Equinor — Interim / Quarterly Report 2011

Jul 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 July 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 contains a report of the second quarter 2011 results of Statoil ASA.

TABLE OF CONTENTS

SECOND 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 Reconciliation of adjusted earnings to net operating income Reconciliation of adjusted earnings after tax to net income 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 HSE ACCOUNTING

STATEMENT ON FINANCIAL COMPLIANCE SIGNATURES

Table of Contents

SECOND QUARTER 2011 RESULTS

Statoil's second quarter 2011 net operating income was NOK 61.0 billion, a 129% increase compared to NOK 26.6 billion in the second quarter of 2010. The quarterly result was mainly affected by a 32% increase in the average prices for liquids measured in NOK, a 28% increase in average gas prices, a NOK 8.8 billion gain related to the 40% Peregrino divestment and an 18% decrease in lifted volumes, when compared to the same period last year.

"Statoil delivered record net income in the second quarter of 2011, reflecting an operational performance in line with expectations, the value-creating Peregrino transaction and strong oil and gas prices throughout the period. Production was mainly impacted by previously announced extensive maintenance activities and seasonal variability in gas off-take. We continued to make progress within exploration and project developments in the quarter, staying on track to deliver future growth," says Helge Lund, Statoil's chief executive officer.

Net income in the second quarter of 2011 was NOK 27.1 billion compared to NOK 3.1 billion in the same period last year. This result reflected higher prices for both liquids and gas, a gain on sale of asset of NOK 7.5 billion net of tax, reduced exploration expenses and higher net financial income, partly offset by reduced liftings. The tax rate for the quarter was 56%.

Adjusted earnings in the second quarter of 2011 were NOK 43.6 billion, compared to NOK 36.5 billion in the second quarter of 2010.

Adjusted earnings after tax were NOK 12.8 billion in the second quarter of 2011. Adjusted earnings after tax exclude the effect of tax on net financial items, and represent an effective adjusted tax rate of 71% in the second quarter of 2011.

Total equity production was 1,692 mboe per day in the second quarter of 2011 compared to 1,957 mboe per day in the second quarter of 2010.

	Second quarter — 2011	2010	Change	First half — 2011	2010	Change	Full year — 2010
Net operating income (NOK billion)	61.0	26.6	>100%	111.8	66.2	69%	137.3
Adjusted earnings (NOK billion)	43.6	36.5	20%	90.8	75.3	21%	142.8
Net income (NOK billion)	27.1	3.1	>100%	43.1	14.2	>100%	37.6
Earnings per share (NOK)	8.44	1.14	>100%	13.45	4.63	>100%	11.94
Average liquids price (NOK/bbl) [3]	610	462	32%	593	447	33%	462
Average gas prices (NOK/scm)	2.06	1.61	28%	2.00	1.62	23%	1.72
Equity production (mboe per day)	1,692	1,957	(14%)	1,831	2,029	(10%)	1,888

Highlights since first quarter 2011:

• The sale of 40% of the Peregrino offshore field in Brazil was completed and a gain of NOK 8.8 billion before tax is recorded.
• Successful exploration drilling activities in Norway and internationally.
• The approval of the Plan for development and operation (PDO) for the Hyme field (formerly Gygrid) on the NCS.
• The approval of the Plan for development and operation of the Valemon gas and condensate field on the NCS.
• The announcement of the divestment of a 24.1% interest in the Gassled joint venture to Solveig Gas Norway AS.
• The approval of the Plan for development and operation for Visund South fast track on the NCS.
• Statoil awarded the contract for construction of two new specially designed category D drilling rigs.
• First shipment of Peregrino crude.
• Strengthened position in Eagle Ford through acquiring new leases.

Table of Contents

OPERATIONAL REVIEW

Second quarter

Total liquids and gas entitlement production in the second quarter of 2011 was 1,486 mboe per day, compared to 1,765 mboe per day in the second quarter of 2010. Total equity production [9] was 1,692 mboe per day in the second quarter of 2011 compared to 1,957 mboe per day in the second quarter of 2010.

The 14% decrease in total equity production was primarily caused by lower gas off-take, reduced production permits, reduced water injection at Gullfaks, planned maintenance activities and natural decline on mature fields. Also suspended production in Libya added to the decrease. Increased volumes from start-up of the new fields Vega, Morvin, Gjøa, Peregrino and Leismer, and ramp-up of production from existing fields, partly compensated for the second quarter decrease in equity production.

Entitlement production, down 16% since second quarter last year, was impacted by the reduction in equity production as described above and by increasing effects from Production Sharing Agreements (PSA-effects). The average PSA-effect was 206 mboe per day in the second quarter of 2011 compared to 192 mboe per day in the second quarter last year. The increase in PSA-effect was mainly a result of higher prices for liquids and gas leading to lower entitlement production and a higher government take because of changes in profit tranches regarding fields in Angola, compared to the same quarter last year.

Operational data	Second quarter — 2011	2010	Change	First half — 2011	2010	Change	Full year — 2010
Price
Average liquids price (USD/bbl)	112.1	74.1	51%	106.2	74.0	43%	76.5
USDNOK average daily exchange rate	5.44	6.24	(13%)	5.59	6.04	(8%)	6.05
Average liquids price (NOK/bbl) [3]	610	462	32%	593	447	33%	462
Average gas prices (NOK/scm)	2.06	1.61	28%	2.00	1.62	23%	1.72
Refining margin (reference margin, USD/bbl) [4]	2.2	4.9	(55%)	2.4	4.4	(45%)	3.9
Production
Total entitlement liquids production (mboe per day) [5]	893	981	(9%)	921	1,023	(10%)	968
Total entitlement gas production (mboe per day)	593	783	(24%)	704	817	(14%)	738
Total entitlement liquids and gas production (mboe per day) [6]	1,486	1,765	(16%)	1,625	1,839	(12%)	1,705
Total equity liquids production (mboe per day)	1,075	1,147	(6%)	1,099	1,182	(7%)	1,122
Total equity gas production (mboe per day)	616	809	(24%)	731	847	(14%)	766
Total equity liquids and gas production (mboe per day)	1,692	1,957	(14%)	1,831	2,029	(10%)	1,888
Liftings
Total liquids liftings (mboe per day)	823	942	(13%)	853	1,010	(15%)	969
Total gas liftings (mboe per day)	593	783	(24%)	704	817	(14%)	738
Total liquids and gas liftings (mboe per day) [7]	1,416	1,725	(18%)	1,557	1,826	(15%)	1,706
Production cost
Production cost entitlement volumes (NOK/boe, last 12 months) [8]	46.2	40.1	15%	46.2	40.1	15%	42.8
Production cost equity volumes (NOK/boe, last 12 months)	41.2	36.3	14%	41.2	36.3	14%	38.6
Equity production cost excluding restructuring and gas injection cost (NOK/boe, last 12 months) [9]	41.1	35.2	17%	41.1	35.2	17%	37.9

Total liftings of liquids and gas were 1,416 mboe per day in the second quarter of 2011, an 18% decrease from 1,725 mboe per day in the second quarter of 2010. The decrease in lifting is a result of the decrease in entitlement production and increased underlift compared to the second quarter last year. In the second quarter of 2011 there was an underlift of 56 mboe per day [5], compared to an underlift of 26 mboe per day in the second quarter of 2010.

Refining margins (reference margin) were USD 2.2 per barrel in the second quarter of 2011, compared to USD 4.9 per barrel in the second quarter of 2010.

Production cost per boe of entitlement volumes was NOK 46.2 for the 12 months ended 30 June 2011, compared to NOK 40.1 for the 12 months ended 30 June 2010 [8]. Based on equity volumes, the production cost per boe for the two periods was NOK 41.2 and NOK 36.3, respectively.

The adjusted production cost per boe of equity production for the 12 months ended 30 June 2011 was NOK 41.1 [9]. The comparable figure for the 12 months ended 30 June 2010 was NOK 35.2. Adjustments to production cost include restructuring costs and other costs arising from the merger recorded in the fourth quarter of 2007 that were partially reversed in the fourth quarter of 2009 and 2010, and gas injection costs.

The increase in adjusted production cost per boe is mainly a result of the lower equity production and higher cost from fields preparing for production start-up during the last 12 months, such as Peregrino in Brazil and Leismer Demonstration Project in Canada.

Exploration expenditure (including capitalised exploration expenditure) was NOK 3.9 billion in the second quarter 2011, compared to NOK 3.8 billion in the second quarter of 2010. The NOK 0.1 billion increase was mainly due to more wells being drilled compared to last year.

In the second quarter of 2011, a total of nine exploration wells were completed before 30 June 2011, six on the NCS and three internationally. Six wells were announced as discoveries in the period, four on the NCS and two internationally.

Major business developments since first quarter 2011 include:

• The submission (12 May) and approval (28 June) of the Plan for development and operation (PDO) for the Hyme field on the NCS (formerly Gygrid). Production start-up is scheduled for the first quarter of 2013.
• The approval of the Plan for development and operation of the Valemon gas and condensate field on the NCS (9 June). Production start-up is planned for in 2014.
• Also on 9 June, Statoil and Talisman entered into an agreement with Denver-based independent SM Energy Company that will add 15,400 acres to the companies' 50/50 Eagle Ford joint venture in Texas, USA. The total purchase price is USD 225 million. The transaction is expected to close in August.
• The approval of the Plan for development and operation for Visund South fast track (10 June). Production start-up is planned for in the third quarter of 2012.
• The farm-in on the Kakuna-prospect in deepwater Gulf of Mexico in the USA providing Statoil with a 27.5% interest in the prospect, which is operated by Nexen Inc, controlling the remaining 72.5%.
• The decision to sell a 24.1% direct and indirect stake in the Gassled joint venture for a consideration of NOK 17.35 billion to Solveig Gas Norway AS. Following this transaction, Statoil will continue to own 5.0% in the joint venture.
• The farm-in of three offshore exploration licenses in Indonesia. Statoil will acquire a 40% equity interest in a North Makassar Strait Production Sharing Contract (PSC) and a similar interest in two additional offshore PSCs (West Papua IV and Halmahera-Kofiau).
• On 6 July the UK Government announced that the annual rate of the Ring Fence Expenditure Supplement (RFES) for the North Sea fiscal regime will be increased from 6% to 10%. This change will provide extra support for investments in the UK part of the North Sea. As a consequence, Statoil will resume the work on maturing the Mariner field in UK towards a Final Investment Decision in the end of 2012.

First half 2011

Total liquids and gas entitlement production in the first half of 2011 was 1,625 mboe per day, down 12% from 1,839 mboe per day in the first half of 2010. Total equity production was 1,831 mboe per day in the first half of 2011 compared to 2,029 mboe per day in the first half of 2010.

The 10% decrease in total equity production in the first half of 2011 compared to the same period in 2010 was primarily caused by deferred production as a result of commercial considerations mainly related to the flexible gas fields Troll and Oseberg, maintenance shut downs and general decline on mature fields. Increased volumes from start-up of new fields (Beta Vest, Vega, Morvin, Gjøa, Peregrino and Leismer) and ramp-up of production from existing fields, partly compensated for the decrease in equity production in the first half of 2011.

The 12% decrease in entitlement production in the first half of 2011 was impacted by the reduction in equity production as described above, and by increasing PSA-effects. The average PSA-effect on entitlement production was 206 mboe per day in the first half of 2011 compared to 190 mboe per day in the first half of 2010. The increase was a result of changes in profit tranches regarding fields in Angola, and higher prices in first half 2011 compared to same period 2010 leading to reduced entitlement shares.

Total liquids and gas liftings in the first half of 2011 were 1,557 mboe per day, compared to 1,826 mboe per day in the first half of 2010. The 15% decrease in lifting is based on the decrease in entitlement production. In the first half of 2011 there was an underlift position of 54 mboe per day. There was no over/underlift position in the first half of 2010.

Refining margins (reference margin) were USD 2.4 per barrel in the first half of 2011, compared to USD 4.4 per barrel in the first half of 2010.

Exploration expenditure (including capitalised exploration expenditure) was NOK 8.3 billion in the first half of 2011, compared to NOK 7.4 billion in the same period of 2010. The NOK 0.9 billion increase was mainly due to more expensive wells and increased number of wells being drilled compared to last year.

In the first half of 2011 Statoil completed 19 exploration wells , 13 on the NCS and six internationally. A total of nine wells were announced as discoveries in the period, seven on the NCS and two internationally.

Table of Contents

FINANCIAL REVIEW

Second quarter

In the second quarter of 2011, net operating income was NOK 61.0 billion, compared to NOK 26.6 billion in the second quarter of 2010. Revenues were positively impacted by higher liquids and gas prices and were only partly offset by the decrease in volumes of both liquids and gas sold. Other income was NOK 8.8 billion in the second quarter 2011, and was attributable to the gain from the 40% Peregrino divestment recognised in the second quarter 2011. Purchases (net of inventory variation) represent Statoil's purchases of SDFI and 3rd party volumes and increased by 21% compared to second quarter 2010, mainly due to higher prices of liquids measured in NOK.

IFRS income statement — (in NOK billion)	Second quarter — 2011	2010	Change	First half — 2011	2010	Change	Full year — 2010
REVENUES AND OTHER INCOME
Revenues	159.5	129.3	23%	305.3	258.0	18%	527.0
Net income (loss) from equity accounted investments	0.4	0.3	52%	0.9	0.7	24%	1.2
Other income	8.8	(0.0)	<(100%)	14.5	0.4	>100%	1.8
Total revenues and other income	168.8	129.5	30%	320.7	259.1	24%	529.9
OPERATING EXPENSES
Purchase [net of inventory variation]	78.6	64.9	21%	148.7	122.3	22%	257.4
Operating expenses and selling, general and administrative expenses	17.7	19.9	(11%)	34.0	38.3	(11%)	68.8
Depreciation, amortisation and net impairment losses	11.2	14.6	(23%)	22.3	25.5	(13%)	50.7
Exploration expenses	0.2	3.6	(94%)	3.8	6.8	(44%)	15.8
Total operating expenses	(107.7)	(102.9)	5%	(208.9)	(192.9)	8%	(392.7)
Net operating income	61.0	26.6	>100%	111.8	66.2	69%	137.3
Net financial items	0.2	(0.8)	<(100%)	(0.3)	(2.5)	(88%)	(0.4)
Income tax	(34.2)	(22.8)	50%	(68.4)	(49.5)	38%	(99.2)
Net income	27.1	3.1	>100%	43.1	14.2	>100%	37.6

Net operating income includes certain items that management does not consider to be reflective of Statoil's underlying operational performance. Management adjusts for these items to arrive at adjusted earnings. Adjusted earnings is a supplemental non-GAAP measure to Statoil's IFRS measure of net operating income which management believes provides an indication of Statoil's underlying operational performance in the period and facilitates a better evaluation of operational developments between periods.

In the second quarter of 2011, underlift (NOK 2.2 billion) had a negative impact on net operating income while net gain on sale of the 40% Peregrino asset (NOK 8.8 billion), higher fair values of derivatives (NOK 6.3 billion), reversal of impairment losses (NOK 2.2 billion) and other adjustments (NOK 0.8 billion) had a positive impact on net operating income. Adjusted for these items and the effects of eliminations (NOK 1.5 billion), adjusted earnings were NOK 43.6 billion in the second quarter of 2011.

In the second quarter of 2010, impairment losses net of reversals (NOK 3.0 billion) mainly related to the Mongstad refinery, underlift (NOK 0.6 billion), lower values of products in operational storage (NOK 0.1 billion), lower fair value of derivatives (NOK 1.5 billion) and other provisions (NOK 4.6 billion), including provision for an onerous contract regarding a re-gasification terminal in the US (NOK 3.8 billion), all had a negative impact on net operating income. Adjusted for these items, adjusted earnings were NOK 36.5 billion in the second quarter of 2010.

The 20% increase in adjusted earnings from second quarter 2010 to second quarter 2011 was mainly attributable to higher prices for both liquids and gas. The increase was partly offset by lower volumes sold because of the decrease in production, lower exchange rates and weaker trading results.

Adjusted purchase [net of inventory variation] increased by 21% mainly due to higher prices of liquids, oil products and gas.

Adjusted operating expenses and selling, general and administrative expenses were NOK 18.1 billion in the second quarter of 2011, compared to NOK 16.6 billion in the second quarter last year. The 9% increase stemmed 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.

Adjusted depreciation, amortisation and net impairment losses were NOK 11.3 billion, down 3% compared to the same period last year mainly because of the impact of lower production. The reduction was partly offset by higher depreciation from new fields and assets coming on stream, and the impact on depreciation from revisions of removal and abandonment estimates.

Adjusted exploration expenses decreased by NOK 1.4 billion compared to the same period last year mainly because successful drilling resulted in a higher proportion of current periods exploration expenditures being capitalised this quarter compared to last year. Also lower exploration expenditure capitalised in previous years being expensed this period, added to the decrease.

Adjusted earnings — (in NOK billion)	Second quarter — 2011	2010	Change	First half — 2011	2010	Change	Full year — 2010
Adjusted total revenues and other income	154.0	133.2	16%	305.6	261.1	17%	530.2
Adjusted purchase [net of inventory variation]	78.6	64.8	21%	149.5	122.7	22%	258.0
Adjusted operating expenses and selling, general and administrative expenses	18.1	16.6	9%	36.1	33.8	7%	68.0
Adjusted depreciation, amortisation and net impairment losses	11.3	11.7	(3%)	23.3	22.6	3%	45.9
Adjusted exploration expenses	2.3	3.7	(37%)	5.9	6.6	(10%)	15.5
Adjusted earnings [11]	43.6	36.5	20%	90.8	75.3	21%	142.8

Financial data	Second quarter — 2011	2010	Change	First half — 2011	2010	Change	Full year — 2010
Weighted average number of ordinary shares outstanding	3,182,596,063	3,182,704,054		3,182,780,866	3,182,943,356		3,182,574,787
Earnings per share (NOK)	8.44	1.14	>100%	13.45	4.63	>100%	11.94
Non-controlling interests (NOK billion)	(0.1)	0.6	<(100%)	(0.2)	0.5	<(100%)	(0.4)
Cash flows provided by operating activities (NOK billion)	32.8	23.4	40%	53.6	48.1	12%	80.8
Gross investments (NOK billion)	19.8	18.7	6%	41.5	39.9	4%	84.4
Net debt to capital employed ratio	13.6%	29.2%		13.6%	29.2%		24.6%

Net financial items amounted to a gain of NOK 0.2 billion in the second quarter of 2011, compared to a loss of NOK 0.8 billion in the second quarter of 2010. The gain in the second 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 1.6 billion, partly offset by foreign exchange losses of NOK 1.4 billion. Correspondingly, the loss in the second quarter of 2010 primarily related to foreign exchange losses of NOK 3.3 billion, partly offset by fair value gains on interest rate swap positions, included in interest expenses, related to the interest rate management of external loans of NOK 2.9 billion.

Interest expenses in the second quarter of 2011 amounted to net gain of NOK 0.7 billion, correspondingly interest expenses of the second quarter of 2010 amounted to a net gain of NOK 2.1 billion.

The fair value gains on interest rate swap positions were caused by decreasing USD interest rates during the second quarter of 2011 and the second quarter of 2010.

Adjusted for these factors, net financial items excluding foreign exchange effects and interest rate derivatives, was a loss of approximately NOK 0.1 billion for the period. In the second quarter of 2010, net financial items excluding foreign exchange and interest rate derivatives before tax amounted to a loss of NOK 0.6 billion.

Financial items in second quarter 2011	Interest income	Net foreign exchange	Interest expense	Net before tax	Estimated tax effect	Net after tax
(in NOK billion)
Financial items according to IFRS	0.9	(1.4)	0.7	0.2	(0.6)	(0.4)
Foreign exchange (FX) impacts (incl. derivatives)	(0.1)	1.4		1.3
Interest rate (IR) derivatives			(1.6)	(1.6)
Subtotal	(0.1)	1.4	(1.6)	(0.3)	0.9	0.6
Financial items excluding FX and IR derivatives	0.8	0.0	(0.9)	(0.1)	0.3	0.2

Exchange rates	30 June 2011	31 March 2011	30 June 2010
USDNOK	5.39	5.51	6.50
EURNOK	7.79	7.83	7.97

Income tax was NOK 34.2 billion in the second quarter of 2011, equivalent to an effective tax rate of 55.8%, compared to NOK 22.8 billion in the second quarter of 2010, equivalent to an effective tax rate of 88.2%. The variance in effective tax rates between the periods is mainly explained by capital gains and the reversal of impairments (net of impairments) in the second quarter of 2011 with lower than average tax rates, compared with impairments with lower than average tax rates in the second quarter of 2010. The decreased effective tax rate in the second quarter of 2011 was also caused by relatively lower income from the NCS, which is subject to higher than average tax rates and higher deferred tax income in the second quarter of 2011 compared to the second quarter of 2010 related to currency effects in companies that are taxable in currencies other than the functional currency. The decreased effective tax rate in the second quarter of 2011 was partially offset by higher taxable income than accounting income before tax in the second quarter of 2011 compared to the second quarter of 2010 related to currency effects in companies that are taxable in currencies other than the functional currency.

In the second quarter of 2011, income before tax amounted to NOK 61.2 billion, while taxable income was estimated to be NOK 3.2 billion higher. The estimated difference of NOK 3.2 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 55.8%.

Management provides an alternative tax measure that excludes items not directly related to underlying operational performance. Adjusted earnings after tax, which exclude net financial items and tax on net financial items, is an alternative measure which provides an indication of Statoil's tax exposure to its underlying operational performance in the period, and management believes that this measure better facilitates a comparison between periods.

Composition of tax expense and effective tax rate in the second quarter of 2011	Before tax	Tax	Tax rate	After tax
Adjusted earnings	43.6	(30.8)	71%	12.8
Adjustments	17.4	(2.8)	16%	14.6
Net operating income	61.0	(33.6)	55%	27.4
Financial items	0.2	(0.6)	>100%	(0.4)
Total	61.2	(34.2)	56%	27.1

Adjusted earnings after tax in the second quarter of 2011 were NOK 12.8 billion, up from NOK 10.6 billion in the second quarter of 2010. The tax rate on adjusted earnings was 71% in the second quarter of both 2011 and 2010.

Adjusted earnings by segment are stated in the table below. The composition of Statoil's reportable segments was changed on the basis of the new corporate structure implemented with effect from 1 January 2011, see note 3 to the Interim Financial Statements.

Adjusted earnings after tax by segment — (in NOK billion)	Second quarter — 2011			2010
	Adjusted earnings	Tax on adjusted earnings	Adjusted earnings after tax	Adjusted earnings	Tax on adjusted earnings	Adjusted earnings after tax
D&P Norway	37.0	27.7	9.3	29.1	21.5	7.6
D&P International	5.8	2.8	3.0	2.9	1.5	1.4
Marketing, Processing & Renewable energy	0.5	0.5	0.0	3.4	2.5	0.8
Fuel & Retail	0.5	0.1	0.4	0.6	0.2	0.4
Other	(0.2)	(0.4)	0.1	0.6	0.1	0.4
Group	43.6	30.8	12.8	36.5	25.9	10.6

In the second quarter of 2011, net income was NOK 27.1 billion compared to NOK 3.1 billion last year. The substantial increase stems primarily from the increase in operating income caused by higher prices for both liquids and gas, a gain on the 40% Peregrino divestment, gain on derivatives, reversals of impairments made in prior periods and a lower effective tax rate. The increase was partly offset by lower volumes of liquids and gas sold and weaker trading results.

In the second quarter of 2011, earnings per share was NOK 8.44 compared to NOK 1.14 in the second quarter of 2010.

First half 2011

In the first half of 2011, net operating income was NOK 111.8 billion, compared to NOK 66.2 billion in the first half of 2010, an increase of 69%. Net operating income was positively impacted by higher liquids and gas prices, gains from the 40% Kai Kos Dehseh divestment In Canada and the 40% Peregrino divestment in Brazil, reversal of provisions and impairments made in prior periods and unrealised gains on derivatives. Decreased volumes of both liquids and gas sold because of reduced production and increased underlift only partly offset the increase in net operating income. Purchases (net of inventory variation) increased by 22%, mainly due to higher prices of liquids measured in NOK.

Depreciation, amortisation and net impairment losses decreased by 13% in the first half of 2011 compared to same period last year, mainly due to lower production and reversals of impairments made in previous periods, only partly offset by higher depreciation cost from new fields coming on stream. Exploration expenses were down from NOK 6.8 billion to NOK 3.8 billion compared to first half of 2010 mainly because of higher capitalised exploration in the first half of 2011, and lower exploration expenditure capitalised in previous years being expensed. This was partly offset by higher exploration activity with higher equity share and expensing of unsuccessful wells.

In the first half of 2011, underlift (NOK 3.7 billion) negatively impacted net operating income, while gain on sale of assets (NOK 14.3 billion), higher fair value of derivatives (NOK 3.6 billion), reversals net of impairment losses (NOK 3.1 billion), higher values of products in operational storage (NOK 0.8 billion) and other provisions/adjustments (NOK 1.5 billion) had a positive impact on net operating income. Adjusted for these items and effects of eliminations (NOK 1.4 billion) adjusted earnings were NOK 90.8 billion in the first half of 2011.

In the first half of 2010, impairment losses net of reversals (NOK 3.1 billion), lower fair value of derivatives (NOK 1.1 billion), underlift (NOK 0.2 billion) and other provisions (NOK 5.1 billion) including provision for an onerous contract regarding a re-gasification terminal in the US (NOK 3.8 billion), negatively impacted net operating income, while higher values of products in operational storage (NOK 0.4 billion) and gain on sale of assets (NOK 0.2 billion) had a positive impact on net operating income. Adjusted for these items and effects of eliminations (NOK 0.2 billion), adjusted earnings were NOK 75.3 billion in the first half of 2010.

The 21% increase in adjusted earnings from the first half of 2010 to the first half of 2011 was primarily caused by the increase in liquids and gas prices and was only partly offset by the lower volumes being sold because of the reduction in production and liftings.

Adjusted exploration expenses decreased by 10% in the first half of 2011 compared to last year, mainly due to lower exploration expenditure capitalised in previous years being expensed. Exploration expenses incurred in the period increased because of higher drilling costs and a higher number of wells being drilled, and partly counteracted the decrease.

Adjusted depreciation, amortisation and net impairment losses increased by 3% compared to last year mainly because of higher depreciation from new fields and assets coming on stream, and the impact on depreciation from revisions of removal and abandonment estimates. The increase was partly compensated by the impact of lower production and increased reserve estimates in Angola.

Adjusted operating expenses, and selling, general and administrative expenses has increased by NOK 2.3 billion compared to the same period last year mainly due to 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.

Net financial items amounted to a loss of NOK 0.3 billion in the first half of 2011, compared to a loss of NOK 2.5 billion in first half of 2010. The loss in the first half of 2011 was primarily due to foreign exchange losses of NOK 0.8 billion, partly offset by fair value gains on interest rate swap positions related to the interest rate management of external loans of NOK 0.6 billion. The loss in the first half of 2010 was primarily due to foreign exchange losses of NOK 5.8 billion, partly offset by fair value gains on interest rate swap positions related to the interest rate management of external loans of NOK 4.0 billion.

The fair value gains on interest rate swap positions are caused by decreasing USD interest rates during the six month period ended 30 June 2011 and 30 June 2010.

Adjusted for foreign exchange effects on the financial income and interest rate derivatives, net financial items before tax would amount to approximately a loss of NOK 0.9 billion for the period. In the first half of 2010, adjusted net financial items before tax were a loss of NOK 0.8 billion.

Financial items in the first half of 2011	Interest income	Net foreign exchange	Interest expense	Net before tax	Estimated tax effect	Net after tax
(in NOK billion)
Financial items according to IFRS	2.4	(0.8)	(1.8)	(0.3)	(1.1)	(1.4)
Foreign exchange (FX) impacts (incl. derivatives)	(0.8)	0.8		0.1
Interest rate (IR) derivatives			(0.7)	(0.7)
Subtotal	(0.8)	0.8	(0.7)	(0.6)	1.1	0.5
Financial items excluding FX and IR derivatives	1.6	0.0	(2.5)	(0.9)	0.0	(0.9)

Income taxes were NOK 68.4 billion in the first half of 2011, equivalent to a tax rate of 61%, compared to NOK 49.5 billion in the first half of 2010, equivalent to a tax rate of 78%. The variance in effective tax rates between the periods is mainly explained by capital gains and the reversal of impairments (net of impairments) in the first half of 2011 with lower than average tax rates, compared with impairments with lower than average tax rates in the first half of 2010. The decreased effective tax rate in the first half of 2011 was also caused by relatively lower income from the NCS, which is subject to higher than average tax rates in the first half of 2011 compared with the first half of 2010 and higher deferred tax income in the first half of 2011 compared to the first half of 2010 related to currency effects in companies that are taxable in other currencies than the functional currency. The decreased tax rate in the first half of 2011 was partially offset by higher taxable income than accounting income before tax in the first half of 2011 related to currency effects in companies that are taxable in currencies other than the functional currency.

Composition of tax expense and effective tax rate in the first half of 2011	Before tax	Tax	Tax rate	After tax
Adjusted earnings	90.8	(66.2)	73%	24.7
Adjustments	20.9	(1.1)	5%	19.8
Net operating income	111.8	(67.3)	60%	44.5
Financial items	(0.3)	(1.1)	<(100%)	(1.4)
Total	111.5	(68.4)	61%	43.1

Adjusted earnings after tax excludes the effects of net financial items and tax on financial items, and in the first half of 2011 adjusted earnings after tax were NOK 24.7 billion, up from NOK 22.9 billion in the same period last year. The adjusted tax rate on adjusted earnings was 73% and 70% in the first half of 2011 and 2010, respectively.

Adjusted earnings after tax by segment	First half
	2011			2010
(in NOK billion)	Adjusted earnings	Tax on adjusted earnings	Adjusted earnings after tax	Adjusted earnings	Tax on adjusted earnings	Adjusted earnings after tax
D&P Norway	76.4	57.4	19.0	58.2	43.1	15.1
D&P International	10.9	6.6	4.4	7.3	3.3	4.0
Marketing, Processing & Renewable energy	3.3	2.6	0.7	8.4	5.6	2.8
Fuel & Retail	0.9	0.2	0.6	1.0	0.4	0.5
Other	(0.6)	(0.6)	(0.0)	0.4	(0.1)	0.5
Group	90.8	66.2	24.7	75.3	52.4	22.9

In the first half of 2011, net income was NOK 43.1 billion compared to NOK 14.2 billion in the same period last year. The significant increase is mainly due to increased operating income caused by higher revenues from liquids and gas sales, gains from sale of assets, reduced loss on net financial items and a lower effective tax rate, and was only partly offset by lower volumes of liquids and gas sold and weaker trading results.

In the first half of 2011 earnings per share based on net income amounted to NOK 13.45, compared to NOK 4.63 in the first half of 2010.

The cash-flows were strong in the first half of 2011. Cash flows from underlying operations amounted to NOK 120.2 billion, mainly due to high prices of liquids and gas. Also received payments 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 half of 2011.

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OUTLOOK

On the Capital Market Day on 20 June, an updated outlook was communicated.

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.

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

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

Planned turnarounds are expected to have a large impact during the third quarter of 2011 with an anticipated effect on production of around 70 mboe per day in the quarter, of which approximately 80% are liquids. 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.

Equity production for 2012 is expected to grow with around 3% Compound Annual Growth Rate (CAGR) based on the actual 2010 equity production [13]. Statoil expects equity production in 2011 to be slightly below the 2010 level. Commercial considerations related to gas sales activities, operational regularity, the timing of new capacity coming on stream and gas off take represent the most significant risks related to the production guidance. Current market situation implies favourable conditions for deferring gas sales.

For the period beyond 2012, Statoil has an ambition to reach an equity production above 2.5 million barrels of oil equivalent in 2020. The growth is expected to come from new projects in the period from 2014 to 2016 resulting in a growth rate of 2 to 3% (GAGR) for the period 2012 to 2016. A second wave of projects is expected to come on stream from 2016 to 2020 resulting in an accelerated growth rate (GAGR) of 3 to 4%. The 2013 production is expected to be around 2012 level.

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 obtained in NOK for products sold. Specifically, such factors include the level of liquids and natural gas prices, trends in the 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 USDNOK 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 comfortably for 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 certificates with minimum single A-rating, or with banks with minimum single A-rating.

In accordance with our internal credit rating policy, we assess counterparty credit risk annually and assess counterparties identified as high risk more frequently. The internal credit ratings reflect our assessment of the counterparties' credit risk.

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HEALTH, SAFETY AND THE ENVIRONMENT (HSE)

Second quarter

The total recordable injury frequency was 3.9 in the second quarter of 2011 compared to 3.7 in the second quarter of 2010. The serious incident frequency improved from 1.4 in the second quarter of 2010 to 0.9 in the second quarter of 2011.

The volume of oil spills was 6.0 cubic metres in the second quarter of 2011, the same as in the second quarter of 2010. The number of accidental oil spills decreased from 117 spills in the second quarter of 2010 to 95 in the second quarter of 2011.

First half 2011

The total recordable injury frequency was 4.4 in the first half year of 2011 compared to 4.1 in the first half year of 2010. The serious incident frequency rate improved from 1.3 in the first half year of 2010 to 1.0 in the first half year of 2011. There were no fatal accidents in the first half of 2011.

The volume of oil spills increased from 13 cubic metres in the first half year of 2010 to 19 cubic metres in the first half year of 2011. The number of accidental oil spills in the first half year of 2011 decreased compared to the first half year of 2010.

HSE	Second quarter — 2011	2010	First half — 2011	2010	Year — 2010
Total recordable injury frequency	3.9	3.7	4.4	4.1	4.2
Serious incident frequency	0.9	1.4	1.0	1.3	1.4
Accidental oil spills (number)	95	117	168	196	374
Accidental oil spills (cubic metres)	6	6	19	13	44

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DEVELOPMENT AND PRODUCTION NORWAY

IFRS income statement — (in NOK billion)	Second quarter — 2011	2010	Change	First half — 2011	2010	Change	Full Year — 2010
Total revenues and other income	50.4	43.0	17%	102.8	85.1	21%	170.7
Operating expenses and selling, general and administrative expenses	5.5	5.7	(3%)	10.9	12.0	(9%)	23.6
Depreciation, amortisation and net impairment losses	6.9	6.4	9%	14.0	12.5	13%	26.0
Exploration expenses	0.8	1.3	(39%)	2.1	2.4	(14%)	5.5
Total operating expenses	13.2	13.4	(1%)	27.0	26.9	1%	55.1
Net operating income	37.2	29.6	26%	75.8	58.2	30%	115.6
Adjusted earnings [11]	Second quarter			First half			Full Year
(in NOK billion)	2011	2010	Change	2011	2010	Change	2010
Adjusted total revenues and other income	50.7	42.7	19%	104.4	85.1	23%	167.2
Adjusted operating expenses and selling, general and administrative expenses	6.0	5.9	2%	12.0	12.0	(1%)	23.8
Adjusted depreciation, amortisation and net impairment losses	6.9	6.4	9%	14.0	12.5	13%	26.0
Adjusted Exploration expenses	0.8	1.3	(39%)	2.1	2.4	(14%)	5.5
Adjusted earnings [11]	37.0	29.1	27%	76.4	58.2	31%	111.9

Operational data	Second quarter — 2011	2010	Change	First half — 2011	2010	Change	Full year — 2010
Prices:
Liquids price (USD/bbl)	111.6	73.6	52%	105.9	73.6	44%	76.3
Liquids price (NOK/bbl)	607.2	459.1	32%	591.4	444.6	33%	461.0
Transfer price natural gas (NOK/scm)	1.76	1.17	50%	1.64	1.15	43%	1.27
Liftings:
Liquids (mboe per day)	625	700	(11%)	648	736	(12%)	711
Natural gas (mboe per day)	518	709	(27%)	628	739	(15%)	669
Total liquids and gas liftings (mboe per day)	1,144	1,409	(19%)	1,276	1,475	(13%)	1,380
Production:
Entitlement liquids (mboe per day)	672	723	(7%)	688	750	(8%)	704
Entitlement natural gas (mboe per day)	518	709	(27%)	628	739	(15%)	669
Total entitlement liquids and gas production (mboe per day)	1,190	1,432	(17%)	1,316	1,488	(12%)	1,374

Second quarter

• Revenues were positively impacted by a 32% increase in liquids prices measured in NOK.
• Production decreased by 17% compared to the second quarter of 2010.
• High project activity with three sanctioned projects in the period and three PDOs approved: Hyme, Valemon and Visund South.
• Six exploration wells completed in the period, four new discoveries.

OPERATIONAL REVIEW

Average daily production of liquids decreased from 723 mboe per day in the second quarter of 2010 to 672 mboe per day in the second quarter of 2011. The decrease in production is mainly related to Gullfaks reduced water injection, Visund riser challenges and higher effect of planned turnarounds on several fields compared to the same quarter last year. 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, Gjøa and increased production at Tyrihans and Snorre, and increased ownership share at Heidrun.

Average daily production of gas decreased from 709 mboe per day in the second quarter of 2010 to 518 mboe per day in the second quarter of 2011. The decrease was mainly related to lower gas sales at Troll and Oseberg, planned turnarounds at Kvitebjørn, Snøhvit and Ormen Lange and reduced gas production from Gullfaks. This is partly offset by new production from Vega and Gjøa, and increased gas production from Tyrihans.

Average daily lifting of liquids decreased from 700 mboe per day in the second quarter of 2010 to 625 mboe per day in the second quarter of 2011.

Exploration expenditure (including capitalised exploration expenditure) increased by NOK 0.1 billion, from NOK 1.3 billion in the second quarter of 2010 to NOK 1.4 billion in the second quarter of 2011. This was mainly caused by higher drilling activity in the second quarter of 2011 compared to the same period last year. In the second quarter of 2011, six wells were completed and four wells were announced as discoveries.

FINANCIAL REVIEW

In the second quarter of 2011, net operating income for Development and Production Norway was NOK 37.2 billion compared to NOK 29.6 billion in the second quarter of 2010. The increase was mainly attributable to increased oil and gas prices, partly offset by decreased oil and gas lifting as well as a lower USD/NOK exchange rate.

In the second quarter of 2011, underlift (NOK 1.8 billion) had a negative impact on net operating income and an unrealised gain on derivatives (NOK 1.9 billion) had a positive impact on net operating income. In the second quarter of 2010, an unrealised gain on derivatives (NOK 1.3 billion) had a positive impact on net operating income and underlift (NOK 0.7 billion) had a negative impact on net operating income.

Adjusted for these items, adjusted earnings were NOK 37.0 billion in the second quarter of 2011, compared to NOK 29.1 billion in the same period last year. The increase was mainly due to higher realised prices of liquids and natural gas measured in NOK, which positively impacted adjusted earnings by NOK 13.2 billion. This was partly offset by decreased production of oil and natural gas that impacted adjusted earnings negatively by NOK 5.4 billion.

Adjusted depreciation and amortisation (excluding net impairment losses) increased by NOK 0.6 billion compared to the same period last year, mainly due to new fields with high depreciation cost, the impact on depreciation of prior year revisions to removal/abandonment estimates and increased owner share after redetermination on the Heidrun field, partly offset by lower production.

Adjusted operating expenses and selling, general and administrative expenses increased by NOK 0.1 billion compared to the same period last year, mainly due to new fields in production.

Adjusted exploration expenses have decreased by NOK 0.5 billion in the second quarter of 2011 compared to the same period last year. The decrease is mainly due to lower exploration expenditure capitalised in previous years being expensed in the second quarter of 2011 compared to the first quarter of 2010.

First half 2011

OPERATIONAL REVIEW

Average daily production of liquids decreased from 750 mboe per day in the first half of 2010 to 688 mboe per day in the first half of 2011. The decrease in liquids production was mainly related to Gullfaks reduced water injection, Oseberg turnaround at all installations in second quarter of 2011, Visund turnaround and riser challenges, Statfjord and Kvitebjørn turnarounds. 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 increased ownership share at Heidrun.

Average daily production of gas decreased from 739 mboe per day in the first half of 2010 to 628 mboe per day in the first half of 2011. The reduction in gas production is mainly related to Troll and Oseberg due lower gas sales, planned turnarounds at Snøhvit and Ormen Lange and reduced gas export from Gullfaks. In addition, a 13 day unplanned shutdown at Snøhvit in first quarter of 2011 contributed to the reduction. This is partly offset by new production from Vega and Gjøa, and increased gas export Tyrihans.

Average daily lifting of liquids decreased from 736 mboe per day in the first half of 2010 to 648 mboe per day in the first half of 2011.

Exploration expenditure (including capitalised exploration expenditure) increased by NOK 0.8 billion, from NOK 2.4 billion in the first half of 2010 to NOK 3.2 billion in the first half of 2011. The increase was mainly caused by higher drilling activity in the first half of 2011 compared to the same period last year. In the first half of 2011, 13 wells were completed and seven were announced as discoveries.

FINANCIAL REVIEW

In the first half of 2011, the net operating income for Development and Production Norway was NOK 75.8 billion compared to NOK 58.2 billion in the first half of 2010.

In the first half of 2011, underlift (NOK 2.7 billion) and change in future settlement related to a sale of a licence share (NOK 0.1 billion) negatively impacted net operating income. An unrealised gain on derivatives (NOK 2.2 billion) positively impacted net operating income. In the first half of 2010, an unrealised gain on derivatives (NOK 1.1 billion) positively impacted net operating income. A change in future settlement related to a sale of a licence share (NOK 0.1 billion) and underlift (NOK 1.0 billion) negatively impacted net operating income.

Adjusted for these items, adjusted earnings were NOK 76.4 billion in the first half of 2011. In the first half of 2010, adjusted earnings were NOK 58.2 billion. The increase 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 the adjusted earnings by NOK 27.3 billion. This was partly offset by a decrease in oil and natural gas production, which negatively impacted adjusted earnings by NOK 8.6 billion.

Adjusted depreciation and amortisation (excluding net impairment losses) increased by NOK 1.6 billion compared to same the 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.

Adjusted operating expenses and selling, general and administrative expenses amounted to NOK 12.0 billion in the first half of 2011 and were at the same level as the same period in 2010. Reduced costs for purchase of gas for re-injection on Grane were fully offset by increased costs of new fields in production. As a consequence of cost improvements, the level of remaining operating expenses was stable compared to last year.

Adjusted exploration expenses have decreased by NOK 0.3 billion in the first half of 2011 compared to the same period last year, mainly due to lower exploration expenditure capitalised in previous years being expensed. This was partly offset by higher drilling activity and a smaller proportion of exploration expenditure being capitalised in the first half of 2011 compared to the first half of 2010.

Important events since last quarter:

• Exploration activity in the period included four discoveries: PL532 Skrugard, PL272 Krafla, PL050 Opal and PL501 Avaldsnes appraisal.
• On 1 April Beta West (Sleipner) started production.
• Plan for development and operation (PDO) for three fast track projects were submitted; Vigdis North East, Stjerne and Hyme.
• The Ministry of Petroleum and Energy (MPE) has approved three PDOs: ValemonVisund South and Hyme.
• In July, Statoil awarded the contract for construction of two new specially designed category D drilling rigs, and signed a contract for hire of the exploration rig Songa Trym.

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DEVELOPMENT AND PRODUCTION INTERNATIONAL

IFRS income statement — (in NOK billion)	Second quarter — 2011	2010	Change	First half — 2011	2010	Change	Full Year — 2010
Total revenues and other income	22.9	11.3	103%	41.6	25.1	65%	51.0
Purchase [net of inventory variation]	(0.1)	(0.0)	<(100%)	(0.0)	0.0	0%	0.0
Operating expenses and selling, general and administrative expenses	3.2	2.8	15%	6.0	5.8	2%	11.4
Depreciation, amortisation and net impairment losses	3.1	3.8	(18%)	6.6	7.6	(13%)	16.7
Exploration expenses	(0.6)	2.3	<(100%)	1.8	4.4	(60%)	10.3
Total operating expenses	5.6	8.8	(36%)	14.3	17.8	(20%)	38.4
Net operating income	17.3	2.5	>100%	27.3	7.3	>100%	12.6
Adjusted earnings [11]	Second quarter			First half			Full Year
(in NOK billion)	2011	2010	Change	2011	2010	Change	2010
Adjusted total revenues and other income	13.8	12.1	14%	27.8	24.7	12%	49.9
Adjusted purchase [net of inventory variation]	(0.1)	(0.0)	<(100%)	(0.0)	0.0	0%	0.0
Adjusted operating expenses and selling, general and administrative expenses	3.3	3.0	10%	6.3	5.5	13%	11.1
Adjusted depreciation, amortisation and net impairment losses	3.3	3.9	(15%)	6.8	7.7	(12%)	14.9
Adjusted exploration expenses	1.5	2.4	(36%)	3.9	4.2	(8%)	10.0
Adjusted earnings [11]	5.8	2.9	>100%	10.9	7.3	49%	13.9

Operational data	Second quarter — 2011	2010	Change	First half — 2011	2010	Change	Full year — 2010
Prices:
Liquids price (USD/bbl)	113.1	75.2	50%	107.0	74.9	43%	76.8
Liquids price (NOK/bbl)	615.2	468.9	31%	597.5	452.8	32%	464.2
Liftings:
Liquids (mboe per day)	198	242	(18%)	206	274	(25%)	258
Natural gas (mboe per day)	75	75	0%	76	78	(2%)	68
Total liquids and gas liftings (mboe per day)	272	317	(14%)	282	352	(20%)	327
Production:
Entitlement liquids (mboe per day)[6]	221	258	(14%)	232	273	(15%)	263
Entitlement natural gas (mboe per day)	75	75	0%	76	78	(2%)	68
Total entitlement liquids and gas production (mboe per day)	296	333	(11%)	308	351	(12%)	332
Total equity liquids production (mboe per day)	404	425	(5%)	411	433	(5%)	417
Total equity gas production (mboe per day)	98	100	(2%)	103	108	(5%)	97
Total equity liquids and gas production (mboe per day)	502	525	(4%)	514	541	(5%)	514

Second quarter

• Revenues were positively impacted by a 31% increase in liquids prices measured in NOK compared to the second quarter of 2010.
• Equity production decreased by 4% compared to the second quarter of 2010.
• Entitlement production decreased by 11%.
• The sale of 40% of the Peregrino offshore field in Brazil was completed. A gain of NOK 8.8 billion before tax on the sale of the divested interest is recorded.

OPERATIONAL REVIEW

Average daily entitlement production of liquids and gas was 296 mboe per day in the second quarter of 2011, compared to 333 mboe per day in the second quarter of 2010.

The decrease in entitlement production was due to lower equity production in the second quarter of 2011, and a higher negative effect from Production Sharing Agreements (PSA). The PSA effect on entitlement production was 206 mboe per day in the second quarter of 2011, compared to 192 mboe in the second quarter 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 second quarter of 2010 to 404 mboe per day in the second quarter of 2011. The decrease in liquids production was mainly due to decline and planned 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 on Peregrino in Brazil and Leismer in Canada in 2011.

Average daily equity production of gas decreased from 100 mboe per day in the second quarter of 2010 to 98 mboe per day in the second quarter of 2011. The decrease was mainly due to lower nominations from In Salah in Algeria and lower production from the Independence Hub fields in the U.S. where Q Gas and San Jacinto are depleted. The decrease was offset by increased production from Marcellus with increased number of wells online.

Average daily lifting of liquids and gas decreased from 317 mboe per day in the second quarter of 2010 to 272 mboe per day in the second quarter of 2011.

Exploration expenditure (including capitalised exploration expenditure) was NOK 2.1 billion in the second quarter of 2011 and NOK 2.3 in the second quarter of 2010. Decreased exploration expenditure due to lower drilling activity was partly offset by more expensive wells and higher Statoil equity shares in the second quarter of 2011.

In the second quarter of 2011, a total of three exploration (and appraisal) wells were completed before 30 June 2011. Two wells were announced as discoveries.

FINANCIAL REVIEW

In the second quarter of 2011, net operating income for Development and Production International was NOK 17.3 billion compared to NOK 2.5 billion in the same period last year.

Net operating income in the second quarter of 2011 was positively impacted by a gain on sale of assets of NOK 8.8 billion, net impairment reversals of NOK 2.3 billion and other adjustments of NOK 0.8 billion. An underlift of NOK 0.4 billion had a negative effect on net operating income. In the second quarter of 2010, reversal of impairments of NOK 0.2 billion and underlift of NOK 0.1 billion positively impacted net operating income. An accrual of NOK 0.7 billion for disputed cost recovery audits related to prior years negatively impacted net operating income.

Adjusted for these items, adjusted earnings in the second quarter of 2011 and 2010 were NOK 5.8 billion and NOK 2.9 billion, respectively. Increased realised liquids and gas prices measured in NOK impacted adjusted earnings positively by NOK 2.8 billion. Decreased exploration costs of NOK 0.9 billion also impacted adjusted earnings positively. These effects were partly offset by reduced entitlement production, which impacted adjusted earnings negatively by NOK 1.4 billion.

Adjusted operating expenses and selling, general and administrative expenses were increased by 10% from the second quarter of 2010 to the second quarter of 2011. The increase was mainly due to increased activity related to start-up and ramp-up of production of various fields.

Adjusted depreciation, amortisation and net impairment losses were NOK 3.3 billion in the second quarter of 2011, compared to NOK 3.9 billion in the second quarter of 2010. The decrease was mainly due to lower production and increase of reserves on various fields. The decrease was partly offset by increased production, mainly from Peregrino, Leismer, Marcellus and Eagle Ford.

Adjusted exploration expenses were NOK 1.5 billion in the second quarter of 2011, compared to NOK 2.4 billion in the second quarter of 2010. The decrease of NOK 0.9 billion was mainly due to higher proportion of current period exploration expenditure being capitalised in the second quarter of 2011 compared to the second quarter of 2010. In addition, a smaller proportion of exploration expenditure capitalised in previous years was expensed in the second quarter of 2011 compared to the same period last year.

First half 2011

OPERATIONAL REVIEW

Average daily entitlement production of liquids and gas was 308 mboe per day in the first half of 2011, compared to 351 mboe per day in the first half of 2010.

The decrease in entitlement production was due to lower equity production in the first half of 2011 and a higher negative effect from Production Sharing Agreements (PSA). The PSA effect on entitlement production was 206 mboe per day in the first half of 2011, compared to 190 mboe in the first half 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 433 mboe per day in the first half of 2010 to 411 mboe per day in the first half 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 on Peregrino in Brazil and Leismer in Canada in 2011.

Average daily equity production of gas decreased from 108 mboe per day in the first half of 2010 to 103 mboe per day in the first half of 2011. The decrease was mainly due to lower nominations from In Salah in Algeria and from Shah Deniz in Azerbaijan. The decrease was partly offset by Marcellus in the U.S with an increased number of wells online.

Average daily lifting of liquids and gas decreased from 352 mboe per day in the first half of 2010 to 282 mboe per day in the first half of 2011.

Exploration expenditure (including capitalised exploration expenditure) decreased by NOK 0.3 billion from NOK 3.6 billion in the first half of 2010 to NOK 3.3 billion in the first half of 2011. The decrease was mainly due to lower drilling activity in the first half of 2011 compared to the same period last year, which was partly offset by more expensive wells drilled in 2011.

In the second half of 2011, a total of six exploration (and appraisal) wells were completed before 30 June 2011. Two wells were announced as discoveries.

FINANCIAL REVIEW

In the first half of 2011, net operating income for Development and Production International was NOK 27.3 billion compared to NOK 7.3 billion in the same period last year.

Net operating income for the first half of 2011 was positively impacted by NOK 14.4 billion from gains on sale of Peregrino and the Canadian oil sands assets, net impairment reversals of NOK 2.3 billion and other adjustments of NOK 0.8 billion. An underlift of NOK 1.0 billion and unrealised loss on derivative of NOK 0.1 billion negatively impacted net operating income for the first half of 2011. In the first half of 2010, impairment losses net of reversals of NOK 0.1 billion and an adjustment on total revenues and other income on NOK 0.7 billion negatively impacted net operating income. An overlift of NOK 0.8 billion had a positive effect on net operating income.

Adjusted for these items, adjusted earnings in the first half of 2011 and 2010 for Development and Production International were NOK 10.9 billion and NOK 7.3 billion, respectively. The increase was mainly due to an increase in realised liquids and gas prices measured in NOK, which positively impacted adjusted earnings by NOK 5.6 billion. The increase in adjusted earnings was partly offset by lower entitlement volumes which negatively impacted adjusted earnings by NOK 3.1 billion.

Adjusted operating expenses, and selling, general and administrative expenses have increased by NOK 0.8 billion compared to the same period last year mainly due to increased operating expenses related to preparing Peregrino for operations, and increased operating expenses related to Leismer that was under development in 2010 and in production in 2011.

Adjusted depreciation, amortisation and net impairment losses decreased by NOK 0.9 billion compared to the same period last year, mainly due to lower production and increase of reserves in various fields. The decrease was partly offset by increased production, mainly from Peregrino, Leismer, Marcellus and Eagle Ford.

Adjusted exploration expenses were NOK 3.9 billion in the first half of 2011, compared to NOK 4.2 billion in the first half of 2010. The decrease of NOK 0.3 billion was mainly due to higher proportion of current period exploration expenditure being capitalised in the first half of 2011 compared to the first half of 2010. In addition, a smaller proportion of exploration expenditure capitalised in previous years was expensed in the first half of 2011 compared to the same period last year.

Important events since last quarter

• On 6 July the UK Government announced that the annual rate of the Ring Fence Expenditure Supplement (RFES) for the North Sea fiscal regime will be increased from 6% to 10%. This change will provide extra support for investments in the UK part of the North Sea. As a consequence, Statoil will resume the work on maturing the Mariner field in UK towards a Final Investment Decision in the end of 2012.
• On 9 June Statoil and Talisman entered into an agreement with Denver-based independent SM Energy Company that will add 15,400 acres to the companies' 50/50 Eagle Ford joint venture in Texas, USA. The total purchase price is USD 225 million. The transaction is expected to close in August.
• Hibernia Southern Extension located offshore in Canada delivered its first oil on 25 June. Statoil has 10.5% share in the development, while ExxonMobil is the operator.

Table of Contents

MARKETING, PROCESSING AND RENEWABLE ENERGY

IFRS income statement — (in NOK billion)	Second quarter — 2011	2010	Change	First half — 2011	2010	Change	Full Year — 2010
Total revenues and other income	147.2	120.5	22%	284.4	241.2	18%	493.6
Purchase [net of inventory variation]	134.3	112.3	20%	262.7	219.2	20%	452.1
Operating expenses and selling, general and administrative expenses	7.4	10.8	(31%)	14.0	18.3	(23%)	29.3
Depreciation, amortisation and net impairment losses	0.7	3.9	(81%)	0.7	4.4	(84%)	6.0
Total operating expenses	142.4	127.0	12%	277.4	241.9	15%	487.5
Net operating income	4.8	(6.5)	<(100%)	7.0	(0.7)	<(100%)	6.1
Adjusted earnings [11]	Second quarter			First half			Full Year
(in NOK billion)	2011	2010	Change	2011	2010	Change	2010
Adjusted total revenues and other income	142.9	123.5	16%	282.9	243.5	16%	499.1
Adjusted purchase [net of inventory variation]	134.3	112.2	20%	263.5	219.6	20%	452.7
Adjusted operating expenses and selling, general and administrative expenses	7.4	6.9	7%	14.7	13.9	5%	28.4
Adjusted depreciation, amortisation and net impairment losses	0.6	1.0	(33%)	1.5	1.5	0%	3.1
Adjusted earnings [11]	0.5	3.4	(84%)	3.3	8.4	(61%)	14.8

Operational data	Second quarter — 2011	2010	Change	First half — 2011	2010	Change	Full year — 2010
Refining margin (reference margin, USD/bbl)	2.2	4.9	(55%)	2.4	4.4	(45%)	3.9
Contract price methanol (EUR/tonne)	305	250	22%	310	243	28%	254
Natural gas sales Statoil entitlement (bcm)	8.2	11.0	(26%)	19.4	22.7	(14%)	41.7
Natural gas sales (third-party volumes) (bcm)	3.4	2.8	25%	6.2	5.3	17%	11.1
Natural gas sales (bcm)	11.6	13.8	(16%)	25.6	27.9	(8%)	52.8
Natural gas sales on commission	0.3	0.4	(19%)	0.6	0.8	(23%)	1.5
Natural gas price (NOK/scm)	2.06	1.61	28%	2.00	1.62	23%	1.72
Transfer price natural gas (NOK/scm)	1.76	1.17	50%	1.64	1.15	43%	1.27
Regularity at delivery point	100%	100%	0%	100%	100%	0%	100%

Second quarter

• Significant increase in oil and gas prices compared to the second quarter of 2010.
• Weaker results in Natural gas marketing and trading due to lower trading margin and lower entitlement production compared to the second quarter of 2010.
• Lower results in Natural gas processing and transportation from lower tariffs and a 3.7% reduction in ownership share in Gassled to 29.1% compared to the second quarter of 2010.
• Weaker results in Crude oil processing, marketing and trading due to lower margin from trading and storage strategies in a backwardated and difficult market, and significantly lower refining margins compared to the second quarter of 2010.
• High available capacity at gas and oil processing facilities compared to the second quarter of 2010.

OPERATIONAL REVIEW

Natural gas sales volumes in the second quarter of 2011 were 11.6 billion standard cubic metres (bcm), compared to 13.8 bcm in the second quarter of 2010. Of total gas sales in the second quarter of 2011, entitlement gas amounted to 8.2 bcm gas and 1.1 bcm was related to the Norwegian State's direct financial interest (SDFI) share of US gas sales. In the second quarter of 2010, 11.0 bcm of total sales was entitlement gas and 1.1 bcm was SDFI share of US gas sales. The 16% decrease in total gas volumes from the second quarter of 2010 to the second quarter of 2011 was mainly related to high entitlement production in the second quarter of 2010.

In the second quarter of 2011 the volume weighted average natural gas sales price was NOK 2.06 per scm (USD 9.88 per million British thermal units), compared to NOK 1.61 per scm (USD 7.72 per million British thermal units) in the second quarter of 2010, an increase of 28%. The increase was due to increase in gas prices linked to oil products as well as gas indexed prices.

Refinery throughput in the second quarter of 2011 was lower than in the second quarter of 2010 as capacity utilisation was reduced due to low margins. The on stream factor however, was higher both at the Mongstad and the Kalundborg refinery.

Methanol production in the second quarter of 2011 was 44% higher than in the second quarter of 2010, mainly due to turnaround in 2010, but also improved on stream factor and capacity utilisation in 2011.

FINANCIAL REVIEW

In the second quarter of 2011 net operating income for Marketing, Processing and Renewable Energy was NOK 4.8 billion compared to a loss of NOK 6.5 billion in the second quarter of 2010.

Net operating income in the second quarter of 2011 included a gain due to periodisation of inventory hedging effects (NOK 2.7 billion), a positive change in fair value of derivatives (NOK 1.6 billion), and an impairment loss related to onshore wind assets (NOK 0.1 billion). Net operating income in the second quarter of 2010 included a gain due to periodisation of inventory hedging effects (NOK 0.9 billion), a provision for an onerous contract in connection with the Cove Point regasification terminal in the US (NOK 3.8 billion), a negative change in fair value of derivatives (NOK 3.7 billion), and impairment losses mainly related to a refinery asset (NOK 3.1 billion).

Adjusted for these items, adjusted earnings were NOK 0.5 billion in the second quarter of 2011, compared to NOK 3.4 billion in the second quarter of 2010. The decrease was due to weaker trading results, lower volumes, lower refining margins and lower results from Gassled.

Adjusted total revenues and other income were up 16% to NOK 142.9 billion due to higher prices for crude, other oil products and gas, but were partly offset by lower volumes of oil and gas sold.

Adjusted purchase [net of inventory variation] was up 20% to NOK 134.3 due to the same factors.

Adjusted operating expenses and selling, general and administration expenses were up 7% to NOK 7.4 billion. The increase was mainly due 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.

Adjusted depreciation, amortisation and net impairment losses were down 33% to NOK 0.6 billion due to 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. (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.) The reduction in adjusted depreciation, amortisation and net impairment losses was partly offset by increased depreciation on new Mongstad refinery units.

Adjusted earnings in Natural gas processing and transportation were NOK 1.1 billion in the second quarter of 2011, compared to NOK 1.4 billion in the second quarter of 2010. The reduction was mainly due to reduced tariffs in Gassled and a 3.7% reduction in ownership share in Gassled. The adjusted earnings for the second quarter of 2011 include results from ongoing operations related to the 24.1% share of Gassled that Statoil has agreed to sell to Solveig Gas Norway AS. Adjusted earnings in Natural gas marketing and trading were a loss of NOK 0.1 billion in the second quarter of 2011, compared to positive adjusted earnings of NOK 1.9 billion in the second quarter of 2010. The reduction was mainly due to lower margin on gas sales, lower entitlement volumes, and mark to market loss related to time optimisation. The overall result from the time optimisation is still positive.

Adjusted earnings in Crude oil processing, marketing and trading were a loss of NOK 0.4 billion in the second quarter of 2011, compared to positive adjusted earnings of NOK 0.2 billion in the second quarter of 2010. The reduction was mainly due to lower margin from crude oil trading and storage strategies in a backwardated and challenging market, and lower refining margins, but partly offset by higher methanol prices.

First half 2011

OPERATIONAL REVIEW

Natural gas sales volumes in the first half of 2011 were 25.6 billion standard cubic metres (bcm), compared to 27.9 bcm in the first half of 2010. Of total gas sales in the first half of 2011, entitlement gas amounted to 19.4 bcm gas and 2.2 bcm was related to the Norwegian State's direct financial interest (SDFI) share of US gas sales. In the first half of 2010, 22.7 bcm of total sales was entitlement gas and 2.1 bcm was SDFI share of US gas sales. The 8% decrease in total gas volumes from the first half of 2010 to the first half of 2011 was mainly related to high entitlement production in the second quarter of 2010.

In the first half of 2011 the volume weighted average sales price was NOK 2.00 per scm (USD 9.59 per million British thermal units), compared to NOK 1.62 per scm (USD 7.77 per million British thermal units) in the first half of 2010, an increase of 23%. The increase was due to increase in gas prices linked to oil products as well as gas indexed prices.

Refinery throughput in the first half of 2011 was higher than in the first half 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 half of 2011 compared to the first half of 2010.

Methanol production in the first half of 2011 was 18% higher than in the first half of 2010, mainly due to turnaround in 2010, but also improved on stream factor and capacity utilisation.

FINANCIAL REVIEW

In the first half of 2011 net operating income for Marketing, Processing and Renewable Energy was NOK 7.0 billion compared to a loss of NOK 0.7 billion in the first half of 2010.

Net operating income in the first half of 2011 included a reversal of a provision and an impairment in connection with Cove Point (NOK 1.6 billion), a positive change in fair value of derivatives (NOK 1.3 billion), a gain on our operational storage (NOK 0.8 billion), a gain due to periodisation of inventory hedging effects (NOK 0.2 billion) and an impairment loss related to onshore wind assets (NOK 0.1 billion). Net operating income in the first half of 2010 included a gain due to periodisation of inventory hedging effects (NOK 0.9 billion), a gain on our operational storage (NOK 0.4 billion), a provision for an onerous contract in connection with Cove Point (NOK 4.3 billion), a negative change in fair value of derivatives (NOK 3.2 billion), and an impairment loss on a refinery asset (NOK 2.9 billion).

Adjusted for these items, adjusted earnings were NOK 3.3 billion in the first half of 2011, compared to NOK 8.4 billion in the first half of 2010. The decrease was due to 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.

Adjusted total revenues and other income were up 16% to NOK 282.9 billion due to higher prices for crude, other oil products and gas, but were partly offset by lower volumes of oil and gas sold.

Adjusted purchase [net of inventory variation] was up 20% to NOK 263.5 due to the same factors.

Adjusted operating expenses and selling, general and administration expenses were up 5% to NOK 14.7 billion. The increase was mainly due 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.

Adjusted depreciation, amortisation and net impairment losses amounted to NOK 1.5 billion in the first half of 2011, and remain at the same level as the first half of 2010. New Mongstad refinery units were fully offset by the 3.7% reduction in ownership share in Gassled from 1 January 2011.

Adjusted earnings in Natural gas processing and transportation were NOK 2.3 billion in the first half of 2011, compared to NOK 3.0 billion in the first half of 2010. The reduction was mainly due to reduced tariffs in Gassled and 3.7% reduction in ownership share in Gassled.

Adjusted earnings in Natural gas marketing and trading were NOK 1.9 billion in the first half of 2011, compared to NOK 4.9 billion in the first half of 2010. The reduction was mainly due to lower margin on our gas sales, lower entitlement volumes, and realised loss related to time optimisation. The overall result from the time optimisation is still positive.

Adjusted earnings in Crude oil processing, marketing and trading were a loss of NOK 0.8 billion in the first half of 2011, compared to a positive adjusted earnings of NOK 0.8 billion in the first half of 2010. The reduction was mainly due to lower margin from trading of crude oil and gas liquids, and storage strategies in a backwardated and challenging market, and lower refining margins, but partly offset by higher methanol prices.

Important events since last quarter:

• Statoil has signed an agreement to sell 24.1% of Gassled ownership to Solveig Gas Norway AS. The transaction is subject to governmental approval.
• On 26 May, Statoil Natural Gas LLC executed a new gas sales agreement with JP Morgan (JPM) for 120,000 MMBtu/day (1.2 bcm/year) of firm volumes for an 11 year term.
• Statoil has signed a new gas sales agreement at St Fergus of 5 Bcm in total over a 10 year term with Scottish and Southern Energy (SSE) from 1 October 2012.
• Agreements to sell major parts of Statoil's onshore wind power activities in Norway were signed, transferring Statoil's stake in Sarepta Energi AS to Trønder Energi Kraft AS and our wind power projects in Finnmark to Finnmark Kraft AS. The transactions are expected to close in September.
• Statoil has lifted the first cargo of Peregrino oil from the field, for blending and delivery to a customer on the US Gulf Coast.

Table of Contents

FUEL & RETAIL

IFRS income statement — (in NOK billion)	Second quarter — 2011	2010	Change	First half — 2011	2010	Change	Full Year — 2010
Total revenues and other income	19.1	16.3	17%	36.0	31.6	14%	65.9
Purchase [net of inventory variation]	16.4	13.7	20%	31.0	26.1	19%	54.8
Operating expenses and selling, general and administrative expenses	1.8	1.8	1%	3.6	3.6	(1%)	7.4
Depreciation, amortisation and net impairment losses	0.3	0.4	(24%)	0.6	0.7	(15%)	1.3
Total operating expenses	18.6	15.9	17%	35.2	30.4	15%	63.5
Net operating income	0.5	0.5	0%	0.9	1.2	(23%)	2.4

Second quarter

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

OPERATIONAL REVIEW

Road transport fuel volumes for the second quarter of 2011 were slightly up compared to the same period last year. A slight decrease in Scandinavian volumes 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 second quarter rose by 8.5% to NOK 0.654 compared with the same period in 2010. In Scandinavia, margins increased by 14.5% driven by a favourable development in refined oil product prices and improved micro market pricing. In Central and Eastern Europe the margins decreased by 15.7% compared with last year, primarily driven by lower margins in Central and Eastern Europe where increased refined oil product prices were not fully reflected in retail prices. A domestic price war in Estonia put further pressure on margins.

FINANCIAL REVIEW

In the second quarter of 2011, net operating income was NOK 0.5 billion, on par with the same period in 2010.

Total revenues and other income increased from NOK 16.3 billion in the second quarter of 2010 to NOK 19.1 billion in the second quarter of 2011 driven by higher underlying refined oil products prices.

Purchase [net of inventory variation] increased from NOK 13.7 billion in the second quarter of 2010 to NOK 16.4 billion in the second quarter of 2011, explained by the same factors described under total revenues.

Operating expenses and selling, general and administrative expenses amounted to 1.8 billion, on the same level compared to same period in 2010.

Depreciation, amortisation and impairment decreased from NOK 0.4 billion in the second quarter of 2010 to NOK 0.3 in 2011, primarily due to an impairment in the second quarter of 2010 of NOK 0.1 billion.

First half 2011

OPERATIONAL REVIEW

For the first half of 2011, volumes decreased marginally compared to 2010. In Scandinavia, volumes were in line with the same period last year, despite a reduction in total market volumes and fewer stations due to network optimisation. In Central and Eastern Europe, volumes increased by 0.4% compared to 2010, primarily due to increased volumes in the B2B (business-to-business) segment.

Margins for the first half of 2011 increased by 8.5% compared to the first quarter of 2010, from NOK 0.579 to NOK 0.628. In Scandinavia, improved micro market pricing and a favourable development in refined oil product prices during the second quarter 2011 increased margins by 13.2%. In Central and Eastern Europe, margins decreased by 10.7%, as pump prices did not fully reflect the increase in refined oil product prices.

FINANCIAL REVIEW

In the first half of 2011 net operating income decreased by NOK 0.3 billion, from NOK 1.2 billion to 0.9 billion in the first half 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 31.6 billion in the first half of 2010 to NOK 36.0 billion in the first half of 2011 driven by higher underlying refined oil products prices.

Purchase [net of inventory variation] increased from NOK 26.1 billion in the first half of 2010 to NOK 31.0 billion in the first half of 2011, explained by the same factors described under total revenues.

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

Depreciation, amortisation and impairment decreased from NOK 0.7 billion in the first half of 2010 to NOK 0.6 in the first half of 2011, primarily due to an impairment in 2010 of NOK 0.1 billion.

Table of Contents

LIQUIDITY AND CAPITAL RESOURCES

Second quarter

Cash flows provided by operations amounted to NOK 32.8 billion in the second quarter of 2011, compared to NOK 23.4 billion in the second quarter of 2010. The NOK 9.4 billion increase was mainly due to higher cash flows from underlying operations of NOK 21.4 billion and positive changes in working capital of NOK 5.1 billion. These effects were partly offset by negative changes in financial investments and derivatives of NOK 8.4 billion, other changes of NOK 6.7 billion and lower taxes paid of NOK 2.0 billion, compared to the second quarter of 2010.

Condensed cash flow statement — (in NOK billion)	Second quarter — 2011	2010	Change	First half — 2011	2010	Change	Full year — 2010
Cash flows from underlying operations [14]	63.0	41.6	21.4	120.2	91.4	28.8	190.9
Cash flows from (to) changes in working capital	4.4	(0.7)	5.1	(0.9)	(7.7)	6.8	(10.6)
Changes in current financial investments	(2.4)	3.4	(5.8)	(16.2)	0.3	(16.5)	(4.5)
Changes in net derivative financial instruments	(3.3)	(0.7)	(2.6)	(2.7)	(0.9)	(1.8)	(0.6)
Taxes paid	(28.9)	(26.9)	(2.0)	(44.8	(39.7)	(5.1)	(92.3)
Other changes	0.0	6.7	(6.7)	(1.9)	4.7	(6.7)	(2.2)
Cash flows provided by operations	32.8	23.4	9.4	53.6	48.1	5.6	80.8
Additions to PP&E and intangible assets	(18.6)	(18.4)	(0.2)	(36.0)	(31.6)	(4.4)	(68.1)
Proceeds from sales	18.0	2.1	15.9	29.4	0.9	28.5	1.9
Other changes	0.4	(0.1)	0.5	(2.8)	(5.3)	2.5	(10.3)
Cash flows used in investing activities	(0.2)	(16.5)	16.2	(9.4)	(36.1)	26.6	(76.5)
Net change in long-term borrowing	(4.1)	(0.2)	(3.9)	(4.4)	(3.0)	(1.5)	12.2
Net change in short-term borrowing	(4.1)	1.7	(5.8)	2.3	0.7	1.6	0.8
Dividends paid	(19.9)	(19.1)	(0.8)	(19.9)	(19.1)	(0.8)	(19.1)
Other changes	(0.2)	(0.1)	(0.1)	(0.4)	(0.1)	(0.3)	5.2
Cash flows provided by (used in) financing activities	(28.3)	(17.7)	(10.6)	(22.4)	(21.4)	(1.0)	(0.9)
Net increase (decrease) in cash flows	4.2	(10.8)	14.9	21.8	(9.4)	31.2	3.4

Cash flows used in investing activities amounted to NOK 0.2 billion in the second quarter of 2011, compared to NOK 16.5 billion in the second quarter of 2010. The NOK 16.2 billion decrease stems mainly from higher proceeds from sale of assets of NOK 15.9 billion in the second quarter of 2011 compared to the same period last year, mainly related to payments from the sale of interests in the Peregrino oil filed in Brazil.

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 19.8 billion in the second quarter of 2011, compared to NOK 18.7 billion in the second quarter of 2010.

Gross investments — (in NOK billion)	Second quarter — 2011	2010	Change	First half — 2011	2010	Change	Full year — 2010
- D&P Norway	9.6	8.4	14%	18.5	15.7	18%	31.9
- D&P International	8.3	8.4	(1%)	18.0	21.0	(14%)	40.4
- Marketing, Processing & Renewable Energy	1.1	1.2	(2%)	2.3	2.3	0%	6.3
- Fuel & Retail	0.3	0.3	26%	0.5	0.3	52%	0.8
- Other	0.4	0.4	12%	2.2	0.6	>100%	4.9
Gross investments	19.8	18.7	6%	41.5	39.9	4%	84.4

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

Reconciliation of cash flow to investments	Second quarter		First half		Full year
(in NOK billion)	2011	2010	2011	2010	2010
- Cash flows to investments	0.2	16.5	9.4	36.1	76.5
- Proceeds from sale of assets	18.0	2.1	29.4	0.9	1.9
- Financial lease	0.0	0.2	1.8	1.4	1.5
- Other changes	1.6	(0.1)	1.0	1.5	4.5
Gross investments	19.8	18.7	41.5	39.9	84.4

Cash flows provided by (used in) financing activities in the second quarter of 2011 amounted to NOK 28.3 billion, compared to NOK 17.7 billion in the second quarter of 2010. The NOK 10.6 billion change was mainly related to repayments of non-current bonds of NOK 3.9 billion and dividends paid of NOK 0.8 billion, partly offset by change in net current loans of NOK 5.8 billion.

Gross financial liabilities (non-current and current financial liabilities) were NOK 109.0 billion at 30 June 2011, compared to NOK 107.9 billion at 30 June 2010. The NOK 1.2 billion increase was mainly due to an increase in non-current bonds, bank loans and finance lease liabilities of NOK 0.9 billion.

Net financial liabilities [10] were NOK 38.2 billion at 30 June 2011, compared to NOK 85.3 billion at 30 June 2010. The decrease of NOK 47.1 billion was mainly related to an increase in cash and cash equivalents and current financial investments of NOK 51.2 billion, partly offset by an increase in gross financial liabilities of NOK 1.2 billion and a change in adjustments to net interest-bearing debt of NOK 2.9 billion.

The net debt to capital employed ratio [1] was 13.6% at 30 June 2011, compared to 29.2% at 30 June 2010. The 15.6% decrease was mainly related to a decrease in net financial liabilities of NOK 20.9 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 78.1 billion at 30 June 2011, compared to NOK 27.0 at 30 June 2010. The NOK 51.2 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 50.4 billion at 30 June 2011, compared to NOK 19.1 billion at 30 June 2010. Cash and cash equivalents include restricted cash of NOK 5.4 billion at 30 June 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. Current financial investments, which are part of our cash management, amounted to NOK 27.7 billion at 30 June 2011, compared to NOK 7.9 billion at 30 June 2010.

Current items (total current assets less total current liabilities) increased by NOK 45.9 billion from negative NOK 4.8 billion at 30 June 2010 to positive NOK 41.1 billion at 30 June 2011. The change was due to increases in current receivables such as inventories of NOK 3.9 billion, accounts receivables of NOK 10.2 billion, financial investments of NOK 19.8 billion, cash and cash equivalents of NOK 31.3 billion and decrease in financial derivatives current liabilities partly offset by increases in current liabilities such as current taxes payable of NOK 7.0 billion, accounts payable of NOK 3.6 billion and other current liabilities of NOK 12.6 billion.

First half 2011

Cash flows provided by operating activities amounted to NOK 53.6 billion in the first half of 2011, compared to NOK 48.1 billion in the first half of 2010. The NOK 5.6 increase was mainly due to NOK 28.8 billion increased cash flow from underlying operations and positive changes in working capital of NOK 6.8 billion, partly offset by NOK 18.3 billion negative changes in financial investments and derivatives, negative other changes contributing NOK 6.7 billion and lower taxed paid of NOK 5.1 billion.

Cash flows used in investing activities amounted to NOK 9.4 billion in the first half of 2011, compared to NOK 36.1 billion in the first half of 2010. The NOK 26.6 billion decrease stems mainly from NOK 28.5 billion higher proceeds from sales, mainly related to payments from the sale of interests in the Kai Kos Dehseh oil sands in Canada and the sale of interests in the Peregrino oil filed in Brazil.

Gross investments amounted to NOK 41.5 billion in the first half of 2011 compared to NOK 39.9 billion in the first half of 2010.

Cash flow provided by (used in) financing activities in the first half of 2011 amounted to NOK 22.4 billion, compared to NOK 21.4 billion for the first half of 2010. The NOK 1.0 billion change was mainly related to increased repayments of non-current bonds of NOK 1.4 billion and increased dividends paid of NOK 0.8 billion, partly offset by change in net current loans of NOK 1.6 billion.

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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 measures may be considered non-GAAP financial measures:

• Adjusted earnings
• Adjusted earnings after tax
• Adjusted production cost
• Net debt to capital employed ratio

Adjusted earnings begins with net operating income and adjusts for certain items affecting the income for the period in order to separate out effects that management considers may not to be specifically related to Statoil's underlying operational performance in the individual reporting period. Management considers adjusted earnings to be a supplemental measure to Statoil's IFRS measures that provides an indication of Statoil's underlying operational performance in the period and facilitates a better understanding of operational trends between the periods. Adjusted earnings exclude the following items:

• Adjustments are made for changes in the unrealised fair value of derivatives not accounted for as hedges. Statoil uses derivatives to manage certain exposures to fluctuations in foreign currency, interest rates or commodity prices. However, when hedge accounting is not applied the unrealised fair value adjustment for derivatives is not matched by a similar adjustment for the exposure being managed. As a result, only the realised gains and losses on derivatives are reflected in adjusted earnings. The gains and losses on derivatives are then reflected in the period in which they impact our cash flows and generally match the associated cash flow of the exposure being managed.
• Periodisation of inventory hedging effect : The commercial storage is hedged in the paper market. The commercial storage is accounted for by using the lowest of cost and market price. If market prices increase over cost price, there will be a loss in the IFRS profit & loss statement since the derivatives always reflects changes in the market price. An adjustment is made to reflect the unrealised market value on the commercial storage. As a result, loss on derivatives is matched by a similar adjustment for the exposure being managed. If market prices decrease under cost price, the write-down and the derivative effect in the IFRS profit & loss statement will offset each and no adjustment is done.
• Over/underlift is accounted for using the sales method and therefore revenues are reflected in the period the product is sold rather than in the period it is produced. The over/underlift position depends on a number of factors related to our lifting programme and the way it corresponds to our entitlement share of production. The effect on income for the period is therefore adjusted, to show earnings based upon the production for the period which management believes better reflects operational performance.
• Operational storage includes inventories held in the refining and retail operations which are accounted for at the lower of cost and net realisable value. An adjustment is made in the cost of goods sold for changes in the value of inventories during the period held (holding gains or losses) to align to the product pricing.
• Impairment and reversal of impairment are excluded from adjusted earnings since they affect the economics of an asset for the lifetime of that asset; not only the period in which it is impaired or the impairment is reversed. (Impairment and reversal of impairment can impact both the Exploration expenses and the Depreciation, amortisation and impairment line items.)
• Gain or loss from sale of assets is eliminated from the measure since the gain or loss does not give an indication of future performance or periodic performance; such a gain or loss is related to the cumulative value creation from the time the asset is acquired until it is sold.
• Other items of income and expense are also adjusted when the impacts on income in the period are not reflective of Statoil's underlying operational performance in the reporting period. Such items may be unusual or infrequent transactions but they may also include transactions that are significant which would not necessarily qualify as either unusual or infrequent. Other items can include transactions such as provisions related to reorganisation, early retirement, etc.

The measure adjusted earnings after tax excludes net financial items (the principle line items impacted by the change in functional currency) and the associated tax effects on net financial items. It is based on adjusted earnings less the tax effects on all elements included in adjusted earnings (or calculated tax on operating income and on each of the adjusting items using an estimated marginal tax rate). Management considers adjusted earnings after tax, which reflects a normalised tax charge associated with its operational performance excluding the impact of financing, to be a supplemental measure to Statoil's net income. Certain net USD denominated financial positions are held by group companies that have a USD functional currency that is different from the currency in which the taxable income is measured. As currency exchange rates change between periods, the basis for measuring net financial items for IFRS will change disproportionally with taxable income which includes exchange gains and losses from translating the net USD denominated financial positions into the currency of the applicable tax return. Therefore, effective tax rate may be significantly higher or lower than the statutory tax rate for any given period.

Management considers that adjusted earnings after tax provides a better indication of the taxes associated with underlying operational performance in the period (excluding financing), and therefore better facilitates a comparison between periods. However, the adjusted taxes included in adjusted earnings after tax should not be considered indicative of the amount of current or total tax expense (or taxes payable) for the period.

Adjusted earnings and adjusted earnings after tax should be considered additional measures rather than substitutes for net operating income and net income, which are the most directly comparable IFRS measures. There are material limitations associated with the use of adjusted earnings and adjusted earnings after tax compared with the IFRS measures since they do not include all the items of revenues/gains or expenses/losses of Statoil which are needed to evaluate its profitably on an overall basis. Adjusted earnings and adjusted earnings after tax are only intended to be indicative of the underlying developments in trends of our on-going operations for the production, manufacturing and marketing of our products and exclude pre and post tax impacts of net financial items. We reflect such underlying development in our operations by eliminating the effects of certain items that may not be directly associated with the period's operations or financing. However, for that reason, adjusted earnings and adjusted earnings after tax are not complete measures of profitability. The measures should therefore not be used in isolation.

Adjusted earnings equal the sum of net operating income less all applicable adjustments. Adjusted earnings after tax equals the sum of net operating income less income tax in business areas and adjusted to operating income taking the applicable marginal tax into consideration. See the tables in the following section for details.

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 to production cost	For the three months ended — 2011				2010
(in NOK billion)	30-Jun	31-Mar	31-Dec	30-Sep	30-Jun
Operating expenses, Statoil Group	14.1	13.5	13.5	12.8	15.6
Deductions of costs not relevant to production cost calculation
1) Business Areas non-upstream	6.2	6.2	5.5	5.0	7.9
Total operating expenses upstream	8.0	7.3	8.0	7.8	7.7
2) Operation over/underlift	(0.8)	(0.7)	0.6	0.0	(0.4)
3) Transportation pipeline/vessel upstream	1.2	1.3	1.1	1.0	1.1
4) Miscellaneous items	0.7	0.2	(0.5)	0.2	0.4
Total operating expenses upstream excl. over/underlift & transportation	6.8	6.6	6.8	6.5	6.6
Total production costs last 12 months	26.6	26.4	26.3	26.3	26.2
5) Grane gas purchase	(0.0)	0.1	0.1	0.2	0.2
6) Restructuring costs from the merger	0.0	0.0	(0.4)	0.0	0.0
7) Change in ownership interest	(0.0)	0.1	(0.0)	0.0	0.0
Total operating expenses upstream for adjusted cost per barrel calculation	6.9	6.3	7.1	6.3	6.3

Production cost summary	Entitlement production — 30.Jun		Equity production — 30.Jun
(in NOK per boe)	2011	2010	2011	2010
Calculated production cost	46.2	40.1	41.2	36.3
Calculated production cost, excluding reversals of restructuring cost arising from the merger	46.9	40.5	41.9	36.7
Calculated production cost, excluding reversals of restructuring costs and gas injection cost	46.0	38.8	41.1	35.2

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.

Calculation of capital employed and net debt to capital employed ratio	30 June		Full year
(in NOK billion, except percentages)	2011	2010	2010
Total shareholders' equity	235.7	205.6	219.5
Non-controlling interests	6.9	1.3	6.9
Total equity and minority interest (A)	242.6	207.0	226.4
Short-term debt	12.2	12.0	11.7
Long-term debt	96.8	95.9	99.8
Gross interest-bearing debt	109.0	107.9	111.5
Cash and cash equivalents	50.4	18.8	30.3
Current financial investments	27.7	7.9	11.5
Cash and cash equivalents and current financial investment	78.1	26.7	41.8
Net debt before adjustments (B1)	30.9	81.1	69.7
Other interest-bearing elements	9.1	6.4	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)	38.2	85.3	73.8
Normalisation for cash-build up before tax payment (50% of tax payment)	0.0	0.0	0.0
Net interest-bearing debt (B3)	38.2	85.3	73.8
Calculation of capital employed:
Capital employed before adjustments to net interest-bearing debt (A+B1)	273.5	288.1	296.1
Capital employed before normalisation for cash build up for tax payment (A+B2)	280.7	292.3	300.2
Capital employed (A+B3)	280.7	292.3	300.2
Calculated net debt to capital employed:
Net debt to capital employed before adjustments (B1/(A+B1)	11.3%	28.2%	23.5%
Net debt to capital employed before normalisation for tax payment (B2/(A+B2)	13.6%	29.2%	24.6%
Net debt to capital employed (B3/(A+B3)	13.6%	29.2%	24.6%

Cash flow from underlying operation is reconciled to income before tax in the table below:

Cash flows from underlying operations — (in NOK billion)	Second quarter — 2011	2010	First half — 2011	2010
Income before tax	61.2	25.8	111.5	63.7
Adjustments:
Depreciation, amortization, impairment	11.2	14.3	22.3	25.5
Exploration expenditures written off	0.9	1.0	1.7	2.0
(Gains) losses on foreign currency trans	2.1	0.0	3.0	0.3
(Gains) losses on sales of ass, oth item	(12.5)	0.5	(18.3)	(0.2)
Cash flows from underlying operations	63.0	41.7	120.2	91.4

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Reconciliation of adjusted earnings to net operating income

The table specifies the adjustments made to each of the profit and loss line item included in the net operating income subtotal.

Statoil group

Items impacting net operating income — (in NOK billion)	Second quarter — 2011	2010	Change	First half — 2011	2010	Change
Net operating income	61.0	26.6	>100%	111.8	66.2	69%
Total revenues and other income	(14.8)	3.7	<(100%)	(15.0)	2.0	<(100%)
Change in Fair Value	(3.7)	2.4	<(100%)	(3.8)	2.0	<(100%)
Inventory hedging effects	(2.5)	(0.9)	>100%	0.1	(0.9)	(115%)
Impairment	0.0	0.2	(100%)	0.0	0.2	(100%)
Reversal of Impairment	0.0	0.0	(100%)	0.0	(0.2)	(100%)
Over/Underlift	2.8	1.1	>100%	5.2	(0.0)	<(100%)
Other Adjustments	(0.8)	0.0	<(100%)	(0.8)	0.0	<(100%)
Gain/loss on sale of assets	(8.8)	0.0	<(100%)	(14.4)	(0.3)	>100%
Provisions	0.0	0.7	(100%)	0.0	0.7	(100%)
Eliminations	(1.7)	0.2	<(100%)	(1.4)	0.4	<(100%)
Purchase net of inventory variation	0.0	0.1	(100%)	(0.8)	(0.4)	100%
Operational Storage effects	0.0	0.1	(100%)	(0.8)	(0.4)	100%
Operating expenses	(0.4)	1.6	<(100%)	(1.4)	2.8	<(100%)
Over/Underlift	(0.6)	(0.4)	<(100%)	(1.5)	0.2	<(100%)
Operational Storage effects	0.0	0.0	(100%)	0.0	0.0
Gain/loss on sale of assets	(0.0)	0.0	<(100%)	0.1	0.1	>100%
Cost accrual changes	0.0	2.2	(100%)	0.0	2.7	(100%)
Eliminations	0.2	(0.2)	<(100%)	0.0	(0.2)	(100%)
Selling, general and administrative expenses	(0.0)	1.7	(100%)	(0.7)	1.7	<(100%)
Provisions	(0.0)	0.0		(0.7)	0.0
Cost accrual changes	0.0	1.7	(100%)	0.0	1.7	(100%)
Depreciation, amortisation and impairment	(0.1)	2.9	<(100%)	(1.0)	2.9	<(100%)
Impairment net of reversal	(0.1)	2.9	<(100%)	(1.0)	2.9	<(100%)
Exploration expenses	(2.1)	(0.1)	>100%	(2.1)	0.2	<(100%)
Impairment net of reversal	(2.1)	(0.1)	>100%	(2.1)	0.2	<(100%)
Sum of adjustments	(17.4)	9.8	<(100%)	(20.9)	9.1	<(100%)
Adjusted earnings	43.6	36.5	20%	90.8	75.3	21%

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Reconciliation of adjusted earnings after tax to net income

Reconciliation of adjusted earnings after tax to net income — (in NOK billion)		Second quarter — 2011	2010	First half — 2011	2010
Net operating income (NOI)	A	61.0	26.6	111.8	66.2
Tax on NOI	B	33.6	24.2	67.3	51.6
NOI after tax	C = A-B	27.4	2.4	44.5	14.6
Adjustments	D	(17.4)	(9.8)	(20.9)	9.1
Tax on adjustments	E	(2.8)	1.7	(1.1)	0.8
Adjusted earnings after tax	F = C+D-E	12.8	10.6	24.7	22.9
Net financial items	G	0.2	(0.8)	(0.3)	(2.5)
Tax on net financial items	H	0.6	(1.4)	1.1	(2.2)
Net income	I = C+G-H	27.1	3.1	43.1	14.2

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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 first 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. For a definition of non-GAAP financial measures, see report section "Use and reconciliation of non-GAAP 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 14.0 mboe per day in the second quarter of 2011 and 13.2 mboe in the first quarter of 2010 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.
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 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. These are non-GAAP figures. See report section "Use and reconciliation of non-GAAP measures" for details.
12. 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.
13. The production guidance for 2012 reflects our estimates of proved reserves calculated in accordance with US Securities and Exchange Commission (SEC) guidelines and additional production from other reserves not included in proved reserves estimates.
14. This is non-GAAP figure. See report section "Use and reconciliation of non-GAAP measures" for details.

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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", "anticipate", "believe", "continue", "could", "estimate", "expect", "intend", "likely", "may", "outlook", "plan", "schedule", "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; research and development initiatives and strategy; 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 Eagle Ford joint venture, and the North Makassar Strait Production Sharing Contract; completion and results of acquisitions, disposals and other contractual arrangements; reserve information; reserve replacement ratios; recovery factors and levels; future margins; projected returns; future levels 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 and volatility; oil, gas, alternative fuel and energy supply and demand; natural gas contract prices; 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; our goal of safe and efficient operations; 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, impact or timing of HSE regulations; HSE goals and 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; future impact of legal proceedings; plans for capital distribution and amounts of dividends 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; 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, particularly in the renewable energy sector; 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 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 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.

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INTERIM FINANCIAL STATEMENTS

2nd quarter 2011

CONSOLIDATED STATEMENT OF INCOME	For the three months		For the six months		For the year ended
	ended 30 June		ended 30 June		31 December
	2011	2010	2011	2010	2010
(in NOK million)	(unaudited)	(unaudited)	(unaudited)	(unaudited)
REVENUES AND OTHER INCOME
Revenues	159,543	129,260	305,263	257,983	526,950
Net income from associated companies	444	293	879	708	1,168
Other income	8,778	(27)	14,518	426	1,797
Total revenues and other income	168,765	129,526	320,660	259,117	529,915
OPERATING EXPENSES
Purchases [net of inventory variation]	(78,625)	(64,904)	(148,706)	(122,332)	(257,436)
Operating expenses	(14,147)	(15,587)	(27,628)	(31,367)	(57,670)
Selling, general and administrative expenses	(3,519)	(4,295)	(6,414)	(6,902)	(11,081)
Depreciation, amortisation and net impairment losses	(11,240)	(14,554)	(22,298)	(25,512)	(50,694)
Exploration expenses	(206)	(3,571)	(3,821)	(6,793)	(15,773)
Total operating expenses	(107,737)	(102,911)	(208,867)	(192,906)	(392,654)
Net operating income	61,028	26,615	111,793	66,211	137,261
FINANCIAL ITEMS
Net foreign exchange gains (losses)	(1,450)	(3,291)	(819)	(5,826)	(1,826)
Interest income and other financial items	948	405	2,367	1,282	3,113
Interest and other finance expenses	717	2,090	(1,840)	2,054	(1,722)
Net financial items	215	(796)	(292)	(2,490)	(435)
Income before tax	61,243	25,819	111,501	63,721	136,826
Income tax	(34,190)	(22,762)	(68,390)	(49,527)	(99,179)
Net income	27,053	3,057	43,111	14,194	37,647
Attributable to:
Equity holders of the company	26,922	3,623	42,900	14,732	38,082
Non-controlling interests	131	(566)	211	(538)	(435)
	27,053	3,057	43,111	14,194	37,647
Earnings per share for income attributable to equity holders of the company - basic and diluted	8.44	1.14	13.45	4.63	11.94
Dividend declared and paid per ordinary share	6.25	6.00	6.25	6.00	6.00
Weighted average number of ordinary shares outstanding	3,182,596,063	3,182,704,054	3,182,780,868	3,182,943,356	3,182,574,787
See notes to the Interim financial statements.

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME	For the three months ended 30 June		For the six months ended 30 June		For the year ended 31 December
	2011	2010	2011	2010	2010
(in NOK million)	(unaudited)	(unaudited)	(unaudited)	(unaudited)
Net income	27,053	3,057	43,111	14,194	37,647
Foreign currency translation differences	(747)	7,309	(6,546)	11,009	2,039
Actuarial gains (losses) on employee retirement benefit plans	56	104	(31)	888	(33)
Change in fair value of available for sale financial assets	(94)	565	(198)	565	209
Income tax effect on income and expense recognised directly in OCI	(4)	(121)	20	(762)	16
Other comprehensive income	(789)	7,857	(6,755)	11,700	2,231
Total comprehensive income	26,264	10,914	36,356	25,894	39,878
Attributable to:
Equity holders of the parent company	26,133	11,480	36,145	26,432	40,313
Non-controlling interests	131	(566)	211	(538)	(435)
	26,264	10,914	36,356	25,894	39,878
See notes to the Interim financial statements.

CONSOLIDATED BALANCE SHEET	At 30 June	At 31 December	At 30 June
	2011	2010	2010
(in NOK million)	(unaudited)		(unaudited)
ASSETS
Non-current assets
Property, plant and equipment	352,896	351,578	355,438
Intangible assets	47,940	43,171	64,617
Investments in associated companies	8,122	8,997	10.113
Deferred tax assets	741	1,878	1,813
Pension assets	7,465	5,265	5,544
Derivative financial instruments	21,992	20,563	21,496
Financial investments	15,359	15,357	14,639
Prepayments and financial receivables	4,080	3,945	4,696
Total non-current assets	458,595	450,754	478,356
Current assets
Inventories	26,570	23,627	22,629
Trade and other receivables	66,422	74,810	63,883
Current tax receivables	1,534	1,076	568
Derivative financial instruments	4,161	6,074	4,733
Financial investments	27,746	11,509	7,925
Cash and cash equivalents	50,386	30,521	19,057
Total current assets	176,819	147,617	118,795
Assets classified as held for sale	23,266	44,890	15,156
TOTAL ASSETS	658,680	643,261	612,307
See notes to the Interim financial statements.

CONSOLIDATED BALANCE SHEET	At 30 June	At 31 December	At 30 June
	2011	2010	2010
(in NOK million)	(unaudited)		(unaudited)
EQUITY AND LIABILITIES
Equity
Share capital	7,972	7,972	7,972
Treasury shares	(16)	(18)	(14)
Additional paid-in capital	41,627	41,789	41,622
Additional paid-in capital related to treasury shares	(836)	(952)	(820)
Retained earnings	187,956	164,935	141,731
Other reserves	(928)	5,816	15,142
Statoil shareholders' equity	235,775	219,542	205,633
Non-controlling interests	6,851	6,853	1,332
Total equity	242,626	226,395	206,965
Non-current liabilities
Bonds, bank loans and finance lease liabilities	96,798	99,797	95,898
Deferred tax liabilities	66,956	78,065	74,656
Pension liabilities	22,282	22,112	21,335
Asset retirement obligations, other provisions and other liabilities	69,852	67,978	68,742
Derivative financial instruments	1,199	3,386	5,922
Total non-current liabilities	257,087	271,338	266,553
Current liabilities
Trade and other payables	68,084	73,720	62,037
Current tax payable	61,201	46,694	54,245
Bonds, bank loans, commercial papers and collateral liabilities	12,242	11,730	11,958
Derivative financial instruments	3,199	4,161	6,433
Total current liabilities	144,726	136,305	134,673
Liabilities directly associated with the assets classified as held for sale	14,241	9,223	4,116
Total liabilities	416,054	416,866	405,342
TOTAL EQUITY AND LIABILITIES	658,680	643,261	612,307

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					42,900			42,900	211	43,111
Other comprehensive income					(11)	(198)	(6,546)	(6,755)		(6,755)
Dividend paid					(19,891)			(19,891)		(19,891)
Other equity transactions		2	(162)	116	23			(21)	(213)	(234)
At 30 June 2011	7,972	(16)	41,627	(836)	187,956	11	(939)	235,775	6,851	242,626
						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					14,732			14,732	(538)	14,194
Other comprehensive income					126	565	11,009	11,700		11,700
Dividend paid					(19,095)			(19,095)		(19,095)
Other equity transactions		1	(110)	27	59			(23)	71	48
At 30 June 2010	7,972	(14)	41,622	(820)	141,731	565	14,577	205,633	1,332	206,965
See notes to the Interim financial statements.

CONSOLIDATED STATEMENT OF CASH FLOWS
	For the six months ended 30 June			For the year ended 31 December
	2011		2010	2010
(in NOK million)	(unaudited)		(unaudited)
OPERATING ACTIVITIES
Income before tax	111,501		63,721	136,826
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortisation and net impairment losses	22,298		25,512	50,694
Exploration expenditures written off	1,671		2,049	2,916
(Gains) losses on foreign currency transactions and balances	2,974		282	1,539
(Gains) losses on sales of assets and other items	(18,275)		(213)	(1,104)
Changes in working capital (other than cash and cash equivalents):
(Increase) decrease in inventories	(2,943)		(2,433)	(3,431)
(Increase) decrease in trade and other receivables	8,056		(5,585)	(16,705)
Increase (decrease) in trade and other payables	(5,969)		334	9,521
(Increase) decrease in current financial investments	(16,237)		260	(4,487)
(Increase) decrease in net derivative financial instruments	(2,665)		(903)	(594)
Taxes paid	(44,847)		(39,698)	(92,266)
(Increase) decrease in non-current items related to operating activities	(1,935)		4,747	(2,156)
Cash flows provided by operating activities	53,629		48,073	80,753
INVESTING ACTIVITIES
Additions to property, plant and equipment	(35,989)		(31,609)	(68,070)
Exploration expenditures capitalised	(3,147)		(2,655)	(3,941)
Additions in other intangibles	(266)		(4,809)	(7,628)
Change in non-current loans granted and other non-current items	613		151	(2,855)
Proceeds from sale of assets	29,363	*	858	1,909
Prepayment received related to the held for sale transactions	0		1,995	4,124
Cash flows used in investing activities	(9,426)		(36,069)	(76,461)
FINANCING ACTIVITIES
New non-current bonds	7		30	15,562
Repayment of non-current bonds	(4,437)		(2,999)	(3,324)
Payment (to)/from non-controlling interests	(213)		71	5,489	**
Dividend paid	(19,891)		(19,095)	(19,095)
Treasury shares purchased	(199)		(161)	(294)
Net current loans and other ***	2,314		717	751
Cash flows provided by (used in) financing activities	(22,419)		(21,437)	(911)
Net increase (decrease) in cash and cash equivalents	21,784		(9,433)	3,381
Effect of exchange rate changes on cash and cash equivalents	(1,793)		2,894	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***	49,108		18,747	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 1,278 million at 30 June 2011. Previous periods have been adjusted accordingly. See notes to the Interim financial statements.

Table of Contents

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 second quarter 2011 were authorised for issue by the board of directors on 27 July 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 and 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 half of 2011.

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 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 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 these 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 policies compared to the annual financial statements for 2010.

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 are 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.

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 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.

Table of Contents

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 shareholder's equity or non-controlling interests.

CONSOLIDATED STATEMENT OF INCOME	For the three moths ended	For the year ended	For the three moths ended	For the three moths ended	For the three moths ended	For the three moths 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 moths ended	For the year ended	For the three moths ended	For the three moths ended	For the three moths ended	For the three moths 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 interest	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

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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 Exploration and Production International); Development and Production International (DPI; previously Exploration and Production International); 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 June 2011
Revenues and other income - third party	2,638	12,346	134,710	18,248	379	0	168,321
Revenues and other income - inter-segment	47,774	10,065	12,418	850	0	(71,107)	0
Net income (loss) from associated companies	(5)	479	100	1	(131)	0	444
Total revenues and other income	50,407	22,890	147,228	19,099	248	(71,107)	168,765
Net operating income (loss)	37,180	17,254	4,787	543	(234)	1,498	61,028
Additions to Intangible assets and Property, plant and equipment *	9,613	8,851	1,035	331	407	0	20,237
Three months ended 30 June 2010
Revenues and other income - third party	1,824	1,368	110,240	15,872	139	(210)	129,233
Revenues and other income - inter-segment	41,155	9,670	10,177	467	520	(61,989)	0
Net income (loss) from associated companies	10	231	58	1	(7)	0	293
Total revenues and other income	42,989	11,269	120,475	16,340	652	(62,199)	129,526
Net operating income (loss)	29,624	2,457	(6,510)	483	579	(18)	26,615
Additions to Intangible assets and Property, plant and equipment *	8,450	8,396	1,184	263	216	0	18,509

(in NOK million)	Development and Production Norway	Development and Production International	Marketing, Processing and Renewable Energy	Fuel and Retail	Other	Eliminations	Total
Six months ended 30 June 2011
Revenues and other income - third party	3,552	20,342	260,787	34,578	522	0	319,781
Revenues and other income - inter-segment	99,234	20,546	23,511	1,464	0	(144,755)	0
Net income (loss) from associated companies	10	685	127	1	56	0	879
Total revenues and other income	102,796	41,573	284,425	36,043	578	(144,755)	320,660
Net operating income (loss)	75,782	27,304	7,013	892	(588)	1,390	111,793
Additions to Intangible assets and Property, plant and equipment *	18,483	18,015	1,859	458	2,019	0	40,834
Six months ended 30 June 2010
Revenues and other income - third party	2,118	3,434	222,012	30,754	303	(212)	258,409
Revenues and other income - inter-segment	82,963	21,149	19,026	846	991	(124,975)	0
Net income (loss) from associated companies	28	542	158	1	(21)	0	708
Total revenues and other income	85,109	25,125	241,196	31,601	1,273	(125,187)	259,117
Net operating income (loss)	58,230	7,308	(733)	1,163	432	(189)	66,211
Additions to Intangible assets and Property, plant and equipment *	15,657	21,027	2,329	301	402	0	39,716
*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 a gain of NOK 5.6 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 impairment loss consisted 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 . The reversal of impairment losses have been presented as Exploration expenses , NOK 2.9 billion, and Depreciation, amortisation and net impairment losses , NOK 0.5 billion, on the basis of their nature as intangible assets (exploration assets) and property, plant and equipment (development and producing assets), respectively.

In the MPR segment a reversal of an earlier recognised impairment loss related to an intangible asset and a reversal of an onerous contract provision were recognised as reductions of operating expenses with NOK 0.9 billion and NOK 0.7 billion respectively in the first quarter of 2011. These reversals are related to the impact of the pricing reference inherent 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.

In the MPR segment an impairment loss of NOK 2.9 billion was recognised in the second quarter of 2010 related to a refinery.

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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 ending 30 June 2011 this amounted to fair value gains of NOK 1.6 billion (NOK 2.9 billion for the three months ending 30 June 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 5.4 billion at 30 June 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.

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5 INCOME TAX

	For the three months — ended 30 June		For the six months — ended 30 June		For the year ended — 31 December
(in NOK million)	2011	2010	2011	2010	2010
Income before tax	61,243	25,819	111,501	63,721	136,826
Income tax	(34,190)	(22,762)	(68,390)	(49,527)	(99,179)
Equivalent to a tax rate of	55.8%	88.2%	61.3%	77.7%	72.5%

The tax rates in the second quarter of 2011 and for the first half of 2011 were primarily influenced by capital gains and reversal of impairments in entities with lower than average tax rate and relatively low income from the Norwegian Continental Shelf which is subject to higher than average tax rate.

The tax rates in the second quarter of 2010 and for the first half of 2010 were primarily influenced by operating losses and impairment losses in entities which are subject to lower than average tax rates. 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 deductable, but do not impact the income statement of these entities.

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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. The net carrying amount of the Kai Kos Dehseh assets at the closing was NOK 7.6 billion (40%), including accumulated currency translation differences. As such, the gain of NOK 5.6 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.

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.

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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 and an element intended to reflect changes in the long term interest rate levels, if any, in the period between the economic date and the date for final closing of the transaction. 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 June 2011, the net carrying amount of these Gassled assets was NOK 9 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 second 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.

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 of by approximately NOK 82 billion, estimated as at second 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)	30 June 2011	31 December 2010
Property, plant and equipment	23,224	32,515
Intangible assets	2	12,375
Investments in associated companies	40	0
Total assets classified as held for sale	23,266	44,890
Bonds, bank loans and finance lease liabilities	0	7,796
Deferred tax liabilities	14,241	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	14,241	9,223

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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	39,159	3,993
Transfers	3,380	(3,380)
Disposals	(17,433)	(5,556)
Transferred to assets classified as held for sale**	(23,224)	(2)
Expensed exploration expenditures previously capitalised	-	(738)
Depreciation, amortisation and net impairment losses	(21,159)	895
Effect of foreign currency translation adjustments	(11,920)	(2,818)
Balance at 30 June 2011	352,896	47,940

• Please see note 2 Accounting policy change jointly controlled entities for restatement of Consolidated balance sheets. ** 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 June — 2011	2010	For the six months ended 30 June — 2011	2010
Depreciation, amortisation and net impairment losses	313	3,230	332	3,040
Exploration expenses	853	1,123	933	1,396
Impairment losses	1,166	4,353	1,265	4,436
Depreciation, amortisation and net impairment losses	(458)	(90)	(1,326)	(90)
Exploration expenses	(2,967)	(1,169)	(2,967)	(1,169)
Reversal of impairment losses	(3,425)	(1,259)	(4,293)	(1,259)
Net impairment losses	(2,259)	2,860	(3,028)	3,133

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9 PROVISIONS, COMMITMENTS, CONTINGENT LIABILITIES AND CONTINGENT ASSETS

During the normal course of its business Statoil is involved in legal proceedings, and several 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 the financial position, results of operations or cash flows will be materially affected by the resolution of these legal proceedings.

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HSE ACCOUNTING

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STATEMENT ON FINANCIAL COMPLIANCE

Board and management confirmation

Today, the Board of Directors, the Chief Executive Officer and the Chief Financial Officer reviewed and approved the Statoil ASA consolidated financial statements as of 30 June 2011.

To the best of our knowledge, we confirm that:

• the Statoil ASA consolidated financial statements for the first half of 2011 have been prepared in accordance with IFRSs and IFRICs as adopted by the European Union (EU), IFRSs as issued by the International Accounting Standards Board (IASB) and additional Norwegian disclosure requirements in the Norwegian Accounting Act, and that
• the information presented in the financial statements gives a true and fair view of the company's and the group's assets, liabilities, financial position and results for the period viewed in their entirety, and that
• the information presented in the financial statements gives a true and fair view of the development, performance, financial position, principle risks and uncertanties of the group.

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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.

Dated: July 28, 2011 By: ___/s/ Torgrim Reitan Name: Torgrim Reitan Title: Chief Financial Officer