Equinor — Interim / Quarterly Report 2011

Oct 28, 2011

UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, DC 20549

FORM 6-K

REPORT OF FOREIGN PRIVATE ISSUER PURSUANT TO RULE 13a-16 OR 15d-16 OF THE SECURITIES EXCHANGE ACT OF 1934

October 28, 2011

Commission File Number 1-15200

Statoil ASA

(Translation of registrant’s name into English) FORUSBEEN 50, N-4035, STAVANGER, NORWAY (Address of principal executive offices)

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F:

Form 20-F X Form 40-F

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1):_____

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7):_____

This Report on Form 6-K shall be deemed to be filed and incorporated by reference in the Registration Statements on Form F-3 (File No. 333-167092) and Form S-8 (File No. 333-168426) and to be a part thereof from the date on which this report is furnished, to the extent not superseded by documents or reports subsequently filed or furnished.

This document includes portions from the previously published results announcement of Statoil ASA as of, and for the nine months ended, September 30, 2011, as revised to comply with the requirements of Item 10(e) of Regulation S-K regarding non-GAAP financial information promulgated by the U.S. Securities and Exchange Commission. For more information on our use of non-GAAP financial measures in this report, see the section entitled "Use and Reconciliation of Non-GAAP Financial Measures". This document does not update or otherwise supplement the information contained in the previously published results announcement.

TABLE OF CONTENTS

THIRD QUARTER 2011 RESULTS

OPERATIONAL REVIEW FINANCIAL REVIEW OUTLOOK RISK UPDATE HEALTH, SAFETY AND THE ENVIRONMENT(HSE) DEVELOPMENT AND PRODUCTION NORWAY DEVELOPMENT AND PRODUCTION INTERNATIONAL MARKETING, PROCESSING AND RENEWABLE ENERGY FUEL & RETAIL LIQUIDITY AND CAPITAL RESOURCES USE AND RECONCILIATION OF NON-GAAP FINANCIAL MEASURES END NOTES FORWARD-LOOKING STATEMENTS INTERIM FINANCIAL STATEMENTS

NOTES TO THE INTERIM FINANCIAL STATEMENTS 1 ORGANISATION AND BASIS OF PREPARATION 2 ACCOUNTING POLICY CHANGE JOINTLY CONTROLLED ENTITIES 3 SEGMENTS 4 FINANCIAL ITEMS AND CASH AND CASH EQUIVALENTS 5 INCOME TAX 6 ASSETS ACQUISITIONS AND DISPOSALS 7 ASSETS CLASSIFIED AS HELD FOR SALE 8 INTANGIBLE ASSETS AND PROPERTY, PLANT AND EQUIPMENT 9 PROVISIONS, COMMITMENTS, CONTINGENT LIABILITIES AND CONTINGENT ASSETS 10 SUBSEQUENT EVENTS

SIGNATURES

Table of Contents

THIRD QUARTER 2011 RESULTS

Statoil's third quarter 2011 net operating income was NOK 39.3 billion, a 39% increase compared to NOK 28.2 billion in the third quarter of 2010.

"Statoil delivered strong financial results in the third quarter of 2011, reflecting operational performance in line with expectations and strong oil and gas prices throughout the period," says Helge Lund, Statoil's chief executive officer.

Statoil presented the long term strategy and long term growth outlook on its capital markets day in June 2011, where revitalisation of the NCS with high value barrels and expansion in unconventionals are among key building blocks.

"The giant Aldous/Avaldsnes discovery clearly reaffirms the strong potential of the Norwegian continental shelf, and we continue our long-term effort to position Statoil as an industrial player and operator within unconventionals through the offer to acquire all shares of the Brigham Exploration Company," says Lund.

The quarterly result was mainly affected by a 30% increase in the average prices for liquids measured in NOK, a 13% increase in average gas prices, a 13% increase in lifted volume compared to the same period last year, and a net impairment loss of NOK 4.8 billion mainly related to the refinery business.

Net income in the third quarter of 2011 was NOK 9.9 billion compared to NOK 13.8 billion in the same period last year. The decrease stems primarily from lower gain on net financial items and higher tax rates, and was only partly offset by higher net operating income. The tax rate for the quarter was 76.6%.

Total equity production was 1,764 mboe per day in the third quarter of 2011 compared to 1,552 mboe per day in the third quarter of 2010.

	Third quarter — 2011	2010	Change	First nine months — 2011	2010	Change	Full year — 2010
Net operating income (NOK billion)	39.3	28.2	39 %	151.1	94.4	60 %	137.3
Net income (NOK billion)	9.9	13.8	(28 %)	53.0	28.0	89 %	37.6
Earnings per share (NOK)	3.27	4.34	(25 %)	16.75	8.97	87 %	11.94
Average liquids price (NOK/bbl) [3]	591	455	30 %	593	450	32 %	462
Average gas prices (NOK/scm)	1.97	1.74	13 %	1.99	1.65	21 %	1.72
Equity production (mboe per day)	1,764	1,552	14 %	1,808	1,868	(3 %)	1,888

Highlights since second quarter 2011:

• Successful exploration, highlighted by the Aldous/Avaldsnes oil discovery in the North Sea, one of the largest finds ever on the Norwegian continental shelf. Statoil holds a 40% interest in both licences. In total, 9 discoveries on 13 completed wells by 30 September.
• Further expanding in unconventionals, through a merger agreement between Statoil and Brigham Exploration Company for Statoil to acquire all the outstanding shares of Brigham through an all-cash tender offer. If the tender offer is successful, the acquisition adds 375,000 net acres in the Williston Basin with potential for oil production from the Bakken and Three Forks formations. The transaction builds on Statoil's stepwise build-up in the United States and establishes Statoil as an operator in unconventional plays.
• Maturing the project portfolio, including August start-up of the Pazflor development in Angola. Statoil has a 23.33% interest and Pazflor is expected to contribute with 47 000 barrels per day in equity capacity when plateau is reached in the first quarter next year.
• Industrial progress, as plans for development and operation (PDO) are submitted to the authorities for the Skuld field in the Norwegian Sea and for the subsea gas compression project at Åsgard to maintain production from the Mikkel and Midgard reservoirs. PDO for Stjerne and Vigdis North East has been approved.
• Participating interests in two exploration licences in Camamu-Almada basin offshore Brazil have been farmed down 10% and 15% respectively to Gran Tierra Energy. The agreement is subject to approval by Brazilian authorities and other conditions.

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OPERATIONAL REVIEW

Third quarter

Total liquids and gas entitlement production in the third quarter of 2011 was 1,573 mboe per day, compared to 1,379 mboe per day in the third quarter of 2010. Total equity production [9] was 1,764 mboe per day in the third quarter of 2011 compared to 1,552 mboe per day in the third quarter of 2010.

The 14% increase in total equity production was primarily due to production start-up on new fields, ramp-up of production from existing fields, increased ownership shares and extensive maintenance in the third quarter last year. The increase was partly offset by natural decline on mature fields, reduced water injection at Gullfaks and suspended production in Libya.

Entitlement production, up 14% since third quarter last year, was impacted by the increase in equity production as described above. The average Production Sharing Agreements (PSA-effects) was 191 mboe per day in the third quarter of 2011 compared to 173 mboe per day in the third quarter last year. The higher PSA-effect in third quarter 2011 was mainly a result of the higher prices for liquids and gas leading to lower entitlement production and a higher government take because of changes in profit tranches, compared to the same quarter last year.

Operational data	Third quarter — 2011	2010	Change	First nine months — 2011	2010	Change	Full year — 2010
Average liquids price (USD/bbl)	107.5	73.8	46 %	106.7	73.9	44 %	76.5
USDNOK average daily exchange rate	5.50	6.17	(11 %)	5.56	6.09	(9 %)	6.05
Average liquids price (NOK/bbl) [3]	591	455	30 %	593	450	32 %	462
Average gas prices (NOK/scm)	1.97	1.74	13 %	1.99	1.65	21 %	1.72
Refining margin (reference margin, USD/bbl) [4]	2.7	2.7	0 %	2.5	3.8	(34 %)	3.9
Productions:
Total entitlement liquids production (mboe per day) [5]	949	868	9 %	930	971	(4 %)	968
Total entitlement gas production (mboe per day)	625	511	22 %	677	714	(5 %)	738
Total entitlement liquids and gas production (mboe perday) [6]	1,573	1,379	14 %	1,607	1,684	(5 %)	1,705
Total equity liquids production (mboe per day)	1,124	1,019	10 %	1,108	1,127	(2 %)	1122
Total equity gas production (mboe per day)	640	533	20 %	700	741	(6 %)	766
Total equity liquids and gas production (mboe per day)	1,764	1,552	14 %	1,808	1,868	(3 %)	1,888
Liftings:
Total liquids liftings (mboe per day) [12]	940	872	8 %	889	963	(8 %)	969
Total gas liftings (mboe per day)	625	511	22 %	677	714	(5 %)	738
Total liquids and gas liftings (mboe per day) [7] [12]	1,565	1,383	13 %	1,566	1,677	(7 %)	1,706
Production cost:
Production cost entitlement volumes (NOK/boe, last 12 months) [8]	45.5	42.1	8 %	45.5	42.1	8 %	42.8
Production cost equity volumes (NOK/boe, last 12 months)	40.7	37.9	7 %	40.7	37.9	7 %	38.6

Total liftings of liquids and gas were 1,565 mboe per day in the third quarter of 2011, a 13% increase from 1,383 mboe per day in the third quarter of 2010. The increase in lifting is a result of the increase in entitlement production. In the third quarter of 2011, there was an overlift of 6 mboe per day [5], compared to an overlift of 18 mboe per day in the third quarter of 2010.

Refining margins (reference margin) [4] were USD 2.7 per barrel in the third quarter of 2011, the same as in the third quarter of 2010.

Production cost per boe of entitlement volumes was NOK 45.5 for the 12 months ended 30 September 2011, compared to NOK 42.1 for the 12 months ended 30 September 2010 [8]. Based on equity volumes, the production cost per boe for the two periods was NOK 40.7 and NOK 37.9, respectively.

Exploration expenditure (including capitalised exploration expenditure) was NOK 4.9 billion in the third quarter of 2011, compared to NOK 3.7 billion in the third quarter of 2010. The NOK 1.1 billion increase was mainly due to more wells being drilled compared to the same period last year.

In the third quarter of 2011, a total of 13 exploration wells were completed before 30 September 2011, nine on the NCS and four internationally. Nine wells were announced as discoveries in the period, all on the NCS.

Major business developments since second quarter 2011 include:

• Plan for development and operation (PDO) for the Skuld fast track project was submitted.
• The Ministry of Petroleum and Energy (MPE) approved the PDOs for Vigdis North East and Stjerne.
• On 27 August, the start-up of the Pazflor development in Angola was announced. This third development hub of Block 17 is located 150 kilometres off Luanda in water depths ranging from 600 to 1200 metres. Statoil has a 23.33% interest in Block 17.
• Statoil and Talisman closed the acquisition of properties from Denver-based independent SM Energy Company on 2 August. The transaction added 15,400 acres to the companies' 50/50 Eagle Ford joint venture in Texas, USA. The total purchase price was USD 225 million with an effective date of 1 May 2011.
• On 17 October, Statoil announced that it had entered into a merger agreement with Brigham Exploration Company for Statoil to aquire all the outstanding shares of Brigham through an all cash tender offer. The total equity value is approximately USD 4.4 billion, reflecting an enterprise value of approximately USD 4.7 billion.
• Major parts of Statoil's onshore wind power activities in Norway have been sold to Trønder Energi.

First nine months 2011

Total liquids and gas entitlement production in the first nine months of 2011 was 1,607 mboe per day, down 5% from 1,684 mboe per day in the first nine months of 2010. Total equity production was 1,808 mboe per day in the first nine months of 2011 compared to 1,868 mboe per day in the first nine months of 2010.

The 3% decrease in total equity production in the first nine months of 2011 compared to the same period in 2010 was primarily caused by reduced water injection at Gullfaks, challenges primarily related to risers and maintenance shut downs. In addition, expected reductions due to natural decline on mature fields and suspended production in Libya contributed to the decrease. This was partly offset by production from start-up of new fields, ramp-up of production on existing fields and increased ownership shares.

The 5% decrease in entitlement production in the first nine months of 2011 compared to the same period in 2010, was impacted by the reduction in equity production as described above, and by increasing PSA-effects. The average PSA-effect on entitlement production was 201 mboe per day in the first nine months of 2011 compared to 184 mboe per day in the first nine months of 2010. The increase was a result of changes in profit tranches regarding fields in Angola, and higher prices in the first nine months 2011 compared to the same period in 2010, leading to reduced entitlement shares.

Total liquids and gas liftings in the first nine months of 2011 were 1,566 mboe per day, compared to 1,677 mboe per day in the first nine months of 2010. The 7% decrease in lifting is based on the decrease in entitlement production. In the first nine months of 2011 there was an underlift position of 27 mboe per day, compared to an overlift of 6 mboe per day in the first nine months of 2010.

Refining margins (reference margin) were USD 2.5 per barrel in the first nine months of 2011, compared to USD 3.8 per barrel in the first nine months of 2010.

Exploration expenditure (including capitalised exploration expenditure) was NOK 13.2 billion in the first nine months of 2011, compared to NOK 11.1 billion in the same period of 2010. The increase of NOK 2.1 was mainly caused by higher drilling activity as an increased number of wells were drilled compared to the same period last year.

In the first nine months of 2011 Statoil completed 32 exploration wells , 22 on the NCS and ten internationally. A total of 19 wells were announced as discoveries in the period, 16 on the NCS and three internationally.

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FINANCIAL REVIEW

Third quarter

In the third quarter of 2011, net operating income was NOK 39.3 billion, compared to NOK 28.2 billion in the third quarter of 2010. Revenues were positively impacted by higher prices and increased volumes for both liquids and gas. A lower USD/NOK exchange rate and increased depreciation, depletion and amortisation and impairments, partially offset the increase.

IFRS income statement — (in NOK billion)	Third quarter — 2011	2010	Change	First nine months — 2011	2010	Change	Full year — 2010
REVENUES AND OTHER INCOME
Revenues	166.4	125.9	32 %	471.7	383.8	23 %	527.0
Net income (loss) from equity accounted investments	0.3	0.5	(44 %)	1.2	1.2	(4 %)	1.2
Other income	0.1	1.1	(92 %)	14.6	1.5	873 %	1.8
Total revenues and other income	166.8	127.4	31 %	487.5	386.6	26 %	529.9
OPERATING EXPENSES
Purchase [net of inventory variation]	88.1	67.4	31 %	236.8	189.7	25 %	257.4
Operating expenses and selling, general and administrative expenses	18.9	15.6	21 %	53.0	53.9	(2 %)	68.8
Depreciation, amortisation and net impairment losses	17.2	12.6	37 %	37.6	38.1	(1 %)	50.7
Exploration expenses	3.3	3.6	(10 %)	9.0	10.4	(13 %)	15.8
Total operating expenses	(127.6)	(99.2)	29 %	(336.4)	(292.1)	15 %	(392.7)
Net operating income	39.3	28.2	39 %	151.1	94.4	60 %	137.3
Net financial items	2.9	7.1	(59 %)	2.6	4.6	(42 %)	(0.4)
Income tax	(32.3)	(21.5)	50 %	(100.7)	(71.0)	42 %	(99.2)
Net income	9.9	13.8	(28 %)	53.0	28.0	89 %	37.6

In the third quarter of 2011, impairment losses net of reversal (NOK 4.8 billion), lower values of products in operational storage (NOK 0.3 billion), net loss on sale of assets (NOK 0.1 billion) and provisions (NOK 0.1 billion), had a negative impact on net operating income, while higher fair values of derivatives (NOK 3.3 billion) had a positive impact on net operating income.

In the third quarter of 2010, impairment losses net of reversals (NOK 1.6 billion) and lower values of products in operational storage (NOK 0.2 billion) had a negative impact on net operating income, while higher fair value of derivatives (NOK 0.5 billion), overlift (NOK 0.5 billion), gain on sale of assets (NOK 0.8 billion) and other accruals (NOK 1.2 billion) had a positive impact on net operating income.

The 39% increase in net operating income from third quarter 2010 to third quarter 2011 was mainly attributable to higher prices and increased volumes for both liquids and gas and stronger trading results. The increase was partly offset by lower exchange rates, higher purchase (net of inventory valuation) and increased depreciation and amortisation costs because of new fields with higher depreciation coming on stream.

Purchase [net of inventory variation] , which represent Statoil's purchases of SDFI and 3rd party volumes, increased by 31% compared to the third quarter of 2010, mainly due to higher prices of liquids measured in NOK.

Operating expenses and selling, general and administrative expenses were NOK 18.9 billion in the third quarter of 2011, compared to NOK 15.6 billion in the third quarter last year. The 21% increase stems mainly from increased activity related to start-up and ramp-up of production on various fields, increased transportation activity in the US and increased business development costs.

Depreciation, amortisation and net impairment losses were NOK 17.2 billion in the third quarter of 2011, up 37% from NOK 12.6 billion compared to the same period last year. The increase was due to impairment losses totaling NOK 4.2 billion mainly related to the refinery business, new fields with higher depreciation coming on stream, increased depreciation because of higher ownership shares and increased production and the impact from revisions of removal and abandonment estimates.

Exploration expenses decreased by NOK 0.3 billion compared to the same period last year mainly because more successful drilling resulted in a higher portion of current periods exploration expenditures being capitalised this quarter compared to third quarter last year. Also lower exploration expenditures capitalised in previous periods being expensed this period, contributed to the decrease. The decrease was partly offset by net impairment losses related to previously capitalised exploration expenses.

Financial data	Third quarter — 2011	2010	Change	First nine months — 2011	2010	Change	Full year — 2010
Weighted average number of ordinary shares outstanding	3,181,855,580	3,182,526,140		3,182,469,049	3,182,802,752		3,182,574,787
Earnings per share (NOK)	3.27	4.34	(25 %)	16.75	8.97	87 %	11.94
Non-controlling interests (NOK billion)	(0.6)	(0.0)	>100 %	(0.3)	(0.6)	(42 %)	(0.4)
Cash flows provided by operating activities (NOK billion)	24.2	19.0	27 %	77.8	67.1	16 %	80.8
Gross investments (NOK billion)	23.9	18.9	27 %	65.4	58.7	11 %	84.4
Net debt to capital employed ratio [2]	13.6 %	27.7 %		13.6 %	27.7 %		24.6 %

Net financial items amounted to a gain of NOK 2.9 billion in the third quarter of 2011, compared to a gain of NOK 7.1 billion in the third quarter of 2010. The gain in the third quarter of 2011 was primarily due to fair value gains on interest rate swap positions related to the interest rate management of external loans of NOK 5.4 billion and by foreign exchange gains of NOK 1.3 billion offset in part by loss on securities of NOK 2.1 billion. Correspondingly, the gain in the third quarter of 2010 primarily related to foreign exchange gains of NOK 4.0 billion, in combination with fair value gains on interest rate swap positions, included in interest expenses, related to the interest rate management of external loans of NOK 2.8 billion.

Interest income and other financial items in the third quarter of 2011 was a loss of NOK 1.8 billion compared to income of NOK 1.6 billion for the same period of 2010. The negative amount in 2011 was a result of a loss on securities, reflecting the development in the stock markets and negative currency effects on commercial papers in the third quarter.

Interest expenses including fair value gains on interest rate swaps in the third quarter of 2011 amounted to net gain of NOK 3.4 billion, correspondingly interest expenses in the third quarter of 2010 amounted to a net gain of NOK 1.6 billion. The gain in interest expenses in the third quarter of 2011 and 2010 was primarily due to the fair value gains on interest rate swap positions related to the interest rate management of external loans caused by decreasing USD long term interest rates during the third quarter of 2011 and the third quarter of 2010.

USDNOK	5.84	5.39	5.86	5.84
EURNOK	7.89	7.79	7.81	7.97

Income tax was NOK 32.3 billion in the third quarter of 2011, equivalent to an effective tax rate of 76.6%, compared to NOK 21.5 billion in the third quarter of 2010, equivalent to an effective tax rate of 60.9%. The variance in effective tax rates between the periods is mainly explained by impairments in the third quarter of 2011 with lower than average tax rates, and high deferred tax expense in the third quarter of 2011 compared with deferred tax income in the third quarter of 2010, related to currency effects in companies that are taxable in currencies other than the functional currency. The increased effective tax rate in the third quarter of 2011 is also caused by relatively higher income from the NCS compared with the third quarter of 2010. Income from the NCS is subject to higher than average tax rates. The increased tax rate in the third quarter of 2011 was partially offset by lower taxable income than accounting income in the third quarter of 2011 compared with higher taxable income than accounting income in the third quarter of 2010 related to currency effects in companies that are taxable in currencies other than the functional currency.

In the third quarter of 2011, income before tax amounted to NOK 42.2 billion, while taxable income was estimated to be NOK 4.9 billion lower. The estimated difference of NOK 4.9 billion arose in companies that are taxable in currencies other than the functional currency. The tax effect of this estimated difference contributed to a tax rate of 76.6%

In the third quarter of 2011, net income was NOK 9.9 billion compared to NOK 13.8 billion last year. The decrease stems primarily from lower gain on net financial items and higher tax rates, and was only partly offset by higher net operating income.

In the third quarter of 2011, earnings per share , based on net income, was NOK 3.27 compared to NOK 4.34 in the third quarter of 2010.

First nine months 2011

In the first nine months of 2011, net operating income was NOK 151.1 billion, compared to NOK 94.4 billion in the first nine months of 2010, an increase of 60%. Net operating income was positively impacted by higher prices for both liquids and gas and decreasing operating costs. Unrealised gains on derivatives, reversal of provisions and impairments made in prior periods, and gains on sale of assets mainly related to the Peregrino and the Kai Kos Dehseh oil sands divestments in the first nine months of 2011, also contributed significantly to the increase. Lower volume of both liquids and gas sold and net impairment losses related to the refinery business and a gas fire power station, partly offset the increase in net operating income.

In the first nine months of 2011, impairment losses net of reversals (NOK 1.8 billion) and underlift (NOK 2.9 billion), negatively impacted net operating income, while gain on sale of assets (NOK 14.1 billion), higher fair value of derivatives (NOK 6.9 billion), higher values of products in operational storage (NOK 0.5 billion) and net reversal of provisions (NOK 0.5 billion) had a positive impact on net operating income.

In the first nine months of 2010, impairment losses net of reversals (NOK 4.7 billion), lower fair value of derivatives (NOK 0.7 billion) and other accruals (NOK 3.9 billion) negatively impacted net operating income, while overlift (NOK 0.3 billion), higher values of products in operational storage (NOK 0.2 billion) and gain on sale of assets (NOK 1.1 billion) had a positive impact on net operating income.

The 60% increase in net operating income from the first nine months of 2010 to the first nine months of 2011 was primarily caused by the increase in liquids and gas prices, the gain on sale of assets and the higher fair value gain on derivatives, and was only partly offset by the lower volumes being sold and the increase in operating costs discussed below.

Purchases [net of inventory variation] increased by 25% in the first nine months of 2011, mainly due to higher prices for liquids measured in NOK.

Operating expenses, and selling, general and administrative expenses decreased by NOK 0.9 billion compared to the same period last year mainly due an overlift position (NOK 1.2 billion), partly offset by increased activity related to start-up and ramp-up of production on various fields, increased transportation activity in the US and increased business development costs.

Depreciation, amortisation and net impairment losses decreased by 1% in the first nine months of 2011 compared to the same period last year mainly because of the impact of lower production and increased reserve estimates in Angola and Nigeria. The decrease was partly offset by the decrease in production on the Norwegian Continental Shelf, higher depreciation from new fields and assets coming on stream, the impact on depreciation from revisions of removal and abandonment estimates and lower net impairment losses.

Exploration expenses decreased by 13% from NOK 10.4 billion in the first nine months of 2010 to NOK 9.0 billion in the same period of 2011, mainly because successful drilling resulted in a higher portion of exploration expenditures being capitalised, and because a lower portion of exploration expenditure capitalised in previous years was expensed in the first nine months of this year compared to the same period last year.The increase was partly offset by higher exploration activity with higher equity share.

Net financial items amounted to a gain of NOK 2.6 billion in the first nine months of 2011, compared to a gain of NOK 4.6 billion in first nine months of 2010. The gain in the first nine months of 2011 was primarily due to foreign exchange gains of NOK 0.5 billion, in combination with fair value gains on interest rate swap positions related to the interest rate management of external loans of NOK 6.1 billion offset in part by losses on securities of NOK 1.4 billion. The gain in the first nine months of 2010 was primarily due to fair value gains on interest rate swap positions related to the interest rate management of external loans of NOK 6.7 billion, partly offset by foreign exchange losses of NOK 1.8 billion.

Interest and other finance expenses in the first nine months of 2011 amounted to net gain of NOK 1.6 billion, correspondingto a net gain for the first nine months of 2010 of NOK 3.7 billion. The gain in interest expenses in both the first nine months of 2011 and 2010 was primarily due to fair value gains on interest rate swap positions and are caused by decreasing USD interest rates during the nine month periods ended 30 September 2011 and 30 September 2010.

Income tax was NOK 100.7 billion in the first nine months of 2011, equivalent to a tax rate of 65.5%, compared to NOK 71.0 billion in the first nine months of 2010, equivalent to a tax rate of 71.7%. The variance in effective tax rates between the periods is mainly explained by capital gains in the first nine months of 2011 with lower than average tax rates and decreased impairments losses (net of reversals) with lower than average tax rates, in the first nine months of 2011 compared with the first nine months of 2010. The decreased effective tax rate in the first nine months of 2011 is also caused by relatively lower income from the NCS, which is subject to higher than average tax rates, in the first nine months of 2011 compared with the first nine months of 2010. The decreased tax rate in the first nine months of 2011 was partially offset by higher deferred tax expense in the first nine months of 2011 related to currency effects in companies that are taxable in currencies other than the functional currency.

In the first nine months of 2011, net income was NOK 53.0 billion compared to NOK 28.0 billion in the same period last year. The significant increase of 89% is mainly due to increased net operating income which was positively impacted by higher liquids and gas prices, increased unrealised gains on derivatives, gains from sale of assets and a reduction in operating expenses. Lower volumes of liquids and gas sold, a reduced gain on net financial items and a higher effective tax rate partly offset the increase in net income compared to the same period last year.

In the first nine months of 2011 earnings per share based on net income amounted to NOK 16.75, compared to NOK 8.97 in the first nine months of 2010.

The cash-flows from operations improved in the first nine months of 2011 compared with the same period last year. Cash flows from income before tax amounted to NOK 153.7 billion, mainly due to high prices of liquids and gas. In addition, proceeds from the sale of interests in the Kai Kos Dehseh field in Canada and the Peregrino oil field in Brazil contributed to a strong cash flow in the first nine months of 2011.

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OUTLOOK

Organic capital expenditures for 2011 (i.e. excluding acquisitions and capital leases), are estimated at around USD 16 billion. In 2012, a similar level is expected excluding any effect of the recent Brigham Exploration acquisition proposal.

The Company will continue to mature its large portfolio of exploration assets and expects to complete more than 40 wells with a total exploration activity level in 2011 of around USD 3 billion, excluding signature bonuses.

Statoil has an ambition for its unit of production cost to be in the top quartile of its peer group.

Planned turnarounds are expected to have a negative impact on the quarterly production of approximately 30 mboe per day in the fourth quarter. In total, the turnarounds are estimated to have an impact on equity production of around 50 mboe per day for the full year 2011, of which most are liquids.

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. See "Forward-Looking Statements" below.

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RISK UPDATE

Risk factors

The results of operations largely depend on a number of factors, most significantly those that affect the price for volumes sold. Specifically, such factors include liquids and natural gas prices, exchange rates, liquids and natural gas production volumes, which in turn depend on entitlement volumes under profit sharing agreements and available petroleum reserves, Statoil's, as well as our partners' expertise and co-operation in recovering oil and natural gas from those reserves, and changes in Statoil's portfolio of assets due to acquisitions and disposals.

The illustration shows how certain changes in crude oil prices (a substitute for liquids prices), natural gas contract prices and the USD/NOK exchange rate, if sustained for a full year, could impact our net operating income. Changes in commodity prices, currency and interest rates may result in income or expense for the period as well as changes in the fair value of derivatives in the balance sheet.

The illustration is not intended to be exhaustive with respect to risks that have or may have a material impact on the cash flows and results of operation. See the annual report for 2010 and the 2010 Annual Report on Form 20-F for a more detailed discussion of the risks to which Statoil is exposed.

Financial risk management

Statoil has policies in place to manage risk for commercial and financial counterparties by the use of derivatives and market activities in general. The group's exposure towards financial counterparties is considered to have an acceptable risk profile.

The markets for short- and long-term financing are currently considered to function well for corporate borrowers with Statoil's credit standing and general characteristics. With regard to liquidity management, the focus is on finding the right balance between risk and reward and most funds are currently placed in short-term money market instruments with minimum single A-rating.

In accordance with our internal credit rating policy, we continuously assess counterparty credit risk with main focus on counterparties identified as high risk. We assess our overall credit risk as satisfactory.

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HEALTH, SAFETY AND THE ENVIRONMENT (HSE)

Third quarter

The total recordable injury frequency was 4.4 in the third quarter of 2011 compared to 4.1 in the third quarter of 2010. The serious incident frequency improved from 1.3 in the third quarter of 2010 to 1.1 in the third quarter of 2011. There was one fatality in the third quarter of 2011. A contractor employee performing maintenance work at service stations in Riga (Latvia) was killed in a traffic accident.

The number of accidental oil spills in the third quarter of 2011 decreased compared to the third quarter of 2010, and the volume of oil spills decreased from 28 cubic metres in the third quarter of 2010 to 7 in the third quarter of 2011.

First nine months 2011

The total recordable injury frequency was 4.3 in first nine months of 2011 compared to 4.1 in first nine months of 2010. The serious incident frequency improved from 1.3 in the first nine months of 2010 to 1.1 in first nine months of 2011. There was one fatality in the first nine months of 2011 in a traffic accident in Riga.

The number of accidental oil spills in the first nine months of 2011 decreased compared to the first nine months of 2010, and the volume of oil spills decreased from 41 cubic metres in the first nine months of 2010 to 26 in the first nine months of 2011.

HSE	2011	2010	2011	2010	2010
Total recordable injury frequency	4.4	4.1	4.3	4.1	4.2
Serious incident frequency	1.1	1.3	1.1	1.3	1.4
Accidental oil spills (number)	84	104	264	300	374
Accidental oil spills (cubic metres)	7	28	26	41	44

On 6 October, a man working for contractor Beerenberg was reported missing on the Visund platform in the North Sea. The search at the platform and the seabed around the platform has unfortunately been unsuccessful.

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DEVELOPMENT AND PRODUCTION NORWAY

IFRS income statement — (in NOK billion)	Third quarter — 2011	2010	Change	First nine months — 2011	2010	Change	Full Year — 2010
Total revenues and other income	53.6	35.6	51 %	156.4	120.7	30 %	170.7
Operating expenses and selling, general and administrative expenses	6.9	5.5	27 %	17.9	17.5	2 %	23.6
Depreciation, amortisation and net impairment losses	7.6	5.7	33 %	21.6	18.1	19 %	26.0
Exploration expenses	1.1	1.0	18 %	3.2	3.4	(5 %)	5.5
Total operating expenses	15.6	12.1	29 %	42.6	39.0	9 %	55.1
Net operating income	38.0	23.5	62 %	113.8	81.8	39 %	115.6

Operational data	Third quarter — 2011	2010	Change	First nine months — 2011	2010	Change	Full year — 2010
Prices:
Liquids price (USD/bbl)	107.8	73.4	47 %	106.6	73.5	45 %	76.3
Liquids price (NOK/bbl)	593.1	452.6	31 %	592.1	447.5	32 %	461.0
Transfer price natural gas (NOK/scm)	1.55	1.32	17 %	1.61	1.19	35 %	1.27
Liftings:
Liquids (mboe per day)	720	618	17 %	672	696	(3 %)	711
Natural gas (mboe per day)	549	454	21 %	601	643	(6 %)	669
Total liquids and gas liftings (mboe per day)	1,268	1,072	18 %	1,273	1,339	(5 %)	1,380
Production:
Entitlement liquids (mboe per day)	697	609	14 %	691	702	(2 %)	704
Entitlement natural gas (mboe per day)	549	454	21 %	601	643	(6 %)	669
Total entitlement liquids and gas production (mboe perday)	1,245	1,063	17 %	1,292	1,345	(4 %)	1,374

Third quarter

• Production increased by 17% compared to the third quarter of 2010.
• High project activity with three sanctioned projects in the period and two PDOs approved: Stjerne and Vigdis North East.
• Six assets finalised turnarounds in third quarter.
• Nine exploration wells completed in the period, all new discoveries.

OPERATIONAL REVIEW

Average daily production of liquids increased from 609 mboe per day in the third quarter of 2010 to 697 mboe per day in the third quarter of 2011. The increase in production is mainly related to major turnaround effects in third quarter last year, new production at Morvin, Vega, Gjøa, increased production at Sleipner, Tyrihans, Alve, Oseberg and increased ownership share at Heidrun. These effects were partly offset by Gullfaks due to reduced water injection, Visund riser challenges and problems with anchor lines at Volve. Reductions due to natural decline on mature fields were as expected.

Average daily production of gas increased from 454 mboe per day in the third quarter of 2010 to 549 mboe per day in the third quarter of 2011. The increase is mainly related to major turnaround effects in third quarter last year, new production from Vega and Gjøa, increased gas production from Tyrihans and increased production at Ormen Lange due to a more flexible production permit. This is partly offset by lower gas sales at Troll, riser problems at Visund and reduced gas production from Gullfaks satellites.

Average daily lifting of liquids increased from 618 mboe per day in the third quarter of 2010 to 720 mboe per day in the third quarter of 2011.

Exploration expenditure (including capitalised exploration expenditure) increased by NOK 0.2 billion, from NOK 1.4 billion in the third quarter 2010 to NOK 1.6 billion in the third quarter 2011. This was mainly due to higher drilling activity in third quarter of 2011, partly offset by more expensive wells in the same period last year. In third quarter 2011, nine wells were completed, all announced as discoveries, while four wells were completed in the same quarter last year, of which three were announced as discoveries.

FINANCIAL REVIEW

In the third quarter of 2011, net operating income for Development and Production Norway was NOK 38.0 billion compared to NOK 23.5 billion in the third quarter of 2010. The increase was mainly attributable to increased oil and gas prices, increased oil and gas lifting, partly offset by a lower USD/NOK exchange rate and increased depreciation, depletion and amortisation.

In the third quarter of 2011, an unrealised gain on derivatives (NOK 1.9 billion) and overlift (NOK 0.6 billion) had a positive impact on net operating income. A change in future settlement related to a sale of a licence share (NOK 0.2 billion) negatively impacted net operating income. In the third quarter of 2010, an unrealised gain on derivatives (NOK 0.9 billion), overlift (NOK 0.4 billion), gain on sale of assets (NOK 0.2 billion) and an adjustment related to pension cost (NOK 0.2 billion) had a positive impact on net operating income.

Operating expenses and selling, general and administrative expenses increased by NOK 1.4 billion in the third quarter of 2011 compared to the same period last year due to increased transportation and processing costs because of increased production and increased ownership share in Heidrun.

Depreciation, amortisation and net impairment losses increased by NOK 1.9 billion in the third quarter of 2011 compared to the same period last year, mainly due to new fields with high depreciation cost, increased owner share after redetermination on the Heidrun field, the impact on depreciation of prior year revisions of removal/abandonment estimates and increased production.

Exploration expenses increased by NOK 0.1 billion from NOK 1.0 billion in third quarter 2010 to NOK 1.1 billion for the same period in 2011. The increase was mainly due to higher drilling activity, partly offset by higher capitalised exploration cost due to more discoveries compared to the same quarter previous year.

First nine months 2011

OPERATIONAL REVIEW

Average daily production of liquids decreased from 702 mboe per day in the first three quarters of 2010 to 691 mboe per day in the first three quarters of 2011. The decrease in liquids production is mainly related to Gullfaks reduced water injection and turnaround, Visund turnaround and riser challenges and Volve shut down due to anchor problems. In addition, expected reductions due to natural decline on mature fields contributed to the decrease. These effects were partly offset by new production at Morvin, Vega and Gjøa, increased production at Tyrihans and Sleipner and increased ownership share at Heidrun.

Average daily production of gas decreased from 643 mboe per day in the first three quarters of 2010 to 601 mboe in the first three quarters of 2011. The reduction in gas production is mainly related to Troll and Oseberg due to lower gas sales, start-up problems after turnaround at Snøhvit and reduced gas export from Gullfaks. This is partly offset by new production from Vega and Gjøa, increased gas export Tyrihans, start up production from Beta West at Sleipner and increased production at Ormen Lange due to a more flexible production permit.

Average daily lifting of liquids decreased from 696 mboe per day in the first three quarters of 2010 to 672 mboe per day in the first three quarters of 2011.

Exploration expenditure (including capitalised exploration expenditure) increased by NOK 1.1 billion from NOK 3.8 billion in the first nine months of 2010 to NOK 4.9 billion in the first nine months of 2011. The increase was mainly caused by drilling activity in the first nine months of 2011. In the first nine months of 2011, 22 wells were completed and 16 wells announced as discoveries, while 13 wells were completed and 11 wells announced as discoveries in the first nine months of 2010.

FINANCIAL REVIEW

In the first nine months of 2011, net operating income for Development and Production Norway was NOK 113.8 billion compared to NOK 81.8 billion in the first nine months of 2010. The increase in net operating income was mainly due to an increase in realised price of liquids measured in NOK and an increase in the transfer sales price of natural gas, which positively impacted net operating income by NOK 38.6 billion. This was partly offset by a decrease in oil and natural gas production, which negatively impacted net operating income by NOK 3.5 billion.

In the first nine months of 2011, underlift (NOK 2.1 billion) and change in future settlement related to a sale of a licence share (NOK 0.4 billion) negatively impacted net operating income. An unrealised gain on derivatives (NOK 4.1 billion) positively impacted net operating income. In the first nine months of 2010, an unrealised gain on derivatives (NOK 2.1 billion), gain on sale of assets (NOK 0.2 billion) and an adjustment related to pension cost (NOK 0.2 billion) positively impacted net operating income, while an underlift (NOK 0.6 billion) negatively impacted net operating income.

Operating expenses and selling, general and administrative expenses increased by NOK 0.4 billion in the first nine months of 2011, compared to the same period last year. The increase was mainly related to increased transportation and processing costs and increased ownership share in Heidrun, partly offset by reduced costs for purchase of gas for re-injection on Grane.

Depreciation, amortisation and net impairment losses increased by NOK 3.5 billion in the first nine months of 2011 compared to the same period last year, mainly due to new fields with high depreciation cost, updated removal/abandonment estimates and increased owner share after redetermination on Heidrun, partly offset by of lower production.

Exploration expenses were reduced by NOK 0.2 billion from NOK 3.4 billion in the first nine months of 2010 to NOK 3.2 billion in the first nine months of 2011. This is mainly due to lower exploration expenditure capitalised in previous years being expensed and higher capitalised exploration cost as more discoveries have been made this year compared to last year, partly offset by higher drilling activity.

Important events since last quarter:

• Exploration activity in the period included nine discoveries.
• Plan for development and operation (PDO) for the Skuld fast track projects were submitted.
• The Ministry of Petroleum and Energy (MPE) has approved two PDOs: Vigdis North East and Stjerne.

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DEVELOPMENT AND PRODUCTION INTERNATIONAL

IFRS income statement — (in NOK billion)	Third quarter — 2011	2010	Change	First nine months — 2011	2010	Change	Full Year — 2010
Total revenues and other income	12.9	12.6	3 %	54.5	37.7	45 %	51.0
Purchase [net of inventory variation]	0.3	0.1	>100 %	0.2	0.1	>100 %	0.0
Operating expenses and selling, general and administrative expenses	3.5	2.9	18 %	9.4	8.8	8 %	11.4
Depreciation, amortisation and net impairment losses	4.6	5.7	(18 %)	9.3	13.3	(30 %)	16.7
Exploration expenses	2.1	2.7	(20 %)	5.9	7.1	(17 %)	10.3
Total operating expenses	10.5	11.4	(8 %)	24.8	29.2	(15 %)	38.4
Net operating income	2.4	1.2	>100 %	29.7	8.5	>100 %	12.6

Operational data	Third quarter — 2011	2010	Change	First nine months — 2011	2010	Change	Full year — 2010
Prices:
Liquids price (USD/bbl)	106.0	74.6	42 %	106.8	74.7	43 %	76.8
Liquids price (NOK/bbl)	583.1	459.7	27 %	593.2	454.7	30 %	464.2
Liftings:
Liquids (mboe per day) [12]	220	255	(13 %)	217	267	(19 %)	258
Natural gas (mboe per day)	76	57	34 %	76	71	7 %	68
Total liquids and gas liftings (mboe per day) [12]	297	311	(5 %)	293	338	(13 %)	327
Production:
Entitlement liquids (mboe per day) [6]	252	259	(3 %)	239	268	(11 %)	263
Entitlement natural gas (mboe per day)	76	57	34 %	76	71	7 %	68
Total entitlement liquids and gas production (mboe perday)	328	316	4 %	315	339	(7 %)	332
Total equity liquids production (mboe per day)	428	409	4 %	417	425	(2 %)	417
Total equity gas production (mboe per day)	91	79	15 %	99	99	1 %	97
Total equity liquids and gas production (mboe per day)	519	489	6 %	516	523	(1 %)	514

Third quarter

• Revenues were positively impacted by a 28% increase in liquids prices measured in NOK compared to the third quarter of 2010.
• Equity production increased by 6% compared to the third quarter of 2010.
• Entitlement production increased by 4%.

OPERATIONAL REVIEW

Average daily entitlement production of liquids and gas was 328 mboe per day in the third quarter of 2011, compared to 316 mboe per day in the third quarter of 2010.

The increase in entitlement production was due to higher equity production in the third quarter of 2011 partly offset by an increased negative effect from Production Sharing Agreements (PSA). The PSA effect on entitlement production was 191 mboe per day in the third quarter of 2011, compared to 173 mboe in the third quarter of 2010. The increase in PSA effect was mainly a result of higher prices for liquids and gas and changes in profit tranches leading to lower entitlement production.

Average daily equity production of liquids increased from 409 mboe per day in the third quarter of 2010 to 428 mboe per day in the third quarter of 2011. The increase in liquids production was mainly due to production start-up in 2011 on Peregrino in Brazil, Leismer in Canada and Pazflor in Angola. The increase was partly offset by ACG in Azerbaijan due to operational issues and planned turnaround, decline in Angola and suspended production in Libya.

Average daily equity production of gas increased from 79 mboe per day in the third quarter of 2010 to 91 mboe per day in the third quarter of 2011. The increase was mainly due to U.S. onshore production at Marcellus with an increased number of wells online and at Eagle Ford which was acquired in December 2010. The increase was partly offset by Shah Deniz due to wells shut down and planned turnaround.

Average daily lifting of liquids and gas decreased from 311 mboe per day in the third quarter of 2010 to 297 mboe per day in the third quarter of 2011.

Exploration expenditure (including capitalised exploration expenditure) increased by NOK 0.9 billion from NOK 2.4 billion in the third quarter of 2010 to NOK 3.3 billion in the third quarter of 2011. This is mainly caused by higher drilling cost of NOK 0.9 billion. In the third quarter of 2011, there has been drilling activity in eleven wells with four completed, while in the third quarter of 2010, there was drilling activity in eight wells with two completed. Three of the wells in third quarter 2010 were, however, low cost Angola wells. This year, increased drilling activity in Brazil has contributed to the higher cost as the wells are more expensive. There was no drilling activity in GoM in third quarter 2010 due to the GoM Moratorium.

In the third quarter of 2011, a total of four exploration (and appraisal) wells were completed before 30 September 2011 while none were announced as discovery.

FINANCIAL REVIEW

In the third quarter of 2011, net operating income for Development and Production International was NOK 2.4 billion compared to NOK 1.2 billion in the same period last year.

Net operating income in the third quarter of 2011 was negatively impacted by underlift of NOK 0.6 billion and impairments of NOK 0.9 billion. Provisions related to other income and sales/administration impacted net operating income negatively with NOK 0.2 billion. In the third quarter of 2010, net operating income was positively impacted by an increase in total revenues and other income of NOK 0.5 billion and overlift of NOK 0.1 billion, while an impairment of NOK 1.9 billion, of which NOK 1.6 billion was related to the Corrib development asset in Ireland, had a negative impact on net operating income.

Increased realised liquids and gas prices measured in NOK impacted net operating income positively by NOK 2.9 billion. These effects were partly offset by reduced entitlement production.

Operating expenses and selling, general and administrative expenses increased from the third quarter of 2010 to the third quarter of 2011 from NOK 2.9 billion to NOK 3.5 billion respectively. In the third quarter of 2011, costs related to start up of production of additional new wells at Marcellus and Eagle Ford as well as start up at the Leismer field and ramp-up on Peregrino contributed to a cost increase. Further, production bonus and royalties related to Agbami, Tahiti and Terra Nova increased compared to the same quarter last year.

Depreciation, amortisation and net impairment losses were NOK 4.6 billion in the third quarter of 2011, compared to NOK 5.7 billion in the third quarter of 2010. The reduction was mainly due to impairment losses in 2010 of NOK 1.9 billion, of which NOK 1.6 billion was related to the Corrib development asset in Ireland. Higher depreciation resulting from the production and ramp-up on Peregrino and Marcellus in the third quarter of 2011 partly offset the reduction.

Exploration expenses were NOK 2.1 billion in the third quarter of 2011, compared to NOK 2.7 billion in the third quarter of 2010. The decrease of NOK 0.6 billion was mainly due to decreased dry well expense and decreased expensed exploration that was capitalised in earlier years, partly offset by impairments of NOK 0.9 billion recorded in the third quarter of 2011.

First nine months 2011

OPERATIONAL REVIEW

Average daily entitlement production of liquids and gas was 315 mboe per day in the first nine months of 2011, compared to 339 mboe per day in the first nine months of 2010.

The decrease in entitlement production was due to lower equity production in the first nine months of 2011 and a higher negative effect from Production Sharing Agreements (PSA). The PSA effect on entitlement production was 201 mboe per day in the first nine months of 2011, compared to 184 mboe in the first nine months of 2010. The increase in PSA effect was mainly a result of higher prices for liquids and gas leading to lower entitlement production and changes in profit tranches.

Average daily equity production of liquids decreased from 425 mboe per day in the first nine months of 2010 to 417 mboe per day in the first nine months of 2011. The decrease in liquids production was mainly due to decline and turnarounds in Angola, operational issues on ACG in Azerbaijan, lower production from Terra Nova in Canada, and suspended production in Libya. The decrease was partly offset, mainly by production start-up in 2011 on Peregrino in Brazil, Leismer in Canada and Pazflor in Angola.

Average daily equity production of gas was 99 mboe per day in the first nine months of 2011 which is unchanged from the first nine months of 2010. There is increased production due to U.S. onshore production at Marcellus with an increased number of wells online and at Eagle Ford which was acquired in December 2010. The increase was offset by In Salah in Algeria due to turnaround and Shah Deniz in Azerbaijan due to wells shut down and planned turnaround.

Average daily lifting of liquids and gas decreased from 338 mboe per day in the first nine months of 2010 to 293 mboe per day in the first nine months of 2011.

Exploration expenditure (including capitalised exploration expenditure) increased by NOK 1.0 billion from NOK 7.3 billion in the first nine months of 2010 to NOK 8.3 billion in the first nine months of 2011. The increase is due to higher drilling costs compared to the same period last year, with higher Statoil share. Drilling activity stayed at the same level as 2010.

In the first nine months of 2011, a total of ten exploration (and appraisal) wells were completed before 30 September 2011. Three wells were announced as discoveries.

FINANCIAL REVIEW

In the first nine months of 2011, net operating income for Development and Production International was NOK 29.7 billion compared to NOK 8.5 billion in the same period last year.

Net operating income for the first nine months of 2011 was positively impacted by NOK 14.3 billion from gains on sale of Peregrino and the Canadian oil sands assets and net impairment reversals of NOK 1.3 billion. An underlift of NOK 0.8 billion and provisions of NOK 0.2 billion negatively impacted net operating income for the first nine months of 2011. In the first nine months of 2010, impairment losses net of reversals of NOK 2.1 billion and provisions related to total revenues and other income of NOK 0.2 billion negatively impacted net operating income. An overlift of NOK 1 billion had a positive effect on net operating income in the first nine months of 2010.

Operating expenses, and selling, general and administrative expenses increased by NOK 0.6 billion compared to the same period last year, mainly due to increased operating expenses from Peregrino in Brazil and Leismer in Canada which started up production in 2011 and Marcellus in the U.S. which continue to ramp up.

Depreciation, amortisation and net impairment losses decreased by NOK 4.0 billion compared to the same period last year, mainly due to impairment losses of NOK 2.1 billion in 2010 and impairment reversals of NOK 1.3 billion in 2011. An increase of reserves on Agbami in Nigeria and Bl 17 in Angola contributed to a decrease in Depreciation, amortisation and net impairment losses in the third quarter of 2011, partly offset by higher depreciation due to increased production, mainly from Peregrino in Brazil, Leismer in Canada, Marcellus and Eagle Ford in the U.S.

Exploration expenses were NOK 7.1 billion in the first nine months of 2010, compared to NOK 5.9 billion in the same period in 2011. The decrease of NOK 1.2 billion is due to higher capitalisation of exploration expenditure in 2011 compared to 2010.

Important events since last quarter

• Successful business development by entering into a merger agreement with Brigham Exploration Company for Statoil to acquire all the outstanding shares of Brigham through an all-cash tender offer. If the tender offer is successful, the acquisition will further expand Statoil's position in unconventionals and will add 375,000 net acres in the Williston Basin in the U.S. with potential for oil production from the Bakken and Three Forks formations.
• On 24 August, the start-up of the Pazflor development in Angola was announced. This third development hub of Block 17 is located 150 kilometres off Luanda in water depths ranging from 600 to 1200 meters. Statoil has a 23.33% interest in Block 17.
• Statoil and Talisman closed the acquisition of properties from Denver-based independent SM Energy Company on 2 August. The transaction added 15,400 acres to the companies' 50/50 Eagle Ford joint venture in Texas, USA. The total purchase price was USD 225 million.
• Participating interests in two exploration licences in Camamu-Almada basin offshore Brazil have been farmed down 10% and 15% respectively to Gran Tierra Energy. The agreement is subject to approval by Brazilian authorities and other conditions.

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MARKETING, PROCESSING AND RENEWABLE ENERGY

IFRS income statement — (in NOK billion)	Third quarter — 2011	2010	Change	First nine months — 2011	2010	Change	Full Year — 2010
Total revenues and other income	153.9	116.0	33 %	438.3	357.2	23 %	493.3
Purchase [net of inventory variation]	142.2	107.0	33 %	404.8	326.2	24 %	452.1
Operating expenses and selling, general and administrative expenses	7.3	6.0	22 %	21.3	24.3	(12 %)	29.2
Depreciation, amortisation and net impairment losses	4.6	0.8	>100 %	5.3	5.2	2 %	5.9
Total operating expenses	154.0	113.8	35 %	431.4	355.7	21 %	487.2
Net operating income	(0.1)	2.3	>(100 %)	6.9	1.5	>100 %	6.1

Operational data	Third quarter — 2011	2010	Change	First nine months — 2011	2010	Change	Full year — 2010
Refining margin (reference margin, USD/bbl)	2.7	2.7	0 %	2.5	3.8	(34 %)	3.9
Contract price methanol (EUR/tonne)	295	255	16 %	305	247	23 %	254
Natural gas sales Statoil entitlement (bcm)	8.7	7.5	16 %	28.1	30.1	(7 %)	41.7
Natural gas sales (third-party volumes) (bcm)	2.6	2.9	(12 %)	8.8	8.2	7 %	11.1
Natural gas sales (bcm)	11.3	10.4	8 %	36.9	38.3	(4 %)	52.8
Natural gas sales on commission	0.3	0.4	(18 %)	0.9	1.1	(21 %)	1.5
Natural gas price (NOK/scm)	1.97	1.74	13 %	1.99	1.65	21 %	1.72
Transfer price natural gas (NOK/scm)	1.55	1.32	17 %	1.61	1.19	35 %	1.27
Regularity at delivery point	100 %	100 %	0 %	100 %	100 %	0 %	100 %

Third quarter

• Significant increase in oil and gas prices compared to the third quarter of 2010.
• Stronger results in Natural gas marketing and trading due to higher trading margin and higher entitlement production compared to the third quarter of 2010.
• Weaker results in Crude oil processing, marketing and trading due to lower margins from products and gas liquids trading compared to the third quarter of 2010.
• High available capacity at gas and oil processing facilities compared to the third quarter of 2010.

OPERATIONAL REVIEW

Natural gas sales volumes in the third quarter of 2011 were 11.3 billion standard cubic metres (bcm), compared to 10.4 bcm in the third quarter of 2010. Of total gas sales in the third quarter of 2011, entitlement gas amounted to 8.7 bcm gas and 1.1 bcm was related to the Norwegian State's direct financial interest (SDFI) share of US gas sales. In the third quarter of 2010, 7.5 bcm of total sales was entitlement gas and 1.0 bcm was SDFI share of US gas sales. The 8% increase in total gas volumes from the third quarter of 2010 to the third quarter of 2011 was related to low entitlement production in the third quarter of 2010.

In the third quarter of 2011 the volume weighted average natural gas sales price was NOK 1.97 per scm (USD 9.45 per million British thermal units), compared to NOK 1.74 per scm (USD 8.34 per million British thermal units) in the third quarter of 2010, an increase of 13%. The increase was due to an increase in gas prices linked to oil products as well as gas indexed prices.

Refinery throughput in the third quarter of 2011 was higher than in the third quarter of 2010 due to turnaround at Mongstad in 2010 and higher on stream factor and capacity utilisation in 2011 at the Mongstad refinery. This was partly offset by the Kalundborg refinery, which had lower on stream factor and capacity utilisation this year.

Methanol production in the third quarter of 2011 was 8% higher than in the third quarter of 2010, due to improved on-stream factor and capacity utilisation in 2011. FINANCIAL REVIEW

In the third quarter of 2011 net operating income for Marketing, Processing and Renewable Energy was a loss of NOK 0.1 billion compared to a profit of NOK 2.3 billion in the third quarter of 2010. The decrease was mainly due to impairment losses related to refinery assets and a gas fire power station (NOK 3.8 and 0.1 billion), partly offset by stronger trading results and higher volumes and a gain on sale of assets (NOK 0.2 billion). The refinery assets impairment losses in the third quarter of 2011 were related to the Mongstad and Kalundborg refineries, primarily reflecting our lower forecast for future margins.

Net operating income in the third quarter of 2010 included a reduction of provision for an onerous contract in connection with the Cove Point regasification terminal in the US (NOK 0.8 billion), and a positive change in fair value of derivatives (NOK 0.8 billion).

Total revenues and other income were up 33% to NOK 153.9 billion due to higher prices for crude, other oil products and gas and higher volumes of oil and gas sold.

Purchase [net of inventory variation] was up 33% to NOK 142.2 due to the same factors.

Operating expenses and selling, general and administration expenses were up 22% to NOK 7.3 billion. The increase was mainly due to increased transportation activity in the US and operation of the new combined heat and power plant (CHP) at Mongstad.

Depreciation, amortisation and net impairment losses increased by NOK 3.8 billion to NOK 4.6 billion in the third quarter of 2011, mainly due to impairment losses related to the Mongstad and Kalundborg refineries. Reduced ownership share of 3.7% in Gassled from 1 January 2011 and the 24.1% ownership share of Gassled to be sold being reclassified to held for sale on 5 June 2011 and depreciation of the associated share of assets ceasing as of that date, partly offset the increase. (The Gassled ownership share was reduced by 3.7% on 1 January as an effect of historical agreements when Gassled was established. On 5 June 2011 Statoil entered into an agreement to sell a 24.1% interest pending approval of the Norwegian authorities.)

Net operating income in Natural gas processing and transportation was NOK 1.3 billion in the third quarter of 2011, compared to NOK 1.3 billion in the third quarter of 2010. The reduction in tariffs in Gassled, and a 3.7% reduction in ownership share in Gassled was offset by lower depreciations. The net operating income for the third quarter of 2011 included results from on-going operations related to the 24.1% share of Gassled that Statoil has agreed to sell to Solveig Gas Norway AS, but without depreciation on these assets.

Net operating income in Natural gas marketing and trading were NOK 1.7 billion in the third quarter of 2011, compared to NOK 1.9 billion in the third quarter of 2010. The decrease was mainly due to a reduction of provision for an onerous contract in connection with the Cove Point regasification terminal in the US in the third quarter of 2010, partly offset by higher margin on gas sales and higher entitlement volumes in the third quarter of 2011. In the third quarter of 2011, there was a mark to market loss related to time optimization. The overall result from the time optimization is positive and mainly reflected in Development & Production Norway.

Net operating income in Crude oil processing, marketing and trading was a loss of NOK 3.2 billion in the third quarter of 2011, compared to a loss of NOK 0.7 billion in the third quarter of 2010. The increased loss was mainly due to impairment losses related to refinery assets and a gas fire power station (NOK 3.8 and 0.1 billion) in the third quarter of 2011. This loss was partly offset by a positive change in fair value of derivatives. In the third quarter of 2011, margins from products and gas liquids were lower than in the same period in 2010. The traditionally strong gasoline market, during this part of the year, has been very weak. Gas liquids experienced slower than expected demand growth and an oversupplied market.

First nine months 2011

OPERATIONAL REVIEW

Natural gas sales volumes in the first nine months of 2011 was 36.9 (bcm), compared to 38.3 bcm in the first nine months of 2010. Of total gas sales in the first nine months of 2011, entitlement gas amounted to 28.1 bcm gas and 3.4 bcm was related to the Norwegian state's direct financial interest (SDFI) share of US gas sales. In the first nine months of 2010, 30.1 bcm of total sales was entitlement gas and 3.0 bcm was SDFI share of US gas sales. The 4% decrease in total gas volumes from the first nine months of 2010 to the first nine months of 2011 was mainly related to high entitlement production in the second quarter of 2010.

In the first nine months of 2011 the volume weighted average sales price was NOK 1.99 per scm (USD 9.54 per million British thermal units), compared to NOK 1.65 per scm (USD 7.91 per million British thermal units) in the first nine months of 2010, an increase of 21%. The increase was due to an increase in gas prices linked to oil products as well as gas indexed prices.

Refinery throughput in the first nine months of 2011 was higher than in the first nine months of 2010 due to higher on stream factor and capacity utilisation at the Mongstad refinery. This was partly offset by the Kalundborg refinery, which had lower on stream factor and capacity utilisation in the first nine months of 2011 compared to the first nine months of 2010.

Methanol production in the first nine months of 2011 was 15% higher than in the first nine months of 2010, mainly due to turnaround in 2010, but also improved on stream factor and capacity utilisation.

FINANCIAL REVIEW

In the first nine months of 2011 net operating income for Marketing, Processing and Renewable Energy was NOK 6.9 billion compared to NOK 1.5 billion in the first nine months of 2010. The increase was mainly due to a reversal of a provision and impairment in connection with the Cove Point regasification terminal in the US (NOK 1.6 billion), positive changes to the fair value of derivatives of NOK 1.6 billion in the first nine months of 2011 compared with a provision for onerous contract of NOK 3.6 billion and a negative change in fair value of derivatives of NOK 2.9 billion in the same period last year. The increase was partly offset by higher impairment losses related to refinery assets and a gas fire power station in the current period, weaker trading results, lower volumes, lower refining margins and lower results from the 3.7% reduction in interest in Gassled as of 1 January 2011.

Total revenues and other income were up 23% to NOK 438.3 billion due to higher prices for crude, other oil products and gas, but were partly offset by lower volumes of oil and gas sold.

Purchase [net of inventory variation] was up 24% to NOK 404.8 due to the same factors.

Operating expenses and selling, general and administration expenses were down 12% to NOK 21.3 billion. The decrease was mainly due to a provision for an onerous contract in connection with Cove Point during the first nine months of 2010, partly offset by increased expenses related to new time charter shipping contracts, increased transportation activity in the US, and operation of the new combined heat and power plant (CHP) at Mongstad.

Depreciation, amortisation and net impairment losses were up 2% to NOK 5.3 billion in the first nine months of 2011 due to higher impairment losses related to refinery assets in 2011 compared to 2010. Lower depreciation related to the assets held for sale and the 3.7% reduction in ownership share in Gassled from 1 January 2011 partly offset the increase.

Net operating income in Natural gas processing and transportation was NOK 3.6 billion in the first nine months of 2011, compared to NOK 4.3 billion in the first nine months of 2010. The reduction was mainly due to reduced tariffs in Gassled and 3.7% reduction in ownership share in Gassled.

Net operating income in Natural gas marketing and trading was NOK 6.6 billion in the first nine months of 2011, compared to a loss on NOK 0.8 billion in the first nine months of 2010. The increase was mainly due to an onerous contract in connection with Cove Point regasification terminal in the US and a negative change in fair value of derivatives in the first nine month of 2010. This was partly offset by lower margin from gas sales, lower entitlement volumes, and realized loss related to time optimization.

Net operating income in Crude oil processing, marketing and trading was a loss of NOK 3.1 billion in the first nine months of 2011, compared to a loss of NOK 1.5 billion in the first nine months of 2010. The reduction was mainly due to impairment losses related to refinery assets and a gas fire power station (NOK 3.8 and 0.1 billion) in the third quarter of 2011 compared with impairment losses of NOK 2.9 billion in the first nine months of 2010. Other factors that contributed to the reduction included lower margins from trading of crude oil, products and gas liquids, and storage strategies in a challenging market in backwardation , and lower refining margins further contributed to the reduction.

Important events since last quarter :

• The transactions related to sale of major parts of Statoil's onshore wind power activities in Norway have been closed.

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FUEL & RETAIL

IFRS income statement — (in NOK billion)	Third quarter — 2011	2010	Change	First nine months — 2011	2010	Change	Full Year — 2010
Total revenues and other income	19.0	16.9	13 %	55.0	48.5	14 %	65.9
Purchase [net of inventory variation]	16.4	14.0	17 %	47.4	40.1	18 %	54.8
Operating expenses and selling, general and administrative expenses	1.7	1.8	(7 %)	5.3	5.4	(3 %)	7.4
Depreciation, amortisation and net impairment losses	0.3	0.3	(6 %)	0.9	1.0	(12 %)	1.3
Total operating expenses	18.4	16.1	14 %	53.5	46.5	15 %	63.5
Net operating income	0.6	0.7	(15 %)	1.5	1.9	(20 %)	2.4

Third quarter

At the end of the third quarter of 2011, Statoil's ownership interest in Statoil Fuel & Retail ASA was 54%.

OPERATIONAL REVIEW

Road transport fuel volumes for the third quarter of 2011 were flat compared with same period last year. A small decrease in Scandinavian volumes driven by a decline in gasoline business-to-consumer (B2C) sales was offset by a moderate increase in Central and Eastern Europe, primarily through growth in the business-to-business (B2B) segment.

Road transportation fuel unit margins for the third quarter decreased by 3.3% to NOK 0.618 compared with the same period in 2010. In Scandinavia, margins increased by 4.2%, primarily driven by improved micro market pricing. In Central and Eastern Europe the margins decreased by 30.7% compared with last year, primarily driven by lower margins in Poland and Russia where increased refined oil product prices were not fully reflected in retail prices. Increased business-to-business sales are also affecting Central and Eastern European margins negatively.

FINANCIAL REVIEW

In the third quarter of 2011, net operating income was NOK 0.6 billion, compared with NOK 0.7 billion in the same period in 2010.

Total revenues and other income increased from NOK 16.9 billion in the third quarter of 2010 to NOK 19.0 billion in the third quarter of 2011 driven by higher underlying refined oil products prices.

Purchase [net of inventory variation] increased from NOK 14.0 billion in the third quarter of 2010 to NOK 16.4 billion in the third quarter of 2011, explained by higher underlying refined oil products prices.

Operating expenses and selling, general and administrative expenses amounted to NOK 1.7 billion in the third quarter of 2011, compared to NOK 1.8 billion for the same period in 2010.

Depreciation, amortisation and net impairment losses ended at NOK 0.3 billion in third quarter of 2011, on par with same period last year.

First nine months 2011

OPERATIONAL REVIEW

For the first nine months of 2011, volumes decreased marginally compared with 2010. In Scandinavia, volumes were slightly lower than the same period last year, due to dieselisation. In Central and Eastern Europe volumes increased by 1.1% compared to 2010, primarily due to increased volumes in the business-to-business (B2B) segment.

Margins for the first nine months of 2011 increased by 4.0% compared to same period last year, from NOK 0.600 to NOK 0.624. In Scandinavia, improved micro market pricing and a favourable development in refined oil product prices, during the second quarter of 2011, increased margins by 9.9%. In Central and Eastern Europe, margins decreased by 18.6%, as pump prices did not fully reflect the increase in refined oil product prices.

FINANCIAL REVIEW

In the first nine months of 2011 net operating income decreased by NOK 0.4 billion, from NOK 1.9 billion to 1.5 billion in the first nine months of 2011. The decrease was primarily explained by the gain of NOK 0.3 billion from the sale of Swedegas in first quarter 2010.

Total revenue and other income increased from NOK 48.5 billion in the first nine months of 2010 to NOK 55.0 billion in the first nine months of 2011 driven by higher underlying refined oil products prices.

Purchase [net of inventory variation] increased from NOK 40.1 billion in the first nine months of 2010 to NOK 47.4 billion in the first nine months of 2011, explained by higher underlying refined oil products prices.

Operating expenses and selling, general and administrative expenses were on approximately the same level in the first nine months of 2011 as compared with same period last year, despite inflationary pressure and increased standalone costs.

Depreciation, amortisation and net impairment losses decreased from NOK 1.0 billion in the first nine months of 2010 to NOK 0.9 in the first nine months of 2011, primarily due to an impairment in 2010 of NOK 0.1 billion.

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LIQUIDITY AND CAPITAL RESOURCES

Third quarter

Cash flows provided by operations amounted to NOK 24.2 billion in the third quarter of 2011, compared to NOK 19.0 billion in the third quarter of 2010. The NOK 5.1 billion increase was mainly due to higher cash flows from income before tax of NOK 6.9 billion, adjustments to income before tax of NOK 5.2 billion and net cash provided by other changes of NOK 4.4 billion. An increase in production combined with an increase in the prices of liquids and gas in 2011 compared to 2010 was the main driver for the increase in income before tax in the third quarter of 2011, compared to the third quarter of 2010. The increase in cash flows from income before tax and adjustments to income before tax was partially offset by an increase in current financial investments of NOK 5.2 billion and an increase in taxes paid of NOK 5.1 billion. In the third quarter of 2011, excess cash and cash equivalents have been invested in financial instruments with an acceptable risk profile to obtain an acceptable return on investment.

Condensed cash flow statement — (in NOK billion)	Third quarter — 2011	2010	Change	First nine months — 2011	2010	Change	Full year — 2010
Income before tax	42.2	35.3	6.9	153.7	99.0	54.7	136.8
Adjustments to income before tax	17.5	12.3	5.2	23.2	40.0	(16.7)	54.1
Cash flows from (to) changes in working capital	4.6	5.8	(1.2)	6.7	(1.9)	8.6	(10.6)
Changes in current financial investments	(12.8)	(7.6)	(5.2)	(29.0)	(7.4)	(21.7)	(4.5)
Changes in net derivative financial instruments	(5.7)	(5.8)	0.1	(8.4)	(6.7)	(1.7)	(0.6)
Taxes paid	(22.5)	(17.4)	(5.1)	(67.4)	(57.1)	(10.3)	(92.3)
Other changes	0.9	(3.5)	4.4	(1.1)	1.2	(2.3)	(2.2)
Cash flows provided by operations	24.2	19.0	5.1	77.8	67.1	10.7	80.8
Additions to PP&E and other intangible assets	(19.5)	(18.1)	(1.3)	(55.5)	(49.8)	(5.7)	(68.1)
Proceeds from sales (including prepayments)	0.2	0.7	(0.6)	29.5	1.6	28.0	1.9
Other changes	(4.5)	(0.7)	(3.8)	(7.3)	(6.0)	(1.3)	(10.3)
Cash flows used in investing activities	(23.8)	(18.1)	(5.7)	(33.3)	(54.2)	20.9	(76.5)
Net change in long-term borrowing	(0.4)	11.4	(11.8)	(4.8)	8.5	(13.3)	12.2
Net change in short-term borrowing	2.9	4.0	(1.1)	5.2	4.8	0.5	0.8
Dividends paid	0.0	0.0	0.0	(19.9)	(19.1)	(0.8)	(19.1)
Other changes	(0.2)	0.0	(0.2)	(0.6)	(0.1)	(0.5)	5.2
Cash flows provided by (used in) financing activities	2.3	15.5	(13.1)	(20.1)	(6.0)	(14.1)	(0.9)
Net increase (decrease) in cash and cash equivalents	2.7	16.4	(13.7)	24.4	6.9	17.5	3.4

Cash flows used in investing activities amounted to NOK 23.8 billion in the third quarter of 2011, compared to NOK 18.1 billion in the third quarter of 2010. The NOK 5.7 billion increase stems mainly from a NOK 1.3 billion increased capital expenditures related to property, plant and equipment and other intangible assets and NOK 2.3 billion increase in capitalized exploration expenditures in the third quarter of 2011 compared to the same period last year. In the third quarter of 2011 the investment activities have been higher compared to 2010.

Gross investments , defined as additions to property, plant and equipment (including capitalised financial lease), capitalised exploration expenditure, intangible assets, long-term share investments and non-current loans granted, were NOK 23.9 billion in the third quarter of 2011, compared to NOK 18.9 billion in the third quarter of 2010.

Gross investments — (in NOK billion)	Third quarter — 2011	2010	Change	First nine months — 2011	2010	Change	Full year — 2010
- D&P Norway	10.4	7.8	33 %	28.8	23.4	23 %	31.9
- D&P International	11.8	8.2	43 %	29.8	29.3	2 %	40.4
- Marketing, Processing & Renewable Energy	1.3	1.6	(16 %)	3.6	3.9	(7 %)	6.3
- Fuel & Retail	0.4	0.2	>100 %	0.9	0.5	94 %	0.8
- Other	0.0	1.1	(96 %)	2.3	1.7	36 %	4.9
Gross investments	23.9	18.9	27 %	65.4	58.7	11 %	84.4

Cash flows used in investing activities and gross investments have been reconciled in the table below.

(in NOK billion)	2011	2010	2011	2010	2010
- Cash flows to investments	23.8	18.1	33.3	54.2	76.5
- Proceeds from sale of assets	0.2	0.7	29.5	1.6	1.9
- Financial lease	0.1	0.0	1.9	1.4	1.5
- Other changes	(0.3)	0.0	0.7	1.5	4.5
Gross investments	23.9	18.9	65.4	58.7	84.4

Cash flows provided by (used in) financing activities in the third quarter of 2011 amounted to NOK 2.3 billion, compared to NOK 15.5 billion in the third quarter of 2010. The NOK 13.1 billion change was mainly related to the issuance of new non-current bonds of NOK 11.6 billion in the third quarter of 2010 in addition to net change in net current loans of NOK 1.3 billion and changes in repayment of non-current bonds of NOK 0.2 billion.

Gross financial liabilities (non-current and current financial liabilities) were NOK 119.5 billion at 30 September 2011, compared to NOK 115.8 billion at 30 September 2010. The NOK 3.7 billion increase was due to an increase in current financial liabilities of NOK 2.1 billion and non-current bonds, bank loans and finance lease liabilities of NOK 1.6 billion.

Net financial liabilities [10] were NOK 30.2 billion at 30 September 2011, compared to NOK 72.8 billion at 30 September 2010. The decrease of NOK 42.6 billion was mainly related to an increase in cash and cash equivalents and current financial investments of NOK 43.7 billion, partly offset by an increase in gross financial liabilities of NOK 3.7 billion and a change in adjustments to net interest-bearing debt of NOK 2.6 billion.

The net debt to capital employed ratio [1] was 13.6% at 30 September 2011, compared to 27.7% at 30 September 2010. The 14.1 % decrease was mainly related to a decrease in net financial liabilities of NOK 39.8 billion. In the calculation of net interest-bearing debt, we make certain adjustments, which make net interest-bearing debt and the net debt to capital employed ratio non-GAAP financial measures. For an explanation and calculation of the ratio, see the following section: Use and reconciliation of non-GAAP financial measures. [2]

Cash, cash equivalents and current financial investments amounted to NOK 95.5 billion at 30 September2011, compared to NOK 46.9 at 30 September 2010. The NOK 48.6 billion increase reflects the high cash flow from operations and proceeds related to the sale of 40% of the Kai Kos Dehseh oil sands project and 40% of the Peregrino offshore heavy-oil field combined with high investment activity during 2011 and 2010. Cash and cash equivalents were NOK 54.9 billion at 30 September 2011, compared to NOK 32.5 billion at 30 September 2010. Cash and cash equivalents include restricted cash of NOK 5.9 billion at 30 September 2011 (NOK 2.6 billion at 31 December 2010) deposited with Statoil's US dollar denominated bank account in Nigeria. There are certain restrictions on the use of cash from Statoil's Nigerian operations following an injunction against Statoil by the Nigerian courts related to an on-going litigation claim. Both the injunction and the disputed claim have been appealed. Current financial investments, which are part of our cash management, amounted to NOK 40.5 billion at 30 September 2011, compared to NOK 14.4 billion at 30 September 2010.

The increase in cash, cash equivalents and other financial investments at 30 September 2011 compared to 30 September 2010 further strengthens the financial robustness and provide a basis for further business development, including the acquisition of Brigham.

Current items (total current assets less total current liabilities) increased by NOK 33.3 billion from positive NOK 0.9 billion at 30 September 2010 to positive NOK 34.2 billion at 30 September 2011. The change was due to increases in current receivables such as inventories of NOK 5.5 billion, accounts receivables of NOK 10.7 billion, financial investments of NOK 26.2 billion, cash and cash equivalents of NOK 22.2 billion and decrease in financial derivatives current liabilities of NOK 4.1 billion partly offset by increases in current liabilities such as current taxes payable of NOK 13.8 billion, accounts payable of NOK 8.1 billion and other current liabilities of NOK 5.4 billion.

First nine months 2011

Cash flows provided by operations amounted to NOK 77.8 billion in the first nine months of 2011, compared to NOK 67.1 billion in the first nine months of 2010. In the first nine months of 2011, cash flows from income before tax increased by NOK 54.7 billion from NOK 99.0 billion in the first nine months of 2010 to NOK 153.7 billion in the first nine months of 2011. The increase in cash flows from income before tax can largely be explained by higher liquids and gas prices in the first nine months of 2011 compared to the same period in 2010. In the first nine months of 2011, changes in working capital was NOK 8.6 billion higher compared to the first nine months of 2010. The positive changes described above was partly offset by NOK 23.4 billion negative changes in financial investments and derivative financial instruments, negative changes in adjustments to income before tax of NOK 16.7 billion, higher taxed paid of NOK 10.3 billion and negative other changes contributing NOK 2.3 billion. The increase in current financial investments is mainly related to the placement of cash of NOK 29.0 billion in financial instruments with an acceptable risk profile to obtain an acceptable return on investment.

Cash flows used in investing activities amounted to NOK 33.3 billion in the first nine months of 2011, compared to NOK 54.2 billion in the first nine months of 2010. In 2011, the investment activities have been higher compared to 2010, with an increase in additions to property, plant and equipment and other intangible assets of NOK 5.7 billion. However, the NOK 20.9 billion decrease in cash used in investing activities stems mainly from NOK 28.0 billion higher proceeds from sales, mainly related to proceeds from the sale of interests in the Kai Kos Dehseh oil sands in Canada and the Peregrino oil field in Brazil.

Gross investments amounted to NOK 65.4 billion in the first nine months of 2011 compared to NOK 58.7 billion in the first nine months of 2010.

Cash flows provided by (used in) financing activities in the first nine months of 2011 amounted to NOK 20.1 billion, compared to NOK 6.0 billion for the first nine months of 2010. The NOK 14.1 billion change was mainly related to new non-current bonds of NOK 11.6 billion issued in 2010, and the net increase in repayments of non-current bonds of NOK 1.7 billion and increased dividends paid of NOK 0.8 billion in the first nine months compared to the same period in 2010.

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USE AND RECONCILIATION OF NON-GAAP FINANCIAL MEASURES

Non-GAAP financial measures are defined as numerical measures that either exclude or include amounts that are not excluded or included in the comparable measures calculated and presented in accordance with GAAP (i.e. IFRS).

For more information on our use of non-GAAP financial measures, see report section - Financial performance - Use and reconciliation of Non-GAAP measures in Statoil's 2010 Annual Report on Form 20-F.

The following financial measure may be considered non-GAAP financial measures:

• Net debt to capital employed ratio

Production cost per barrel is based on operating expenses related to production of oil and gas. The following is a reconciliation of overall operating expenses to operating expenses exclusively related to production of oil and gas volumes:

Reconcilliation of overall operating expenses toproduction cost — (in NOK billion)	2011 — 30-Sep	30-Jun	31-Mar	31-Dec	2010 — 30-Sep
Operating expenses, Statoil Group	15.3	14.1	13.5	13.5	12.8
Deductions of costs not relevant to production cost calculation
1) Business Areas non-upstream	5.7	6.2	6.2	5.5	5.0
Total operating expenses upstream	9.6	8.0	7.3	8.0	7.8
2) Operation over/underlift	0.4	(0.8)	(0.7)	0.6	0.0
3) Transportation pipeline/vessel upstream	1.4	1.2	1.3	1.1	1.0
4) Miscellaneous items	0.8	0.7	0.2	(0.5)	0.2
Total operating expenses upstream excl. over/underlift & transportation	6.9	6.8	6.6	6.8	6.5
Total production costs last 12 months	27.1	26.6	26.4	26.3	26.3

Production cost summary — (in NOK per boe)	30.Sep — 2011	2010	30.Sep — 2011	2010
Calculated production cost	45.5	42.1	40.7	37.9

The calculated net debt to capital employed ratio is viewed by the company as providing a more complete picture of the group's current debt situation than gross interest-bearing debt. The calculation uses balance sheet items related to total debt and adjusts for cash, cash equivalents and current financial investments. Further adjustments are made for different reasons:

• Since different legal entities in the group lend to projects and others borrow from banks, project financing through external bank or similar institutions will not be netted in the balance sheet and will over-report the debt stated in the balance sheet compared to the underlying exposure in the group. Similarly, certain net interest-bearing debt incurred from activities pursuant to the Marketing Instruction of the Norwegian government is off-set against receivables on the SDFI.

• Some interest-bearing elements are classified together with non-interest bearing elements, and are therefore included when calculating the net interest-bearing debt.

The table below reconciles net interest-bearing debt, capital employed and the net debt to capital employed ratio to the most directly comparable financial measure or measures calculated in accordance with IFRS.

(in NOK billion, except percentages)	2011	2010	2010
Total shareholders' equity	254.4	209.1	219.5
Non-controlling interests	6.2	1.3	6.9
Total equity and minority interest (A)	260.6	210.4	226.4
Short-term debt	17.2	15.1	11.7
Long-term debt	102.3	100.7	99.8
Gross interest-bearing debt	119.5	115.8	111.5
Cash and cash equivalents	54.9	32.5	30.3
Current financial investments	40.5	14.4	11.5
Cash and cash equivalents and current financial investment	95.5	46.9	41.8
Net debt before adjustments (B1)	24.0	68.9	69.7
Other interest-bearing elements	8.0	6.0	6.2
Marketing instruction adjustment	(1.4)	(1.5)	(1.5)
Adjustment for project loan	(0.5)	(0.7)	(0.6)
Net interest-bearing debt (B2)	30.2	72.8	73.8
Normalisation for cash-build up before tax payment (50% of tax payment)	10.8	8.0	0.0
Net interest-bearing debt (B3)	41.0	80.8	73.8
Calculation of capital employed:
Capital employed before adjustments to net interest-bearing debt (A+B1)	284.6	279.3	296.1
Capital employed before normalisation for cash build up for tax payment (A+B2)	290.7	283.2	300.2
Capital employed (A+B3)	301.6	291.2	300.2
Calculated net debt to capital employed:
Net debt to capital employed before adjustments (B1/ (A+B1)	8.4 %	24.7 %	23.5 %
Net debt to capital employed before normalisation for tax payment (B2/ (A+B2)	10.4 %	25.7 %	24.6 %
Net debt to capital employed (B3/ (A+B3)	13.6 %	27.7 %	24.6 %

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END NOTES

1. See table under report section "Net debt to capital employed ratio" for a reconciliation of capital employed. Statoil's third quarter 2011 interim consolidated financial statements have been prepared in accordance with IFRS. Comparative financial statements for previous periods presented have also been prepared in accordance with IFRS.
2. The ratio of net debt to capital employed is a non-GAAP financial measure used in this report. For more information on our use of non-GAAP financial measures, see report section "Use and reconciliation of non-GAAP financial measures".
3. The Group's average liquids price is a volume-weighted average of the segment prices of crude oil, condensate and natural gas liquids (NGL), including a margin for oil sales, trading and supply.
4. The refining reference margin is a typical average gross margin of our two refineries, Mongstad and Kalundborg. The reference margin will differ from the actual margin though, due to variations in type of crude and other feedstock, throughput, product yields, freight cost, inventory etc.
5. A total of 13.8 mboe per day in the third quarter of 2011 and 14.1 mboe per day in the first nine months of 2011 represent our share of production in associated companies which is accounted for under the equity method. These volumes have been included in the production figure, but excluded when computing the over/underlift position. The computed over/underlift position is therefore based on the difference between produced volumes excluding our share of production in an associated company and lifted volumes. In the third quarter and first nine months of 2010, the production in associated companies accounted for under the equity method were 13.9 and 13.0 mboe per day, respectively.
6. Liquids volumes include oil, condensate and NGL, exclusive of royalty oil.
7. Lifting of liquids corresponds to sales of liquids for Development & Production Norway and Development and Production International. Deviations from the share of total lifted volumes from the field compared to the share in the field production are due to periodic over- or underliftings.
8. The production cost per boe is calculated by dividing operational costs related to the production of oil and natural gas by the total production of liquids and natural gas, excluding our share of operational costs and production in an associated company as described in end note 5.
9. Equity volumes represent produced volumes under a Production Sharing Agreement (PSA) contract that correspond to Statoil's ownership percentage in a particular field. Entitlement volumes, on the other hand, represent the Statoil share of the volumes distributed to the partners in the field, which are subject to deductions for, among other things, royalty and the host government's share of profit oil. Under the terms of a PSA, the amount of profit oil deducted from equity volumes will normally increase with the cumulative return on investment to the partners and/or production from the licence. As a consequence, the gap between entitlement and equity volumes will likely increase in times of high liquids prices. The distinction between equity and entitlement is relevant to most PSA regimes, whereas it is not applicable in most concessionary regimes such as those in Norway, the UK, Canada and Brazil.
10. Net financial liabilities are non-current financial liabilities and current financial liabilities reduced by cash, cash equivalents and current financial investments. Net interest-bearing debt is normalised by excluding 50% of the cash build-up related to tax payments due in the beginning of February, April, June, August, October and December each year.
11. Transactions with the Norwegian State. The Norwegian State, represented by the Ministry of Petroleum and Energy (MPE), is the majority shareholder of Statoil and also holds major investments in other entities. This ownership structure means that Statoil participates in transactions with many parties that are under a common ownership structure and therefore meet the definition of a related party. Statoil purchases liquids and natural gas from the Norwegian State, represented by SDFI (The State's Direct Financial Interest). In addition, Statoil is selling the State's natural gas production in its own name, but for the Norwegian State's account and risk as well as related expenditures refunded by the State. All transactions are considered to be on a normal arms-length basis and are presented in the financial statements.
12. Lifted volumes in prior quarters should have been increased to reflect the volumes related to disputed profit oil / tax oil barrels in Nigeria to align with the accounting treatmentfor this dispute. See Note 9 to the Interim Financial Statements included in this report. Year to date lifted volumes have been adjusted for these effects. The amounts are not material.

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FORWARD-LOOKING STATEMENTS

This report contains certain forward-looking statements that involve risks and uncertainties. In some cases, we use words such as "ambition", "believe", "continue", "could", "estimate", "expect", "focus", "intend", "likely", "may", "outlook", "plan", "should", "will" and similar expressions to identify forward-looking statements. All statements other than statements of historical fact, including, among others, statements regarding future financial position, results of operations and cash flows; changes in the fair value of derivatives; future financial ratios and information; future financial or operational portfolio or performance; future market position and conditions; business strategy; growth strategy; future impact of accounting policy judgments; sales, trading and market strategies; market outlook and future economic projections and assumptions; competitive position; projected regularity and performance levels; expectations related to our recent transactions and projects, such as the divestment of 24.1% of our stake in Gassled, the Pazflor development in Angola, the Eagle Ford joint venture, the proposed Brigham acquisition and the Aldous/Avaldness discovery; completion and results of acquisitions, disposals and other contractual arrangements; reserve information; future margins; projected returns; future levels, timing or development of capacity, reserves or resources; future decline of mature fields; planned turnarounds and other maintenance (and the effects thereof); oil and gas production forecasts and reporting; growth, expectations and development of production, projects, pipelines or resources; estimates related to production and development levels and dates; operational expectations, estimates, schedules and costs; exploration and development activities, plans and expectations; projections and expectations for upstream and downstream activities; oil, gas, alternative fuel and energy prices; oil, gas, alternative fuel and energy supply and demand; natural gas contract prices; timing of gas off-take; renewable energy production, industry outlook and carbon capture and storage; new organisational structure and policies; technological innovation, implementation, position and expectations; future energy efficiency; projected operational costs or savings; projected unit of production cost; our ability to create or improve value; future sources of financing; exploration and project development expenditure; effectiveness of our internal policies and plans; our ability to manage our risk exposure; our liquidity levels and management; estimated or future liabilities, obligations or expenses and how such liabilities, obligations and expenses are structured; expected impact of currency and interest rate fluctuations; expectations related to contractual or financial counterparties; capital expenditure estimates and expectations; projected outcome, objectives of management for future operations; impact of PSA effects; projected impact or timing of administrative or governmental rules, standards, decisions, standards or laws (including taxation laws); estimated costs of removal and abandonment; estimated gas transport commitments and future impact of legal proceedings are forward-looking statements. You should not place undue reliance on these forward-looking statements. Our actual results could differ materially from those anticipated in the forward-looking statements for many reasons, including the risks described above in "Risk update".

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. There are a number of factors that could cause actual results and developments to differ materially from those expressed or implied by these forward-looking statements, including levels of industry product supply, demand and pricing; price and availability of alternative fuels; currency exchange rates; the political and economic policies of Norway and other oil-producing countries; EU directives; general economic conditions; political stability and economic growth in relevant areas of the world; global political events and actions, including war, terrorism and sanctions; changes or uncertainty in or non-compliance with laws and governmental regulations; the timing of bringing new fields on stream; an inability to exploit growth opportunities; material differences from reserves estimates; unsuccessful drilling; an inability to find and develop reserves; ineffectiveness of crisis management systems; adverse changes in tax regimes; the development and use of new technology; geological or technical difficulties; operational problems; operator error; inadequate insurance coverage; the lack of necessary transportation infrastructure when a field is in a remote location; the actions of competitors; the actions of field partners; the actions of governments (including the Norwegian state as majority shareholder); counterparty defaults; natural disasters and adverse weather conditions and other changes to business conditions; an inability to attract and retain personnel; the ability of Statoil to complete the transactions contemplated by the Brigham merger agreement; the timing of the Brigham tender offer and the subsequent merger; the possibility that various conditions to the consummation of the Brigham tender offer or the subsequent merger may not be satisfied or waived; relevant governmental approvals; industrial actions by workers and other factors discussed elsewhere in this report. Additional information, including information on factors that may affect Statoil's business, is contained in Statoil's Annual Report on Form 20-F for the year ended December 31, 2010, filed with the U.S. Securities and Exchange Commission, which can be found on Statoil's website at www.statoil.com.

Although we believe that the expectations reflected in the forward-looking statements are reasonable, we cannot assure you that our future results, level of activity, performance or achievements will meet these expectations. Moreover, neither we nor any other person assumes responsibility for the accuracy and completeness of the forward-looking statements. Unless we are required by law to update these statements, we will not necessarily update any of these statements after the date of this report, either to make them conform to actual results or changes in our expectations.

Table of Contents

INTERIM FINANCIAL STATEMENTS

3rd quarter 2011

CONSOLIDATED STATEMENT OF INCOME	For the three months		For the nine months		For the year ended
	ended 30 September		ended 30 September		31 December
	2011	2010	2011	2010	2010
(in NOK million)	(unaudited)	(unaudited, restated)	(unaudited)	(unaudited, restated)	(restated)
REVENUES AND OTHER INCOME
Revenues	166,445	125,862	471,709	383,846	526,950
Net income from associated companies	288	512	1,167	1,220	1,168
Other income	86	1,075	14,604	1,501	1,797
Total revenues and other income	166,819	127,449	487,480	386,567	529,915
OPERATING EXPENSES
Purchases [net of inventory variation]	(88,141)	(67,367)	(236,847)	(189,699)	(257,436)
Operating expenses	(15,334)	(12,809)	(42,964)	(44,176)	(57,670)
Selling,general and administrative expenses	(3,579)	(2,802)	(9,992)	(9,704)	(11,081)
Depreciation,amortisation and net impairment losses	(17,237)	(12,612)	(37,576)	(38,124)	(50,694)
Exploration expenses	(3,265)	(3,634)	(9,044)	(10,427)	(15,773)
Total operating expenses	(127,556)	(99,224)	(336,423)	(292,130)	(392,654)
Net operating income	39,263	28,225	151,057	94,437	137,261
FINANCIAL ITEMS
Net foreign exchange gains (losses)	1,317	4,011	498	(1,815)	(1,826)
Interest income and other financial items	(1,811)	1,392	555	2,674	3,113
Interest and other finance expenses	3,418	1,647	1,577	3,701	(1,722)
Net financial items	2,924	7,050	2,630	4,560	(435)
Income before tax	42,187	35,275	153,687	98,997	136,826
Income tax	(32,326)	(21,498)	(100,714)	(71,026)	(99,179)
Net income	9,861	13,777	52,973	27,971	37,647
Attributable to:
Equity holders of the company	10,411	13,823	53,312	28,555	38,082
Non-controlling interests	(550)	(46)	(339)	(584)	(435)
	9,861	13,777	52,973	27,971	37,647
Earnings per share for income attributable to equity holders of the company - basic and diluted	3.27	4.34	16.75	8.97	11.94
Dividend declared and paid per ordinary share	-	-	6.25	6.00	6.00
Weighted average number of ordinary shares outstanding	3,181,855,580	3,182,526,140	3,182,469,049	3,182,802,756	3,182,574,787
See notes to the interim financial statements.

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME	For the three months ended 30 September		For the nine months ended 30 September		For the year ended 31 December
	2011	2010	2011	2010	2010
(in NOK million)	(unaudited)	(unaudited, restated)	(unaudited)	(unaudited, restated)	(restated)
Net income	9,861	13,777	52,973	27,971	37,647
Foreign currency translation differences	8,415	(9,985)	1,869	1,024	2,039
Actuarial gains (losses) on employee retirement benefit plans	(167)	(199)	(198)	689	(33)
Change in fair value of available for sale financial assets	1	(395)	(197)	170	209
Income tax effect on income and expense recognised directly in OCI	(25)	161	(5)	(601)	16
Other comprehensive income	8,224	(10,418)	1,469	1,282	2,231
Total comprehensive income	18,085	3,359	54,442	29,253	39,878
Attributable to:
Equity holders of the parent company	18,635	3,405	54,781	29,837	40,313
Non-controlling interests	(550)	(46)	(339)	(584)	(435)
	18,085	3,359	54,442	29,253	39,878
See notes to the interim financial statements.

CONSOLIDATED BALANCE SHEET	At 30 September	At 31 December	At 30 September
	2011	2010	2010
(in NOK million)	(unaudited)	(restated)	(unaudited, restated)
ASSETS
Non-current assets
Property, plant and equipment	378,290	351,578	357,813
Intangible assets	53,563	43,171	51,822
Investments in associated companies	9,297	8,997	9,522
Deferred tax assets	2,582	1,878	2,067
Pension assets	7,108	5,265	5,114
Derivative financial instruments	30,190	20,563	24,908
Financial investments	14,782	15,357	14,609
Prepayments and financial receivables	4,054	3,945	4,453
Total non-current assets	499,866	450,754	470,308
Current assets
Inventories	26,651	23,627	21,125
Trade and other receivables	70,411	74,810	58,366
Current tax receivables	1,182	1,076	605
Derivative financial instruments	4,575	6,074	5,985
Financial investments	40,543	11,509	14,377
Cash and cash equivalents	54,942	30,521	32,734
Total current assets	198,304	147,617	133,192
Assets clasified as held for sale	18,349	44,890	14,059
TOTAL ASSETS	716,519	643,261	617,559
See notes to the interim financial statements.

CONSOLIDATED BALANCE SHEET	At 30 September	At 31 December	At 30 September
	2011	2010	2010
(in NOK million)	(unaudited)	(restated)	(unaudited, restated)
EQUITY AND LIABILITIES
Equity
Share capital	7,972	7,972	7,972
Treasury shares	(18)	(18)	(16)
Additional paid-in capital	41,731	41,789	41,707
Additional paid-in capital related to treasury shares	(938)	(952)	(851)
Retained earnings	198,172	164,935	155,512
Other reserves	7,488	5,816	4,762
Statoil shareholders' equity	254,407	219,542	209,086
Non-controlling interests	6,184	6,853	1,326
Total equity	260,591	226,395	210,412
Non-current liabilities
Bonds, bank loans and finance lease liabilities	102,298	99,797	100,725
Deferred tax liabilities	74,307	78,065	78,722
Pension liabilities	22,428	22,112	21,434
Asset retirement obligations, other provisions and other liabilities	78,524	67,978	67,726
Derivative financial instruments	2,947	3,386	2,559
Total non-current liabilities	280,504	271,338	271,166
Current liabilities
Trade and other payables	75,571	73,720	60,958
Current tax payable	66,966	46,694	53,112
Bonds, bank loans, commercial papers and collateral liabilities	17,164	11,730	15,097
Derivative financial instruments	4,369	4,161	3,144
Total current liabilities	164,070	136,305	132,311
Liabilities directly associated with the assets classified as held for sale	11,354	9,223	3,670
Total liabilities	455,928	416,866	407,147
TOTAL EQUITY AND LIABILITIES	716,519	643,261	617,559
See notes to the interim financial statements.

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
						Other reserves
(unaudited, in NOK million)	Share capital	Treasury shares	Additional paid-in capital	Additional paid-in capital related to treasury shares	Retained earnings	Available for sale financial assets	Currency translation adjustments	Statoil shareholders' equity	Non-controlling interests	Total
At 31 December 2010	7,972	(18)	41,789	(952)	164,935	209	5,607	219,542	6,853	226,395
Net income for the period					53,312			53,312	(339)	52,973
Other comprehensive income					(203)	(197)	1,869	1,469		1,469
Dividend paid					(19,891)			(19,891)		(19,891)
Other equity transactions			(58)	14	19			(25)	(330)	(355)
At 30 September 2011	7,972	(18)	41,731	(938)	198,172	12	7,476	254,407	6,184	260,591
						Other reserves
(unaudited, in NOK million)	Share capital	Treasury shares	Additional paid-in capital	Additional paid-in capital related to treasury shares	Retained earnings	Available for sale financial assets	Currency translation adjustments	Statoil shareholders' equity	Non-controlling interests	Total
At 31 December 2009	7,972	(15)	41,732	(847)	145,909	0	3,568	198,319	1,799	200,118
Net income for the period					28,555			28,555	(584)	27,971
Other comprehensive income					88	170	1,024	1,282		1,282
Dividend paid					(19,095)			(19,095)		(19,095)
Other equity transactions		(1)	(25)	(4)	55			25	111	136
At 30 September 2010	7,972	(16)	41,707	(851)	155,512	170	4,592	209,086	1,326	210,412
See notes to the interim financial statements.

CONSOLIDATED STATEMENT OF CASH FLOWS
	For the nine months ended 30 September			For the year ended 31 December
	2011		2010	2010
(in NOK million)	(unaudited)		(unaudited, restated)	(restated)
OPERATING ACTIVITIES
Income before tax	153,687		98,997	136,826
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortisation and net impairment losses	37,576		38,124	50,694
Exploration expenditures written off	1,326		2,278	2,916
(Gains) losses on foreign currency transactions and balances	4,493		961	1,539
(Gains) losses on sales of assets and other items	(20,150)		(1,401)	(1,104)
Changes in working capital (other than cash and cash equivalents):
• (Increase) decrease in inventories	(3,024)		(929)	(3,431)
• (Increase) decrease in trade and other receivables	4,614		296	(16,705)
• Increase (decrease) in trade and other payables	5,081		(1,301)	9,521
(Increase) decrease in current financial investments	(29,034)		(7,355)	(4,487)
(Increase) decrease in net derivative financial instruments	(8,359)		(6,694)	(594)
Taxes paid	(67,362)		(57,102)	(92,266)
(Increase) decrease in non-current items related to operating activities	(1,056)		1,225	(2,156)
Cash flows provided by operating activities	77,792		67,099	80,753
INVESTING ACTIVITIES
Additions to property, plant and equipment	(55,480)		(49,755)	(68,070)
Exploration expenditures capitalised	(5,488)		(2,999)	(3,941)
Additions in other intangibles	(2,343)		(5,153)	(7,628)
Change in non-current loans granted and other non-current items	506		134	(2,855)
Proceeds from sale of assets	29,540	*	1,585	1,909
Prepayment received related to the held for sale transactions	0		1,995	4,124
Cash flows used in investing activities	(33,265)		(54,193)	(76,461)
FINANCING ACTIVITIES
New non-current bonds	7		11,608	15,562
Repayment of non-current bonds	(4,794)		(3,145)	(3,324)
Payment (to)/from non-controlling interests	(330)		111	5,489	**
Dividend paid	(19,891)		(19,095)	(19,095)
Treasury shares purchased	(300)		(194)	(294)
Net current loans and other ***	5,215		4,753	751
Cash flows provided by (used in) financing activities	(20,093)		(5,962)	(911)
Net increase (decrease) in cash and cash equivalents	24,434		6,944	3,381
Effect of exchange rate changes on cash and cash equivalents	(447)		306	450
Cash and cash equivalents at the beginning of the period***	29,117		25,286	25,286
Cash and cash equivalents at the end of the period ***	53,104		32,536	29,117

Including payment received in 2011 related to the sale of 40% of the Kai Kos Dehseh oil sands project and 40% of the Peregrino offshore heavy-oil field. For further information see note 6 Asset acquisitions and disposals . Including net cash of NOK 5,195 million received from non-controlling interests related to the listing of Statoil's subsidiary Statoil Fuel and Retail ASA as a separate company on the Oslo Stock Exchange in 2010. **Cash and cash equivalents includes a net bank overdraft of NOK 1,838 million at 30 September 2011, NOK 1,404 million at 31 December 2010, NOK 198 million at 30 September 2010 and NOK 196 million at 31 December 2009.

See notes to the interim financial statements.

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NOTES TO THE INTERIM FINANCIAL STATEMENTS

1 ORGANISATION AND BASIS OF PREPARATION

General information and organisation Statoil ASA, originally Den Norske Stats Oljeselskap AS, was founded in 1972 and is incorporated and domiciled in Norway. The address of its registered office is Forusbeen 50, N-4035 Stavanger, Norway.

Statoil's business consists principally of the exploration, production, transportation, refining and marketing of petroleum and petroleum-derived products. Statoil ASA is listed on the Oslo Stock Exchange (Norway) and the New York Stock Exchange (USA).

All Statoil's oil and gas activities and net assets on the Norwegian Continental Shelf (NCS) are owned by Statoil Petroleum AS, a 100% owned operating subsidiary. Statoil Petroleum AS is co-obligor or guarantor of certain debt obligations of Statoil ASA.

Following changes in Statoil's internal organisational structure as of 1 January 2011 the composition of Statoil's reportable segments was changed as of the first quarter 2011. For further information see note 3 Segments to these interim financial statements.

Statoil's interim financial statements for the third quarter 2011 were authorised for issue by the board of directors on 26 October 2011.

Basis of preparation These interim financial statements are prepared in accordance with International Accounting Standard 34 Interim Financial Reporting as issued by the International Accounting Standards Board (IASB) and as adopted by the European Union (EU). The interim financial statements do not include all of the information and footnotes required by International Financial Reporting Standards (IFRS) for a complete set of financial statements, and these interim financial statements should be read in conjunction with the annual financial statements. IFRS as adopted by the EU differs in certain respects from IFRS as issued by the IASB, but the differences do not impact Statoil's financial statements for the periods presented. A detailed description of the accounting policies used is included in the Statoil annual financial statements for 2010.

With effect from 1 January 2011 Statoil adopted certain revised and amended accounting standards, IFRS interpretations (IFRICs) and improvements to IFRSs as further outlined in the Significant accounting policies note disclosure to Statoil's financial statements for 2010. None of these revised standards or amendments has significantly impacted the interim financial statements for the first three quarters of 2011.

On 12 May 2011 the IASB issued IFRS 10 Consolidated Financial Statements , IFRS 11 Joint Arrangements , IFRS 12 Disclosure of Interests in Other Entities , and IFRS 13 Fair Value Measurement, and also issued amendments to and retitled IAS 27 Separate Financial Statements and IAS 28 Investments in Associates and Joint Ventures. All these new and amended standards will be effective from 1 January 2013, include amendments to a number of additional standards, and are to be implemented retrospectively in the financial statements upon adoption. On 16 June 2011 the IASB issued amendments to IAS 19 Employee Benefits , effective from 1 January 2013, and amendments to IAS 1 Presentation of Financial Statements , effective for financial years beginning after 1 July 2012. Statoil has not yet determined its adoption date for the new standards and amendments, and has not yet finalised evaluating their potential impact for the financial statements.

The interim financial statements reflect all adjustments which are, in the opinion of management, necessary for a fair statement of the financial position, results of operations and cash flows for the dates and interim periods presented. Interim period results are not necessarily indicative of results of operations or cash flows for an annual period.

The interim financial statements are unaudited.

Accounting policy application judgements There is a conflict in the accounting standards between the requirements of IAS 27 Consolidated and Separate Financial Statements and IAS 31 Interests in Joint Ventures / SIC-13 Jointly Controlled Entities - Non-Monetary Contributions by Venturers for gain recognition when forming joint ventures by reducing ownership shares in subsidiaries. This conflict was raised in an IASB Staff Paper in December 2009, and in May 2011 it was discussed in the IFRS Interpretations Committee, who referred it to the IASB to be resolved as part of a broader project on equity accounting. In view of the inconsistency, companies are required to make a policy choice in determining which guidance it will follow. Statoil has chosen as its accounting policy for sales transactions, when the substance of such a transaction is the establishment of a joint venture, to account for such transactions under the provisions of IAS 31/SIC-13. Under IAS 31/ SIC-13, a gain on such a sale will be recognised for the portion attributable to the equity interests of the respective buyer. Accordingly, the gains on Statoil's sale of 40% of the Kai Kos Dehseh oil sands project, recognised in the first quarter of 2011, and the sale of 40% of the Peregrino offshore heavy-oil field, recognised in the second quarter of 2011, have been recognised for the 40% portions attributable to the equity interests of the respective buyers.

With effect from 1 April 2011 Statoil changed its policy for accounting for jointly controlled entities under IAS 31 Interests in Joint Ventures , from application of the equity method to proportionate consolidation. The change has been applied retrospectively in the interim financial statements. Prior to the second quarter of 2011, Statoil had limited oil and gas development and production activities organised in jointly controlled legal entities. On the basis of increased materiality of such activities and with a view to ensuring consistency of the accounting for all jointly controlled oil and gas development and production activities, Statoil concluded that reflecting its share of assets, liabilities, revenues and expenses provides more relevant information concerning this type of activity carried out through jointly controlled entities than including it under the equity method. While Statoil has not finalised its evaluation of its joint arrangements under IFRS 11 Joint Arrangements , issued by the IASB on 12 May 2011, the new standard allows for accounting similar to the proportionate consolidation method for jointly controlled legal entities when the joint owner has rights to the assets and obligations for the liabilities of the joint operation. For further information on the change in accounting policy see note 2 Accounting policy change jointly controlled entities to these interim financial statements.

There have not been other significant changes in accounting policy application compared to the annual financial statements for 2010.

Use of estimates The preparation of financial statements in conformity with IFRS requires management to make judgments, estimates and assumptions that affect the application of policies and reported amounts of assets and liabilities, income and expenses. The estimates and associated assumptions are based on historical experience and various other factors that are believed to be reasonable under the circumstances, the result of which form the basis for making the judgments about carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates. The estimates and underlying assumptions are reviewed on an ongoing basis, considering the current and expected future market conditions. Change in accounting estimates are recognised in the period in which the estimate is revised if the revision affects only that period or in the period of the revision and future periods if the revision affects both current and future periods.

Commercial factors affecting the financial statements Statoil is exposed to a number of underlying economic factors, such as liquids prices, natural gas prices, refining margins, foreign exchange rates, interest rates, as well as financial instruments with fair values derived from changes in one or more of these factors, which affect the overall results for each period. In addition the results of Statoil are influenced in each period by the level of production, which in the short term may be influenced by for example maintenance programmes. In the long term, the results are impacted by the success of exploration and field development activities.

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2 ACCOUNTING POLICY CHANGE JOINTLY CONTROLLED ENTITIES

As stated in note 1 Organisation and basis of preparation , Statoil changed its policy for accounting for jointly controlled entities under IAS 31 Interests in Joint Ventures , from application of the equity method to proportionate consolidation with effect from 1 April 2011. Proportionate consolidation has been retrospectively applied in these interim financial statements and the following tables show the effect of the changes on previous periods. The change has no effect on net income, earnings per share, or shareholders' equity or non-controlling interests.

CONSOLIDATED STATEMENT OF INCOME	For the three months ended	For the year ended	For the three months ended	For the three months ended	For the three months ended	For the three months ended
As restated	31 March	31 December	31 December	30 September	30 June	31 March
(in NOK million)	2011	2010	2010	2010	2010	2010
REVENUES AND OTHER INCOME
Revenues	145,720	526,950	143,106	125,862	129,260	128,723
Net income from associated companies	435	1,168	(52)	512	293	415
Other income	5,740	1,797	296	1,075	(27)	453
Total revenues and other income	151,895	529,915	143,350	127,449	129,526	129,591
OPERATING EXPENSES
Purchases [net of inventory variation]	(70,081)	(257,436)	(67,737)	(67,367)	(64,904)	(57,428)
Operating expenses	(13,482)	(57,670)	(13,495)	(12,809)	(15,587)	(15,780)
Selling, general and administrative expenses	(2,894)	(11,081)	(1,377)	(2,802)	(4,295)	(2,607)
Depreciation, amortisation and net impairment losses	(11,058)	(50,694)	(12,569)	(12,612)	(14,554)	(10,958)
Exploration expenses	(3,615)	(15,773)	(5,346)	(3,634)	(3,571)	(3,222)
Total operating expenses	(101,130)	(392,654)	(100,524)	(99,224)	(102,911)	(89,995)
Net operating income	50,765	137,261	42,826	28,225	26,615	39,596
FINANCIAL ITEMS
Net foreign exchange gains (losses)	630	(1,826)	(12)	4,011	(3,291)	(2,535)
Interest income and other financial items	1,418	3,113	439	1,392	405	877
Interest and other finance expenses	(2,556)	(1,722)	(5,423)	1,647	2,090	(36)
Net financial items	(508)	(435)	(4,996)	7,050	(796)	(1,694)
Income before tax	50,257	136,826	37,830	35,275	25,819	37,902
Income tax	(34,200)	(99,179)	(28,154)	(21,498)	(22,762)	(26,765)
Net income	16,057	37,647	9,676	13,777	3,057	11,137

CONSOLIDATED STATEMENT OF INCOME	For the three months ended	For the year ended	For the three months ended	For the three months ended	For the three months ended	For the three months ended
As earlier reported	31 March	31 December	31 December	30 September	30 June	31 March
(in NOK million)	2011	2010	2010	2010	2010	2010
REVENUES AND OTHER INCOME
Revenues	145,648	526,718	143,042	125,809	129.204	128.663
Net income from associated companies	209	1,133	(52)	533	53	599
Other income	5,743	1,797	296	1,075	(27)	453
Total revenues and other income	151,600	529,648	143,286	127,417	129,230	129,715
OPERATING EXPENSES
Purchases [net of inventory variation]	(70,114)	(257,427)	(67,734)	(67,368)	(64,902)	(57,423)
Operating expenses	(13,371)	(57,531)	(13,455)	(12,782)	(15,552)	(15,742)
Selling, general and administrative expenses	(2,876)	(11,081)	(1,377)	(2,802)	(4,295)	(2,607)
Depreciation, amortisation and net impairment losses	(11,051)	(50,608)	(12,558)	(12,602)	(14,310)	(11,138)
Exploration expenses	(3,469)	(15,773)	(5,346)	(3,634)	(3,571)	(3,222)
Total operating expenses	(100,881)	(392,420)	(100,470)	(99,188)	(102,630)	(90,132)
Net operating income	50,719	137,228	42,816	28,229	26,600	39,583
FINANCIAL ITEMS
Net foreign exchange gains (losses)	629	(1,836)	(12)	3,997	(3,288)	(2,533)
Interest income and other financial items	1,444	3,175	458	1,409	420	888
Interest and other finance expenses	(2,537)	(1,751)	(5,434)	1,639	2,083	(39)
Net financial items	(464)	(412)	(4,988)	7,045	(785)	(1,684)
Income before tax	50,255	136,816	37,828	35,274	25,815	37,899
Income tax	(34,198)	(99,169)	(28,152)	(21,497)	(22,758)	(26,762)
Net income	16,057	37,647	9,676	13,777	3,057	11,137

CONSOLIDATED BALANCE SHEET — As restated	At 31 March	At 31 December	At 30 September	At 30 June	At 31 March	At 1 January
(in NOK million)	2011	2010	2010	2010	2010	2010
ASSETS
Non-current assets
Property, plant and equipment	359,236	351,578	357,813	355,438	349,733	342,520
Intangible assets	47,197	43,171	51,822	64,617	60,043	54,344
Investments in associated companies	9,056	8,997	9,522	10,113	9,587	9,424
Deferred tax assets	2,214	1,878	2,067	1,813	1,548	1,960
Pension assets	7,832	5,265	5,114	5,544	5,920	2,694
Derivative financial instruments	19,362	20,563	24,908	21,496	18,041	17,644
Financial investments	14,780	15,357	14,609	14,639	14,359	13,267
Prepayments and financial receivables	4,251	3,945	4,453	4,696	4,428	4,207
Total non-current assets	463,928	450,754	470,308	478,356	463,659	446,060
Current assets
Inventories	27,327	23,627	21,125	22,629	20,990	20,196
Trade and other receivables	70,953	74,810	58,366	63,883	61,080	58,992
Current tax receivables	1,131	1,076	605	568	76	179
Derivative financial instruments	6,417	6,074	5,985	4,733	4,825	5,369
Financial investments	25,348	11,509	14,377	7,925	9,316	7,022
Cash and cash equivalents	46,573	30,521	32,734	19,057	27,866	25,286
Total current assets	177,749	147,617	133,192	118,795	124,153	117,044
Assets classified as held for sale	23,084	44,890	14,059	15,156	0	0
TOTAL ASSETS	664,761	643,261	617,559	612,307	587,812	563,104

CONSOLIDATED BALANCE SHEET — As restated	At 31 March	At 31 December	At 30 September	At 30 June	At 31 March	At 1 January
(in NOK million)	2011	2010	2010	2010	2010	2010
EQUITY AND LIABILITIES
Equity
Share capital	7,972	7,972	7,972	7,972	7,972	7,972
Treasury shares	(14)	(18)	(16)	(14)	(14)	(15)
Additional paid-in capital	41,538	41,789	41,707	41,622	41,582	41,732
Additional paid-in capital related to treasury shares	(738)	(952)	(851)	(820)	(756)	(847)
Retained earnings	180,885	164,935	155,512	141,731	157,217	145,909
Other reserves	(87)	5,816	4,762	15,142	7,268	3,568
Statoil shareholders' equity	229,556	219,542	209,086	205,633	213,269	198,319
Non-controlling interests	6,856	6,853	1,326	1,332	1,904	1,799
Total equity	236,412	226,395	210,412	206,965	215,173	200,118
Non-current liabilities
Bonds,bank loans and finance lease liabilities	97,293	99,797	100,725	95,898	98,179	95,962
Deferred tax liabilities	77,936	78,065	78,722	74,656	76,707	76,335
Pension liabilities	22,141	22,112	21,434	21,335	21,212	21,144
Asset retirement obligations, other provisions and other liabilities	67,230	67,978	67,726	68,742	55,034	55,834
Derivative financial instruments	2,298	3,386	2,559	5,922	3,697	1,657
Total non-current liabilities	266,898	271,338	271,166	266,553	254,829	250,932
Current liabilities
Trade and other payables	67,675	73,720	60,958	62,037	55,451	60,050
Current tax payable	64,926	46,694	53,112	54,245	54,595	40,994
Bonds, bank loans, commercial papers and collateral liabilities	14,798	11,730	15,097	11,958	5,144	8,150
Derivative financial instruments	5,150	4,161	3,144	6,433	2,620	2,860
Total current liabilities	152,549	136,305	132,311	134,673	117,810	112,054
Liabilities directly associated with the assets classified as held for sale	8,902	9,223	3,670	4,116	0	0
Total liabilities	428,349	416,866	407,147	405,342	372,639	362,986
TOTAL EQUITY AND LIABILITIES	664,761	643,261	617,559	612,307	587,812	563,104

CONSOLIDATED BALANCE SHEET — As earlier reported	At 31 March	At 31 December	At 30 September	At 30 June	At 31 March	At 1 January
(in NOK million)	2011	2010	2010	2010	2010	2010
ASSETS
Non-current assets
Property, plant and equipment	348,497	348,204	355,113	352,963	347,454	340,835
Intangible assets	42,005	39,695	51,755	64,546	59,977	54,253
Investments in associated companies	22,742	13,884	10,661	10,801	10,463	10,056
Deferred tax assets	2,217	1,878	2,067	1,813	1,548	1,960
Pension assets	7,833	5,265	5,114	5,544	5,920	2,694
Derivative financial instruments	19,363	20,563	24,908	21,496	18,041	17,644
Financial investments	14,783	15,357	14,609	14,639	14,359	13,267
Prepayments and financial receivables	4,835	4,510	5,073	5,386	5,138	5,747
Total non-current assets	462,275	449,356	469,300	477,188	462,900	446,456
Current assets
Inventories	27,208	23,627	21,125	22,629	20,990	20,196
Trade and other receivables	72,718	76,139	59,514	65,019	61,095	58,895
Current tax receivables	1,132	1,076	605	568	76	179
Derivative financial instruments	6,420	6,074	5,985	4,733	4,825	5,369
Financial investments	25,353	11,509	14,377	7,925	10,102	7,022
Cash and cash equivalents	46,167	30,337	32,543	18,815	27,596	24,723
Total current assets	178,998	148,762	134,149	119,689	124,684	116,384
Assets classified as held for sale	23,084	44,890	14,059	15,156	0	0
TOTAL ASSETS	664,357	643,008	617,508	612,033	587,584	562,840

CONSOLIDATED BALANCE SHEET — As earlier reported	At 31 March	At 31 December	At 30 September	At 30 June	At 31 March	At 1 January
(in NOK million)	2011	2010	2010	2010	2010	2010
EQUITY AND LIABILITIES
Equity
Share capital	7,972	7,972	7,972	7,972	7,972	7,972
Treasury shares	(14)	(18)	(16)	(14)	(14)	(15)
Additional paid-in capital	41,538	41,789	41,707	41,622	41,582	41,732
Additional paid-in capital related to treasury shares	(738)	(952)	(851)	(820)	(756)	(847)
Retained earnings	180,885	164,935	155,512	141,731	157,217	145,909
Other reserves	(87)	5,816	4,762	15,142	7,268	3,568
Statoil shareholders' equity	229,556	219,542	209,086	205,633	213,269	198,319
Non-controlling interests	6,856	6,853	1,326	1,332	1,902	1,799
Total equity	236,412	226,395	210,412	206,965	215,171	200,118
Non-current liabilities
Bonds, bank loans and finance lease liabilities	97,299	99,797	100,725	95,898	98,179	95,962
Deferred tax liabilities	77,913	78,052	78,709	74,643	76,692	76,322
Pension liabilities	22,140	22,110	21,432	21,333	21,211	21,142
Asset retirement obligations, other provisions and other liabilities	67,111	67,910	67,726	68,742	55,034	55,834
Derivative financial instruments	2,299	3,386	2,559	5,922	3,697	1,657
Total non-current liabilities	266,762	271,255	271,151	266,538	254,813	250,917
Current liabilities
Trade and other payables	67,408	73,551	60,931	61,785	55,241	59,801
Current tax payable	64,920	46,693	53,103	54,238	54,595	40,994
Bonds, bank loans, commercial papers and collateral liabilities	14,802	11,730	15,097	11,958	5,144	8,150
Derivative financial instruments	5,151	4,161	3,144	6,433	2,620	2,860
Total current liabilities	152,281	136,135	132.275	134.414	117.600	111,805
Liabilities directly associated with the assets classified as held for sale	8,902	9,223	3.670	4.116	0	0
Total liabilities	427,945	416,613	407.096	405.068	372.413	362,722
TOTAL EQUITY AND LIABILITIES	664,357	643,008	617.508	612.033	587.584	562,840

Table of Contents

3 SEGMENTS

The composition of Statoil's reportable segments has changed on the basis of the new corporate structure implemented with effect from 1 January 2011. Comparable periods have been restated accordingly.

Statoil's operations are managed through the following operating segments; Development and Production Norway (DPN; previously Exploration and Production Norway); Development and Production North America (DPNA; previously included in International Exploration and Production); Development and Production International (DPI; previously International Exploration and Production); Marketing Processing and Renewable Energy (MPR; previously Natural Gas, Manufacturing and Marketing and parts of Technology and New energy which were included in the Other segment); Fuel and Retail (FR) and Other.

The Development and Production operating segments, which are organised based on a regional model with geographical clusters or units, are responsible for the commercial development of the oil and gas portfolios within their respective geographical areas, DPN on the Norwegian continental shelf, DPNA in North America including offshore and onshore activities in the United States of America and Canada, and DPI worldwide outside of North America and Norway.

Exploration activities are managed by a separate business unit, which has the global responsibility across the group for discovery and appraisal of new exploration resources. Exploration activities are allocated to and presented in the respective Development and Production segments.

The MPR segment is responsible for marketing and trading of oil and gas commodities (crude, condensate, gas liquids, products, natural gas and LNG), electricity and emission rights; as well as transportation, processing and manufacturing of the above mentioned commodities, operations of refineries, terminals, processing and power plants, wind parks and other activities within renewable energy.

The FR segment markets fuel and related products principally to retail consumers.

The Other reporting segment includes activities within Global Strategy and Development, Technology, Projects and Drilling and the Corporate Centre, and Corporate Services.

Statoil reports its business through reporting segments which correspond to the operating segments, except for the operating segments DPI and DPNA which have been combined into one reporting segment, Development and Production International. This combination into one reporting segment has its basis in similar economic characteristics, the nature of products, services and production processes, as well as the type and class of customers and the methods of distribution.

The Eliminations section includes elimination of inter-segment sales and related unrealised profits, mainly from the sale of crude oil and products. Inter-segment revenues are based upon estimated market prices.

The measurement basis of segment profit is Net operating income . Financial items, tax expense and tax assets are not allocated to the operating segments.

(in NOK million)	Development and Production Norway	Development and Production International	Marketing, Processing and Renewable Energy	Fuel and Retail	Other	Eliminations	Total
Three months ended
30 September 2011
Revenues and other income - third party	2,236	2,488	143,168	18,294	345	0	166,531
Revenues and other income - inter-segment	51,360	10,213	10,709	707	0	(72,989)	0
Net income (loss) from associated companies	36	217	(5)	1	39	0	288
Total revenues and other income	53,632	12,918	153,872	19,002	384	(72,989)	166,819
Net operating income (loss)	38,004	2,408	(145)	634	103	(1,741)	39,263
Additions to Intangible assets and Property, plant and equipment *	10,377	11,757	1,470	376	473		24,453
Three months ended
30 September 2010 (restated)
Revenues and other income - third party	1,441	1,722	106,556	16,368	799	51	126,937
Revenues and other income - inter-segment	34,170	10,515	9,295	484	595	(55,059)	0
Net income (loss) from associated companies	18	314	195	0	(15)	0	512
Total revenues and other income	35,629	12,551	116,046	16,852	1,379	(55,008)	127,449
Net operating income (loss)	23,521	1,183	2,254	744	269	254	28,225
Additions to Intangible assets and Property, plant and equipment *	7,762	8,237	1,593	154	269		18,015
*excluding changes in asset retirement obligations.

(in NOK million)	Development and Production Norway	Development and Production International	Marketing, Processing and Renewable Energy	Fuel and Retail	Other	Eliminations	Total
Nine months ended
30 September 2011
Revenues and other income - third party	5,788	22,830	403,954	52,872	869	0	486,313
Revenues and other income - inter-segment	150,594	30,760	34,221	2,171	3	(217,749)	0
Net income (loss) from associated companies	46	902	122	2	95	0	1,167
Total revenues and other income	156,428	54,492	438,297	55,045	967	(217,749)	487,480
Net operating income (loss)	113,786	29,712	6,868	1,526	(489)	(346)	151,057
Additions to Intangible assets and Property, plant and equipment *	28,859	29,772	3,329	835	2,492		65,287
Nine months ended
30 September 2010 (restated)
Revenues and other income - third party	3,558	5,156	328,567	47,122	1,104	(160)	385,347
Revenues and other income - inter-segment	117,135	31,664	28,320	1,330	1,585	(180,034)	0
Net income (loss) from associated companies	46	856	354	1	(37)	0	1,220
Total revenues and other income	120,739	37,676	357,241	48,453	2,652	(180,194)	386,567
Net operating income (loss)	81,752	8,491	1,520	1,907	701	66	94,437
Additions to Intangible assets and Property, plant and equipment *	23,419	29,264	3,922	455	671		57,731
*excluding changes in asset retirement obligations.

In the DPI segment a gain of NOK 8.8 billion was recognised in the second quarter of 2011 in relation to the sale of 40% of the Peregrino offshore heavy-oil field in Brazil. In the first quarter of 2011 a gain of NOK 5.5 billion was recognised in relation to the sale of 40% of the Kai Kos Dehseh oil sands project. See note 6 Asset acquisitions and disposals for more information on these transactions.

The DPI segment recognised a net reversal of impairment losses of NOK 2.3 billion related to assets in the Gulf of Mexico in the second quarter of 2011. This consisted of impairment losses of NOK 1.1 billion and reversals of prior period impairment losses of NOK 3.4 billion. The impairment losses of NOK 1.1 billion have been presented as Exploration expenses . Of the reversals of impairment losses NOK 1.0 billion has been presented as Exploration expenses and NOK 2.4 billion as Depreciation, amortisation and net impairment losses , on the basis of their nature as intangible assets (exploration assets) and property, plant and equipment (development and producing assets), respectively.

The MPR segment recognised impairment losses related to refineries of NOK 3.8 billion and NOK 2.9 billion in the third quarter of 2011 and the second quarter of 2010 respectively. The basis for the impairment losses is value in use estimates triggered by lower future expected refining margins.

In the MPR segment a reversal of an earlier recognised impairment loss related to an intangible asset of NOK 0.9 billion and a reversal of an onerous contract provision of NOK 0.7 billion were recognised as reductions of operating expenses in the first quarter of 2011. These reversals are related to the impact of the pricing reference included in a long term US-based LNG sourcing contract combined with improved marketing opportunities due to increased natural gas prices in other parts of the world. The consequence of this reversal is that the provision of NOK 3.8 billion recognised in the second quarter 2010 (year to date 2010, NOK 4.4 billion) was fully reversed by the end of first quarter 2011.

Table of Contents

4 FINANCIAL ITEMS AND CASH AND CASH EQUIVALENTS

Included in Interest and other finance expenses are fair value effects on interest rate swap positions, which are used to manage the interest rate risk on external loans. For the three months ended 30 September 2011 this amounted to fair value gains of NOK 5.4 billion (NOK 2.8 billion for the three months ended 30 September 2010), caused by decreased interest rates.

Interest and other finance expenses for 2010 included fair value gains of NOK 2.4 billion on interest rate swap positions. The fair value gains were caused by decreased interest rates.

Cash and cash equivalents include restricted cash of NOK 5.9 billion at 30 September 2011 (NOK 2.6 billion at 31 December 2010) deposited with Statoil's US dollar denominated bank account in Nigeria. There are certain restrictions on the use of cash from Statoil's Nigerian operations following an injunction against Statoil by the Nigerian courts related to an ongoing litigation claim. Both the injunction and the disputed claim have been appealed.

Table of Contents

5 INCOME TAX

	For the three months — ended 30 September		For the nine months — ended 30 September		For the year ended — 31 December
(in NOK million)	2011	2010 (restated)	2011	2010 (restated)	2010 (restated)
Income before tax	42,187	35,275	153,687	98,997	136,826
Income tax	(32,326)	(21,498)	(100,714)	(71,026)	(99,179)
Equivalent to a tax rate of	76.6 %	60.9 %	65.5 %	71.7 %	72.5 %

The tax rates in the third quarter of 2011 were primarily influenced by impairments in entities with lower than average tax rates and relatively high income from the Norwegian Continental Shelf which is subject to a higher than average tax rate. The tax rates were also influenced by high deferred taxes related to currency effects in entities that are taxable in other currencies than the functional currency.This was partly offset by foreign exchange losses in entities that are taxable in other currencies than the functional currency. These foreign losses are tax deductible, but do not impact the income statement of these entities.

The tax rates for the first nine months of 2011were primarily influenced by capital gains in entities with lower than average tax rates and relatively high income from entities outside the Norwegian Continental Shelf which are subject to lower than average tax rates. This was partly offset by impairments in entities with lower than average tax rates.

The tax rates in the third quarter of 2010 were primarily influenced by relatively high income from entities outside the Norwegian Contintental Shelf. These entities are subject to lower than average tax rates.

Table of Contents

6 ASSETS ACQUISITIONS AND DISPOSALS

On 21 November 2010 Statoil entered into an agreement with PTT Exploration and Production (PTTEP) to form a joint venture relating to the Kai Kos Dehseh oil sands project, which reduces Statoil's ownership interest from 100% to 60%. The Kai Kos Dehseh oil sands project in Alberta, Canada, is legally organised as a partnership and through the sale, PTTEP acquired 40% of the partnership interests. Following the transaction, which was closed on 21 January 2011, the Kai Kos Dehseh oil sands activity is accounted for as a jointly controlled entity using proportionate consolidation. See note 2 Accounting policy change jointly controlled entities for more information .

PTTEP paid a total consideration of NOK 13.2 billion. A gain of NOK 5.5 billion has been recognised in accordance with the provisions of IAS 31/SIC 13 (see Note 1 Organisation and basis of preparation ) and presented as Other income . The transaction was recognised in the Development and Production International segment in the first quarter of 2011.

On 21 May 2010 Statoil entered into an agreement with Sinochem Group to sell 40% of the Peregrino offshore heavy-oil field in Brazil. Following closure of the transaction Statoil holds a 60% ownership share and together with Sinochem jointly control the Peregrino assets. Statoil will remain operator of the field which started production in April 2011. Governmental approvals were received in April 2011 and the transaction was closed on 14 April 2011.

Sinochem Group paid a total of NOK 19.5 billion in cash for the 40% share of the net assets through acquisition of shares in various Statoil entities. The gain from the transaction of NOK 8.8 billion was recognised in accordance with the provisions of IAS 31/SIC 13 (see note 1 Organisation and basis of preparation ) and presented as Other income . The transaction was recognised in the Development and Production International segment in the second quarter of 2011.

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7 ASSETS CLASSIFIED AS HELD FOR SALE

On 5 June 2011 Statoil entered into an agreement with Solveig Gas Norway AS to sell a 24.1% ownership interest in the Gassled joint venture ("Gassled"). Following the transaction Statoil will continue to hold a 5% interest in the joint venture.

Solveig Gas Norway AS will pay a consideration of NOK 17.35 billion in cash for the 24.1% ownership interest in the joint venture. The transaction is principally subject to the tax exemption rules in the Norwegian Petroleum Tax system, however, a portion will be taxable under the ordinary Norwegian tax system. The consideration is based on an economic date of 1 January 2011 and is subject to adjustments for working capital, a proportional share of operational and capital expenditures incurred as well as a proportional share of the tariff revenue in the period between the economic date and the date for final closing of the transaction. In addition a consideration adjustment element intended to reflect changes in the long term interest rate levels has been agreed between the parties. The transaction is among others subject to approvals from the Norwegian Ministry of Petroleum and Energy and the Norwegian Ministry of Finance. Statoil will continue to consolidate the proportional share (current ownership share) of the revenues and expenditures from Gassled until the date of closing of the transaction.

As at 30 September 2011, the net carrying amount of these Gassled assets was NOK 7 billion. The transaction will be recognised in the Marketing, Processing and Renewable Energy segment at the time of closing, which is expected in fourth quarter 2011.

On the basis of the agreement, at third quarter end 2011 the carrying amounts of non-current assets and deferred tax liabilities related to the 24.1% ownership interest to be divested have been classified as held for sale in the Consolidated balance sheet, and the depreciation of the assets have been ceased from the date of the agreement.

Statoil has reflected its ownership in Gassled on proportionate basis in the Consolidated financial statements, and consequently for its note disclosure in the Consolidated financial statements for 2010 included the Gassled related transport commitments on a net basis as part of Statoil's external commitments. This means the disclosures reflect the gross minimum commitments less the portion attributable to Statoil's ownership share in Gassled. Consequently, the sale of a 24.1% ownership share in Gassled will increase Statoil's external nominal minimum long term commitments to be disclosed by approximately NOK 78 billion, estimated as at third quarter end. Pipeline capacity bookings and natural gas transport during the time period until transaction closing will impact the actual change in Statoil's Gassled-related long-term commitments compared to those disclosed in the group's financial statements for 2010.

The carrying amounts of assets and liabilities classified as held for sale in the Consolidated balance sheet at year end 2010 are related to Statoil's agreements with PTTEP for the sale of a 40% ownership interest in the Kai Kos Dehseh oil sands project and the Sinochem Group for the sale of a 40% ownership in the Peregrino offshore heavy-oil field. See note 6 Asset acquisitions and disposals for information on the closing of these transactions.

The table below shows a specification of assets and liabilities classified as held for sale:

(in NOK million)	At 30 September 2011	At 31 December 2010
Property, plant and equipment	18,295	32,515
Intangible assets	2	12,375
Investments in associated companies	52	0
Total assets classified as held for sale	18,349	44,890
Bonds, bank loans and finance lease liabilities	0	7,796
Deferred tax liabilities	11,354	0
Asset retirement obligation, other provisions and other liabilities	0	549
Bonds, bank loans, commercial papers and collateral liabilities	0	878
Total liabilities directly associated with the assets classified as held for sale	11,354	9,223

Table of Contents

8 INTANGIBLE ASSETS AND PROPERTY, PLANT AND EQUIPMENT

(in NOK million)	Property, plant and equipment	Intangible assets
Balance at 31 December 2010 (restated)*	351,578	43,171
Transferred from assets classified as held for sale **	32,515	12,375
Additions	66,437	7,717
Transfers	2,682	(2,682)
Disposals	(18,001)	(5,529)
Transferred to assets classified as held for sale***	(18,295)	(2)
Expensed exploration expenditures previously capitalised	0	(827)
Depreciation, amortisation and net impairment losses	(37,576)	(500)
Effect of foreign currency translation adjustments	(1,050)	(160)
Balance at 30 September 2011	378,290	53,563

• Please see note 2 Accounting policy change jointly controlled entities for restatement of Consolidated balance sheet. ** Reflects a reversal of previous period's assets classified as held for sale for which the portion sold during the period is included as "Disposals". *** For information on intangible assets and property, plant and equipment classified as held for sale, see note 7 Assets classified as held for sale .

In assessing the need for impairment of the carrying amount of a potentially impaired asset, the asset's carrying amount is compared to its recoverable amount. The recoverable amount is the higher of fair value less costs to sell and estimated value in use. When preparing a value in use calculation the estimated future cash flows are adjusted for risks specific to the asset and discounted using a real post-tax discount rate adjusted for asset specific differences, such as tax rates and time horizon of cash flows. The base discount rate used is 6.5% real after tax in a 28% tax regime with a 10 year duration. The discount rate is derived from Statoil's weighted average cost of capital. A derived pre-tax discount rate would generally be in the range of 8-12%, depending on asset specific characteristics, such as specific tax treatments, cash flow profiles and economic life. For certain assets a pre-tax discount rate could be outside this range, mainly due to special tax elements (e.g. permanent differences) affecting the pre-tax equivalent.

Impairment losses and reversals of impairment losses are presented as Exploration expenses and Depreciation, amortisation and net impairment losses on the basis of their nature as exploration assets (intangible assets) and development and producing assets (property, plant and equipment and intangible assets), respectively. The table below shows the net impairment losses recognised in the reporting period by line item under which it has been reported.

(in NOK million)	For the three months ended 30 September — 2011	2010 (restated)	For the nine months ended 30 September — 2011	2010 (restated)
Depreciation, amortisation and net impairment losses	4,214	1,559	4,546	4,789
Exploration expenses	576	485	1,509	1,881
Impairment losses	4,790	2,044	6,055	6,670
Depreciation, amortisation and net impairment losses *	0	0	(3,283)	(280)
Exploration expenses *	0	(467)	(1,010)	(1,636)
Reversal of impairment losses	0	(467)	(4,293)	(1,916)
Net impairment losses	4,790	1,577	1,762	4,754

• For the nine months period ended 30 September 2011, the figures for reversal of impairment losses related to Depreciation, amortisation and net impairment losses include NOK 2.0 billion that had previously been classified as reversal of impairment losses related to Exploration expenses in the interim financial statements for the second quarter of 2011. Had the second quarter figures been reclassified to conform to the third quarter presentation, there would have been no impact on Total operating expenses in the second quarter.

Table of Contents

9 PROVISIONS, COMMITMENTS, CONTINGENT LIABILITIES AND CONTINGENT ASSETS

The increase in the Asset retirement obligations, other provisions and other liabilities is mainly related to asset retirement obligations and is caused by decreased discount rates as a result of declining interest rates. The increased asset retirement obligation also impacts Property, plant and equipment and will increase depreciation expenses.

In 2011 Statoil has entered into certain new operational lease contracts for a number of drilling rigs, which contribute to an increase in the group's total future leasing commitments as of third quarter end. The new drilling rig contracts at commencement involve future minimum lease payments of approximately NOK 15.6 billion and terms ranging from 6 months to 8 years.

On the basis of annual audits of Statoil's participation in Block 4, Block 15 and Block 17 offshore Angola, the Angolan Ministry of Finance has assessed additional profit oil and taxes due on the basis of activities that currently include the years 2002 up to and including 2009. Statoil disputes the assessments and is pursuing these matters in accordance with relevant Angolan legal and administrative procedures. The exposure for Statoil at the end of the third quarter 2011 is estimated to be approximately USD 0.5 billion, the most significant part of which relates to profit oil elements. Statoil has provided in the interim financial statements for its best estimate related to the assessments, reflected in the Consolidated statement of income as revenue reduction, interest expenses and tax expenses, respectively.

There is a dispute between the Nigerian National Petroleum Corporation (NNPC) and the partners in tract two of the unitised Agbami field (oil mining lease 128), concerning interpretation of the terms of the OML 128 Production Sharing Contract (PSC) relating to the calculation of tax oil volumes, which are lifted by NNPC on behalf of the Nigerian government, and to the respective parties' share of profit oil volumes. NNPC claims that in the aggregate for 2009, 2010 and the three first quarters of 2011, Statoil has lifted excess volumes which should be refunded to NNPC in order to comply with the PSC contractual terms. Statoil disputes NNPC's position, and is actively pursuing the matter under the terms of the PSC. The exposure for Statoil at the end of the third quarter 2011 is mainly related to profit oil volumes and has been estimated to the equivalent of approximately USD 0.5 billion. Statoil has provided in the interim financial statements for its best estimate related to the claims, which has been reflected in the Consolidated statement of income as revenue reduction.

During the normal course of its business Statoil 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 cannot be determined at this time. Statoil has provided in its financial statements for probable liabilities related to litigation and claims based on the Company's best judgement. Statoil does not expect that its financial position, results of operations or cash flows will be materially affected by the resolution of these legal proceedings.

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10 SUBSEQUENT EVENTS

On 17 October, Statoil announced that it had entered into a merger agreement with Brigham Exploration Company for Statoil to acquire all the outstanding shares of Brigham through an all cash tender offer. The total equity value is approximately USD 4.4 billion, reflecting an enterprise value of approximately USD 4.7 billion. Brigham holds 375,000 net acres in the Williston Basin in the U.S. with potential for oil production from the Bakken and Three Forks formations. Brigham also holds interests in 40,000 net acres in other areas.

The cash tender offer is expected to commence within 10 business days from the date of the merger agreement. The transaction is subject to the terms and conditions set forth in the merger agreement, including that at least a majority of the outstanding Brigham shares are tendered, the waiting period under the U.S. antitrust laws has expired or been terminated, and other customary conditions.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: October 28, 2011	By:	STATOIL ASA (Registrant) — Name: Torgrim Reitan Title: Chief Financial Officer