic to drill on the Alvheim Area, from December 2016 to August 2017. Licence partners have approved the drilling plans for the rig which cover the full lease period thus rig commitments disclosed represent Aker BP share only.

On behalf of the partners in Ivar Aasen, the company signed an agreement in 2013 with Maersk Drilling for the delivery of a jack-up rig for the development project on the Ivar Aasen field. The rig is drilling production wells on the Ivar Aasen field. The contract period is five years, with options for up to seven years.

The company has on behalf of the partners in Valhall entered into a new lease agreement for delivery of Maersk Invincible in May 2017. The rig will be used for plug and abandonment (P&A) activities on the Valhall area. The contract period is five years, with an additional two years option period.

Other lease commitments related to licences

The company has also entered into other operating lease agreements as rental of supply and standby vessels. These agreements are entered into on behalf of Aker BP's operated licences. In addition the company has lease commitments pertaining to its ownership in partner operated oil and gas fields.

The operating lease expenses recognized in the Income statement for the rig contracts and the vessel contracts were as follows:

	Group		Parent company
(USD 1 000*)	2016	2015	2016	2015
Lease payments	139 724	156 551	136 707	156 551
Total	139 724	156 551	136 707	156 551

Future minimum lease payments for rigs and other related operating leases are as follows:

	Group		Parent company
(USD 1 000)*	31.12.2016	31.12.2015	31.12.2016	31.12.2015
Within one year	132 298	116 777	132 298	116 777
One to five years	360 555	175 953	360 555	175 953
After five years	73 684	-	73 684	-
Total	566 538	292 729	566 538	292 729

* All numbers represents Aker BP`s interest in the licences as the lease commitments have been fully allocated to licences for the expected lease periods.

Other contractual commitments

The company has future capital commitments of USD 520 million on non-operated licences (USD 824 million in 2015). In addition, the company has entered into future capital commitments (other than leases) for the Greater Alvheim Area amounting to approximately USD 27 million as of year-end 2016. The corresponding amount for year-end 2015 was USD 146 million. On behalf of the partners for the Valhall fields, the company has signed a commitment amounting to USD 9 million. Aker BP has entered into agreements for transport of petroleum products and other contractual obligations related to operation of offshore installations of USD 597 million. These amounts are not included in any of the tables.

Lease liabilities - office premises and IT services

The operating lease expenses recognized in the Income statement for office premises and hire of IT services are as follows:

	Group		Parent company
(USD 1 000)	2016	2015	2016	2015
Lease payments	16 261	12 835	15 644	12 835
Payments received on subleases	-100	-391	-100	-391
Total	16 161	12 444	15 545	12 444

Minimum lease liabilities related to office premises and IT services to fall as follows:

	Group		Parent company
(USD 1 000)	31.12.2016	31.12.2015	31.12.2016	31.12.2015
Within one year	50 210	4 757	50 210	4 757
One to five years	42 329	11 550	42 329	11 550
After five years	12 173	6 299	12 173	6 299
Total	104 712	22 606	104 712	22 606

The company has entered into a new rental agreement for office premises in Oslo, which expires in 2027. The old agreement expired in 2016. The company has two rental agreements for office space in Trondheim (both will have expired in 2020) and one in Harstad (expires in 2020). The company has also entered into a new rental agreement for offic premises in Stavanger, which expires in 2023. The old agreement expired in 2016. As a result of the acquisition with BP Norge AS, the company entered into further rental agreement for office premises in Stavanger, which expires in 2021.

Liability for damages / insurance

As for other licences on the NCS, the company has unlimited liability for damage, including pollution damage. The company has insured its pro rata liability on the NCS on a par with other oil companies. Installations and liability are covered by an operational liability insurance policy.

Guarantees

The company has established a loan scheme whereby permanent employees can borrow up to 30 per cent of their gross annual salary at the prescribed interest rate for tax purposes. The company covers the difference between the market interest rate and the prescribed interest rate for tax purposes at any time. The lender is one selected bank, and the company guarantees for the employees' loans. Guarantees furnished by the company for employees totalled USD 1.3 million at 31 December 2016. The corresponding amount for 2015 was USD 1.6 million.

Guarantees have also been furnished in connection with the establishment of the debt facilities.

Contingent liabilities

During the normal course of its business, the company will be involved in disputes, including tax disputes. Potential tax claims related to previous taxable income of acquired companies can to some extent be reimbursed from the sellers. The company has made accruals for probable liabilities related to litigation and claims based on the management's best judgment and in line with IAS 37 and IAS 12. The management is of the opinion that none of the disputes will lead to significant commitments for the company.

Transactions with related parties

At year-end 2016, Aker (Aker Capital AS) and BP Global Investments Limited are the two major shareholders in Aker BP, with ownership interest of 40.00 and 30.00 per cent respectively. An overview of the 20 largest shareholders is provided in Note 20.

Transactions with related parties are carried out on the basis of the "arm’s length" principle.

		Group		Parent company
Related party (USD 1 000)	Receivables (+) / liabilities (-)	31.12.2016	31.12.2015	31.12.2016	31.12.2015
Aker Engineering	Trade creditors	-	26	-	26
Aker Solutions	Trade creditors	-3 205	88	-3 205	88
Aker Subsea Solutions	Trade creditors	-	279	-	279
Other Aker Group Companies	Trade creditors	-35	-	-35	-
BP Shipping	Trade creditors	-458	-	-458	-
BP Fuels and Lubricants	Trade creditors	-67	-	-67	-
Other BP Group Companies	Trade creditors	-56	-	-56	-
Frontica Advantage AS	Trade creditors	-146	-	-146	-
BP Oil International Ltd.	Trade debtors	141 415	-	141 415	-
BP Gas Marketing	Trade debtors	16 136	-	16 136	-
BP America Production	Trade debtors	83	-	83	-
Other BP Group Companies	Trade debtors	139	-	139	-

		Group		Parent company
Related party (USD 1 000)	Revenues (-) / expenses (+)	2016	2015	2016	2015
Aker Achievements	Other personnel costs	22	40	22	40
Aker ASA	Software & Board remuneration	230	640	230	640
Aker Business Services	Development costs	-	952	-	952
Aker Engineering	Development costs	-	137	-	137
Aker Geo (First Geo AS)	Exploration expenses	758	619	758	619
Aker Kværner	Other operating expenses	133	3	133	3
Aker Pharma Holdco	Other operating expenses	101	148	101	148
Aker Solutions	Development costs	25 433	637	18 131	637
Aker Solutions Holding AS	Other operating expenses	327	-	327	-
Aker Subsea Solutions	Development costs	835	22 919	835	22 919
AKOFS Offshore Operations AS	Development costs	334	-	334	-
BP Exploration Operating Co	Other operating expenses	4 376	-	940	-
BP International	Other operating expenses	9 990	-	2	-
BP Shipping	Other operating expenses	916	-	458	-
BP EOC	Other operating expenses	932	-	8	-
BP Gas Marketing	Other operating expenses	294	-	-	-
BP Fuels and Lubricants	Other operating expenses	81	-	26	-
BP Business Service Centre	Other operating expenses	101	-	101	-
Other BP Group Companies	Other operating expenses	347	-	1	-
BP Oil International	Sales of Oil and NGL	-242 593	-	-149 075	-
BP Gas Marketing	Sales of Gas	-46 207	-	-17 504	-
Fornebuporten Holding AS	Other operating expenses	1 260	-	1 260	-
Fornebuporten Næring 3 AS	Other operating expenses	454	-	454	-
Frontica Advantage AS	Other operating expenses	752	-	752	-
Frontica Business Solutions AS	Other operating expenses	435	-	435	-
Other Aker companies	Other operating expenses	105	-	105	-

The majority of transactions with BP Group companies listed above are in connection with transitional services. Following closing of the deal to merge BP Norge and Det norske on 30 September 2016, the BP Group continued to provide transitional support to Aker BP in areas such as IT infrastructure and systems, engineering and petro-technical consultancy, hydrocarbon sales and marketing.

Capital structure and equity

The main objective of the company's management of the capital structure is to maximize return to the owners by ensuring competitive conditions for both the company's own capital and borrowed capital.

The size of the company's resource and reserve base is very important in relation to access to capital and borrowing terms. The increase in resources, reported reserves and equity ratio as a result of large acquisitions in the last couple of years has significantly strengthened the company's ability to obtain attractive terms and conditions for its debt portfolio. The company seeks to optimize its capital structure by balancing return on equity against liquidity requirements.

The size of the company's resource and reserve base is very important in relation to access to capital and borrowing terms. The increase in resources, reported reserves and equity ratio as a result of large acquisitions in the last couple of years has significantly strengthened the company's ability to obtain attractive terms and conditions for its debt portfolio. The company seeks to optimize its capital structure by balancing return on equity against liquidity requirements.

The company monitors changes in financing needs, risk, assets and cash flows, and evaluates the capital structure continuously. To maintain the desired capital structure, the company considers various types of instruments, including refinancing of its debt, purchase or issue new shares or debt instruments, sell assets or pay back capital to the owners.

Categories of financial assets and liabilities

The company has the following financial assets and liabilities: financial assets and liabilities recognized at fair value through profit or loss, loans and receivables, and other liabilities. The latter two are recognized in the accounts at amortized cost, while the first item is recognized at fair value.

Categories of financial assets and financial liabilities - Group and Parent
31.12.2016	Financial assets at fair value Designated as such upon initial recognition	Loan and receivables	Financial liabilities at fair value Designated as such upon initial recognition		Financial liabilities measured at amortized costs	Total
Assets
Accounts receivable	-	170 000	-	-	-	170 000
Other short-term receivables 1)	-	382 202	-	-	-	382 202
Cash and cash equivalents	-	115 286	-	-	-	115 286
Total financial assets	-	667 488	-	-	-	667 488
Liability
Derivatives	-	-	-	40 708	-	40 708
Trade creditors	-	-	-	-	88 156	88 156
Bonds	-	-	-	-	510 337	510 337
Reserve-based lending facility	-	-	-	-	2 030 209	2 030 209
Other short-term liabilities	-	-	-	-	622 893	622 893
Total financial liabilities	-	-	-	40 708	3 251 595	3 292 303

¹⁾ Prepayments are not included in other short-term receivables, as prepayments are not deemed to constitute financial instruments.

31.12.2015	Financial assets at fair value Designated as such upon initial recognition	Loan and receivables	Financial liabilities at fair value Designated as such upon initial		Financial liabilities measured at amortized costs	Total
Assets
Other current financial assets	2 907	-	-	-	-	2 907
Accounts receivable	-	85 546	-	-	-	85 546
Other short-term receivables 1)	-	83 556	-	-	-	83 556
Derivatives	45 217	-	-	-	-	45 217
Other non-current assets	-	12 628	-	-	-	12 628
Cash and cash equivalents	-	90 599	-	-	-	90 599
Total financial assets	48 124	272 329	-	-	-	320 453
Liability
Derivatives	-	-	-	75 518	-	75 518
Trade creditors	-	-	-	-	51 078	51 078
Bonds	-	-	-	-	503 440	503 440
Reserve-based lending facility	-	-	-	-	2 118 935	2 118 935
Other short-term liabilities	-	-	-	-	319 735	319 735
Total financial liabilities	-	-	-	75 518	2 993 188	3 068 706

¹⁾ Prepayments are not included in Other short-term receivables, as prepayments are not deemed to constitute financial instruments.

Financial risk

The company has financed its activities with a reserve-based lending facility (see Note 24) and two bonds (see Note 21). In addition, the company has financial instruments such as accounts receivable, trade creditors etc., directly related to its day-to-day operations. For hedging purposes, the company has different types of hedging instruments, but no hedge accounting is applied. Commodity derivatives are used to hedge the risk of oil price reduction. Foreign currency exchange contracts and options are used in order to reduce currency risk related to cash flows. The company manages its interest rate exposure with a cross currency interest rate swap and interest rate derivatives.

The most important financial risks which the company is exposed to relate to oil and gas prices, foreign exchange rates, interest rates and access to funding.

The company's risk management, including financial risk management, is designed to ensure identification, analysis and systematic and cost-efficient handling of risk. Established management procedures provide a good basis for reporting and monitoring of the company's risk exposure.

(i) Commodity price risk

Aker BP's revenues are derived from the sale of petroleum products, and the revenue flow is therefore exposed to oil and gas price fluctuations. With the current unstable macro environment the company is continuously evaluating and assessing opportunities for hedging as part of a prudent financial risk management process. In December 2016 the company entered into new commodity hedges for 2017. These are put options with a strike price of 50 USD/bbl. for approximately 15 per cent of estimated 2017 oil production, corresponding to approximately 50 per cent of the after tax value. In 2016 the company had put options in place with a strike of USD 55/bbl. for around 20 per cent of the 2016 oil production relating to the assets of Det norske oljeselskap (prior to inclusion of the production from the BP Norge assets).

The following table summarizes the sensitivity of the commodity derivatives to a reasonably possible change in the forward oil price as of 31 December 2016, with all other variables held constant. As the company has not hedged production after 2017, the calculation is based on 2017 forward curve only. The impact presented below is on the fair value of the commodity derivatives only, and does not include other Income statement effects from changes in oil prices.

(USD 1 000)	Increase/decrease in oil price	31.12.2016	31.12.2015
Effect on pre-tax profit/loss:	+30%	-6 613	-47 084
	-30%	28 750	44 613

(ii) Currency risk

Revenues from sale of petroleum and gas are mainly in USD, EUR and GBP, while expenditures are mainly in NOK, USD, EUR and GBP. Sales and expenses in the same currency contribute to mitigating some of the currency risk. Currency derivatives may be used to further reduce this risk.

The table below shows the impact on profit/loss from changes in USD/NOK exchange rate. Other currencies are not included as the exposure is deemed immaterial.

(USD 1 000)	Change in exchange rate	31.12.2016	31.12.2015
Effect on pre-tax profit/loss*:	+10%	-35 467	32 383
	-10%	38 465	-35 715

* The sensitivity disclosed above includes the impact from currency derivatives.

The table below shows the company's exposure in NOK as of 31 December:

Exposure relating to (USD 1 000)	31.12.2016	31.12.2015
Receivables, cash and cash equivalents, other short-term receivables and deposits	867 226	192 536
Trade creditors, tax payable and other short-term liabilities	-604 001	-251 506
Bond loan	-	-215 689
Net exposure to NOK	263 225	-274 658

The company is also exposed to change in other exchange rates such as GBP/USD and EUR/USD, but the amounts are deemed immaterial.

(iii) Interest-rate risk

The company is exposed to interest-rate risk to borrowings and cash deposits. Floating-interest loans involve risk exposure for the company's future cash flows. As of 31 December 2016, the company's total loan liabilities amounted to approximately USD 2.5 billion, distributed between two long-term bond issues and one reserve-based lending facility. The corresponding loan liabilities as of 31 December 2015 amounted to approximately USD 2.6 billion.

The terms of the company's loans are described in Notes 21 and 24. The interest-rate risk relating to cash and cash equivalents is relatively limited. The following table shows the company's sensitivity to potential changes in interest rates which is reasonably possible:

Change in interest rate level in basis points (USD 1 000)		31.12.2016	31.12.2015
Effect on pre-tax profit/loss:	+100 points	-9 844	-24 932
	-100 points	9 089	24 864

In order to calculate sensitivity of interest rate changes, floating interest rates have been changed by + / - 100 basis points.

The table shows the effect on profit or loss in 2016 from changes in expected future interest rates. Such changes in expected future interest rates would have impacted the fair value of interest-rate swaps on the balance sheet date. However, the floating rate interest received on the interest rate swaps is associated with a corresponding floating rate interest payment on a bond or a loan. A change in fair value on the interest rate swaps has reduced the exposure to interest-rate risk by USD 16.6 million in the sensitivity presented.

(iv) Liquidity risk/liquidity management

The company's liquidity risk is the risk that it will not be able to meet its financial obligations as they fall due.

In addition, short-term (12 months) and long-term (five years) forecasts are prepared on a regular basis to plan the company's liquidity requirements. These plans are updated regularly for various scenarios and form part of the decision basis for the company's management and Board of Directors.

Excess liquidity is defined as a portfolio consisting of liquid assets other than the funds deposited in regular operational bank accounts and unused credit facilities. This means that excess liquidity includes high-interest accounts and financial investments in banks, money-market instruments and bonds. For excess liquidity, the requirement for low liquidity risk (i.e. the risk of realization on short notice) is generally more important than maximizing the return.

The company's objective for the placement and management of excess capital is to maintain a low risk profile and good liquidity.

The company's liquid assets as of 31 December 2016 are mainly deposited in bank accounts. As of 31 December 2016, the company had cash reserves of USD 115 million (2015: USD 91 million). Revenues and expenses are carefully managed on a day-to-day basis for liquidity risk management purposes.

The table below shows the payment structure for the company's financial commitments, based on undiscounted contractual payments

		Contract related cash flow
31.12.2016	Book value	Less than 1 year	1-2 years	2-5 years	over 5 years	SUM
Non-derivative financial liabilities:
Bond issue	510 337	48 221	48 221	354 929	312 642	764 012
Reserve-based lending facility	2 030 209	108 072	108 072	2 400 949	-	2 617 093
Trade creditors and other liabilities	88 156	88 156	-	-	-	88 156
Derivative financial liabilities
Derivatives	40 708	5 052	3 699	31 956	-	40 708
Total as of 31.12.2016	2 669 410	249 501	159 992	2 787 834	312 642	3 509 969

		Contract related cash flow
31.12.2015	Book value	Less than 1 year	1-2 years	2-5 years	over 5 years	SUM
Non-derivative financial liabilities:
Bond issue	503 440	47 886	47 841	355 056	343 819	794 602
Reserve-based lending facility	2 118 935	84 986	84 986	258 096	2 238 142	2 666 210
Trade creditors and other liabilities	51 078	51 078	-	-	-	51 078
Derivative financial liabilities
Derivatives	75 518	13 506	4 980	57 032	-	75 518
Total as of 31.12.2015	2 748 971	197 456	137 806	670 184	2 581 961	3 587 408

(v) Credit risk

The risk of counterparties being financially incapable of fulfilling their obligations is regarded as minor as there have not historically been any losses on accounts receivable. The company's customers and licence partners are large and credit worthy oil companies, and it has thus not been necessary to make any provision for bad debt.

In the management of the company's liquid assets, low credit risk is prioritized. Liquid assets are generally placed in bank deposits that represent a low credit risk

The maximum credit risk exposure corresponds to the book value of financial assets. The company deems its maximum risk exposure to correspond with the book value of accounts receivable and other short-term receivables, see Notes 16 and 17.

Determination of fair value

The fair value of forward exchange contracts is determined using the forward exchange rate at the end of the reporting period. The fair value of interest rate swaps and cross currency interest rate swaps is determined by using the expected floating interest rates at the end of the period. The fair value of commodity derivatives is determined using the forward Brent blend curve at the end of the reporting period. The fair value of interest rate swaps and cross currency interest rate swaps is determined by using the expected floating interest rates at the end of the period. The fair value is confirmed by Bloomberg. See Note 23 for detailed information about the derivatives.

The following of the company's financial instruments have not been valued at fair value: trade debtors, other short-term receivables, other long-term receivables, short-term loans and other short-term liabilities, bonds and other interest bearing liabilities.

The carrying amount of cash and cash equivalents is approximately equal to fair value, since these instruments have a short term to maturity. Similarly, the carrying amount of accounts receivable, other receivables, trade creditors and other short-term liabilities is virtually the same as their fair value as they are entered into on ordinary terms and conditions.

The bond issues from September 2013 and May 2015 are listed on Oslo Børs, and the fair value for disclosure purposes is determined using the quoted value as of 31 December 2016. For the RBL facility, it is assumed that the fair value equals the book value.

The following is a comparison between the book value and fair value of the company's financial instruments, except those where the carrying amount is a reasonable approximation of fair value (such as short-term trade receivables and payables in addition to instruments measured to fair value)

	31.12.2016		31.12.2015
Fair value of financial instruments (USD 1 000)	Book value	Fair value	Book value	Fair value
Financial liabilities measured at amortized cost:
Bond issue	510 337	584 400	503 440	484 139
Other interest-bearing debt	2 030 209	2 030 209	2 118 935	2 118 935
Total financial liabilities	2 540 546	2 614 609	2 622 375	2 603 074

Fair value hierarchy

The company classifies fair value measurements by employing a value hierarchy that reflects the significance of the input used in preparing the measurements. The fair value hierarchy consists of the following levels:

Level 1 - input in the form of listed (unadjusted) prices in active markets for identical assets or liabilities.
Level 2 - input other than listed prices of assets and liabilities included in Level 1 that is observable for assets or liabilities, either directly (i.e. as prices) or indirectly (i.e. derived from prices).
Level 3 - input for assets or liabilities for which there is no observable market data (non-observable input).

The company has no assets or liabilities in Level 3.

31.12.2016
Financial instruments recognized at fair value (USD 1 000)	Level 1	Level 2	Level 3
Financial assets or liabilities measured at fair value with changes in value recognized through profit or loss
Derivatives	-	40 708	-

31.12.2015
Financial instruments recognized at fair value (USD 1 000)	Level 1	Level 2	Level 3
Financial assets or liabilities measured at fair value with changes in value recognized through profit or loss
Derivatives	-	120 735	-
Market-based financial investments	2 907	-	-

In the course of the reporting period, there were no changes in the fair value measurements that involved any transfers between levels.

The company's investments in licences on the Norwegian Continental Shelf as of:
Fields operated:	31.12.2016	31.12.2015	Fields non-operated:	31.12.2016	31.12.2015
Alvheim	65.000 %	65.000 %	Alta	10.000 %	10.000 %
Bøyla	65.000 %	65.000 %	Enoch	2.000 %	2.000 %
Hod	37.000 %	0.000 %	Gina Krog	3.300 %	3.300 %
Ivar Aasen Unit	34.786 %	34.786 %	Johan Sverdrup****	11.573 %	11.573 %
Jette Unit	70.000 %	70.000 %	Jotun	7.000 %	7.000 %
Valhall	35.953 %	0.000 %	Varg	5.000 %	5.000 %
Vilje	46.904 %	46.904 %
Volund	65.000 %	65.000 %
Tambar	55.000 %	0.000 %
Tambar Øst	46.200 %	0.000 %
Ula	80.000 %	0.000 %
Skarv	23.835 %	0.000 %

Production licences in which Aker BP is the operator:			Production licences in which Aker BP is a partner:
Licence:	31.12.2016	31.12.2015	Licence:	31.12.2016	31.12.2015
PL 001B	35.000%	35.000 %	PL 006C***	15.000 %	0.000 %
PL 006B***	35.833 %	0.000 %	PL 018D***	13.338 %	0.000 %
PL 019***	80.000 %	0.000 %	PL 019C	30.000 %	30.000 %
PL 026B	90.260 %	62.130 %	PL 019D*	0.000 %	30.000 %
PL 027D	100.000 %	100.000 %	PL 026***	30.000 %	0.000 %
PL 028B	35.000 %	35.000 %	PL 029B	20.000 %	20.000 %
PL 033***	37.500 %	0.000 %	PL 035	50.000 %	50.000 %
PL 033B***	37.500 %	0.000 %	PL 035B*	0.000 %	40.000 %
PL 036C	65.000 %	65.000 %	PL 035C	50.000 %	50.000 %
PL 036D	46.904 %	46.904 %	PL 038	5.000 %	5.000 %
PL 065***	55.000 %	0.000 %	PL 038D***	0.000 %	30.000 %
PL 088BS	65.000 %	65.000 %	PL 038E*	0.000 %	5.000 %
PL 103B	70.000 %	70.000 %	PL 048B*	0.000 %	10.000 %
PL 150	65.000 %	65.000 %	PL 048D	10.000 %	10.000 %
PL 150B	65.000 %	65.000 %	PL 102C	10.000 %	10.000 %
PL 169C	50.000 %	50.000 %	PL 102D	10.000 %	10.000 %
PL 203	65.000 %	65.000 %	PL 102F	10.000 %	10.000 %
PL 203B	65.000 %	65.000 %	PL 102G	10.000 %	10.000 %
PL 212***	30.000 %	0.000 %	PL 265	20.000 %	20.000 %
PL 212B***	30.000 %	0.000 %	PL 272	50.000 %	50.000 %
PL 212E***	30.000 %	0.000 %	PL 362	0.000 %	40.000 %
PL 242	35.000 %	35.000 %	PL 405***	15.000 %	0.000 %
PL 261***	50.000 %	0.000 %	PL 438*	0.000 %	10.000 %
PL 262***	30.000 %	0.000 %	PL 457	40.000 %	40.000 %
PL 300***	55.000 %	0.000 %	PL 457BS	40.000 %	40.000 %
PL 340	65.000 %	65.000 %	PL 492***	60.000 %	40.000 %
PL 340 BS	65.000 %	65.000 %	PL 502	22.222 %	22.222 %
PL 364***	100.000 %	50.000 %	PL 507***	45.000 %	0.000 %
PL 407***	50.000 %	0.000 %	PL521*	0.000 %	25.000 %
PL 442***	90.260 %	60.000 %	PL 533	35.000 %	35.000 %
PL 460	100.000 %	100.000 %	PL 550*	0.000 %	10.000 %
PL 494*	0.000 %	30.000 %	PL 551*	0.000 %	20.000 %
PL 494B*	0.000 %	30.000 %	PL 554	30.000 %	30.000 %
PL 494C*	0.000 %	30.000 %	PL 554B	30.000 %	30.000 %
PL 504	47.593 %	47.593 %	PL 554C	30.000 %	30.000 %
PL 539*	0.000 %	40.000 %	PL 567*	0.000 %	40.000 %
PL 626	50.000 %	50.000 %	PL583*	0.000 %	45.000 %
PL 659***	35.000 %	20.000 %	PL 574*	0.000 %	10.000 %
PL 663*	0.000 %	30.000 %	PL 610***	37.500 %	0.000 %
PL 677	60.000 %	60.000 %	PL 613	20.000 %	20.000 %
PL 690*	0.000 %	30.000 %	PL 627	20.000 %	20.000 %
PL 709*	0.000 %	40.000 %	PL 627B	20.000 %	20.000 %
PL 715	40.000 %	40.000 %	PL 650***	25.000 %	0.000 %
PL 719**	20.000 %	0.000 %	PL 653	30.000 %	30.000 %
PL 724	40.000 %	40.000 %	PL 672***	0.000 %	25.000 %
PL 724B	40.000 %	40.000 %	PL 678S***	0.000 %	25.000 %
PL 736S	65.000 %	65.000 %	PL 681*	0.000 %	16.000 %
PL 748	30.000 %	30.000 %	PL689	20.000 %	20.000 %
PL762***	20.000 %	0.000 %	PL 689B**	20.000 %	0.000 %
PL 777	40.000 %	40.000 %	PL690*	0.000 %	30.000 %
PL 777B**	40.000 %	0.000 %	PL 694	20.000 %	20.000 %
PL 784***	40.000 %	0.000 %	PL 721***	20.000 %	0.000 %
PL 790	30.000 %	30.000 %	PL722***	20.000 %	10.000 %
PL 814**	40.000 %	0.000 %	PL 730*	0.000 %	30.000 %
PL 818**	40.000 %	0.000 %	PL 730B*	0.000 %	30.000 %
PL 821**	60.000 %	0.000 %	PL 778	20.000 %	20.000 %
PL 822S**	60.000 %	0.000 %	PL 782S***	20.000 %	0.000 %
PL 839***	23.835 %	0.000 %	PL 782SB**	20.000 %	0.000 %
PL 843**	40.000 %	0.000 %	PL797	25.000 %	25.000 %
PL 858**	40.000 %	0.000 %	PL 804	30.000 %	30.000 %
Number	53	37	PL 811**	20.000 %	0.000 %
			PL 813**	3.300 %	0.000 %
			PL 838***	30.000 %	0.000 %
			PL 842**	30.000 %	0.000 %
			PL 844***	30.000 %	0.000 %
			PL 852**	20.000 %	0.000 %
			PL 857**	40.000 %	0.000 %
			Number	48	49

* Relinquished licences or Aker BP has withdrawn from the licence.

** Interest awarded in the APA & 23rd licensing rounds in 2015. The awards were announced in 2016.

*** Acquired/changed through licence transactions or licence splits.

**** According to a ruling by the Ministry of Oil and Energy

Classification of reserves and contingent resources

Aker BP ASA's reserve and contingent resource volumes have been classified in accordance with the Society of Petroleum Engineer’s (SPE’s) “Petroleum Resources Management System”. This classification system is consistent with Oslo Børs requirements for the disclosure of hydrocarbon reserves and contingent resources. The framework is illustrated in Figure 1.

Figure 1 - SPE's classification system used by Aker BP ASA

Reserves, developed and non-developed

Aker BP ASA has a working interest in 28 fields/projects containing reserves, see table 1 and table 2. Out of these fields/projects, 13 are in the sub-class 'On Production'/Developed, eight are in the sub-class 'Approved for development'/Undeveloped and seven are in the sub-class 'Justified for development'/Undeveloped. Note that several fields have reserves in more than one reserve sub-class.

Table 1 - Aker BP fields - Developed reserves
Field/project	Investment share	Operator	Resource class
Alvheim	65.00 %	Aker BP	On production
Alta	10.00 %	Total	On production
Bøyla	65.00 %	Aker BP	On production
Hod	37.50 %	Aker BP	On production
Ivar Aasen	34.79 %	Aker BP	On production
Skarv	23.84 %	Aker BP	On production
Tambar	55.00 %	Aker BP	On production
Tambar Øst	46.20 %	Aker BP	On production
Ula	80.00 %	Aker BP	On production
Valhall	35.95 %	Aker BP	On production
Vilje	46.90 %	Aker BP	On production
Viper/Kobra	65.00 %	Aker BP	On production
Volund	65.00 %	Aker BP	On production

Table 2 - Aker BP fields - Undeveloped reserves
Field/project	Investment share	Operator	Resource class
Alvheim Boa Infill South	65.00 %	Aker BP	Approved for development
Alvheim Boa Infill North	65.00 %	Aker BP	Approved for development
Alvheim Kam Phase 3	65.00 %	Aker BP	Approved for development
Gina Krog	3.30 %	Statoil	Approved for development
Hanz	34.79 %	Aker BP	Approved for development
Johan Sverdrup	11.57 %	Statoil	Approved for development
Valhall 7 IP Wells	35.95 %	Aker BP	Approved for development
Volund Infill	65.00 %	Aker BP	Approved for development
Oda	15.00 %	Aker BP	Justified for development
Snadd A-1H	23.84 %	Aker BP	Justified for development
Tambar Artificial Lift	55.00 %	Aker BP	Justified for development
Tambar Infill South	55.00 %	Aker BP	Justified for development
Ula Oda	80.00 %	Aker BP	Justified for development
Ula TAL effect	80.00 %	Aker BP	Justified for development
Ula Tambar IFS eff	80.00 %	Aker BP	Justified for development

Total net proven reserves (1P/P90) as of 31 December 2016 to Aker BP ASA are estimated at 529 million barrels of oil equivalents. Total net proven plus probable reserves (2P/P50) are estimated at 711 million barrels of oil equivalents. The split between liquid and gas and between the different subcategories are given in table 3, 4 and 5.

Changes from 2015 reserve report are summarized in table 6. The main reason for increased net reserve estimate is the acquisition of BP Norge AS. As of 31 December 2016 these assets represent approximately 28 per cent of the company’s total reserves.

Except for the former BP Norge AS fields and Oda (15 per cent from Tullow) acquisitions, there have been only minor changes in reserve estimates. Ivar Aasen and Viper/Kobra commenced production in 2016 and have been reclassified from “Approved for production” (Undeveloped) to “On production” (Developed) reserves. In addition, two infill wells on Alvheim were sanctioned in December 2016 and have been included as “Approved for development”.

The future oil price assumption for the reserves given in table 3 below is 60.6 USD/bbl. A sensitivity with a higher oil price of 75 USD/bbl. had only minor impact on net total reserves to Aker BP with an increase of proved net reserves of two per cent compared to base price assumption. The higher oil price has no effect on net proved plus probable (2P/P50) reserves. In addition, a lower price scenario with an oil price of 45 USD/bbl. has been run. This gives marginal lower reserve compared to the base price assumption with a three and two per cent reduction in proved (1P/P90) reserves and proved plus probable (2P/P50) reserves respectively

Table 3 - Reserves by field - on production
	Interest	1P / P90 (low estimate)					2P / P50 (best estimate)
On production 31.12.2016	%	Gross oil/cond. (million barrels	Gross NGL Mton	Gross gas (bcm)	Gross oil equival. (million barrels)	Net oil equival. (million barrels)	Gross oil/cond. (million barrels	Gross NGL Mton	Gross gas (bcm)	Gross oil equival. (million barrels)	Net oil equival. (million barrels)
Alvheim	65.0 %	58.7	-	5.7	64.4	41.9	76.0	-	9.1	85.1	55.3
Vilje	46.9 %	14.3	-	-	14.3	6.7	18.9	-	-	18.9	8.9
Volund	65.0 %	6.1	-	0.1	6.3	4.1	12.7	-	1.0	13.7	8.9
Bøyla	65.0 %	7.5	-	0.3	7.8	5.1	12.7	-	0.6	13.3	8.7
Alta	10.0 %	0.4	-	0.2	0.6	0.1	0.4	-	0.3	0.8	0.1
Ula	80.0 %	24.8	1.2	-	26.0	20.8	47.7	2.4	-	50.1	40.1
Tambar	55.0 %	0.7	0.1	0.1	0.9	0.5	1.4	0.1	0.2	1.7	0.9
Tambar Øst	46.2 %	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0
Valhall	36.0 %	97.8	3.8	14.7	116.2	41.8	128.2	5.1	19.7	153.0	55.0
Hod	37.5 %	3.5	0.1	0.5	4.1	1.6	4.2	0.2	0.6	4.9	1.8
Skarv	23.8 %	28.0	31.7	119.4	179.0	42.7	45.2	32.8	147.7	225.6	53.8
Viper/Kobra	65.0 %	5.5	-	0.5	6.0	3.9	8.9	-	0.7	9.6	6.2
Ivar Aasen	34.8 %	106.3	7.7	20.8	134.8	46.9	144.4	10.1	27.1	181.6	63.2
Total						215.9					302.9

Table 4 - Reserves by field - approved for development
	Interest	1P / P90 (low estimate)					2P / P50 (best estimate)
Approved for development 31.12.2016	%	Gross oil/cond. (million barrels	Gross NGL Mton	Gross gas (bcm)	Gross oil equival. (million barrels)	Net oil equival. (million barrels)	Gross oil/cond. (million barrels	Gross NGL Mton	Gross gas (bcm)	Gross oil equival. (million barrels)	Net oil equival. (million barrels)
Johan Sverdrup	11.6 %	1 961.2	50.1	63.4	2 074.6	240.1	2 452.0	62.6	79.2	2 593.8	300.2
Hanz	35.0 %	11.7	0.6	1.6	14.0	4.9	14.4	0.8	2.3	17.5	6.1
Alvheim Phase 3	65.0 %	-	-	13.1	13.1	8.5	-	-	21.1	21.1	13.7
Alvheim Boa IFS	65.0 %	2.9	-	0.9	3.8	2.5	4.9	-	1.3	6.2	4.0
Alvheim Boa IFN	65.0 %	3.1	-	1.4	4.5	2.9	4.6	-	2.0	6.6	4.3
Valhall 7 IP Wells	36.0 %	46.0	1.7	6.6	54.3	19.5	60.3	3.1	12.1	75.5	27.2
Volund Infill	65.0 %	8.9	-	0.9	9.8	6.4	13.5	-	1.2	14.7	9.6
Gina Krog	3.3 %	81.7	31.7	56.7	170.1	5.6	105.7	38.6	74.5	218.7	7.2
Total						290.4					372.3

Table 5 - Reserves by field - justified for development
	Interest	1P / P90 (low estimate)					2P / P50 (best estimate)
Justified for development 31.12.2016	%	Gross oil/cond. (million barrels	Gross NGL Mton	Gross gas (bcm)	Gross oil equival. (million barrels)	Net oil equival. (million barrels)	Gross oil/cond. (million barrels	Gross NGL Mton	Gross gas (bcm)	Gross oil equival. (million barrels)	Net oil equival. (million barrels)
Snadd A-1H	23.8 %	5.0	7.0	31.7	43.7	10.4	6.0	8.8	39.9	54.6	13.0
Ula TAL effect	80.0 %	0.9	0.0	-	0.9	0.8	1.9	0.1	-	2.0	1.6
Ula Oda effect	80.0 %	2.7	0.1	-	2.8	2.2	5.8	0.3	-	6.1	4.9
Ula Tambar IFS effect	80.0 %	0.3	0.0	-	0.4	0.3	2.5	0.1	-	2.6	2.1
Tambar Artifical Lift	55.0%	2.7	0.1	0.6	3.4	1.9	4.1	0.2	0.9	5.2	2.8
Tambar Infill South	55.0 %	3.6	0.2	1.0	4.8	2.7	6.0	0.3	1.6	7.9	4.3
Oda	15.0 %	28.3	-	1.7	30.0	4.5	45.2	-	2.9	48.1	7.2
Total						22.7					35.9
Total reserves 31.12.2016						529.0					711.1
Total reserves 31.12.2015						373.9					498.2

Table 6 - Aggregated reserves, production, developments, and adjustments
Net attributed million barrels of oil equivalent	On production		Approved for devlop.		Justified for devlop.		Total
(mmboe)	1P/P90	2P/P50	1P/P90	2P/P50	1P/P90	2P/P50	1P/P90	2P/P50
Balance as of 31.12.2015	56.4	84.4	317.5	413.8	-	-	373.9	498.2
Production	-27.7	-27.7	-	-	-	-	-27.7	-27.7
Transfer	56.4	76.6	-56.4	-76.6	-	-	-	-
Revisions	18.9	13.4	4.4	-0.4	-	-	23.3	13.0
IOR	-	-	5.4	8.3	-	-	5.4	8.3
Discovery and extensions	-	-	-	-	-	-	-	-
Acquisition and sale	111.9	156.2	19.5	27.2	22.7	35.9	154.1	219.3
Balance as of 31.12.2016	215.9	302.9	290.4	372.3	22.7	35.9	529.0	711.1
Delta	159.5	218.5	-27-1	-41.5	22.7	35.9	155.2	212.9