statoil petroleum as - annual report 2012 · statoil petroleum as is paying nok 31.0 billion in tax...

Statoil Petroleum AS - annual report 2012

Statoil Petroleum AS - annual report 2012

Board of directors' report 1Profit and loss analysis 2Our business 3Cash flows 4Liquidity and capital resources 4Research and development 5Financial risks 5Outlook and market view 5Health, safety and the environment 6People and the organisation 6Environment and climate 6Society 6Board developments 7

Financial statements 8Notes to the financial statements for Statoil Petroleum AS 11

1 Organisation and basis of presentation 112 Significant accounting policies 113 Acquisitions and dispositions 154 Financial risk management and derivatives 165 Revenues 166 Remuneration 177 Auditors' remuneration 178 Research and development expenditures 179 Financial items 1810 Income taxes 1911 Property, plant and equipment 2112 Intangible assets 2213 Investments in subsidiaries and other equity accounted companies 2214 Financial assets and liabilities 2315 Trade and other receivables 2416 Equity and shareholders 2417 Provisions 2518 Trade and other payables 2619 Leases 2620 Other commitments and contingencies 2621 Related parties 2722 Reserves (unaudited) 28

Independent auditor's report 29

Board of directors' report

Statoil Petroleum AS delivered strong cash flows despite somewhat lower net operating income in 2012. The financial position is solid and the company is well placed to maintain its production on the NCS, and to continue to deliver shareholder value. Net operating income was NOK 175.6 billion in 2012, down 3% compared to NOK 181.4 billion in 2011. The decrease was mainly attributable to decreased net income from subsidiaries due to substantial gains from sale of assets in 2011. Net income decreased by 23% in 2012 compared to 2011, largely affected by the decrease in net operating income and a higher effective tax rate. Strategic portfolio optimisation in 2012, including the farm down agreement of NCS assets with Centrica (closed in the second quarter of 2012) and the agreement with Wintershall announced in November 2012 (pending governmental approval), further underpin our ability to redeploy capital and create value. Statoil Petroleum AS is paying NOK 31.0 billion in tax free group contribution to the parent company, Statoil ASA. Statoil Petroleum AS was founded in 2007 and is domiciled in Norway. Statoil Petroleum's business consists principally of the exploration, production and transportation of petroleum and petroleum-derived products. In accordance with the Norwegian Accounting Act §3-7, Statoil Petroleum AS does not prepare consolidated financial statements. For further information, see the notes to the Financial statements and Statoil ASA's annual report 2012.

Statoil Petroleum AS, Statutory report 2012 1

Profit and loss analysis

Net operating income was NOK 175.6, compared to NOK 181.4 billion in 2011. The 3% decrease was mainly attributable to decreased net income from subsidiaries.

Condensed financial statements NGAAP For the year ended 31 December (in NOK billion) 2012 2011 Change

Revenues and other income

Revenues 246.8 241.6 2%

Net income (loss) from subsidiaries and other equity accounted companies (2.2) 10.7 >(100%)

Other income 7.8 9.0 (13%)

Total revenues and other income 252.4 261.4 (3%)

Operating expenses

Purchases [net of inventory variation] (6.3) (8.3) (23%)

Operating expenses and selling, general and administrative expenses (36.2) (35.2) 3%

Depreciation, amortisation and net impairment losses (30.7) (31.3) (2%)

Exploration expenses (3.5) (5.1) (31%)

Net operating income 175.6 181.4 (3%)

Net financial items (5.1) (3.9) 31%

Income before tax 170.5 177.5 (4%)

Income tax (125.9) (119.9) 5%

Net income 44.6 57.6 (23%)

The statements below are related to developments in 2012 compared to 2011. Revenues and other income decreased by 3%, mainly attributable to a drop in net income from subsidiaries and other equity accounted companies due to substantial gains from sale of assets in 2011 and decreased production of liquids. The decrease was partly offset by increased production of gas and higher average prices measured in NOK for both liquids and gas. Purchases [net of inventory variation] amounted to NOK 6.3 billion in 2012. The 23% decrease was mainly due to lower volumes of gas purchased, partly offset by higher prices of gas (measured in NOK). Operating expenses include field production and transport systems costs related to the company's share of oil and natural gas production while selling, general and administrative expenses include expenses related to the sale and marketing of our products. Operating expenses and selling, general and administrative expenses increased by 3% mainly because of increased operating plant costs related to higher maintenance activity and well maintenance at some fields. Depreciation, amortisation and net impairment losses includes depreciation of production installations and transport systems, depletion of fields in production, amortisation of intangible assets and impairment of capitalised exploration expenditure. It also includes impairment of long-lived assets and reversals of impairment. These expenses amounted to NOK 30.7 billion in 2012. The 2% decrease was mainly due to increased reserves estimates and reduced ownership share following the Heidrun redetermination, partly offset by an impairment loss. Exploration expenditures are capitalised to the extent that exploration efforts are considered successful, or pending such assessment. Otherwise, such expenditures are expensed. The exploration expense consists of the expensed portion of our exploration expenditure in 2012 and write-offs of exploration expenditure capitalised in previous years. Exploration expenses decreased by 31% due to lower drilling activity, high seismic activity in 2011 and lower exploration expenditures capitalised in previous periods being expensed in this period. Net operating income was NOK 175.6 billion in 2012, down 3%. The decrease was mainly attributable to lower revenues and other income of NOK 9.0 billion, partly offset by decreased purchases [net of inventory variation] and exploration expenses.

2 Statoil Petroleum AS, Statutory report 2012

Net financial items amounted to a loss of 5.1 billion in 2012. The NOK 1.2 billion negative change stem mainly from net foreign exchange losses, partly offset by decreased interest expenses and other financial expenses. Income taxes were NOK 125.9 billion in 2012, equivalent to a tax rate of 74%, compared to NOK 119.9 billion in 2011, equivalent to a tax rate of 68%. The higher tax rate in 2012 compared to 2011 is mainly explained by capital gains on sale of assets in 2011 with lower than average tax rates. Net income decreased by 23%, primarily due to decreased operating income caused by decreased net income from subsidiaries and other equity accounted companies and a higher effective tax rate. The net income of NOK 44.6 billion will be allocated to group contribution to Statoil ASA of NOK 31.0 billion and NOK 13.6 billion to retained earnings. The company's distributable equity after re-allocations amounts to NOK 46.0 billion. In accordance with Section 3-3 of the Norwegian Accounting Act, the board of directors confirms that the financial statements have been prepared on the basis of the going concern assumption.


Our business

Statoil Petroleum AS is a wholly owned subsidiary of Statoil ASA, and operates approximately 71% of all oil and gas production on the NCS. Effective 1 January 2009, Statoil Petroleum AS received certain assets and assumed certain liabilities from its parent company with a net amount of NOK 47.9 billion. The transfer included all of the parent company's exploration and production assets and liabilities on the Norwegian continental shelf (NCS) and related transportation systems, processing plants and terminals. Following the restructuring of assets and liabilities within the Statoil group, Statoil Petroleum AS has become the co-obligor or guarantor of certain parent company liabilities. Through its subsidiaries and other equity accounted companies, Statoil Petroleum AS owns additional licenses in oil and gas fields internationally. The company also owns oil and gas processing and transportation facilities in Norway. Statoil Petroleum AS has no employees, but purchases necessary services from the parent company and other companies in the Statoil group.

Cash flows

Cash flows from underlying operations, less tax payments, contributed NOK 94.0 billion in 2012. Cash flows used in investing activities amounted to NOK 76.9 billion.

Condensed cash flows statement For the year ended 31 December (in NOK billion) 2012 2011 Change

Cash flows from underlying operations 201.2 190.7 10.5

Cash flows from (to) changes in working capital 3.3 (2.3) 5.7

Taxes paid (111.9) (107.7) (4.2)

Other changes 1.4 0.8 0.6

Cash flows provided by operating activities 94.0 81.5 12.5

Cash flows used in investing activities (76.9) (61.9) (15.0)

Group contribution (49.0) (27.0) (22.0)

Increase (decrease) in financial receivables and liabilities to/from Statoil group companies* 31.9 7.4 24.5

Cash flows used in financing activities (17.1) (19.6) 2.5

Net increase (decrease) in cash and cash equivalents 0.0 0.0 0.0

* Including deposits in Statoil group’s internal bank arrangement

Statoil Petroleum AS' primary source of cash flows is cash flows provided by operating activities. The major factors impacting changes between periods are the level of profitability reflected in cash flows from underlying operations, taxes paid and changes in working capital. In 2012, cash flows provided by operating activities amounted to NOK 94.0 billion, an increase of NOK 12.5 billion compared to NOK 81.5 billion in 2011. The increase was largely driven by an increase in cash flows from underlying operations, affected by increased production of gas and higher average prices measured in NOK for both liquids and gas. The increase was partly offset by higher taxes paid of NOK 4.2 billion between the two years. Cash flows provided by operating activities was NOK 81.6 billion lower than net operating income in 2012, and the principally reason for this significant difference is the NOK 111.9 billion payment of taxes in 2012. Cash flows used in investing activities was NOK 76.9 billion in 2012 compared to NOK 61.9 billion in 2011. The increase was mainly related to an increase in non-current loans granted and other non-current items and higher additions to PP&E and intangible assets, partly offset by increased proceeds from sales and businesses (primarily from the sale of Gassled in 2011 and the NCS assets to Centrica in 2012), and repayment of capital contribution. Cash flows used in financing activities was NOK 17.1 billion in 2012, compared to NOK 19.6 billion in 2011. The decrease of NOK 2.5 billion was due to aNOK 24.5 billion positive change in cash flows to/from Statoil group companies related to financial receivables and liabilities, partly offset by higher cash payments related to group contribution of NOK 22.0 billion.


Liquidity and capital resources

Statoil Petroleum AS has maintained a solid financial position through 2012. Our annual cash flow from operations is highly dependent on oil and gas prices and our levels of production. It is only influenced to a small degree by seasonality and maintenance turnarounds. Fluctuations in oil and gas prices, which are outside our control, will cause fluctuations in our cash flows. Statoil Petroleum AS' liquidity and debt position are managed at Statoil group level.

Research and development

Statoil is a technology intensive group of companies and research and development is an integral part of its strategy. Improved oil and gas recovery and improved drilling and well solutions are important to successfully fight declining production from mature fields. The research and development work is managed at a Statoil group level, and is in close cooperation with universities, research institutions, other operators and the supplier industry. Statoil has achieved some of the petroleum industry's highest recovery factors on the NCS by combining scientific and engineering capabilities and boldly introducing new technology. As a part of the Statoil group, we contribute to the group's intention to further advance the most important technologies to meet forthcoming improved oil recovery ambitions. Research and development expenditures were NOK 2.2 billion in 2012, compared to NOK 1.9 billion in 2011.


Financial risks

The financial results are very dependent upon the prices of crude oil and natural gas, the USDNOK exchange rate and realised refining margins. The financial results of operations largely depend on a number of factors, most significantly those that affect the price we receive in NOK for our sold products. Specifically, such factors include the level of crude oil and natural gas prices, trends in the exchange rate between the USD and NOK, equity production and entitlement sales volumes of liquids and natural gas, available petroleum reserves, and Statoil Petroleum AS', as well as its partners' expertise and cooperation in recovering oil and natural gas from those reserves, and changes in the portfolio of assets due to acquisitions and disposals. The results will also be affected by trends in the international oil industry, including possible actions by governments and other regulatory authorities in the jurisdictions in which the group operates. Also possible or continued actions by members of the Organization of Petroleum Exporting Countries (Opec) that affect price levels and volumes, refining margins, increasing cost of oilfield services, supplies and equipment, increasing competition for exploration opportunities and operatorships, and deregulation of the natural gas markets may cause substantial changes to the existing market structures and to the overall level and volatility of prices. Fluctuating foreign exchange rates can have a significant impact on our operating results. Our revenues and cash flows are mainly denominated in, or driven by US dollars, while our operating expenses and income taxes payable largely accrue in NOK. We seek to manage this currency mismatch by issuing or swapping long-term debt in USD. This debt policy is an integrated part of our total risk management programme. We also engage in foreign currency hedging in order to cover our non-USD needs, which are primarily in NOK. We manage the risk arising from our interest rate exposure through the use of interest rate derivatives, primarily interest rate swaps, based on a benchmark for the interest reset profile of our long-term debt portfolio. In general, an increase in the value of USD in relation to NOK can be expected to increase our reported earnings.

Outlook and market viewStatoil Petroleum AS expects to maintain and increase its production level on the NCS in the short to medium term by exploring for new discoveries and maturing projects from its large portfolio of existing discoveries. Statoil Petroleum AS expects prices for crude oil to continue to be volatile in the short to medium term, but at a relatively high level. Oil product prices will in general follow those of crude oil. Supply of natural gas liquids (NGL) is expected to increase significantly, especially as supply associated with new US shale gas production reaches the market. European NGL production is likely to remain high as volumes associated with oil fields are replaced by NGL volumes from non-associated production. Statoil Petroleum AS' income could vary significantly with changes in commodity prices, even if volumes remain stable through the year. There is a small seasonal effect on volumes in the winter and summer seasons due to normally higher off-takes of natural gas during cold periods. There is normally an additional small seasonal effect on volumes as a result of the higher maintenance activity level on offshore production facilities during the second and third quarters each year, since generally better weather conditions allow for more maintenance work. These forward-looking statements reflect current views about future events and are, by their nature, subject to significant risks and uncertainties because they relate to events and depend on circumstances that will occur in the future.

Health, safety and the environmentStatoil Petroleum AS' objective is to operate with zero harm to people and the environment and in accordance with the Statoil group's principles for sustainable development. Safe and efficient operations is our first priority. The board of directors emphasises the importance of understanding factors that create risks in order to avoid major accidents. We work systematically to mitigate risks that are critical to operating safely and reliably, and continuous improvement for better safety results has high attention in all our business areas.


People and the organisationStatoil Petroleum AS has no employees, and relies on the services provided by other companies in the Statoil group and the Statoil group's principles and practices pertaining to people and organisation.

Environment and climate

The company is subject to group-wide policies and programmes pertaining to environmental and climate issues. Our activities, from exploration through construction and operation of facilities and to the end use of our products, have potential to affect the environment. The impact may be due to emissions, discharges or resource use. Statoil Petroleum AS is committed through Statoil group's climate policy to contribute to sustainable development. We recognise that there is an accepted link between the use of fossil fuels and man-made climate change, and the climate policy takes into account the need for proactively combating global climate change in our operations, as well as evaluating the company's efforts on renewables and clean technology. Statoil Petroleum AS relies in full on the Statoil group's climate policy which sets out the principles for addressing the challenge of global warming and its ambition of maintaining the position as an industry leader in relation to sustainable development. Statoil Petroleum AS is continuously focusing on energy efficiency on our installations. Requirements for energy efficiency are incorporated in governing documents. We continuously monitor our emissions and several modification projects for further reductions are being implemented. The group-wide indicators to measure environmental performance are oil spills, emissions of carbon dioxide and nitrogen oxides, energy consumption and the recovery rate for non-hazardous waste. The volume of accidental oil spills increased from 9.0 cubic meters in 2011 to 12.8 cubic meters in 2012. Carbon dioxide emissions have increased from 8.9 million tonnes in 2011, to 9.1 million tonnes in 2012. Nitrogen oxides emissions have increased from 35.5 thousand tonnes in 2011 to 36.0 thousand tonnes in 2012. Energy consumption has increased from 40.8 TWh in 2011 to 42.0 TWh in 2012. The recovery rate for non-hazardous waste has decreased from 96% in 2011 to 94% in 2012.

Society

Growing and sustaining our business depends on our ability to establish enduring and mutually beneficial relationships with the societies in which we operate. Wherever we operate, we make decisions based on how they affect our interests and those of the societies around us. Stakeholders include governments, communities, partners, contractors and suppliers, employees, customers and investors. It is Statoil Petroleum AS' responsibility to create value for its stakeholders. This is not only an ethical imperative. Living up to these responsibilities is required to support long-term profitability and consistency in complex environments. In line with our corporate policy on social responsibility, we are committed to: making decisions based on how they affect the group's interests and the interests of the affected societies.

ensuring transparency, anti-corruption, and respect for human rights and labour standards. generating positive spin-offs from core activities to help meet the aspirations of the societies in which the group operates.

Board developments

At present, Statoil Petroleum AS' board of directors consists of 5 members. The composition of the board has remained unchanged during 2012. The board held nine meetings in 2012 and the average meeting attendance was 89%.

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Financial statements STATEMENT OF INCOME STATOIL PETROLEUM AS - NGAAP

For the year ended 31 December (in NOK million) Note 2012 2011

Revenues 5 246,790 241,597

Net income (loss) from subsidiaries and other equity accounted companies 13 (2,198) 10,738

Other income 3 7,831 9,028

Total revenues and other income 252,423 261,363

Purchases [net of inventory variation] (6,344) (8,252)

Operating expenses (34,550) (34,062)

Selling, general and administrative expenses (1,655) (1,169)

Depreciation, amortisation and net impairment losses 11, 12 (30,679) (31,345)

Exploration expenses (3,546) (5,135)

Net operating income 175,649 181,400

Net financial items 9 (5,132) (3,926)

Income before tax 170,517 177,474

Income tax 10 (125,941) (119,875)

Net income 44,576 57,599

BALANCE SHEET STATOIL PETROLEUM AS - NGAAP

At 31 December At 31 December(in NOK million) Note 2012 2011

Property, plant and equipment 11 241,340 215,531

Intangible assets 12 5,613 7,695

Investments in subsidiaries and other equity accounted companies 13 144,868 112,893

Prepayments and financial receivables 14 2,225 1,009

Receivables on group companies 449 105

Total non-current assets 394,495 337,233

Trade and other receivables 15 10,804 25,461

Receivables on group companies 14 24,579 31,251

Total current assets 35,383 56,712

TOTAL ASSETS 429,878 393,945


BALANCE SHEET STATOIL PETROLEUM AS - NGAAP

At 31 December At 31 December(in NOK million) Note 2012 2011

Share capital 26,136 26,136

Additional paid-in capital 14,035 14,035

Retained earnings 53,369 38,233

Reserves for valuation variances 0 1,310

Other reserves (7,413) (678)

Total equity 16 86,127 79,036

Deferred tax liabilities 10 58,551 55,596

Liabilities to group companies 14 67,735 68,619

Provisions 17 73,298 63,828

Total non-current liabilities 199,584 188,043

Trade and other payables 18 15,172 16,672

Current tax payable 10 58,961 50,412

Liabilities to group companies 14 70,034 59,782

Total current liabilities 144,167 126,866

Total liabilities 343,751 314,909

TOTAL EQUITY AND LIABILITIES 429,878 393,945


STATEMENT OF CASH FLOWS STATOIL PETROLEUM AS - NGAAP

(in NOK million) 2012 2011


Adjustments for:

Depreciation, amortisation and impairment losses 30,679 31,346

Exploration expenditures written off 788 1,078

(Gains) losses on foreign currency transactions and balances (337) 0

(Gains) losses on sales of assets and other items (443) (19,161)

(Increase) decrease in inventories (19) 0

(Increase) decrease in trade and other receivables 956 (1,657)

Increase (decrease) in trade and other payables (134) 4,065

(Increase) decrease in receivables/liabilities to/from group companies 2,519 (4,741)

Taxes paid (111,917) (107,680)

(Increase) decrease in non-current items related to operating activities 1,375 756

Cash flows provided by operating activities 93,984 81,480

Additions to property, plant and equipment (48,165) (40,076)

Exploration expenditures capitalised and additions to other intangibles (2,397) (2,572)

(Increase) decrease in non-current loans granted and other non-current items (60,606) (19,616)

Proceeds from sale of assets and businesses, and repayment of capital contribution 34,289 376

Cash flows used in investing activities (76,879) (61,888)

Group contribution (49,000) (27,000)

Increase (decrease) in financial receivables and liabilities to/from Statoil group companies* 31,915 7,408

Cash flows used in financing activities (17,085) (19,592)

Net increase (decrease) in cash and cash equivalents 20 0

Cash and cash equivalents at the beginning of the period 0 0

Cash and cash equivalents at the end of the period 20 0

*Including deposits in Statoil group’s internal bank arrangement.


Notes to the financial statements for Statoil Petroleum AS


1 Organisation and basis of presentationStatoil Petroleum AS was founded in 2007 as a demerger of Norsk Hydro Produksjon AS, prior to and in connection with the merger between Statoil ASA and the oil and gas activities of Norsk Hydro ASA (Hydro Petroleum), which was effective 1 October 2007. The company is incorporated and domiciled in Norway. The address of its registered office is Forusbeen 50, N-4035 Stavanger, Norway. Statoil Petroleum AS' business consists principally of the exploration, production and transportation of petroleum and petroleum-derived products. The Statoil group's net assets on the Norwegian continental shelf (NCS) are owned by Statoil Petroleum AS. 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 2012. The Consolidated financial statements can be obtained by contacting Statoil ASA, Forusbeen 50, 4035 Stavanger or from the website, www.statoil.com. 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 Norwegian kroner (NOK).

2 Significant accounting policiesStatement 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. The Statement of cash flows has been prepared in accordance with the indirect method. 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 through including Statoil Petroleum AS' 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 at 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 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 license holders, and on an unfunded basis for projects at its own risk. The company's own share of the license holders' funding and the total costs of the unfunded projects are considered for capitalisation under the applicable NGAAP requirements. Subsequent to initial recognition, any 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 when it relates to items recognised directly in equity, in which case it is recognised in equity. Current tax consists of the expected tax payable on the taxable income for the year and any adjustment to tax payable for 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 recognised in the period in which they are earned or incurred, and are presented within Net 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 and their respective tax bases, subject to the initial recognition exemption. The amount of deferred tax 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 income will be available against which the asset can be utilised. In order for a deferred tax asset to be recognised based on future taxable income, 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 (Norwegian Petroleum Tax), currently levied at 50%, is levied on profits derived from petroleum production and pipeline transportation on the NCS. 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 (uplift) is computed on the basis of the original capitalised cost of offshore production installations at a rate of 7.5% per year. 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. The uplift benefit is recognised 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 expenditures 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 expenditures within Intangible assets until the well is complete and the results have been evaluated. If, following the 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 (carried interests), these expenditures are reflected in the financial statements as and when the exploration and development work progresses. The company reflects exploration and evaluation asset dispositions (farm-out arrangements) when the farmee correspondingly undertakes to fund carried interests as part of the of the consideration on a historical cost basis with no gain or loss recognition. A gain or loss related to a post-tax based disposition of assets on the NCS includes the release of tax liabilities previously computed and recognised related to the assets in question. The resulting gross gain or loss is recognised in full in the line item Other income in the Statement of income. 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. Capitalised exploration and evaluation expenditures, 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 Assets under development (Property, plant and equipment) at the time of sanctioning of the development project.


Property, plant and equipment Property, plant and equipment are reflected 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 an asset retirement 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 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 regularly scheduled major maintenance programs planned and carried out at recurring intervals exceeding one year, are capitalised and amortised over the period to the next scheduled inspection and overhaul. All other maintenance costs are expensed as incurred. Capitalised exploration and evaluation expenditures, 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. Such capitalised costs 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 assets the company has established separate depreciation categories which as a minimum distinguish between platforms, pipelines, and wells. 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 de-recognised 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 de-recognition 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 for which the company assumes substantially all the risks and rewards of the ownership are reflected as finance leases within Property, plant and equipment and Bonds, bank loans and finance lease liabilities. All other leases are classified as operating leases and the costs are charged to the relevant operating expense related caption on a straight line basis over the lease term, unless another basis is more representative of the benefits of the lease to the company. The company distinguishes between lease and capacity contracts. Lease contracts provide the right to use a specific asset for a period of time, while capacity contracts confer on the company the right to and the obligation to pay for certain volume capacity availability related to transport, terminal use, 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 aspecific asset are not considered by the company to qualify as leases for accounting purposes. Capacity payments are reflected as Operating expenses in the Statement 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 mainly include expenditure on the exploration for and evaluation of oil and natural gas resources. Expenses related to the drilling of exploration wells are initially capitalised as intangible assets pending determination of whether potentially economic oil and gas reserves have been discovered by the drilling effort. This evaluation is normally finalised within one year after well completion. Exploration wells that discover potentially economic quantities of oil and natural gas remain capitalised as intangible assets during the evaluation phase of the find, see further information under the "Oil and gas exploration and development expenditures" section above. Intangible assets relating to expenditures on the exploration for and evaluation of oil and natural gas resources are not amortised. When the decision to develop a particular area is made, its intangible exploration and evaluation assets are reclassified to Property, plant and equipment. Certain balance sheets of subsidiaries and associated companies reflected through the equity method include goodwill, which is depreciated over ten years on a straight line basis. The related depreciation expense is included in Statoil Petroleum AS' Statement of income under Net income (loss) from subsidiaries and other equity accounted companies. Financial assets Trade and other receivables are carried at the original invoice amount, less a provision for doubtful receivables, which is made when there is objective evidence that the company will be unable to recover the balances in full. Financial assets are presented as current if these contractually will expire or otherwise are expected to be recovered within 12 months after the balance sheet date, or if these are held for the purpose of being traded.


Derivative financial instruments Commodity-based derivatives traded on organised exchanges are valued at fair market value and the resulting gains and losses are recognised in the Statement of income. Other commodity-based derivatives such as over-the counter (OTC) instruments are valued according to the lower of cost or market principle. Under NGAAP, elements with derivative characteristics (embedded derivatives) are not separately identified nor reflected at fair value. Impairment of intangible assets and of 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 expenditures, 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 applied are based on reasonable and supportable assumptions and represent management's best estimates of the range of economic conditions that will exist over the remaining useful life of the cash generating assets, set down in the Statoil group's most recently approved long-term plans. The long-term plans are reviewed by corporate management and updated at least annually. The plans cover a 10-year period and reflect expected production volumes for oil and natural gas in that period. For assets and cash generating units with an expected useful life or timeline for production of expected reserves extending beyond 10 years, the related cash flows include project or asset specific estimates reflecting the relevant period. Such estimates are established on the basis of Statoil group principles and group assumptions consistently applied. In performing a value-in-used-based impairment test, the estimated future cash flows are adjusted for risks specific to the asset and discounted using a real post-tax discount rate which is based on Statoil's post-tax weighted average cost of capital (WACC). 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 major capital expenditure can be justified or where the economic viability of that major capital expenditure depends on the successful completion of further exploration work, 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 are no concrete plans for future drilling in the licence. Impairments are reversed as applicable to the extent that conditions for impairment are no longer present. Impairment losses and reversals of impairment losses are presented in the Statement of income as Exploration expenses or Depreciation, amortisation and net impairment losses, on the basis of their nature as either exploration assets (intangible exploration assets) or development and producing assets (property, plant and equipment), respectively. Financial liabilities Interest-bearing loans and borrowings are generally from the parent company Statoil ASA, or from other entities in the Statoil group. These are initially recognised at cost and subsequently measured at amortised cost using the effective interest method. Amortised cost is calculated by taking into account any issue costs as well as discount or premium on settlement. Financial liabilities are presented as current if the liabilities are due to be settled within 12 months after the balance sheet date, or if these are held for the purpose of being traded. Group contributions for the year to other entities within Statoil's Norwegian tax group are reflected in the balance sheet as current liabilities within Liabilities to group companies. Provisions 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 under Interest and other finance expenses in Net financial items. Onerous contracts The company recognises as provisions the net 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 (ARO) Provisions for ARO costs are recognised when the company has an obligation (legal or constructive) 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 amount recognised is the present value of the estimated future expenditure determined in accordance with local conditions and requirements. The expenses are estimated based upon current regulation and technology, considering relevant risks and uncertainties. The discount rate used in the calculation of the ARO is a risk-free rate based on the applicable currency and time horizon of the underlying cash flows, adjusted for a credit premium which reflects the company's credit premium. 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 may also crystallise during the period of operation of a facility through a change in legislation or through a decision to terminate operations, or be based on commitments associated with the company's ongoing use of pipeline transport systems where removal obligations rest with the volume shippers. The provisions are classified under Provisions in the Balance sheet. Processing plants that are not limited by licence periods are deemed to have indefinite lives and in consequence no ARO has been recognised. When a provision for ARO cost is recognised, a corresponding amount is recognised 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 expenditures is reflected as an adjustment to the provision and the corresponding property, plant and equipment. Removal provisions associated with shipping of volumes through third party transport systems are expensed as incurred. 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 company 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. Proved oil and gas reserves have been estimated by internal experts on the basis of industry standards and governed by criteria established by regulations of the SEC. 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 producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Unless evidence indicates that renewal is reasonably certain, estimates of economically producible reserves only reflect the period before the contracts providing the right to operate expire. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence within a reasonable time. Expected oil and gas reserves, which differ from proved reserves, have been estimated by internal experts on the basis of industry standards and are used for impairment testing purposes and for calculation of asset retirement obligations.


3 Acquisitions and dispositions 2012 Sale of interests in exploration and production licenses on the Norwegian continental shelf In April 2012 Statoil Petroleum AS closed an agreement with Centrica, entered into in November 2011, to sell interests in certain licences on the Norwegian continental shelf (NCS) for a total consideration of NOK 8.6 billion. The consideration includes a cash payment of NOK 7.1 billion, a contingent element and the responsibility for tax payments for the period between 1 January 2012 and the transaction date. The contingent element relates to production in a four year period and is capped at NOK 0.6 billion. A gain of NOK 7.5 billion has been presented as Other income. The net book value of the assets taken over by Centrica was NOK 2.0 billion. The transaction was tax exempt under the rules in the Norwegian Petroleum Tax system and the gain includes a release of deferred tax liabilities of NOK 0.9 billion related to the transaction. Agreement with Wintershall to sell interest in exploration and production licenses on the NCS In October 2012 Statoil Petroleum AS entered into an agreement with Wintershall to sell its ownership interests in certain licences on the NCS. Wintershall will pay a cash consideration of NOK 7.5 billion (USD 1.4 billion). In addition Statoil Petroleum AS will receive a 15% working interest in the Edvard Grieg licence and a contingent consideration of up to NOK 0.6 billion (USD 0.1 billion). Statoil Petroleum AS will continue to recognise the proportionate share (current ownership share) of the revenues and expenditures until the date of closing of the transaction. The consideration will be adjusted for the activity after 1 January 2013 and for working capital at the transaction date. The transaction is subject to approvals from the Norwegian Ministry of Petroleum and Energy and the Norwegian Ministry of Finance, which includes approval of the transfer of operatorship on the Brage licence to Wintershall. Statoil Petroleum AS expects to recognise a gain from the transaction estimated to be between NOK 6 and 7 billion, to be adjusted for activity between 1 January 2013 and the transaction date, expected in the second half of 2013. The transaction will be tax exempt under rules in the Norwegian Petroleum Tax system and the estimated gain includes a release of related deferred tax liabilities. 2011 Sale of interests in Gassled, Norway In June 2011 Statoil Petroleum AS entered into an agreement with Solveig Gas Norway AS to sell a 24.1% ownership interest in the Gassled joint venture (Gassled). Statoil Petroleum AS continues to hold a 5% interest in the joint venture after the divestment date 30 December 2011. Solveig Gas Norway AS paid a consideration of NOK 13.9 billion in cash in January 2012 for the 24.1% ownership interest in the joint venture. The transaction is principally tax exempt under the rules in the Norwegian Petroleum Tax system, however, a portion is taxable under the ordinary Norwegian tax system. Statoil Petroleum AS has recognised a pre-tax gain of NOK 9.0 billion from the transaction, which includes a release of deferred tax liabilities related to the tax exempted portion of the transaction. The transaction has been presented as Other income.

4 Financial risk management and derivativesGeneral information relevant to financial 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 exposure, defined as having a time horizon of six months or more, are managed at the corporate level while short-term exposure 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 derivative contracts to manage its commodity price, foreign currency rate, and interest rate risk. Within the guidelines, Statoil has developed a comprehensive model, which encompasses Statoil Petroleum AS' most significant market and operational risks. Market risk Statoil Petroleum AS operates in the worldwide crude oil and natural gas market and is 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. Statoil Petroleum AS has established guidelines for entering into commodity based derivative contracts in order to manage the commodity price risk, mainly related to natural gas prices. The commodity based derivative contracts consist of over-the-counter (OTC) forward contracts, market swaps and options related to natural gas. The term for natural gas derivatives is usually three years or less. However they are presented in the balance sheet as current since the contracts included in the portfolio are entered into and held for the purpose of being traded. Currency risk In addition to price developments Statoil Petroleum AS' operating results and cash flows are affected by foreign currency fluctuations of the most significant currencies, the USD and the EUR, against the NOK. The company's cash inflows are largely denominated in or driven by USD while cash outflows, such as operating expenses and taxes payable, are to a large extent denominated in NOK. Foreign exchange risk is managed at corporate level in accordance with policies and mandates. Interest rate risk Statoil Petroleum AS has liabilities with both variable and fixed interest rates. The liabilities with floating interest rate condition expose the company to cash flow risk caused by market interest rate fluctuations. Fair value measurement of derivative financial instruments Statoil Petroleum AS measures derivative financial instruments at the lowest of the cost price and the fair value. Changes in the carrying value of the derivative financial instruments are recognised in the Statement of income within Revenues. Statoil Petroleum AS' portfolio of derivative financial instruments consists of commodity based derivative contracts. When determining the fair value of the derivative financial instruments Statoil Petroleum AS uses prices quoted in an active market to the extent possible. When this is not available Statoil Petroleum AS uses inputs that either directly or indirectly are observable in the market as a basis for valuation techniques such as discounted cash flow analysis or pricing models.


5 Revenues


Revenues third party 106,243 94,570

Intercompany revenues 140,547 147,027

Revenues 246,790 241,597

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. The receivables from these sales are included in the balance sheet as receivables from group companies.

6 RemunerationThe company has no employees. No salary or other remuneration has been paid to the chief executive officer (CEO) in 2012 or 2011. The CEO is employed and paid by Statoil ASA. No compensation was paid to the board of directors in 2012 or 2011.


7 Auditors' remuneration

For the year ended 31 December (in NOK million, excluding VAT) 2012 2011

Audit fees 4.0 5.2

Audit related fees 0.1 0.2

Total 4.1 5.4

In addition to the figures above, audit fees and audit related fees to the external auditor related to Statoil Petroleum-operated licences amount to NOK 6.6 million and NOK 8.8 million for 2012 and 2011, respectively. There are no fees incurred related to tax services or to other services. On 15 May 2012, the General meeting of shareholders appointed KPMG AS as Statoil's auditor, thereby replacing Ernst & Young AS as of that date.

8 Research and development expendituresResearch and Development (R&D) expenditures were NOK 2,235 million in 2012 and NOK 1,880 million in 2011. R&D expenditures are partly financed by partners in 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

For the year ended (in NOK million) 2012 2011

Net foreign exchange gains (1,862) 483

Dividends received 6 13

Interest income from group companies 351 455

Interest income and other financial income 802 705

Interest income and other financial items 1,159 1,173

Capitalised borrowing costs 622 326

Accretion expense asset retirement obligation (2,248) (2,264)

Interest expense to group companies (2,628) (2,939)

Interest expense and other financial expenses (175) (705)

Interest and other financial expenses (4,429) (5,582)

Net financial items (5,132) (3,926)


10 Income taxesIncome tax expense


Current taxes payable (122,106) (118,506)

Change in deferred tax (3,835) (1,369)

Income tax expense (125,941) (119,875)

Uplift credit for the year 10,604 10,150

Unrecognised uplift credit amount to NOK 17.5 billion at 31 December 2012. Reconciliation of Norwegian nominal statutory tax rate to effective tax rate



Calculated income taxes at:

Nominal tax rate (28%) (47,745) (49,693)

Petroleum surtax at statutory rate (50%) (85,258) (88,737)

Tax effect of:

Uplift 5,302 5,075

Financial items subject to 28% basis only (1,024) 39

Tax result subject to 28% basis only 39 2,126

Permanent differences 5,183 14,333

Tax exempted sales transactions (1,404) (2,750)

Income tax prior years 116 (332)

Other (1,150) 64

Total (125,941) (119,875)

Effective tax rate 73.9% 67.5%

There is an increase in the effective tax rate from 2011 to 2012. This is mainly due to capital gains on sale of assets in 2011 of NOK 14.3 billion with lower than average tax rates.


Significant components of deferred tax assets and liabilities were as follows

At 31 December (in NOK million) 2012 2011

Deferred tax assets on

Other items 5,580 6,187

Asset retirement obligations 55,840 47,992

Total deferred tax assets 61,420 54,179

Deferred tax liabilities on

Other items 778 3

Property, plant and equipment 103,448 93,267

Capitalised exploration expenditures and capitalised interest 15,745 16,505

Total deferred tax liabilities 119,971 109,775

Net deferred tax liabilities 58,551 55,596

The movement in deferred income tax


Deferred income tax liability at 1 January 55,596 64,429

Charged to the Statement of income 3,834 1,369

Acquisitions, sales and other (879) (10,202)

Deferred income tax liabilities at 31 December 58,551 55,596


11 Property, plant and equipment

Machinery, Production equipment and plants oil and Refining and transportation gas, including manufacturing Buildings Assets under(in NOK million) equipment pipelines plants and land development Total

Cost at 31 December 2011 1,233 551,849 3,303 107 39,856 596,348

Additions and transfers 83 53,419 149 2 5,236 58,889

Disposal assets at cost 0 (5,608) 0 (1) (518) (6,127)

Cost at 31 December 2012 1,316 599,660 3,452 108 44,574 649,110

Accumulated depreciation and impairment

losses at 31 December 2011 (1,023) (377,398) (2,305) (3) (88) (380,817)

Depreciation and net impairment losses for the year (66) (30,508) (101) (1) 0 (30,676)

Accumulated depreciation and impairment disposed assets 0 3,723 0 0 0 3,723

Accumulated depreciation and impairment

losses at 31 December 2012 (1,089) (404,183) (2,406) (4) (88) (407,770)

Carrying amount at 31 December 2012 227 195,477 1,046 104 44,486 241,340

Estimated useful lives (years) 3 - 10 * 15 - 20 20 - 33

*Depreciation according to Unit of production method, see note 2 Significant accounting policies. In 2012 capitalised interest amounted to NOK 622 million.


12 Intangible assets

Exploration (in NOK million) expenditure Other Total

Cost at 31 December 2011 7,657 48 7,705

Additions 2,345 0 2,345

Disposals at cost (439) 0 (439)

Transfers (3,197) 0 (3,197)

Expensed exploration expenditures previously capitalised (788) 0 (788)

Cost at 31 December 2012 5,578 48 5,626

Accumulated amortisation and impairment losses at 31 December 2011 (10) (10)

Depreciation, impairments and amortisation for the year (3) (3)

Accumulated amortisation and impairment losses at 31 December 2012 (13) (13)

Carrying amount at 31 December 2012 5,578 35 5,613


13 Investments in subsidiaries and other equity accounted companies


Investment at 1 January 112,893 84,738

Adjustment related to conversion to equity method 0 (2,456)

Net income from subsidiaries and other equity accounted companies (2,198) 10,738

Additional paid-in equity 45,726 18,050

Distributions (4,984) (25)

Translation adjustments (6,569) 1,848

Investment at 31 December 144,868 112,893

The closing balance of NOK 144,868 million consists of investments in subsidiaries amounting to NOK 142,651 million and investments in other equity accounted companies amounting to NOK 2,217 million. In 2011, the amounts were NOK 111,587 million and NOK 1,306 million respectively. Amortisation of goodwill amounts to NOK 945 million in 2012.

Ownership in certain subsidiaries and other equity accounted companies (in %) Country of Name % incorporation

Gravitude AS 100 Norway

Saga Petroleum Holding AS 100 Norway

Statoil Algeria Exploration and Production AS 100 Norway

Statoil Angola AS 100 Norway

Statoil Angola Block 22 AS 100 Norway

Statoil Bahamas 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 International Well Response Company 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

SCIRA Offshore Energy Limited 50 United Kingdom


14 Financial assets and liabilities Non-current prepayments and financial receivables


Financial receivables 1,238 5

Prepayments 987 1,004

Prepayments and financial receivables 2,225 1,009

Included in Financial receivables is the project financing of Songa Offshore. Current receivables on group companies Receivables on group companies to Statoil ASA of NOK 25 billion. Non-current liabilities to group companies


Interest bearing liabilities to group companies 65,000 65,000

Non-interest bearing liabilities to group companies 2,735 3,619

Liabilities to group companies 67,735 68,619

NOK 15,0 billion of Interest bearing liabilities to group companies at 31 December 2012 are due within five years. Current liabilities to group companies Liabilities to group companies includes group contribution to Statoil ASA of NOK 31 billion and liabilities related to Statoil group's internal bank arrangements of NOK 31 billion.


15 Trade and other receivables


Trade receivables 641 1,084

Other receivables 10,163 24,377

Trade and other receivables 10,804 25,461

Other receivables mainly consist of joint venture receivables and prepaid expenses.

16 Equity and shareholders


Shareholders’ equity at 1 January 79,036 70,886

Adjustment related to conversion to equity method 0 (2,456)

Net income 44,576 57,599

Foreign currency translation adjustments (6,734) 2,015

Group contribution (31,000) (49,000)

Other 249 (8)

Shareholders’ equity at 31 December 86,127 79,036

Share capital consists of 17,424,000 shares at a nominal value of NOK 1,500. All shares are owned by Statoil ASA. The accumulated foreign currency translation effect as of 31 December 2012 decreases total equity by NOK 7.4 billion. At 31 December 2011 the corresponding effect was a decrease in total equity of NOK 0.7 billion.

17 Provisions

(in NOK million) Asset retirement obligations Other provisions Total

Non-current portion at 31 December 2011 60,929 2,899 63,828

Current portion at 31 December 2011 reported as trade and other payables 679 0 679

Provisions at 31 December 2011 61,608 2,899 64,507

New or increased provisions 3,802 279 4,081

Unused amounts reversed (193) (350) (543)

Amounts charged against provisions (441) (168) (609)

Effects of change in the discount rate 5,255 0 5,255

Reduction due to divestments (689) (23) (712)

Accretion expenses 2,248 0 2,248

Reclassification and transfer 0 (44) (44)

Provisions at 31 December 2012 71,590 2,593 74,183

Current portion at 31 December 2012 reported as trade and other payables 780 105 885

Non-current portion at 31 December 2012 70,810 2,488 73,298

Expected timing of cash outflows

(in NOK million) Asset retirement obligations Other provisions Total

2013 - 2017 3,624 1,986 5,610

2018 - 2022 4,882 0 4,882

2023 - 2027 6,223 0 6,223

2028 - 2032 21,536 0 21,536

Thereafter 35,325 604 35,929

At 31 December 2012 71,590 2,590 74,180

The increase in Asset retirement obligation due to change in discount rate is related to a decrease in the risk free interest rates. The timing of cash outflows related to Asset retirement obligation primarily depends on when the production ceases at the various facilities. The Other provisions category mainly relates to expected payments on unresolved claims. The timing and amounts of potential settlements in respect of these provisions are uncertain and dependent on various factors that are outside management's control. For further discussion of methods applied and estimates required, see note 2 Significant accounting policies.


18 Trade and other payables


Trade payables 1,554 1,545

Non-trade payables, accrued expenses and provisions 13,618 15,127

Trade and other payables 15,172 16,672

Non-trade payables mainly consist of joint venture payables.


19 LeasesStatoil Petroleum AS leases certain assets, notably vessels and drilling rigs. Statoil Petroleum AS has certain operating lease contracts for drilling rigs as of 31 December 2012. The remaining significant contracts' terms range from three months to eight years. Certain contracts contain renewal options. Rig lease agreements are for the most part based on fixed day rates. Statoil Petroleum AS' 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 part of the lease term mainly to Statoil Petroleum AS operated licences on the 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 2012, net rental expenses were NOK 12.1 billion (NOK 8.3 billion in 2011) of which minimum lease payments were NOK 14.3 billion (NOK 10.5 billion in 2011) and sublease payments received were NOK 2.2 billion (NOK 2.3 billion in 2011). No material contingent rent payments have been expensed in 2012 or 2011. The information in the table below shows future minimum lease payments under non-cancellable leases at 31 December 2012.

Operating Operating(in NOK million) leases sublease

2013 14,227 (3,329)

2014 12,894 (1,365)

2015 10,681 (1,155)

2016 9,409 (876)

2017 5,290 (472)

Thereafter 18,869 (1,530)

Total future minimum lease payments 71,370 (8,727)

20 Other commitments and contingenciesContractual commitments Statoil Petroleum AS has contractual commitments of NOK 37,1 billion at 31 December 2012. The contractual commitments reflect Statoil Petroleum AS' share and comprise construction and acquisition of property, plant and equipment. 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 2012, Statoil Petroleum AS was committed to participate in 11 wells with an average ownership interest of approximately 33%. Statoil Petroleum AS' share of estimated expenditures to drill these wells amounts to NOK 1.3 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 Petroleum AS has entered into various long-term agreements for pipeline transportation as well as terminal use, processing, storage and entry/exit capacity commitments and commitments related to specific purchase agreements.The agreements ensure the rights to the capacity or volumes in question, but also impose on the group the obligation to pay for the agreed-upon service or commodity, irrespectively of actual use. The contracts' terms vary, with duration of up to 30 years.

Take-or-pay contracts for the purchase of commodity quantities are only included in the tables below if their contractually agreed pricing is of a nature that will or may deviate from the obtainable market prices for the commodity at the time of delivery. Obligations payable by the group to entities accounted for using the equity method are included gross in the tables below. For assets (e.g. pipelines) that the group accounts for by recognising 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 AS (i.e. gross commitment less Statoil Petroleum AS' ownership share). Nominal minimum commitments at 31 December 2012:

(in NOK million)

2013 9,613

2014 8,278

2015 8,710

2016 8,973

2017 9,127

Thereafter 54,750

Total 99,451

Guarantees All of the group's Norwegian continental shelf (NCS) net assets are owned by Statoil Petroleum AS, and the company is co-obligor or guarantor of existing debt securities and other loan arrangements of Statoil ASA. For the portion of the debt for which it is co-obligor, Statoil Petroleum AS assumes and agrees to perform, jointly and severally with Statoil ASA, all payment and covenant obligations. During 2012, Statoil ASA executed three additional issues of US registered debt securities, all guaranteed by Statoil Petroleum AS. At year end 2012 the carrying value of debts for which Statoil Petroleum AS is the co-obligor or guarantor, mainly for Statoil ASA, is NOK 22.1 billion and NOK 78.5 billion, respectively. Contingencies During 2012 the major part of the financial exposure related to gas sales contracts' price review claims, for which arbitration previously had been requested, was settled on commercial terms with no significant impact on the financial statements 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 in respect of such litigation and claims cannot be determined at this time. Statoil Petroleum AS has provided in its financial statements for probable liabilities related to litigation and claims based on the Company's best judgement. Statoil Petroleum AS does not expect that its financial position, results of operations or cash flows will be materially affected by the resolution of these legal proceedings.


21 Related partiesThe 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 arm's length basis. 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 entities in which Statoil has ownership interests. Such transactions are carried out at an arm's length basis, and are included within the applicable captions in the statement of income.

22 Reserves (unaudited)The company's proved oil and gas reserves have been estimated by its parent company's experts in accordance with industry standards under the requirements of the US Securities and Exchange Commission (SEC). At the end of the year the company's proved reserves amounted to approximately 643 million Sm3 o.e. (662 million Sm3 o.e. in 2011). Proved reserves will be produced in the period from 2013 to 2034. 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 producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Unless evidence indicates that renewal is reasonably certain, estimates of economically producible reserves only reflect the period before the contracts providing the right to operate expire. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence within a reasonable time.

Stavanger, 8 March 2013

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Independent auditor's report


KPMG AS Telephone +47 04063 Verksgata 1A Fax +47 51 57 12 29 P.O. Box 57 Internet www.kpmg.no N-4064 Stavanger Enterprise 935 174 627 MVA

KPMG AS, a Norwegian member firm of the KPMG network of independent member firms affiliated with KPMG International Cooperative (“KPMG International”), a Swiss entity. Statsautoriserte revisorer - medlemmer av Den norske Revisorforening.

Offices in: Oslo Alta Arendal Bergen Bodø Elverum Finnsnes Grimstad Hamar

Haugesund Knarvik Kristiansand Larvik Mo i Rana Molde Narvik Røros Sandefjord

Sandnessjøen Stavanger Stord Straume Tromsø Trondheim Tønsberg Ålesund

To the Annual Shareholders meeting in Statoil Petroleum AS INDEPENDENT AUDITOR’S REPORT Report on the Financial Statements We have audited the accompanying financial statements of Statoil Petroleum AS, showing a profit of MNOK 44 576. The financial statements comprise the balance sheet as at 31 December 2012, and the income statement and cash flow statement for the year then ended, and a summary of significant accounting policies and other explanatory information. The Board of Directors and the Managing Director’s Responsibility for the Financial Statements The Board of Directors and the Managing Director are responsible for the preparation and fair presentation of these financial statements in accordance with the Norwegian Accounting Act and accounting standards and practices generally accepted in Norway, and for such internal control as the Board of Directors and the Managing Director determine is necessary to enable the preparation of financial statements that are free from material misstatement, whether due to fraud or error. Auditor’s Responsibility Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit in accordance with laws, regulations, and auditing standards and practices generally accepted in Norway, including International Standards on Auditing. Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement. An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion. Opinion In our opinion, the financial statements are prepared in accordance with the law and regulations and give a true and fair view of the financial position of Statoil Petroleum AS as at 31 December 2012, and of its financial performance and its cash flows for the year then ended in accordance with the Norwegian Accounting Act and accounting standards and practices generally accepted in Norway.


statoil petroleum as - annual report 2012 · statoil petroleum as is paying nok 31.0 billion in tax...

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