Equinor — Annual Report 2009

Dec 31, 2009

Financial statements

STATEMENT OF INCOME STATOIL PETROLEUM AS - NGAAP

(in NOK million)	Note	2009	2008
REVENUES AND OTHER INCOME
Revenues	5	190,170	81,461
Net income (loss) from subsidiaries and associated companies	13	(3,858)	4,959
Other income		1,120	13
Total revenues and other income		187,432	86,433
OPERATING EXPENSES
Purchases [net of inventory variation]		(5,276)	(4,847)
Operating expenses		(34,983)	(11,717)
Selling, general and administrative expenses		(772)	0
Depreciation, amortisation and net impairment losses	11,12	(27,315)	(7,414)
Exploration expenses		(5,187)	(2,135)
Total operating expenses		(73,533)	(26,113)
Net operating income		113,899	60,320
FINANCIAL ITEMS
Net foreign exchange gains (losses)		(4,537)	2,361
Interest and other financial income		1,017	1,894
Interest and other financial expenses		(4,118)	(4,139)
Net financial items	9	(7,638)	116
Income before tax		106,261	60,436
Income tax	10	(84,197)	(42,259)
Net income		22,064	18,177

BALANCE SHEET STATOIL PETROLEUM AS - NGAAP

(in NOK million)	Note	At 31 December 2009	At 31 December 2008
ASSETS
Non-current assets
Property, plant and equipment	11	197,537	57,125
Intangible assets	12	8,366	1,785
Investments in subsidiaries	13	86,478	69,726
Investments in associated companies	13	824	999
Financial assets	9	1,328	327
Receivables on group companies		97	18
Total non-current assets		294,630	129,980
Current assets
Inventories	14	50	229
Trade and other receivables	15	9,278	4,676
Receivables on group companies		20,663	39,102
Current tax receivable		0	881
Cash and cash equivalents		3	0
Total current assets		29,994	44,888
TOTAL ASSETS		324,624	174,868

BALANCE SHEET STATOIL PETROLEUM AS - NGAAP

(in NOK million)		At 31 December 2009	At 31 December 2008
EQUITY AND LIABILITIES
Equity
Share capital		26,136	4,356
Additional paid-in capital		34,035	7,899
Retained earnings		7,367	21,499
Reserves for valuation variances		0	1,303
Total equity	16	67,538	35,057
Non-current liabilities
Financial liabilities		291	768
Liabilities to group companies	9	46,545	42,623
Deferred tax liabilities	10	65,721	18,477
Assets retirement obligations and other provisions	17	40,138	9,821
Total non-current liabilities		152,695	71,689
Current liabilities
Trade and other payables	18	14,103	5,807
Current tax payable		33,345	19,635
Liabilities to group companies		56,943	42,680
Total current liabilities		104,391	68,122
Total liabilities		257,086	139,811
TOTAL EQUITY AND LIABILITIES		324,624	174,868

STATEMENT OF CASH FLOWS

(in NOK million)	2009	2008
OPERATING ACTIVITIES
Income before tax	106,261	60,436
Adjustments to reconcile net income to net cash flow provided by operating activities
Depreciation, amortisation and impairment loss	27,315	7,414
Exploration expenditures written off	1,177	395
(Gains) losses on foreign currency transactions and balances	( 20)	1
(Gains) losses on sales of assets and other items	4,089	(3,823)
Changes in working capital (other than cash and cash equivalents)
• (Increase) decrease in inventories	1,208	246
• (Increase) decrease in trade and other receivables	(4,598)	(7,613)
• Increase (decrease) in trade and other payables	4,036	1,146
• (Increase) decrease in receivables/liabilities to/from subsidiaries	(12,977)	0
Taxes paid	(66,590)	(40,836)
(Increase) decrease in non-current items related to operating activities	4,232	106
Cash flows provided by operating activities	64,133	17,472
INVESTING ACTIVITIES
Cash flows used in investing activities	(62,931)	(24,006)
FINANCING ACTIVITIES
Group contribution	(40,000)	0
Increase (decrease) in financial receivables and payables to/from subsidiaries	38,801	0
Cash flows used in financing activities	(1,199)	0
Net increase (decrease) in cash and cash equivalents	3	(6,534)
Cash and cash equivalents at the beginning of the period	0	6,534
Cash and cash equivalents at the end of the period	3	0

1 Organisation and basis of presentation

Statoil Petroleum AS was founded in 2007 as a demerger of Norsk Hydro Produksjon AS and is incorporated and domiciled in Norway. The address of its registered office is Forusbeen 50, N-4035 Stavanger, Norway. Statoil Petroleum's business consists principally of the exploration, production and transportation of petroleum and petroleum-derived products.

Statoil Petroleum AS is consolidated into Statoil ASA's consolidated financial statements, cf. Statoil ASA's annual report. In accordance with the Norwegian Accounting Act §3-7, Statoil Petroleum AS does not prepare consolidated financial statements. For more information see Statoil ASA's annual report 2009. The consolidated financial statements can be obtained by contacting Statoil ASA, Forusbeen 50, 4035 Stavanger or from the website, www.statoil.com.

The shareholders of Statoil ASA and Norsk Hydro ASA (Hydro) on 5 July 2007 approved a merger between Statoil ASA and the oil and gas activities of Norsk Hydro ASA (Hydro Petroleum). The merger was effective 1 October 2007. As part of the process of transferring Hydro Petroleum's operations into separate legal entities, a demerger of Norsk Hydro Produksjon AS took place prior to the merger with Statoil ASA. Assets, including shares, rights and obligations related to the petroleum operations were transferred to Norsk Hydro Petroleum AS. The demerger was effective for economic and accounting purposes as of 1 January 2007 and was accounted for as a business combination between entities under common control, using the carrying amounts of assets and liabilities, because the underlying ownership interests were not affected by the demerger.

The company's name changed to StatoilHydro Petroleum AS from 1 October 2007, and subsequently changed to Statoil Petroleum AS as of 1 November 2009.

With effect from 1 January 2009, the parent company Statoil ASA transferred the ownership of its net assets on the Norwegian Continental Shelf (NCS) to Statoil Petroleum AS. Following this transfer, all the Statoil group's NCS net assets are owned by Statoil Petroleum AS. This group internal reorganisation significantly decreases the comparability of amounts between years for Statoil Petroleum AS and impacts the extent and content of the note disclosures in these Financial statements to a significant degree. All the following note disclosures of Statoil Petroleum AS should consequently be read with the Statoil group internal reorganisation on the NCS in mind.

The accounting policies of Statoil Petroleum AS correspond with the NGAAP accounting policies of its parent company Statoil ASA.

The functional currency of Statoil Petroleum AS is NOK.

2 Summary of significant accounting policies

Statement of compliance

The financial statements of Statoil Petroleum AS are prepared in accordance with the Norwegian Accounting Act of 1998 and good accounting practice (NGAAP).

Basis of preparation

The financial statements are prepared on the historical cost basis with some exceptions, as detailed in the accounting policies set out below. These policies have been applied consistently to all periods presented in these financial statements.

Significant changes in accounting policies

Effective from 2009 Statoil Petroleum AS has changed accounting policy in the accounting for investments in subsidiaries. Previously the company used the cost method for investments in subsidiaries, but is now using the equity method. The change has been applied retrospectively for the periods presented as if the new accounting policy had always been applied.

Reclassifications

Certain reclassifications have been made to prior year's figures to be consistent with current year's presentation.

Subsidiaries, associated companies and jointly controlled entities

Shareholdings and interests in subsidiaries, associated companies (companies in which Statoil Petroleum AS does not have control, or joint control, but has the ability to exercise significant influence over operating and financial policies; generally when the ownership share is between 20 and 50%) and jointly controlled entities are accounted for using the equity method.

Jointly controlled assets

Interests in jointly controlled assets are recognised by including Statoil Petroleum AS's share of assets, liabilities, income and expenses on a line-by-line basis.

Statoil Petroleum AS as operator of jointly controlled assets

Indirect operating expenses such as personnel expenses from Statoil ASA are accumulated in cost pools. These expenses are allocated to business areas and Statoil Petroleum AS' operated jointly controlled assets (licenses) on an hours incurred basis. Only Statoil Petroleum AS' share of Statement of income and balance sheet items related to Statoil Petroleum AS operated jointly controlled assets are reflected in the Statement of income and balance sheet.

Asset transfers between Statoil Petroleum AS and its subsidiaries

Transfers of assets and liabilities between Statoil Petroleum AS and entities directly or indirectly controlled by Statoil Petroleum AS are accounted for at the carrying amounts of the assets and liabilities transferred.

Foreign currency translation

Transactions in foreign currencies are translated to NOK at the foreign exchange rate at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated to NOK at the foreign exchange rate at the balance sheet date. Foreign exchange differences arising on translation are recognised in the income statement. Non-monetary assets that are measured in terms of historical cost in a foreign currency are translated using the exchange rate at the date of the transactions.

Revenue recognition

Revenues associated with sale and transportation of crude oil, natural gas, petroleum and chemical products, and other merchandises are recorded when title and risk pass to the customer, which is normally at the point of delivery of the goods based on the contractual terms of the agreements.

Revenues from the production of oil and gas from properties in which Statoil Petroleum AS has an interest with other companies are recognised on the basis of volumes lifted and sold to customers during the period (sales method). Where Statoil Petroleum AS has lifted and sold more than the ownership interest, an accrual is recorded for the cost of the overlift. Where the company has lifted and sold less than the ownership interest, costs are deferred for the underlift.

Sales and purchases of physical commodities, which are not settled net, are presented on a gross basis as Revenues and Purchases [net of inventory variation] in the Statement of income. Activities related to the trading of commodity based derivative instruments are reported on a net basis, with the margin included in Revenues.

Research and development

The company undertakes research and development both on a funded basis for licence holders, and unfunded projects at its own risk. The company's share of the licence holders funding and the total costs of the unfunded projects are development costs that are considered for capitalisation.

Development costs which are expected to generate probable future economic benefits are capitalised as intangible assets if, and only if, all of the following have been demonstrated: the technical feasibility of completing the intangible asset so that it will be available for use or sale; the intention to complete the intangible asset and use or sell it; the ability to use or sell the intangible asset; how the intangible asset will generate probable future economic benefits; the availability of adequate technical, financial and other resources to complete the development and to use or sell the intangible asset; the ability to reliably measure the expenditure attributable to the intangible asset during its development. All other research and development expenditure is expensed as incurred.

Subsequent to initial recognition, capitalised development costs are reported at cost less accumulated amortisation and accumulated impairment losses.

Income tax

Income tax in the Statement of income for the year comprises current and deferred tax expense. Income tax is recognised in the Statement of income except to the extent that it relates to items recognised directly in equity, in which case it is recognised in equity.

Current tax is the expected tax payable on the taxable income for the year and any adjustment to tax payable in respect of previous years. Uncertain tax positions and potential tax exposures are analysed individually and the best estimate of the probable amount for liabilities to be paid (unpaid potential tax exposure amounts, including penalties) and virtually certain amount for assets to be received (disputed tax positions for which payment has already been made) in each case is recognised within current tax or deferred tax as appropriate. Interest income and interest expenses relating to tax issues are estimated and recorded in the period in which they are earned or incurred, and are presented as financial items in the Statement of income.

Deferred tax assets and liabilities are recognised for the future tax consequences attributable to differences between the carrying amounts of existing assets and liabilities in the financial statements and their respective tax bases, subject to the initial recognition exemption. The amount of deferred tax provided is based on the expected manner of realisation or settlement of the carrying amount of assets and liabilities, using tax rates enacted or substantially enacted at the balance sheet date.

A deferred tax asset is recognised only to the extent that it is probable that future taxable profits will be available against which the asset can be utilised. In order for a deferred tax asset to be recognised based on future taxable profits, convincing evidence is required, taking into account the existence of contracts, production of oil or gas in the near future based on volumes of proved reserves, observable prices in active markets, expected volatility of trading profits and similar facts and circumstances.

A special petroleum tax is levied on profits derived from petroleum production and pipeline transportation on the Norwegian Continental Shelf (NCS). The special petroleum tax is currently levied at a rate of 50%. The special tax is applied to relevant income in addition to the standard 28% income tax, resulting in a 78% marginal tax rate on income subject to petroleum tax. The basis for computing the special petroleum tax is the same as for income subject to ordinary corporate income tax, except that onshore losses are not deductible against the special petroleum tax, and a tax-free allowance, or uplift, is granted at a rate of 7.5% per year. The uplift is computed on the basis of the original capitalised cost of offshore production installations. The uplift may be deducted from taxable income for a period of four years, starting in the year in which the capital expenditures are incurred. Uplift benefit is recorded when the deduction is included in the current year tax return and impacts taxes payable. Unused uplift may be carried forward indefinitely.

Oil and gas exploration and development expenditure

Statoil Petroleum AS uses the "successful efforts" method of accounting for oil and gas exploration costs. Expenditures to acquire mineral interests in oil and gas properties and to drill and equip exploratory wells are capitalised as exploration and evaluation expenditure within intangible assets until the well is complete and the results have been evaluated. If, following evaluation, the exploratory well has not found proved reserves, the previously capitalised costs are evaluated for derecognition or tested for impairment. Geological and geophysical costs and other exploration expenditures are expensed as incurred.

For exploration and evaluation asset acquisitions (farm-in arrangements) in which the company has made arrangements to fund a portion of the selling partners' (farmor's) exploration and/or future development expenditures, these expenditures are reflected in the financial statements as and when the exploration and development work progresses. Exploration and evaluation asset dispositions (farm-out arrangements) are accounted for on a historical cost basis with no gain or loss recognition.

Exchanges (swaps) of exploration and evaluation assets are accounted for at the carrying amounts of the assets given up with no gain or loss recognition.

Unproved oil and gas properties are assessed for impairment when facts and circumstances suggest that the carrying amount of the asset may exceed its recoverable amount, and at least once a year. Exploratory wells that have found reserves, but where classification of those reserves as proved depends on whether a major capital expenditure can be justified, will remain capitalised during the evaluation phase for the exploratory finds. Thereafter it will be considered a trigger for impairment evaluation of the well if no development decision is planned for the near future, and there moreover are no concrete plans for future drilling in the license. Impairment of unsuccessful wells is reversed, as applicable, to the extent that conditions for impairment are no longer present. Impairment and reversals of impairment of exploration and evaluation assets are charged to Exploration expenses in the Statement of income.

Capitalised exploration and evaluation expenditure, including expenditures to acquire mineral interests in oil and gas properties, related to wells that find proved reserves are transferred from Exploration expenditure (Intangible assets) to Construction in progress (Property, plant & equipment) at the time of sanctioning of the development project.

Property, plant and equipment

Property, plant and equipment are stated at cost, less accumulated depreciation and accumulated impairment losses. The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into operation, the initial estimate of a decommissioning obligation, if any, and, for qualifying assets, borrowing costs.

Exchanges of assets are measured at the fair value of the asset given up unless the exchange transaction lacks commercial substance or the fair value of neither the asset received nor the asset given up is reliably measurable.

Expenditure on major maintenance refits or repairs comprises the cost of replacement assets or parts of assets, inspection costs and overhaul costs. Where an asset or part of an asset is replaced and it is probable that future economic benefits associated with the item will flow to the company, the expenditure is capitalised. Inspection and overhaul costs associated with major maintenance programs are capitalised and amortised over the period to the next inspection. All other maintenance costs are expensed as incurred.

Depreciation of production installations and field-dedicated transport systems for oil and gas is calculated using the unit of production method based on proved developed reserves expected to be recovered from the area during the concession or contract period. Depreciation of other assets and of transport systems used by several fields is calculated on the basis of their estimated useful lives, using the straight-line method. Each part of an item of property, plant and equipment with a cost that is significant in relation to the total cost of the item is depreciated separately. For exploration and production (E&P) assets the company has established separate depreciation categories for platforms, pipelines, and wells as a minimum.

Capitalised exploration and evaluation expenditure, development expenditure on the construction, installation or completion of infrastructure facilities such as platforms, pipelines and the drilling of development wells, and field-dedicated transport systems for oil and gas are capitalised as producing oil and gas properties within Property, plant and equipment and are depreciated using the unit of production method based on proved developed reserves expected to be recovered from the area during the concession or contract period. Capitalised acquisition costs of proved properties are depreciated using the unit of production method based on total proved reserves. Depreciation of other assets and transport systems used by several fields is calculated on the basis of their estimated useful lives, normally using the straight-line method. Each part of an item of property, plant and equipment with a cost that is significant in relation to the total cost of the item is depreciated separately. For exploration and production (E&P) assets the company has established separate depreciation categories for platforms, pipelines, and wells as a minimum.

The estimated useful lives of property, plant and equipment are reviewed on an annual basis and changes in useful lives are accounted for prospectively. An item of property, plant and equipment is derecognised upon disposal or when no future economic benefits are expected to arise from the continued use of the asset. Any gain or loss arising on derecognition of the asset (calculated as the difference between the net disposal proceeds and the carrying amount of the item) is included in other income or operating expenses, respectively, in the period the item is derecognised.

Leases

Leases in terms of which the company assumes substantially all the risks and rewards of the ownership are reflected as finance leases within Property, plant and equipment and Financial liabilities, respectively. Assets under development for finance lease purposes, and for which the company carries substantially all the risk in the construction period, are recorded as finance leases under development within Property, plant and equipment based on the stage of completion at period end, unless another amount better reflects the realities of the arrangement. All other leases are classified as operating leases and the costs are recognised in the statement of income on a straight line basis over the lease term, unless another basis is more representative of the benefits of the lease to the company.

Finance lease assets are reflected at an amount equal to the lower of fair value and the present value of the minimum lease payments at inception of the lease, and subsequently reduced by accumulated depreciation and impairment losses, if any. When an asset leased by a jointly controlled asset in which the company participates qualifies as a finance lease, the company reflects its proportionate share of the leased asset and related obligations in the balance sheet as Property, plant and equipment and Financial liabilities, respectively. Capitalised leased assets are depreciated over the shorter of the estimated useful life of the asset or the lease term using the depreciation methods described under Property, plant and equipment above, depending on the nature of the leased asset.

The company distinguishes between leases, which imply the right to use a specific asset for a period of time, and capacity contracts, which confer on the company the right to and the obligation to pay for certain capacity volume availability related to transport, terminalling, storage etc. Such capacity contracts that do not involve specified single assets or that do not involve substantially all the capacity of an undivided interest in a specific asset are not considered by the company to qualify as leases for accounting purposes. Capacity payments are reflected as Operating expenses in the Consolidated statements of income in the period for which the capacity contractually is available to the company.

Intangible assets

Intangible assets are stated at cost, less accumulated amortisation and accumulated impairment losses. Intangible assets include expenditure on the exploration for and evaluation of oil and natural gas resources, goodwill and other intangible assets. Intangible assets acquired separately from a business are carried initially at cost. An intangible asset acquired as part of a business combination is recognised separately from goodwill at its fair value if the asset is separable or arises from contractual or other legal rights and its fair value can be measured reliably.

Intangible assets relating to expenditure on the exploration for and evaluation of oil and natural gas resources are not amortised. Such an asset is subject to impairment testing when facts and circumstances suggest that the carrying amount of the asset may exceed its recoverable amount (or at least on an annual basis), and is reclassified to Property, plant and equipment when the decision to develop a particular area is made. Other intangible assets are amortised on a straight-line basis over their expected useful lives. The expected useful lives of the assets are reviewed on an annual basis and changes in useful lives are accounted for prospectively.

Impairment

Impairment of intangible assets and property, plant and equipment

The company assesses assets or groups of assets for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. Individual assets are grouped based on levels with separately identifiable and largely independent cash inflows. Normally, separate cash-generating units are individual oil and gas fields or plants. For capitalised exploration expenditure, the cash-generating units are individual wells.

In assessing whether a write-down of the carrying amount of a potentially impaired asset is required, the asset's carrying amount is compared to the recoverable amount. Frequently the recoverable amount of an asset proves to be the company's estimated value in use, which is determined using a discounted cash flow model. The estimated future cash flows are adjusted for risks specific to the asset and discounted unsing a real post-tax discount rate based on the company's post tax weighted average cost of capital (WACC).

If assets are determined to be impaired, the carrying amounts of those assets are written down to recoverable amount which is the higher of fair value less costs to sell and value in use.

Impairments are reversed as applicable to the extent that conditions for impairment are no longer present.

Financial assets

The company assesses at each balance sheet date whether a financial asset or group of financial assets is impaired.

For assets carried at amortised cost, if there is objective evidence that an impairment loss on loans and receivables has been incurred, the carrying amount of the asset is reduced. Any subsequent reversal of an impairment loss is recognised in the Statement of income.

Financial liabilities

Interest-bearing loans and borrowings are initially recognised at cost. After initial recognition, interest-bearing loans and borrowings are subsequently measured at amortised cost using the effective interest method. Amortised cost is calculated by taking into account any issue costs, and any discount or premium on settlement. Gains and losses arising on the repurchase, settlement or cancellation of liabilities are recognised respectively in interest income and other financial items and interest and other financial expenses.

Provisions and contingent assets and liabilities

Provisions are recognised when the company has a present obligation (legal or constructive) as a result of a past event, it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. If the effect of the time value of money is material, provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and, where appropriate, the risks specific to the liability. Where discounting is used, the increase in the provision due to the passage of time is recognised as other finance expenses.

Contingent liabilities arising from past events and for which it is not probable that an outflow of resources will be required to settle the obligation, if any, are not recognised, but disclosed with indication of uncertainties relating to amounts and timing involved, unless the possibility of an outflow in settlement is remote.

Possible assets arising from past events that will only be confirmed by future uncertain events and are not wholly within the control of the company (contingent assets), are not recognised, but are disclosed when an inflow of economic benefits is probable.

Onerous contracts

The company recognises as provisions the obligation under contracts defined as onerous. Contracts are deemed to be onerous if the unavoidable costs of meeting the obligations under the contract exceed the economic benefits expected to be received in relation to the contract. A contract which forms an integral part of the operations of a cash-generating-unit whose assets are dedicated to that contract, and for which the economic benefits cannot be reliably separated from those of the cash-generating-unit, is included in impairment considerations for the applicable cash-generating-unit.

Asset retirement obligations

Liabilities for decommissioning expenses are recognised when the company has an obligation to dismantle and remove a facility or an item of property, plant and equipment and to restore the site on which it is located, and when a reasonable estimate of that liability can be made. The expenses are estimated based upon current regulation and technology, considering relevant risks and uncertainties to arrive at best estimates. Normally an obligation arises for a new facility, such as an oil and natural gas production or transportation facility, on construction or installation. An obligation for decommissioning may also crystallise during the period of operation of a facility through a change in legislation or through a decision to terminate operations. At the time of the obligating event, a decommissioning liability is recognised and classified as Asset retirement obligations. The amount recognised is the present value of the estimated future expenditure determined in accordance with local conditions and requirements. Refining and processing plants that are not limited by license periods are deemed to have indefinite lives and in consequence no asset retirement obligation has been recorded. For retail outlets, decommissioning provisions are estimated on a portfolio basis.

When a liability for decommissioning cost is recognised, a corresponding amount is recorded to increase the related property, plant and equipment. This is subsequently depreciated as part of the costs of the facility or item of property, plant and equipment.

Any change in the present value of the estimated expenditure or change in timing of the decommissioning is reflected as an adjustment to the provision and the corresponding property, plant and equipment.

Trade and other payables

Trade and other payables are carried at payment or settlement amounts.

Use of estimates

Preparation of the financial statements requires the company to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as disclosures of contingencies. Actual results may ultimately differ from the estimates and assumptions used.

The nature of Statoil Petroleum AS's operations, and the many countries in which the comany operates, are subject to changing economic, regulatory and politicial conditions. Statoil Petroleum AS does not believe it is vulnerable to the risk of a near-term severe impact as a result of any concentration of is activities.

3 Financial market risk

General information relevant to risks

Financial market risks are managed at the group level within the Statoil group on a short-term basis with focus on achieving the highest risk adjusted returns for the group within the given mandate. Long-term positions, defined as having a time horizon of six months or more, are managed at the corporate level while short term positions are managed at segment and lower levels according to trading strategies and mandates approved by the group's Corporate Risk Committee.

Statoil has guidelines for entering into contractual arrangements (derivatives) to manage its commodity price, foreign currency rate, and interest rate risk. Within the program, Statoil has developed a comprehensive model, which encompasses Statoil Petroleum AS' most significant market and operational risks.

Financial risks

Statoil Petroleum AS' activities expose the company to financial risks such as:

• Market risk (including commodity price risk, currency risk and interest rate risk)
• Liquidity risk

Market risk

Statoil Petroleum AS operates in the worldwide crude oil and natural gas market and are exposed to market risks including fluctuations in hydrocarbon prices, foreign currency rates and interest rates that can affect the revenues and costs of operating, investing and financing.

Commodity price risk

Commodity price risk constitutes Statoil Petroleum AS' most important short-term market risk. Changes in commodity prices have a significant effect on the company's income.

Currency risk

Statoil Petroleum AS' operating results and cash flows are affected by price developments of its main products, oil and gas, in addition to foreign currency fluctuations of the most significant currencies, the US dollar and the euro, against the Norwegian kroner. The company's cash inflows are largely denominated in or driven by US dollars while cash outflows, such as operating expenses and taxes payable, are to a large extent denominated in Norwegian kroner.

Interest rate risk

Statoil Petroleum AS has liabilities with variable interest rate that expose the company to cash flow risk caused by market interest rate fluctuations.

Liquidity risk

Liquidity risk is the risk that Statoil Petroleum AS will not be able to meet obligations associated with financial liabilities when due. The purpose of liquidity and current liability management is to make certain that the entity has sufficient funds available at all times to cover its financial obligations. As for the market risks Statoil manages liquidity and funding at group level, ensuring adequate liquidity to cover operational requirements.

4 Business developments

In 2008 Statoil Petroleum AS sold certain oil and gas production assets, with a carrying amount of NOK 9.1 billion, and related deferred tax liabilities with a carrying amount of NOK 4.0 billion, to Statoil ASA. The transfers were accounted for at their carrying amounts as equity transactions with no gain or loss recognition. The same assets were transferred back to Statoil Petroleum AS effective 1 January 2009, as part of the reorganisation described in note 1 Organisation and basis of presentation. This transaction was accounted for as an equity transaction with no gain or loss recognition.

5 Revenues

In presenting information on the basis of geographical areas, revenue from external customers is attributed to countries from which Statoil Petroleum AS derives revenues.

Revenues by counterparties

(in NOK million)	2009	2008
Norway	105,682	66,945
Europe	83,567	14,516
North America	903	0
Other	18	0
Revenues	190,170	81,461
(in NOK million)	2009	2008
Revenues third party	87,566	16,912
Intercompany revenues	102,604	64,549
Revenues	190,170	81,461

Statoil Petroleum AS sells most of its volumes to external customers through the parent company Statoil ASA. A significant portion of these sales are based on back to back contracts between Statoil Petroleum AS and Statoil ASA whereby Statoil Petroleum AS carries all risks related to the sale. These back to back sales contracts are presented as Revenues third party and the revenues are presented on the basis of the location of Statoil ASA's customer in the tables above. The receivables from these sales are included in the balance sheet as receivables from group companies.

6 Remuneration

The company has no employees. No salary or other remuneration has been paid to the CEO in 2009 or 2008. The CEO is employed and paid by Statoil ASA. No compensation was paid to the board of directors in 2009 or 2008.

7 Auditors' remuneration

(in NOK million, excluding VAT)	2009	2008
Audit fees	5.9	5.5
Audit related fees	0.2	0.0
Total	6.1	5.5

In addition to the figures above, audit fees and audit related fees to Ernst & Young related to Statoil Petroleum-operated licences amount to NOK 6.8 and NOK 2.8 million for 2009 and 2008, respectively.

8 Research and development expenditures

Research and Development (R&D) expenditures were NOK 1,927 million in 2009 and 561 million in 2008. R&D expenditures are partly financed by partners of Statoil Petroleum AS-operated licences. Statoil Petroleum AS' share of the expenditures has been recognised as expense in the Statement of income.

9 Financial items

Net financial items

		At 31 December
(in NOK million)	2009	2008
Net foreign exchange gains (losses)	(4,537)	2,361
Interest income from group companies	655	1,204
Interest income and other financial income	362	690
Interest and other financial income	1,017	1,894
Capitalised borrowing costs	587	90
Accretion expense asset retirement obligation	(1,953)	(530)
Interest expense to group companies	(2,286)	(3,098)
Interest expense and other financial expenses	(466)	(601)
Interest and other financial expenses	(4,118)	(4,139)
Net financial items	(7,638)	116

Non-current financial assets

		At 31 December
(in NOK million)	2009	2008
Financial investments	5	2
Financial receivables	1,323	325
Financial assets	1,328	327

Financial receivables at 31 December 2009 and 2008 are non-interest bearing and relate to long-term prepayments.

Non-current liabilities to group companies

		At 31 December
(in NOK million)	2009	2008
Interest bearing liabilities to group companies	40,000	40,000
Non-interest bearing liabilities to group companies	6,545	2,623
Liabilities to group companies	46,545	42,623

Interest bearing liabilities to group companies are due more than five years after 31 December 2009.

10 Income taxes

Income tax expense

(in NOK million)	2009	2008
Current taxes payable	81,181	40,826
Change in deferred tax	3,016	1,069
Tax effect of group contribution recognised in equity		364
Income tax expense	84,197	42,259
Uplift credit for the year	10,104	2,633

Unrecognised uplift credit amount to NOK 15.5 billion at 31 December 2009.

Reconciliation of Norwegian nominal statutory tax rate to effective tax rate

(in NOK million)	2009	2008
Income before tax	106,261	60,436
Nominal tax rate (28%)	29,753	16,922
Petroleum surtax rate (50%)	53,131	30,218
Tax effect of:
Uplift	(5,052)	(1,317)
Financial items included in 28% basis only	2,807	(969)
Tax result included in 28% basis only	(360)	45
Permanent differences	2,850	(2,774)
Income tax prior years	79	(136)
Other	989	270
Total	84,197	42,259
Effective tax rate (%)	79.2	69.9

Significant components of deferred tax assets and liabilities were as follows

		At 31 December
(in NOK million)	2009	2008
Deferred tax assets on
Current items	405	1,866
Asset retirement obligations	29,646	7,153
Other non-current items	5,956	925
Total deferred tax assets	36,007	9,944
Deferred tax liabilities on
Current items	127	176
Property, plant and equipment	82,936	22,691
Capitalised exploration expenditures and interest	18,665	5,229
Other non-current items	0	325
Total deferred tax liabilities	101,728	28,421
Net deferred tax liabilities	65,721	18,477

The movement in deferred income tax

(in NOK million)	2009	2008
Deferred income tax liabilities at 1 January	18,477	21,380
Charged to the Statement of income	3,016	1,069
Deferred income tax (assets)/liabilities on assets transferred to/from Statoil ASA	44,252	(3,972)
Acquisitions, sales and other	(24)	0
Deferred income tax liabilities at 31 December	65,721	18,477

11 Property, plant and equipment

(in NOK million)	Machinery, equipment and transportation equipment	Production plants oil and gas, incl. pipelines	Refining and manufacturing plants	Buildings and land	Assets under development	Total
Cost at 31 December 2008	0	144,694	0	299	2,248	147,241
Transfers from Statoil ASA - original cost	842	327,324	3,749	72	24,442	356,429
Additions and transfers	72	33,946	1,147	44	2,014	37,223
Disposals assets at cost	(68)	(505)	0	(99)	0	(672)
Cost at 31 December 2009	846	505,459	4,896	316	28,704	540,221
Accumulated depr. and impairment losses at
31 December 2008	0	(89,951)	0	(165)	0	(90,116)
Transfers from Statoil ASA - depreciation	(735)	(222,547)	(2,545)	(2)	0	(225,829)
Depreciation and amoritsation	(48)	(27,084)	(178)	(3)	0	(27,313)
Accumulated depr. and impairment disposed assets	68	505	0	1	0	574
Accumulated depr. and impairment losses at
31 December 2009	(715)	(339,077)	(2,723)	(169)	0	(342,684)
Carrying amount at 31 December 2009	131	166,382	2,173	147	28,704	197,537
Estimated useful lives (years)	3 - 10	*	15 - 20	20 - 33

* Depreciation according to Unit of production method, see note 2 Summary of significant accounting policies.

In 2009 capitalised interest amounted to NOK 587 million.

12 Intangible assets

(in NOK million)	Exploration expenditure	Other	Total
Cost at 31 December 2008	1,785	0	1,785
Transfers from Statoil ASA - original cost	5,034	74	5,108
Additions	3,420	3	3,423
Transfers	(740)	0	(740)
Disposals intangible assets at cost	0	(26)	(26)
Expensed exploration expenditures previously capitalised	(1,177)	0	(1,177)
Cost at 31 December 2009	8,322	51	8,373
Accumulated amortisation and impairment losses at 31 December 2008		0	0
Transfers from Statoil ASA - amortisation and impairment losses		(5)	(5)
Amortisation and net impairment losses		(2)	(2)
Accumulated amortisation and impairment losses at 31 December 2009		(7)	(7)
Carrying amount at 31 December 2009	8,322	44	8,366

13 Investments in subsidiaries and associated companies

(in NOK million)	Subsidiaries	Associated companies
Investment at 1 January 2009	69,726	999
Net income subsidiaries and associated companies	(3,883)	25
Additional paid-in equity	28,610	(165)
Distributions	(207)	(35)
Translation adjustments	(7,768)	0
Investment at 31 December 2009	86,478	824

Ownership in certain subsidiaries and associated companies (in %)

Name	%	Country of incorporation
Saga Petroleum Holding AS	100	Norway
Statoil Angola AS	100	Norway
Statoil Bahamas AS	100	Norway
Statoil Cinco AS	100	Norway
Statoil Dezassete AS	100	Norway
Statoil Dolginskaya AS	100	Norway
Statoil Energie AS	100	Norway
Statoil Greenland AS	100	Norway
Statoil Holding AS	100	Norway
Statoil International Holding AS	100	Norway
Statoil Majunga AS	100	Norway
Statoil Morocco AS	100	Norway
Statoil Oil & Gas Cuba AS	100	Norway
Statoil Oil & Gas Mozambique AS	100	Norway
Statoil Quatro AS	100	Norway
Statoil Sverige Kharyaga AB	100	Sweden
Statoil Trinta e Quatro AS	100	Norway
Statoil Turkmenistan AS	100	Norway
SCIRA Offshore Energy Limited	50	United Kingdom

Effective from 2009 Statoil Petroleum AS has changed accounting policy in the accounting for investments in subsidiaries to the equity method. The change has been applied retrospectively for 2008, the effects are reflected in the table below.

(in NOK million)	Cost method	Changes	Equity method
Effects on Balance Sheet at 31 December 2008
Shares in subsidiaries	68,423	1,303	69,726
Total assets according to Balance sheet	173,565	1,303	174,868
Reserve for valuation variances	0	(1,303)	(1,303)
Total equity according to Balance sheet	(33,754)	(1,303)	(35,057)
Effects on Statement of income for 2008
Net income from subsidiaries	0	(4,959)	(4,959)
Dividends from subsidiaries	(141)	141	0
Net income according to Statement of income	(13,359)	(4,818)	(18,177)

14 Inventories

Inventories are valued at the lower of cost and net realisable value, determined by the first-in, first-out (FIFO) method. The inventory consists of materials and spare parts and the book value at year end 2009 and 2008 amounts to NOK 50 and NOK 229 million, respectively.

15 Trade and other receivables

		At 31 December
(in NOK million)	2009	2008
Trade receivables	191	2,329
Other receivables	9,087	2,347
Trade and other receivables	9,278	4,676

Other receivables mainly consist of receivables from jointly controlled assets and prepaid expenses.

16 Equity and shareholders

(in NOK million)	2009	2008
Shareholders' equity 1 January	35,057	37,766
Increase in Share capital*	21,780	2,614
Increase in Additional paid-in capital*	26,136	7,009
Net income	22,064	18,177
Foreign currency translation adjustments	(7,255)	7,199
Group contribution	(30,000)	(40,000)
Other	(244)	2,292
Shareholders' equity 31 December	67,538	35,057

*The increases in Share capital and Additional paid-in capital relate to the transfer of ownership of the net assets on the Norwegian Continental Shelf (NCS) from Statoil ASA to Statoil Petroleum AS. For more details, see note 1 Organisation and basis of presentation.

Share capital consists of 17,424,000 shares at a nominal value of NOK 1,500. All shares are owned by Statoil ASA.

17 Asset retirement obligations and other provisions

(In NOK million)
Asset retirement obligations at 1 January 2008			10,434
Liabilities incurred/revision in estimates			498
Transfer of licenses to Statoil ASA			(879)
Accretion			530
Amounts used and charged against provision			(441)
Asset retirement obligations at 31 December 2008			10,142
Current portion of asset retirement obligations			544
Analysis of provisions at 31 December 2008
Non-current portion of asset retirement obligations			9,598
Other provisions			223
Total asset retirement obligations and other provisions at 31 December 2008			9,821
(in NOK million)	Asset retirement obligations	Other provision	Total Provisions
Non-current portion at 1 January 2009	9,598	223	9,821
Current portion at 1 January 2009	899	0	899
Provisions at 1 January 2009	10,497	223	10,720
Transfer of licenses from Statoil ASA	24,068	1,728	25,796
Liabilities incurred/revision in estimates	324	(43)	281
Amounts used and charged against provision	(522)	(48)	(570)
Effects of change in the discount rate	2,562	0	2,562

Accretion	1,953	0	1,953
Carrying amount at 31 December 2009	38,882	1,860	40,742
Current portion at 31 December 2009	499	105	604

Non-current portion at ³¹ December ²⁰⁰⁹ 38,383 ^{1 755} 40,138 A majority of expenditures related to asset retirement obligations are currently expected to be paid in the period between 2015 and 2025, and only a minor portion of expenditures are expected to be paid in the next five years. The timing depends primarily on when the production ceases at the various facilities whereas the amounts to be paid depend on future development in technologies, regulations, rates and availability of necessary support vessels. The provisions for the expenditures are estimated using existing technology. Assumed vessel rates and all other input prices are estimates of rates and prices at the time of the expenditures and the calculated future expenditures have been discounted using nominal pre-tax discount rates. Input prices in other currencies than the functional currency of the individual entities have been converted into functional currency at the exchange rates ruling at the date of the estimate calculations.

Obligations related to environmental remediation and cleanup related to oil and gas producing assets are included in the estimated asset retirement obligations.

18 Trade and other payables

	At 31 December
(in NOK million)	2009	2008
Trade payables	1,324	423
Non-trade payables, accrued expenses and provisions	12,779	5,384
Trade and other payables	14,103	5,807

Non-trade payables consist mainly of provisions for accrued expenses relating to the licence activity.

19 Leases

Statoil Petroleum AS leases certain assets, notably vessels and drilling rigs.

Statoil Petroleum AS has entered into certain operational lease contracts for a number of drilling rigs as of 31 December 2009. The remaining significant contracts' terms range from three months to four years. Certain contracts contain renewal options. Rig lease agreements are for the most part based on fixed day rates. Statoil Petroleum AS's rig leases have been entered into in order to ensure drilling capacity for sanctioned projects and planned wells and to secure long-term strategic capacity for future exploration and production drilling. Certain rigs have been subleased in whole or for parts of the lease term for the most part to Statoil Petroleum AS-operated licenses on the Norwegian Continental Shelf (NCS). These leases are shown gross as operating leases in the table below. However, for rig leases where the joint venture is the original lessee, Statoil Petroleum AS only includes its proportional share of the rig lease.

In 2009, net rental expense was NOK 8,563 million (NOK 2,243 million in 2008) of which minimum lease payments were NOK 10,249 million (NOK 3,011 million in 2008) and sublease payments received were NOK 1,686 million (NOK 769 million in 2008).

The information in the table below shows future minimum lease payments under non-cancellable leases at 31 December 2009. In addition, Statoil Petroleum AS has entered into subleases of certain of the leased assets providing a total future rental income of NOK 1,314 million (NOK 349 million in 2008). The significant part of the sublease amount as at 31 December 2009 relates to 2010.

(in NOK million)	Operating leases
2010	9,702
2011	7,244
2012	4,862
2013	2,979
2014	1,300
Thereafter	1,265
Total future minimum lease payments	27,352

20 Other commitments and contingencies

Contractual commitments

(in NOK million)	2010	2011	Thereafter	Total
Joint Venture related:
Construction in progress	3,322	996	393	4,711
Property, plant and equipment and other investments	1,609	68	3	1,680
Subtotal joint venture related commitments	4,931	1,064	396	6,391
Non Joint Venture related:
Construction in progress	41	0	0	41
Total	4,972	1,064	396	6,432

The contractual commitments reflect Statoil Petroleum AS' share and mainly comprise construction and acquisition of property, plant and equipment.

Other long-term commitments

Statoil Petroleum AS has entered into agreements for pipeline transportation for most of its prospective gas sales contracts. These agreements ensure the right to transport the production of gas through the pipelines, but also impose an obligation to pay for booked capacity. In addition, the company has entered into certain obligations for other forms of transport capacity as well as terminal, processing, storage and entry capacity commitments.

Obligations payable by Statoil Petroleum AS to entities accounted for using the equity method are included gross in the tables below. As regards assets (e.g. pipelines) that the company accounts for by including its share of assets, liabilities, income and expenses (capacity costs) on a line-by-line basis in the financial statements, the amounts in the table include the net commitment payable by Statoil Petroleum (gross commitment less Statoil Petroleum's ownership share).

The following table outlines nominal minimum obligations for future years. Corresponding expenditures for 2009 were NOK 6 billion. Transport capacity and other contractual commitments at 31 December 2009:

(in NOK million)
2010	4.929
2011	4,613
2012	4,201
2013	4,059
2014	3,114
Thereafter	18,537
Total	39,453

Guarantees

With effect from 1 January 2009, Statoil ASA transferred the ownership of its NCS net assets to Statoil Petroleum AS. Following the transfer, all NCS net assets are owned by Statoil Petroleum AS. Effective from the same date, Statoil Petroleum AS became co-obligor or guarantor of existing debt securities and other loan arrangements of Statoil ASA. As co-obligor, Statoil Petroleum AS assumes and agrees to perform, jointly and severally with Statoil ASA, all payment and covenant obligations for this debt. During 2009, Statoil ASA executed three additional issues of US registered debt securities and three additional issues of debt securities listed on the London Stock Exchange, all of which are guaranteed by Statoil Petroleum AS. At year end 2009 the carrying value of debts for which Statoil Petroleum AS is the co-obligor or guarantor, mainly for Statoil ASA, is NOK 27.5 billion and NOK 56.7 billion, respectively.

Statoil Petroleum AS has guaranteed certain recoverable reserves of crude oil in the Veslefrikk field on the NCS as part of an asset exchange with Petro Canada in 1996. Under the guarantee, Statoil Petroleum AS is obligated to deliver indemnity reserves to Petro Canada in the event that recoverable reserves prove lower than a specified volume. At year end 2009 the value of the remaining volume covered by the guarantee has been estimated to a total of NOK 1.7 billion at current market prices. The provision for this guarantee at year-end amounts to NOK 0.3 billion.

Under the Norwegian public limited companies act section 14-11, Statoil Petroleum AS and Norsk Hydro are jointly and severally liable for certain guarantee commitments entered into by Norsk Hydro prior to the merger between Statoil and Hydro Petroleum in 2007. The total amount that Statoil Petroleum AS is jointly liable for is approximately NOK 3.8 billion with terms extending until 2050. As of the current date, the probability that these guarantee commitments will impact Statoil Petroleum AS is deemed to be remote. No liability has been recognised in the financial statements at year end 2009.

Other commitments and contingencies

As a condition for being awarded oil and gas exploration and production licenses, participants may be committed to drill a certain number of wells. At the end of 2009, Statoil Petroleum AS was committed to participating in 16 wells with an average ownership interest of approximately 53%. Statoil Petroleum AS' share of estimated expenditures to drill these wells amounts to approximately NOK 3.9 billion. Additional wells that Statoil Petroleum AS may become committed to participating in depending on future discoveries in certain licenses are not included in these numbers.

Statoil ASA issued a declaration to the Norwegian Ministry of Petroleum and Energy (MPE) in 1999 in connection with a dispute between four Åsgard partners and Statoil related to the construction of new facilities for the Åsgard development at the Kårstø Terminal. The declaration confirmed that the MPE will receive similar treatment as the four Åsgard partners with respect to the disputed issues. As of 1 January 2009 and following the group internal reorganisation of the NCS assets, the Statoil group's activity and assets related to this declaration belong to Statoil Petroleum AS. On the basis of the declaration, the MPE alleged the right to compensation and initiated legal proceedings against Statoil on 29 April 2008 in a writ involving a multicomponent claim. The aggregate principal exposure for the claim is estimated to be between NOK 4 and 7 billion after tax. Following a verdict in Stavanger district court on 15 January 2010, Statoil and the MPE on 5 March 2010 reached an amicable settlement of the case in which both parties waived their rights to appeal the court verdict. Under the settlement Statoil agreed to pay the MPE a cash compensation of NOK 500 million after tax, and NOK 375 million in pre-tax interest, corresponding to NOK 270 million after tax.

During the fourth quarter of 2008 ExxonMobil, the final Åsgard partner at the time of the original dispute, issued a similar writ with a compensation claim approximating an estimated exposure of up to NOK 1 billion after tax. The dispute with ExxonMobil was settled in October 2009. The impact of this settlement on the financial statements was not material.

Statoil Petroleum AS was informed on 26 September 2007 of possible consultancy agreements and transactions associated with Hydro's petroleum activities in Libya, which were transferred to Statoil as of 1 October 2007 as part of the merger with Hydro Petroleum, and which could be in conflict with applicable Norwegian and US anti-corruption legislation. Following a preliminary assessment by Statoil, an external review of the relevant aspects was initiated. The external US and Norwegian legal counsels that have conducted the review delivered their report to Statoil ASA's CEO on 6 October 2008. The report has also been delivered to the National Authority for Investigation and Prosecution of Economic and Environmental Crime in Norway (Økokrim), the US Department of Justice, the US Securities and Exchange Commission and Libyan authorities. The report does not draw any legal conclusions. In accordance with the mandate for the review, the report entails the facts relevant to applicable Norwegian and US anti-corruption legislation to which Statoil ASA may be subject as a result of the merger. Økokrim informed on 15 May 2009 that there will be no investigation related to the international activities of former Hydro Oil & Energy. Neither US authorities nor Libyan authorities have as of today initiated any steps in relation to the matters described in the investigation reports.

During the normal course of its business Statoil Petroleum AS is involved in legal proceedings, and several other unresolved claims are currently outstanding. The ultimate liability or asset, respectively, in respect of such litigation and claims cannotbe determined at this time. Statoil Petroleum AS has provided in its accounts for probable liabilities related to litigation and claims based on the Company's best judgement. Statoil Petroleum AS does not expect that the financial position, results of operations or cash flows will be materially affected by the resolution of these legal proceedings.

21 Related parties

The Norwegian State is the majority shareholder of Statoil ASA which is the parent company of Statoil Petroleum AS and also holds major investments in other entities. This ownership structure means that Statoil Petroleum AS participates in transactions with many parties that are under a common ownership structure and therefore meet the definition of a related party. All transactions are considered to be on arms-length terms.

In relation to its ordinary business operations such as pipeline transport, gas storage and processing of petroleum products, Statoil Petroleum AS also has regular transactions with certain affiliated entities. Such transactions are carried out at arms-length terms, and are included within the applicable captions in the statement of income.

22 Subsequent events

There are no material subsequent events as of 16 March 2010.

23 Reserves (unaudited)

The company's proved oil and gas reserves are estimated by the parent company's reservoir engineers on the basis of industry standards and governed by criteria established by regulations of the United States Securities and Exchange Commission (SEC). At the end of the year the company's proved reserves amounted to approximately 695 million Sm3 o.e (2008: 217 million Sm3 o.e). Volumes transferred from Statoil ASA at 01.01.2009 amounted to 503 million Sm3 o.e.

Proved reserves will be produced in the period from 2010 to 2030.

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producable from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations.

Stavanger, 16 March 2010 the board of directors of statoil petroleum as eldar sætre chair

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