425

Filed pursuant to Rule 425
of the Securities Act of 1933
Filer: Statoil ASA
Filer’s Exchange Act File No.: 1-15200
Norsk Hydro’s Exchange Act File No.: 1-9159

This document does not constitute an offer to exchange or sell or an offer to exchange or buy any securities.

An offer of securities in the United States pursuant to a business combination transaction will only be made through a prospectus which is part of an effective registration statement filed with the US Securities and Exchange Commission. Norsk Hydro shareholders who are US persons or are located in the United States are advised to read the registration statement when and if it is declared effective by the US Securities and Exchange Commission because it will contain important information relating to the proposed transaction. You will be able to inspect and copy the registration statement relating to the proposed transaction and documents incorporated by reference at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Statoil’s SEC filings are also available to the public at the SEC’s web site at http://www.sec.gov. In addition, Statoil will make the effective registration statement available for free to Norsk Hydro’s shareholders in the United States.

Form 6-K

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Report of Foreign Private Issuer

Pursuant to Rules 13a-16 or 15d-16 of
the Securities Exchange Act of 1934

Dated February 12, 2007

STATOIL ASA
(Exact name of registrant as specified in its charter)

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 Form 20-F or Form 40-F.

Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.

If "Yes" is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b): 82______________

This report on Form 6-K contains a press release issued by Statoil ASA on February 12, 2007, entitled "Best annual income ever".

Disclaimer:

This document does not constitute an offer to exchange or sell or an offer to exchange or buy any securities.

An offer of securities in the United States pursuant to a business combination transaction will only be made through a prospectus which is part of an effective registration statement filed with the US Securities and Exchange Commission. Norsk Hydro shareholders who are US persons or are located in the United States are advised to read the registration statement when and if it is declared effective by the US Securities and Exchange Commission because it will contain important information relating to the proposed transaction. You will be able to inspect and copy the registration statement relating to the proposed transaction and documents incorporated by reference at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Statoil’s SEC filings are also available to the public at the SEC’s web site at http://www.sec.gov. In addition, Statoil will make the effective registration statement available for free to Norsk Hydro’s shareholders in the United States.

BEST ANNUAL INCOME EVER

The Statoil group had a net income of NOK 40.6 billion in 2006, compared to NOK 30.7 billion in 2005. Net income for the fourth quarter of 2006 was NOK 12.0 billion, compared to NOK 8.5 billion for the same period of 2005. The increase in net income of NOK 3.5 billion from the fourth quarter of 2005 to the fourth quarter of 2006 was mainly due to higher financial income and lower income taxes.

”The annual income for 2006 is the best ever for Statoil. We maintain strong earnings and competitive returns, despite temporarily lower production overall,” says chief executive Helge Lund.

“Through the acquisition of two deepwater portfolios in the Gulf of Mexico (GoM) from Anadarko and Plains and the subsequent divestment of the retail operation in Ireland we have further upgraded our portfolio,” states the CEO.

“Both the fourth quarter and the year as a whole have been characterised by high exploration activity, both on the Norwegian continental shelf (NCS) and internationally. At the same time we have also secured new exploration acreage, put new fields on stream and launched new field development plans that support the group’s long-term growth ambition,” says Mr Lund.

The CEO points to the field development plans for Gjøa and Alve as good examples of the group’s efforts in further developing the NCS. During 2006, nine new fields came on stream. On the NCS, Statoil’s portfolio has been strengthened with the Norne K-template, Gimle, Fram East, Oseberg West Flank and Ringhorne East, while the international upstream position has been strengthened with production from In Amenas in Algeria, Dalia in Angola and East Azeri and Shah Deniz in Azerbaijan.

“On 18 December it was announced that the boards of directors of Statoil and Hydro recommend a merger of Hydro’s oil- and gas activities with Statoil. The processes that lead up to the necessary approvals of the merger are well under way. By combining the strengths from both companies, we will build a strong Norwegian based energy company, well positioned to succeed even better in the global competition,” says Mr Lund.

Return on average capital employed after tax (ROACE) (1) for the 12 months ended 31 December 2006 was 27.1%, compared to 27.6% for the 12 months ended 31 December 2005. The decrease in ROACE was mainly due to the increase in capital employed partly offset by higher net income. ROACE is defined as a non-GAAP financial measure (2).

In 2006, earnings per share were NOK 18.79 (USD 3.02) compared to NOK 14.19 (USD 2.10) in 2005. In the fourth quarter of 2006, earnings per share were NOK 5.58 (USD 0.90) compared to NOK 3.94 (USD 0.59) in the fourth quarter of 2005.

Statoil’s board of directors will propose to the annual general meeting an ordinary dividend of NOK 4.00 per share for 2006, as well as NOK 5.12 per share in special dividend. In 2005 the ordinary dividend was NOK 3.60 per share, while the special dividend amounted to NOK 4.60 per share.

Income before financial items, income taxes and minority interest in 2006 was NOK 116.9 billion compared to NOK 95.0 billion in 2005. The increase was mainly due to a 20% increase in the average oil price measured in NOK and a 32% increase in the gas price measured in NOK. The increase was partly offset by a reduction in lifted oil volumes and an increase in cost items.

Income before financial items, income taxes and minority interest decreased from NOK 27.8 billion in the fourth quarter of 2005 to NOK 26.1 billion in the same period of 2006. This was mainly related to a 9% decrease in the total oil and gas liftings, a 43% reduction in refining margins, and the tax-free capital gain of NOK 1.5 billion from the sale of Borealis in the fourth quarter of 2005. In addition, operating expenses increased by NOK 1.2 billion and exploration expenses increased by NOK 1.2 billion, mainly due to higher activity.

The decrease in income before financial items, income taxes and minority interest in the fourth quarter of 2006 was partly offset by an increased average gas price measured in NOK of 16%. Selling, general and administrative expenses decreased by NOK 1.3 billion in the fourth quarter, mainly due to decreased insurance cost of NOK 0.9 billion. The fourth quarter of 2005 included an insurance cost of NOK 0.5 billion due to insurance premium commitments and accruals related to liabilities in the two mutual insurance companies in which Statoil Forsikring participates. These accruals were partially reversed by NOK 0.4 billion in the fourth quarter of 2006. In addition, discontinuing operations in Ireland, including a pre-tax gain of NOK 0.6 billion, is reported net under selling, general and administrative expenses. Depreciations decreased by NOK 1.2 billion, mainly due to the write-down of the South Pars field in Iran in the fourth quarter of 2005 of NOK 2.2 billion, partly offset by increased depreciations related to producing fields.

USGAAP income statement



USGAAP income	Fourth quarter				Year ended 31 December
statement	2006	2005		2006	2006	2005		2006
(in millions)	NOK	NOK	Change	USD*	NOK	NOK	Change	USD*


Sales	103,591	106,142	(2%)	16,631	423,528	384,653	10%	67,996
Equity in net income of affiliates	95	103	(8%)	15	410	1,090	(62%)	66
Other income	49	1,592	(97%)	8	1,228	1,668	(26%)	197


Total revenues	103,735	107,837	(4%)	16,654	425,166	387,411	10%	68,259


Cost of goods sold	58,295	60,490	(4%)	9,359	239,544	230,721	4%	38,458
Operating expenses	9,818	8,643	14%	1,576	34,320	30,243	13%	5,510
Selling, general and administrative expenses	1,289	2,574	(50%)	207	6,990	7,189	(3%)	1,122
Depreciation, depletion and amortisation	6,357	7,592	(16%)	1,021	21,767	20,962	4%	3,495
Exploration expenses	1,917	738	160%	308	5,664	3,253	74%	909


Total expenses before financial items	77,676	80,037	(3%)	12,471	308,285	292,368	5%	49,494


Income before financial items, income taxes and minority interest	26,059	27,800	(6%)	4,184	116,881	95,043	23%	18,765

Net financial items	2,811	(1,515)	286%	451	4,814	(3,512)	237%	773


Income before income taxes and minority interest	28,870	26,285	10%	4,635	121,695	91,531	33%	19,538

Income taxes	(16,769)	(17,581)	(5%)	(2,692)	(80,360)	(60,036)	34%	(12,902)
Minority interest	(89)	(181)	(51%)	(14)	(720)	(765)	(6%)	(116)


Net income	12,012	8,523	41%	1,928	40,615	30,730	32%	6,521




Income before financial items, income taxes and minority interest for	Fourth quarter				Year ended 31 December
the segments	2006	2005		2006	2006	2005		2006
(in millions)	NOK	NOK	Change	USD*	NOK	NOK	Change	USD*


E&P Norway	21,081	22,538	(6%)	3,384	89,389	74,132	21%	14,351
International E&P	1,295	826	57%	208	10,928	8,364	31%	1,754
Natural Gas	2,331	2,435	(4%)	374	10,009	5,901	70%	1,607
Manufacturing & Marketing	1,141	2,692	(58%)	183	6,998	7,593	(8%)	1,124
Other	211	(691)	131%	34	(443)	(947)	53%	(71)


Income before financial items, income taxes and minority interest	26,059	27,800	(6%)	4,184	116,881	95,043	23%	18,765



*Solely for the convenience of the reader, the figures for the fourth quarter of 2006 and the year ended 31 December 2006 have been translated into US dollars at the rate of NOK 6.2287 to USD 1.00, the Federal Reserve noon buying rate in the City of New York on 29 December 2006.


Financial data


	Fourth quarter				Year ended 31 December
	2006	2005		2006	2006	2005		2006
	NOK	NOK	Change	USD*	NOK	NOK	Change	USD*


Weighted average number of ordinary shares outstanding	2,151, 148,995	2,165, 464,649			2,161, 028,202	2,165, 740,054
Earnings per share	5.58	3.94	42%	0.90	18.79	14.19	32%	3.02
ROACE (last 12 months)	27.1%	27.6%			27.1%	27.6%
Cash flows provided by
operating activities (billion)	8.7	0.0	n/a	1.4	60.9	56.3	8%	9.8
Gross investments (billion)	15.7	9.1	72%	2.5	46.2	46.2	0%	7.4
Net debt to capital employed ratio	16.8%	15.1%			16.8%	15.1%



Operational data


	Fourth quarter				Year ended 31 December
	2006	2005	Change		2006	2005	Change


Average oil price (USD/bbl)	59.3	57.3	3%		64.4	53.6	20%
USDNOK average daily exchange rate	6.42	6.63	(3%)		6.42	6.45	0%
Average oil price (NOK/bbl) [3]	381	380	0%		413	345	20%
Gas prices (NOK/scm)	2.01	1.74	16%		1.91	1.45	32%
Refining margin, FCC (USD/boe) [4]	4.7	8.3	(43%)		7.1	7.9	(10%)
Total oil and gas production (1,000 boe/day) [5]	1,153	1,232	(6%)		1,135	1,169	(3%)
Total oil and gas liftings (1,000 boe/day) [6]	1,145	1,252	(9%)		1,133	1,166	(3%)
Reserve replacement rate (annual) [7]					73%	102%	(28%)
Reserve replacement rate 3-year average					94%	102%	(8%)
Proved reserves (mboe)					4,185	4,295	(3%)
Production cost (NOK/boe, last 12 months) [8]	26.6	22.3	20%		26.6	22.3	20%
Production cost normalised (NOK/boe, last 12 months) [9]	26.2	22.0	19%		26.2	22.0	19%

Total oil and gas production in 2006 was 1,135,000 barrels of oil equivalent (boe) per day, compared to 1,169,000 boe per day in 2005. In the fourth quarter of 2006 total oil and gas production amounted to 1,153,000 boe per day, compared to 1,232,000 boe per day in the fourth quarter of 2005. Statoil’s guiding on production for 2006 at 1,140,000 boe per day was based on an oil price of USD 60 per bbl. A realised oil price of USD 60 per bbl would have resulted in an estimated production of 1,139,000 boe per day. The difference from reported production is due to production sharing agreements (PSA) effects.

In the fourth quarter of 2006 total oil and gas liftings were 1,145,000 boe per day compared to 1,252,000 boe per day in the fourth quarter of 2005. This indicates an average underlift of 8,000 boe per day in the fourth quarter of 2006 compared to an average overlift of 20,000 boe per day in the fourth quarter of 2005.

Exploration expenditure in 2006 was NOK 7.5 billion, compared to NOK 4.3 billion in 2005. Exploration expenditure in the fourth quarter of 2006 amounted to NOK 2.0 billion, compared to NOK 1.1 billion in the fourth quarter of 2005. Exploration expenditure reflects the period's exploration activities.

Exploration expenses for the period consist of exploration expenditure adjusted for the period's change in capitalised exploration expenditure. Exploration expenses in 2006 amounted to NOK 5.7 billion, compared to NOK 3.3 billion in 2005. In the fourth quarter of 2006 exploration expenses amounted to NOK 1.9 billion, compared to NOK 0.7 billion in the fourth quarter of 2005. The increase both in exploration expenditure and exploration expenses was mainly due to higher exploration activity in 2006 compared to 2005. Exploration expenses also increased due to an increase in expense of previously capitalised licences and well expenditures.


	Fourth quarter				Year ended 31 December
Exploration	2006	2005		2006	2006	2005		2006
(in millions)	NOK	NOK	Change	USD*	NOK	NOK	Change	USD*


Exploration expenditure (activity)	1,980	1,093	81%	318	7,451	4,337	72%	1,196
Expensed, previously capitalised exploration expenditure	404	3	n/a	65	667	158	322%	107
Capitalised share of current period's exploration activity	(467)	(358)	(30%)	(75)	(2,454)	(1,242)	(98%)	(394)


Exploration expenses	1,917	738	160%	308	5,664	3,253	74%	909

A total of 37 exploration and appraisal wells were completed in 2006, 17 on the NCS and 20 internationally. Of these wells, 19 resulted in discoveries, while six wells await final evaluation. In addition, four exploration extensions on the NCS were completed in 2006, two of which resulted in discoveries. The number of exploration wells completed in 2005 was 20.

Proved reserves at the end of 2006 were 4,185 million boe, compared to 4,295 million boe at the end of 2005, a decrease of 111 million boe. In 2006, 307 million boe were added, mostly through revisions, extensions and discoveries, compared to 453 million boe in 2005. Production in 2006 was 415 million boe compared to 427 million boe in 2005.

The reserve replacement ratio (7) was 73% in 2006, compared to 102% in 2005, while the average three-year replacement ratio was 94% in 2006, compared to 102% in of 2005.

Production cost per boe was NOK 26.6 for the 12 months ended 31 December 2006, compared to NOK 22.3 for the 12 months ended 31 December 2005 (8).

Normalised at a USDNOK exchange rate of 6.00 and adjusted for the estimated volume due to PSA effects based on an average oil price of USD 60 per bbl, the production cost for the 12 months ended 31 December 2006 was NOK 26.2 per boe, compared to NOK 22.0 per boe for the 12 months ended 31 December 2005 (9).

The production unit costs, both actual and normalised, have increased, mainly due to a higher activity level, temporary lower production, and increasing industry cost pressure.

Net financial items amounted to an income of NOK 4.8 billion in 2006 compared to an expense of NOK 3.5 billion in 2005. In the fourth quarter of 2006 net financial items were an income of NOK 2.8 billion, compared to an expense of NOK 1.5 billion in the fourth quarter of 2005.

The increased income in 2006 was mainly caused by increased currency gains, due to a weakening of the USD in relation to the NOK in 2006. Most of the currency gains relate to Statoil’s short-term NOK hedging policy and unrealised gains on long-term USD debt.


Exchange rates	31.12.2006	30.09.2006	31.12.2005	30.09.2005	31.12.2004


USDNOK	6.26	6.50	6.77	6.54	6.04

Income taxes in 2006 were NOK 80.4 billion, with a corresponding tax rate of 66.0%, compared to income taxes in 2005 of NOK 60.0 billion with a corresponding tax rate of 65.6%.

Health, safety and the environment (HSE)
There were no fatalities during 2006. The serious incident indicator has been halved since 2001, and has never been at a lower level. The indicators for personnel injuries have shown a slight increase from the record low results in 2005. The serious injuries have decreased from 22 in 2005 to 18 in 2006.

In 2006, Statoil started a major initiative to reduce incidents caused by dropped objects. There has been a significant reduction in serious incidents of 25% since 2005. The chief executive’s HSE prize 2006 was awarded to the zero dropped objects team, which is devoted to identifying and reducing the threat of dropped objects offshore.

The total volume of oil spills decreased from 2005 to 2006. There was one oil spill of some significance in 2006, in Nynäshamn in Sweden. The spill amounted to 104 standard cubic metres (scm). Statoil’s oil spill emergency response was efficient, and as a result only 10 scm spillage remains uncollected.

Our objective is zero harm to health, security and the environment. Sustained top management involvement, a strong focus on developing the right HSE attitude throughout the company, measures for upgrading skills, and cooperation with our contractors to further improve HSE results, will continue with undiminished strength.


	Fourth quarter		Year ended 31 December
HSE	2006	2005	2006	2005


Total recordable injury frequency	4.8	5.3	5.7	5.1
Serious incident frequency	2.4	1.8	2.1	2.3
Unintentional oil spills (number)	76	144	292	534
Unintentional oil spills (volume, scm)	30	350	157	442

Important events
Recent important events include the following:

E&P NORWAY


	Fourth quarter				Year ended 31 December
	2006	2005		2006	2006	2005		2006
(in millions)	NOK	NOK	Change	USD*	NOK	NOK	Change	USD*


USGAAP income statement

Total revenues	28,786	28,806	0%	4,622	116,967	97,623	20%	18,779


Operating, general and administrative expenses	3,306	2,977	11%	531	12,023	10,223	18%	1,930
Depreciation, depletion and amortisation	3,755	3,020	24%	603	12,913	11,450	13%	2,073
Exploration expenses	644	271	138%	103	2,642	1,818	45%	424


Total expenses	7,705	6,268	23%	1,237	27,578	23,491	17%	4,428


Income before financial items, income taxes and minority interest	21,081	22,538	(6%)	3,384	89,389	74,132	21%	14,351


Operational data
Oil price (USD/bbl)	60.1	58.3	3%		65.0	54.1	20%

Liftings:
Oil (1,000 bbl/day)	509	572	(11%)		520	562	(7%)
Natural gas (1,000 boe/day)	469	475	(1%)		436	423	3%
Total oil and natural gas liftings (1,000 boe/day)	977	1,047	(7%)		956	984	(3%)

Production:
Oil (1,000 bbl/day)	521	553	(6%)		521	562	(7%)
Natural gas (1,000 boe/day)	469	475	(1%)		436	423	3%
Total oil and natural gas production (1,000 boe/day)	989	1,028	(4%)		958	985	(3%)

Income before financial items, income taxes and minority interest for E&P Norway in 2006 was NOK 89.4 billion compared to NOK 74.1 billion in 2005.

The increase was primarily due to a 20% increase in the segment oil price measured in NOK which contributed NOK 12.8 billion, an increase in the transfer price of natural gas, which contributed NOK 7.8 billion, an increase of NOK 3.2 billion related to other income and an increase in lifted volumes of gas which increased income by NOK 0.8 billion. The increase was partly offset by a decrease in lifted volumes of oil, which reduced income by NOK 5.3 billion, as well as an increase in cost items.

In the fourth quarter of 2006 income before financial items, income taxes and minority interest was NOK 21.1 billion, compared to NOK 22.5 billion in the same period of 2005. The decrease was mainly due to an 11% decrease in lifted volumes of oil, which reduced income by NOK 2.4 billion, as well as an increase in cost items. Depreciation, depletion and amortisation increased both in the year and in the quarter, mainly due to start-up of Kristin production in November 2005, and new estimates on decommissioning cost and a change in the well factor depreciation principle. Well costs are depreciated on the basis of proved reserves reduced by a factor of actual wells drilled in proportion to wells planned to be drilled. Other cost items increased as well, mainly due to market pressure and increased activity in existing and new fields. The decrease was partly offset by a 22% increase in the transfer price of natural gas measured in NOK, contributing NOK 1.7 billion, and an increase in other income of NOK 0.6 billon.

Average daily lifting of oil was 520,000 bbl per day in 2006 compared to 562,000 bbl per day in 2005, while average daily production of oil was 521,000 bbl per day in 2006, compared to 562,000 per day in 2005.

The reduction from 2005 to 2006 of 41,000 bbl in average daily production of oil was mainly related to continuing decline on the Statfjord, Troll Oil and Oseberg fields. In addition to a temporary reduction in production on the Tordis and Gullfaks fields from 2005 to 2006, partly due to longer turnarounds. The drop in production was partly offset by increased volumes from the Kristin and Urd fields, which came on stream in November 2005.

In the fourth quarter of 2006 average daily lifting of oil was 509,000 bbl per day, compared to 572,000 bbl per day in the same period in 2005. Average daily oil production in the fourth quarter of 2006 was 521,000 bbl per day compared to 553,000 bbl per day in the same period in 2005.

The reduction from the fourth quarter of 2005 to the fourth quarter of 2006 of 32,000 bbl in average daily production of oil was mainly related to a continuing decline on the Statfjord, Oseberg, and Troll oil fields. Tordis experienced lower production due to condensate leakage and turnaround. Gullfaks has also had turnaround activities in the fourth quarter of 2006. The decrease in production was partly offset by higher production from the Kristin and Kvitebjørn fields, with Kristin coming on stream in early November 2005. Problems with the flash gas compressor at Kollsnes reduced production from Kvitebjørn in the fourth quarter both in 2005 and in 2006. However, the effects of these problems were greater in the fourth quarter of 2005 than in the fourth quarter of 2006.

Average daily gas production was 436,000 boe per day in 2006 compared to 423,000 boe per day in 2005, an increase of 3%. The increase in gas production was due to the production from Kristin, which commenced in November 2005. In the fourth quarter of 2006, average daily gas production was 469,000 boe per day compared to 475,000 boe per day in the same period in 2005. The decrease in production was mainly due to lower customer offtake.

Exploration expenditure (including capitalised exploration expenditure) amounted to NOK 3.5 billion in 2006, compared to NOK 2.2 billion in 2005. In the fourth quarter of 2006 exploration expenditure was NOK 0.9 billion, compared to NOK 0.5 billion in the same period of 2005. Exploration expenses were NOK 2.6 billion in 2006, compared to NOK 1.8 billion in 2005. Exploration expenses in the fourth quarter of 2006 were NOK 0.6 billion compared to NOK 0.3 billion in the same period of 2005. The main reasons for the increase in both exploration expenditure and expenses from 2005 to 2006, on both an annual and quarterly basis, were higher drilling activity and more expensive wells.

During 2006, Statoil participated in the drilling and completion of 17 exploration and appraisal wells on the NCS, eight of which resulted in discoveries. In addition Statoil participated in the drilling and completion of four exploration extension wells, two of which resulted in discoveries. Nine exploration and appraisal wells were completed in 2005.

Four exploration and appraisal wells were completed in the fourth quarter of 2006, of which the PL 090 Astero and PL 229 Goliath South appraisals resulted in discoveries. The PL 229 Goliath West Sidetrack and PL 050 Turmalin wells were dry. One exploration extension well, PL 053 Gamma Statfjord, was completed in the fourth quarter of 2006 and resulted in a discovery. No exploration and appraisal wells were completed in the fourth quarter of 2005.

Statoil’s removal and abandonment obligations have increased by NOK 8.1 billion from NOK 17.4 billion in 2005 to NOK 25.5 billion in 2006. The increase is primarily due to revised estimates related to removal complexity, and costs related to rigs, marine operations and heavy lift vessels. The effects on the profit and loss account for 2006 are insignificant. In the profit and loss account for 2007 depreciation and accretion are expected to increase by approximately NOK 1.5 billion and NOK 0.4 billion, respectively, as a consequence of the revised abandonment estimates.

Statoil as operator and the licensees in the Kvitebjørn field in the North Sea decided to reduce gas and oil production temporarily to enable sound reservoir management and safe drilling operations for the wells remaining to be drilled. Output is planned to be reduced by approximately 50%, which entails an overall reduction from about 190,000 boe per day to roughly 95,000 boe per day. The reduction took effect from 23 December 2006 and is expected to continue for an estimated period of five months. For Statoil this reduction will mean an average decrease of about 15,000 boe per day in 2007. Statoil will meet its commitments to its gas customers during this period with equity natural gas from Troll and other NCS fields.

Statoil has installed a new subsea template to achieve improved recovery on the Norne field in the Norwegian Sea. Production from the new subsea template will contribute to prolong the field's life. This development contributes to strengthening the group's position in the Halten/Nordland area.

Production at Fram East started on schedule on 30 October 2006. Four production wells and two injection wells are planned. Fram East has been developed with two subsea production templates with a total of eight drilling slots connected to the Troll C platform where oil and gas are processed and transported. The Fram East field, which was discovered in 1990, contains 61,000,000 bbl of recoverable oil and 3.1 billion cubic metres (bcm) of recoverable gas.

On 15 December 2006 proposals for developing the Gjøa field in the North Sea were submitted to the Ministry of Petroleum and Energy. The PDO also calls for the Hydro operated condensate and gas fields Vega and Vega South to be tied back to the Gjøa platform.

On 16 January 2007 Statoil submitted a PDO for the Alve gas and condensate field in the Norwegian Sea to the Ministry of Petroleum and Energy. Alve will be phased in via tie-back to the Statoil-operated Norne field. The licensees plan to develop the field with a single subsea template with four drilling slots.

INTERNATIONAL E&P


	Fourth quarter				Year ended 31 December
	2006	2005		2006	2006	2005		2006
(in millions)	NOK	NOK	Change	USD*	NOK	NOK	Change	USD*


USGAAP income statement

Total revenues	5,449	6,105	(11%)	875	24,643	19,563	26%	3,956


Operating, general and administrative expenses	1,375	1,117	23%	221	4,996	3,491	43%	802
Depreciation, depletion and amortisation	1,506	3,695	(59%)	242	5,697	6,273	(9%)	915
Exploration expenses	1,273	467	173%	204	3,022	1,435	111%	485


Total expenses	4,154	5,279	(21%)	667	13,715	11,199	22%	2,202


Income before financial items, income taxes and minority interest	1,295	826	57%	208	10,928	8,364	31%	1,754


Operational data
Oil price (USD/bbl)	56.2	53.4	5%		61.7	51.0	21%

Liftings:
Oil (1,000 bbl/day)	149	167	(11%)		148	139	6%
Natural gas (1,000 boe/day)	18	38	(52%)		29	43	(32%)
Total oil and natural gas liftings (1,000 boe/day)	168	205	(18%)		177	182	(3%)

Production:
Oil (1,000 bbl/day)	147	166	(11%)		149	142	5%
Natural gas (1,000 boe/day)	17	38	(54%)		29	43	(32%)
Total oil and natural gas production (1,000 boe/day)	164	204	(19%)		178	184	(4%)

Income before financial items, income taxes and minority interest in 2006 was NOK 10.9 billion compared to NOK 8.4 billion in the corresponding period of 2005. The increase was mainly due to a 26% increase in realised oil and gas prices measured in NOK, contributing NOK 4.2 billion, and a decrease in depreciation of NOK 0.6 billion. This was partly offset by a NOK 1.6 billion increase in exploration expenses and a NOK 1.5 billion increase in operating, general and administrative expenses due to increased royalty on Sincor, increased transportation costs, new fields in production and an upward cost pressure.

In the fourth quarter of 2006 income before financial items, income taxes and minority interest was NOK 1.3 billion compared to NOK 0.8 billion in the same period of 2005. The increase was mainly due to a decrease in depreciation of NOK 2.2 billion, a NOK 0.3 billion effect of cargoes in transit in 2005 and an 8% increase in the realised oil and gas prices measured in NOK, contributing NOK 0.1 billion. This was partly offset by a NOK 0.8 billion increase in exploration expenses, an 18% decrease in lifted volumes, which contributed NOK 1.0 billion, and a NOK 0.3 billion increase in operating, general and administrative expenses.

The decrease in depreciation, both in the fourth quarter of 2006 and for the year as a whole, is mainly due to the NOK 2.2 billion write-down of the book value of Statoil’s working interest in phases 6-7-8 of the South Pars project in the fourth quarter of 2005. This was partly offset by increased depreciation due to a reduction in the proved reserve estimates which implies higher depreciation related to the PSAs in Angola and Algeria in 2006.

Average daily lifting of oil increased from 139,500 bbl per day in 2005 to 147,900 bbl per day in 2006. In the fourth quarter of 2006 average daily lifting of oil decreased to 149,500 bbl per day, compared to 167,400 bbl per day in the same period in 2005. Average daily production of oil increased from 141,800 bbl per day in 2005 to 148,800 bbl per day in 2006. The average daily oil production in the fourth quarter of 2006 was 146,700 bbl per day, compared to 165,600 bbl per day in the same period of 2005.

The increase in oil production from 2005 to 2006 was mainly related to start-up of new fields such as Kizomba B and the West and East Azeri part of the Azeri-Chirag-Gunashli (ACG) field, which came on stream in the third and fourth quarter of 2005 and fourth quarter of 2006 respectively. This was partly offset by lower entitlement production under the PSAs in Angola, and lower production on the Lufeng field in China and the Alba field in the UK. A drop in production at the Sincor field in Venezuela was mainly due to turnarounds.

The decrease in oil production from the fourth quarter of 2005 to the fourth quarter of 2006 was mainly related to lower entitlement production under the PSAs in Angola, and lower production on the Lufeng field in China and the Alba field in the UK. A drop in production at the Sincor field in Venezuela was mainly due to turnarounds. This was partly offset by higher production related to the start-up of new fields such as the West and East Azeri part of the ACG field, the In Amenas field in Algeria and the Dalia field in Angola.

Average daily gas production was 28,900 boe per day in 2006 compared to 42,600 boe per day in 2005. In the fourth quarter of 2006 average daily gas production was 17,400 boe per day, compared to 38,000 boe per day during the corresponding period of 2005. The large decrease in gas production was mainly attributable to lower entitlement gas sales from the In Salah field due to disproportionate PSA effects.

Exploration expenditure (including capitalised exploration expenditure) was NOK 4.0 billion in 2006 compared to NOK 2.1 billion in 2005. Exploration expenditure in the fourth quarter of 2006 was NOK 1.1 billion compared to NOK 0.6 billion in the corresponding period of 2005. Exploration expenses were NOK 3.0 billion in 2006 compared to NOK 1.4 billion in 2005. Exploration expenses were NOK 1.3 billion in the fourth quarter of 2006 compared to NOK 0.5 billion in the same period of 2005. The increase in exploration expenses was mainly due to increased exploration activity as well as an increase of NOK 0.4 billion in expense of previously capitalised licences and well expenditures.

In 2006, 20 exploration and appraisal wells were completed internationally, 11 of which resulted in discoveries or confirmed earlier discoveries and six wells are pending or awaiting final evaluation. Eleven wells were completed in the corresponding period of 2005. During the fourth quarter of 2006, three exploration and appraisal wells were completed internationally. A gas discovery was confirmed at the Cocuina-2 well on Plataforma Deltana in Venezuela, while the well Terra S42 in Angola block 31 is an oil discovery. Tonga GC771 in the US GoM awaits final evaluation.

On 6 November 2006, Statoil and Anadarko Petroleum Corporation announced the signing of an agreement whereby Statoil acquired two of Anadarko’s US GoM discoveries and one prospect. The transaction of USD 901 million was completed in the first quarter of 2007.

On 15 November 2006, Statoil spudded its first exploration well onshore in the Hassi Mouina block in Algeria. The Hassi Mouina licence was awarded in June 2004 and comprises four blocks within an area of 23,000 square kilometres in the Gourara basin. Statoil's working interest in Hassi Mouina is 75%.

On 13 December 2006, the Dalia oil field on the Angolan continental shelf was brought on stream. Statoil has 13.33% working interest in the field. Dalia is the third in block 17 to be put into production.

On 15 December 2006, the Shah Deniz gas and condensate field in Azerbaijan commenced production. Shah Deniz is expected to reach plateau production of roughly nine bcm annually in 2009. Production on Shah Deniz has halted since December due to technical problems. Current view is to start production again during the end of first quarter 2007.

On 16 January 2007, Statoil signed a production sharing contract (PSC) on a working interest in the deepwater Kuma block off Indonesia. This is the first time the group has been awarded exploration acreage in Indonesia. Statoil's working interest in the Kuma block is 40%, while operator ConocoPhillips has 60%.

On 30 January 2007, operator BP announced an oil discovery in the well Terra S42 in ultra-deepwater in block 31 offshore Angola. This is the 12th discovery in this block in which Statoil is partner with a 13.33% working interest. The discovery is located approximately 30 kilometres north-west of the recently announced Titania discovery.

Statoil has for the first time taken part, and been offered acreage, in an Egyptian licensing round. The Statoil group was awarded operatorship and an 80% working interest in the deepwater blocks 9 and 10 in the 2006 EGAS international bid round. Sonatrach of Algeria will hold the remaining 20% working interest. The offer is subject to finalisation of a detailed PSA and approval by the Egyptian Parliament.

At year end 2006 the partners in the Sincor joint venture were Statoil with 15%, PDVSA with 38% and Total with 47%. The Venezuelan Government has recently indicated that the state requires a majority of minimum 60% for the state-owned PDVSA in the Sincor joint venture, which is to migrate into a mixed company, i.e. a company with a majority Venezuelan state-ownership share. The specifics and extent of such a transition and the level of compensation to be received by Statoil cannot be ascertained at this time. Statoil and our partner are communicating with the Ministry to find an overall solution for Sincor.

NATURAL GAS


	Fourth quarter				Year ended 31 December
	2006	2005		2006	2006	2005		2006
(in millions)	NOK	NOK	Change	USD*	NOK	NOK	Change	USD*


USGAAP income statement

Total revenues	16,954	15,865	7%	2,722	61,134	45,823	33%	9,815


Cost of goods sold	11,573	10,679	8%	1,858	40,831	30,826	32%	6,555
Operating, selling and administrative expenses	2,804	2,541	10%	450	9,424	8,321	13%	1,513
Depreciation, depletion and amortisation	246	210	17%	39	870	775	12%	140


Total expenses	14,623	13,430	9%	2,348	51,125	39,922	28%	8,208


Income before financial items, income taxes and minority interest	2,331	2,435	(4%)	374	10,009	5,901	70%	1,607


Operational data
Natural gas sales (Statoil equity) (bcm)	6.9	7.0	(3%)		25.3	24.6	3%
Natural gas sales (third-party volumes) (bcm)	0.8	0.8	(5%)		3.2	2.6	21%
Natural gas sales (bcm)	7.6	7.9	(3%)		28.5	27.3	4%
Natural gas price (NOK/scm)	2.01	1.74	16%		1.91	1.45	32%
Transfer price natural gas (NOK/scm)	1.48	1.21	22%		1.36	1.04	31%
Regularity at delivery point	100%	100%	0%		100%	100%	0%

Income before financial items, income taxes and minority interest in 2006 was NOK 10.0 billion, compared to NOK 5.9 billion in 2005. The increase of NOK 4.1 billion was mainly due to higher prices of natural gas, increased sales volumes and contributions from short-term market derivatives. The main offsetting factors were a higher transfer price from E&P Norway and increased operating expenses.

In the fourth quarter of 2006, income before financial items, income taxes and minority interest was NOK 2.3 billion, compared to NOK 2.4 billion in the fourth quarter of 2005. Higher prices of natural gas, as well as contributions from short-term optimisation and trading of natural gas impacted our results positively. However, this was more than offset by higher cost of goods sold, higher operating expenses and a small reduction in natural gas volumes sold.

Natural gas sales in 2006 were 28.5 bcm, including sales of third-party liquefied natural gas (LNG), compared to 27.3 bcm in 2005. Of the total gas sales in 2006, equity gas was 25.3 bcm.

In the fourth quarter of 2006, natural gas sales were 7.6 bcm compared to 7.9 bcm in the same period of 2005, a decrease of 3%. Of the total gas sales in the fourth quarter of 2006, equity gas was 6.9 bcm. Sales of natural gas volumes from the In Amenas and In Salah fields in Algerie are reported in the International E&P segment.

The average gas price for gas piped to Europe in 2006 was NOK 1.91 per scm, compared to NOK 1.45 per scm in 2005, an increase of 32%. In the fourth quarter of 2006 the gas price was 16% higher than in the fourth quarter of 2005. The price increased mainly due to higher long-term contract prices and higher average gas prices in the UK market.

Cost of goods sold in 2006 increased by 32% compared to 2005, due to higher transfer price and increased equity volumes. The transfer price for gas from E&P Norway to Natural Gas was NOK 1.36 per scm in 2006, an increase of 31% compared to the transfer price in 2005 of NOK 1.04 per scm. The transfer price increased by 22% from NOK 1.21 per scm in the fourth quarter of 2005 to NOK 1.48 per scm in the fourth quarter of 2006.

MANUFACTURING & MARKETING


	Fourth quarter				Year ended 31 December
	2006	2005		2006	2006	2005		2006
(in millions)	NOK	NOK	Change	USD*	NOK	NOK	Change	USD*


USGAAP income statement


Total revenues	84,581	90,960	(7%)	13,579	354,024	333,493	6%	56,838

Cost of goods sold	78,468	83,482	(6%)	12,598	329,072	308,124	7%	52,832
Operating, selling and administrative expenses	4,224	4,240	0%	678	16,035	15,704	2%	2,574
Depreciation, depletion and amortisation	748	546	37%	120	1,919	2,072	(7%)	308


Total expenses	83,440	88,268	(5%)	13,396	347,026	325,900	6%	55,714


Income before financial items, income taxes and minority interest	1,141	2,692	(58%)	183	6,998	7,593	(8%)	1,124


Operational data
FCC margin (USD/bbl)	4.7	8.3	(43%)		7.1	7.9	(10%)
Contract price methanol (EUR/tonne)	395	220	80%		300	225	33%

Income before financial items, income taxes and minority interest for Manufacturing & Marketing in 2006 was NOK 7.0 billion compared to NOK 7.6 billion of 2005. The decrease of NOK 0.6 billion was mainly due to contribution from the operation and the sale of Borealis in 2005 of NOK 2.2 billion, partly offset by the pre-tax gain from the sale of Statoil Ireland of NOK 0.6 billion and increased trading income in Oil trading.

In the fourth quarter of 2006 income before financial items, income taxes and minority interest was NOK 1.1 billion compared to NOK 2.7 billion in the same period in 2005. The decrease from the fourth quarter of 2005 to the fourth quarter of 2006 was mainly due to the sale of Borealis, which contributed to NOK 1.5 billion in the fourth quarter of 2005, combined with reduced refining margins and an infrequent expense of NOK 0.3 billion due to implementation of the new business model in Energy & Retail.

Oil trading income before financial items, income taxes and minority interest in 2006 was NOK 2.4 billion, compared to NOK 1.7 billion in 2005. The increase from 2005 to 2006 was mainly due to improved results from trading. In the fourth quarter of 2006, income before financial items, income taxes and minority interest was NOK 0.4 billion compared to NOK 0.5 billion in the same period of 2005.

Income before financial items, income taxes and minority interest from Manufacturing was NOK 3.7 billion in 2006, compared to NOK 3.4 billion in 2005. In the fourth quarter of 2006, income before financial items, income taxes and minority interest was NOK 0.5 billion, compared to NOK 0.8 billion in the same period in 2005. The increase from 2005 to 2006 was mainly due to reduced depreciation, partly offset by lower refining margins. The decrease from the fourth quarter of 2005 to the fourth quarter of 2006 was mainly due to lower refining margins. In 2006, the average FCC refining margin was USD 7.1 per barrel compared to USD 7.9 per barrel in 2005. The average contract price of methanol was EUR 300 per tonne in 2006 compared to EUR 225 per tonne in 2005, an increase of 33%.

Income before financial items, income taxes and minority interest from Energy & Retail was NOK 1.2 billion in 2006, compared to NOK 0.4 billion in 2005. Income before financial items, income taxes and minority interest in the fourth quarter of 2006 was NOK 0.4 billion, compared to a loss of NOK 0.1 billion in the same period in 2005. These increases are mainly due to the pre-tax gain from the sale of Statoil Ireland of NOK 0.6 billion and increased fuel margins, partly offset by an infrequent expense of NOK 0.3 billion as a result of the implementation of the new business model in Sweden.

On 13 October 2006 Statoil received the approval from Irish competition authorities to finalise the sale of Statoil Ireland to Topaz Energy Group. A pre-tax gain of NOK 0.6 billion was booked in the fourth quarter of 2006.

In December 2006 it was decided that Energy & Retail will implement a new business model in Sweden. This means that Statoil will take full, end-to-end, ownership of the fuel business, while the franchisees in the retail network will increase their share of the non-fuel business. This will enable better control of micro market pricing that is expected to give higher margins and increased logistics efficiency.

LIQUIDITY AND CAPITAL RESOURCES

Cash flows provided by operating activities were NOK 60.9 billion in 2006, compared to NOK 56.3 billion in 2005. The increase in cash flows provided by operating activities of NOK 4.7 billion in 2006 was mainly due to an increase in cash flows from underlying operations contributing NOK 31.2 billion. Short-term investments contributed NOK 1.0 billion. Increased taxes paid reduced the cash flows from operations by NOK 19.9 billion, increases in non-current items reduced the cash flows from operations by NOK 1.6 billion, and increased working capital reduced the cash flows from operations by NOK 6.1 billion. Cash flows provided by operating activities in the fourth quarter of 2006 increased by NOK 8.7 billion, compared to zero in the fourth quarter of 2005.

Cash flows used in investment activities in 2006 were NOK 40.1 billion, compared to NOK 37.7 billion in 2005. In the fourth quarter of 2006 the cash flows used in investment activities were NOK 16.1 billion, compared to NOK 0.6 billion in the fourth quarter of 2005.

Gross investments, defined as additions to property, plant and equipment (including intangible assets and long-term share investments) and capitalised exploration expenditure in 2006 were NOK 46.2 billion, the same as in 2005. In the fourth quarter of 2006 gross investments were NOK 15.7 billion, compared to NOK 9.1 billion in the fourth quarter of 2005. Investments in the fourth quarter of 2006 included the assets in the GoM that Statoil acquired from Plains Exploration & Production (PXP) for NOK 4.6 billion.


Gross	Fourth quarter				Year ended 31 December
investments	2006	2005		2006	2006	2005		2006
(in billions)	NOK	NOK	Change	USD*	NOK	NOK	Change	USD*


- E&P Norway	5.1	4.5	14%	0.8	20.9	16.3	29%	3.4
- International E&P	8.3	3.2	161%	1.3	20.0	25.3	(21%)	3.2
- Natural Gas	0.7	0.7	0%	0.1	2.3	2.5	(8%)	0.4
- Manufacturing & Marketing	1.3	0.5	146%	0.2	2.5	1.6	53%	0.4
- Other	0.2	0.2	28%	0.0	0.5	0.5	(2%)	0.1


Total gross investment	15.7	9.1	72%	2.5	46.2	46.2	0%	7.4

The difference between cash flows used in investment activities and gross investments in 2006 was mainly related to sale of assets, the capitalisation of future lease payments which have no current cash effects, but are accounted for as financial lease arrangements, and other changes in long-term loans granted and liabilities joint-venture.


Reconciliation of cash flow to gross	Fourth quarter		Year ended 31 December
investments (in NOK billion)	2006	2005	2006	2005


Cash flows to investments	16.1	0.6	40.1	37.7
NCS portfolio transactions	0.0	0.1	0.1	(1.0)
Capital leases	0.2	-	2.4	-
Proceeds from sales of assets	0.5	8.1	2.0	8.9
Other changes in long-term loans granted and liabilities joint-venture	(0.9)	0.2	1.7	0.7


Gross investments	15.7	9.1	46.2	46.2

Cash flows used in financing activities in 2006 amounted to NOK 20.5 billion, compared to NOK 16.5 billion in 2005. The main reason for the increase in cash flows used in financing activities was an increase in dividends paid.

The amount reported for 2006 includes dividends paid to shareholders of NOK 17.8 billion related to the annual result for 2005, while dividends paid to shareholders in 2005 was NOK 11.5 billion. New long-term borrowings in 2006 amounted to NOK 0.1 billion, compared to NOK 0.4 billion in 2005. Repayment of long-term debt in 2006 was NOK 1.4 billion compared to NOK 3.2 billion in 2005.

In the fourth quarter of 2006 cash flows used in financing activities were NOK 2.4 billion, compared to the same amount in the fourth quarter of 2005.

Share buy-backs are an integrated part of Statoil’s dividend policy. In 2006 Statoil bought back 5,867,000 shares in the market. In accordance with the agreement between Statoil ASA and the Norwegian State an additional 14,291,848 shares will be redeemed in 2007. In the fourth quarter of 2006 Statoil bought back 3,430,000 shares in the market, and the corresponding number of shares to be redeemed from the Norwegian State is 8,355,385 shares.

Statoil will not undertake any further share buy-backs until the proposed transaction with Hydro is closed, currently expected to take place in the autumn of 2007.

Interest-bearing debt. Gross interest-bearing debt was NOK 35.8 billion at the end of 2006, compared to NOK 34.1 billion at the end of 2005. The increase in gross interest bearing debt is due to an increase in financial lease of NOK 2.0 billion, and new short-term debt of NOK 2.5 billion to the Norwegian State, which were partly offset by a decrease in long-term interest bearing debt due to weakening of the USD in relation to the NOK in 2006. The increased lease obligation is mainly related to three vessels built for Snøhvit LNG transportation. The new short-term debt to the Norwegian State is related to the share buy-back programme.

For risk management purposes, currency swaps are used to ensure that Statoil keeps long-term interest-bearing debt in USD. As a result, most of the group's long-term debt is exposed to changes in the USDNOK exchange rate.

Net interest-bearing debt (10) was NOK 24.9 billion at 31 December 2006 compared to NOK 19.3 billion at 31 December 2005.

Net interest-bearing debt increased from 31 December 2005 to 31 December 2006, mainly as liquid assets decreased by NOK 5.5 billion and gross interest bearing debt increased by NOK 1.7 billion.

Net debt to capital employed ratio, defined as net interest-bearing debt to capital employed, was 16.8% at 31 December 2006, compared to 15.1% at 31 December 2005. The increase in the net debt to capital employed ratio was mainly related to an increase in net debt, partly offset by an increase in shareholders’ equity.

In the calculation of net interest-bearing debt, Statoil makes certain adjustments which make net interest-bearing debt and the net debt to capital employed ratio non-GAAP figures. For an explanation and calculation of the ratio, see Use and reconciliation of non-GAAP financial measures below.

Cash, cash equivalents and short-term investments were NOK 8.4 billion at 31 December 2006, compared to NOK 13.9 billion at 31 December 2005.

Cash and cash equivalents were NOK 7.4 billion at 31 December 2006, compared to NOK 7.0 billion at 31 December 2005. Short-term investments amounted to NOK 1.0 billion at 31 December 2006, compared to NOK 6.8 billion at 31 December 2005.

Current items (total current assets less current liabilities) decreased by NOK 1.0 billion from a positive amount of NOK 0.3 billion as at 31 December 2005 to a negative amount of NOK 0.7 billion as at 31 December 2006. The change in current items were mainly due to an increase in taxes payable of NOK 0.5 billion, an increase in short-term debt of NOK 4.0 billion, a decrease in accounts receivable of NOK 1.6 billion and a decrease in short-term investments of NOK 5.8 billion. This was partly offset by an increase in inventory of NOK 3.5 billion, an increase in prepaid expenses and other current assets of NOK 2.7 billion, an increase in cash, cash equivalents of NOK 0.3 billion, a decrease in accounts payable to related parties of NOK 2.2 billion and a decrease in accrued liabilities of NOK 1.9 billion.

Update on corporate targets and guidance
Statoil’s production target for 2007 remains at 1,300,000 boe per day at an oil price of USD 60 per bbl. We recognise that this is a challenging and stretched target and that we are more likely to undershoot than overshoot the target. The target is, however, still achievable depending on successful outcome of planned ramp-ups and start up of new projects, positive results from a range of activities initiated on mature fields and normal gas sales.

The production cost target has changed to NOK 27-28 per boe. The target has been adjusted to account for a production target of 1,300,000 boe per day in 2007. In addition, the cost pressure within the industry, including a new NOX-fee on the NCS, contributes to higher costs.

The total capex in the period 2005-2007 is expected to be about NOK 120 billion. The estimate excludes the purchase prices for the Encana, PXP and Anadarko’s GoM assets and other potential inorganic transactions.

The exploration expenditure in 2007 is expected to be about NOK 8 billion. The expected number of exploration wells to be drilled is 35-40, exluding exploration extensions on the NCS.

Horton matter
The Norwegian National Authority for Investigation and Prosecution of Economic and Environmental Crime (Økokrim) conducted an investigation concerning an agreement which Statoil entered into in 2002 with Horton Investments Ltd for consultancy services in Iran. In June 2004, Økokrim informed Statoil that it had concluded that Statoil had violated the Norwegian Penal Code’s prohibitions on trading in influence, which became effective on 4 July 2003, and imposed a penalty of NOK 20 million (USD 3 million). In October 2004, Statoil agreed to accept the penalty without admitting or denying the charges by Økokrim.

On 13 October, 2006, Statoil announced that it had reached agreements with the US Securities and Exchange Commission (SEC), the US Department of Justice (DOJ), and the United States Attorney’s Office for the Southern District of New York (USAO). Statoil has, in the agreements with the DOJ and USAO, accepted a penalty of USD 10.5 million for having violated the US Foreign Corrupt Practices Act (FCPA), as well as accepting responsibility for bribery in connection with the payments under the consultancy services contract with Horton Investments Ltd, for accounting for those payments improperly in its books and records, and for having insufficient internal controls in place to prevent the payments. The NOK 20 million (USD 3 million) fine paid to Økokrim has been deducted, so that the fine actually paid by Statoil under this agreement is USD 7.5 million. Statoil has, in the agreement with the SEC, neither admitted nor denied the charges, but agreed to pay USD 10.5 million as disgorgement.

Since it first learned of the payments in September 2003, Statoil has taken prompt and forceful steps to put in place new policies and practices to ensure the highest standards of transparency and ethical conduct. Among other actions, Statoil retained outside counsel to conduct a thorough internal review and adopted stronger new internal controls and stricter new ethical policies and practices. Statoil has cooperated fully with the SEC, DOJ and USAO throughout their inquiries, and shared the results of the internal review with the agencies.

The settlement takes the form of a three-year deferred prosecution agreement with the DOJ and USAO and a Cease and Desist Order with the SEC. In the deferred prosecution agreement, Statoil has consented to the filing with the United States Court for the Southern District of New York of a criminal information charging violations of the anti-bribery and books and records provisions of the FCPA. If Statoil fulfils its obligations under the deferred prosecution agreement for three years the criminal charges will be dismissed and the Horton case will be closed.

Iranian authorities have been carrying out inquiries into the matter. In April 2004 the Iranian Consultative Assembly initiated an official probe into allegations of corruption in connection with the Horton matter with Iran. The probe was finalised for the parliamentary session at the end of May 2004. It was reported in the international press that at such time no evidence of wrongdoing by the subjects of the probe in Iran had been revealed by the probe.

USE AND RECONCILIATION OF NON-GAAP FINANCIAL MEASURES

Statoil is subject to SEC regulations regarding the use of “non-GAAP financial measures” in public disclosures. 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.

For more information on our use of non-GAAP financial measures, see Item 5 - Operating and Financial Review and Prospects - Use of Non-GAAP Financial Measures in Statoil’s 2005 Annual Report on Form 20-F.

The following financial measures may be considered non-GAAP financial measures:
• Return on average capital employed (ROACE)
• Normalised production cost per barrel
• Net debt to capital employed ratio

ROACE
Statoil uses ROACE to measure the return on capital employed regardless of whether the financing is through equity or debt. This measure is viewed by the company as providing useful information, both for the company and investors, regarding performance for the period under evaluation. Statoil makes regular use of this measure to evaluate its operations. Statoil’s use of ROACE should not be viewed as an alternative to income before financial items, income taxes and minority interest, or to net income, which are the measures calculated in accordance with generally accepted accounting principles or ratios based on these figures.


Calculation of numerator and denominator used in ROACE calculation	Year ended 31 December
(in NOK million, except percentages)	2006	2005


Net income for the last 12 months	40,615	30,730
Minority interest for the last 12 months	720	765
After-tax net financial items for the last 12 months	(3,943)	887


Net income adjusted for minority interest and net financial items after tax (A1)	37,392	32,382


Calculated average capital employed:
Average capital employed before adjustments (B1)	139,722	117,275
Average capital employed (B2)	138,030	117,197


Calculated ROACE
Calculated ROACE based on average capital employed before adjustments (A1/B1)	26.8%	27.6%
Calculated ROACE based on average capital employed (A1/B2)	27.1%	27.6%

Normalised production cost
Normalised production cost in NOK per boe is used to evaluate the underlying development in the production cost. Statoil's production costs internationally are mainly incurred in USD. In order to exclude currency effects and to reflect the change in the underlying production cost, the USDNOK exchange rate is held constant at 6.00 in the calculations of normalised production cost. The normalised figures for the relevant previous periods have been restated in order to facilitate comparison.

Produced volumes used in the calculation of the normalised production cost per boe have been adjusted for PSA effects. The group’s 2007 target for production cost per boe is based on an oil price of USD 60 per bbl. Higher oil price levels affect the production entitlements negatively, and hence the production unit cost (9).

Normalised production cost per boe is reconciled in the table below to the most comparable GAAP measure, production cost per boe.


	Year ended 31 December
Production cost per boe	2006	2005


Total production costs last 12 months (in NOK million)	11,040	9,509
Produced volumes last 12 months (million boe)	414	427
Average USDNOK exchange rate last 12 months	6.41	6.44


Production cost (USD/boe)	4.16	3.46


Calculated production cost (NOK/boe)	26.6	22.3


Normalisation of production cost per boe
Total production costs last 12 months (in NOK million)	11,040	9,509
Production costs last 12 months International E&P (in USD million)	350	263
Normalised exchange rate (USDNOK)	6.00	6.00
Production costs last 12 months International E&P normalised at USDNOK 6.00	2,101	1,578
Production costs last 12 months E&P Norway (in NOK million)	8,798	7,807

Total production costs last 12 months in NOK million (normalised)	10,899	9,385

Produced volumes last 12 months (million boe)	414	427
Adjustment for estimated loss of production under production sharing agreements	1	negligible


Estimated produced volumes	416	427


Production cost (NOK/boe) normalised at USDNOK 6.00 [8]	26.2	22.0

Net debt to capital employed ratio

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 short-term investments. Two further adjustments are made for two different reasons:

1) After-tax return on average capital employed for the last 12 months is calculated as net income before minority interest and after-tax net financial items, divided by the average of opening and closing balances of net interest-bearing debt, shareholders’ equity and minority interest. See table under Return on average capital employed for a reconciliation of the numerator. See table under Net debt to capital ratio for a reconciliation of capital employed.

2) For a definition of non-GAAP financial measures and use of ROACE, see Use and reconciliation of non-GAAP financial measures.

3) The group’s oil price is a volume-weighted average of the segment prices of oil and natural gas liquids (NGL), including a margin for oil sales, trading and supply (O&S).

4) FCC: fluid catalytic cracking.

5) Oil volumes include condensate and NGL, exclusive of royalty oil. Natural gas volumes are measured at a gross calorific value (GCV) of 40 MJ/scm.

6) Lifting of oil equals sales of oil for E&P Norway and International E&P. Deviations from share of total lifted volumes from the field compared to the working interest in the field production are due to periodic over- or underliftings.

7) The reserve replacement ratio is defined as access to new secure reserves in accordance with SEC definitions, including purchases and sales, divided by produced volumes.

8) The production cost is calculated by dividing operational costs related to the production of oil and natural gas by the total production of oil and natural gas. For a specification of normalising assumptions, see end note 9. For normalisation of production cost, see table under Production cost.

9) By normalisation it is assumed that production costs in E&P Norway are incurred in NOK. Only costs incurred in International E&P are normalised at a USDNOK exchange rate of 6.00. Certain reclassifications have been made to prior periods’ figures to be consistent with the current period’s classifications.

For purposes of measuring Statoil’s performance against the 2007 target for normalised production cost a USDNOK exchange rate of 6.00 is used. The normalised production cost per boe is also adjusted for PSA effects at USD 60 per bbl.

10) Net interest-bearing debt is long-term interest-bearing debt and short-term interest-bearing debt reduced by cash, cash equivalents and short-term investments. In the first and third quarter, net interest-bearing debt is normalised by excluding 50% of the cash build-up related to tax payments due in the beginning of April and October each year.

FORWARD LOOKING STATEMENTS

This Operating and Financial Review contains certain forward-looking statements that involve risks and uncertainties. All statements other than statements of historical facts, including, among others, statements such as those regarding Statoil’s oil and gas production forecasts; production costs and other measures; targets with respect to participation in drilling and exploration activities; plans for future development and operation of projects; reserve information; expected HSE achievements; expected removal and abandonment obligations; expected exploration and development activities or expenditures; expected start-up dates for projects; expected benefits from the new energy and retail business model in Sweden; expected gains from the sale of assets; expected acquisitions or dispositions of assets; expected benefits from Statoil’s merger with Hydro’s oil and gas business; expected receipt of regulatory and other approvals required for the mergers; and the redemption, repurchase or annulment of shares buy-back policy are forward-looking statements. Forward-looking statements are sometimes, but not always, identified by such phrases as “will”, “expects”, “is expected to”, “should”, “may”, “is likely to”, “intends” and “believes”. These forward-looking statements reflect current views with respect to 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; political and economic policies of Norway and other oil-producing countries; general economic conditions; political stability and economic growth in relevant areas of the world; global political events and actions, including war, terrorism and sanctions; the timing of bringing new fields on stream; material differences from reserves estimates; inability to find and develop reserves; adverse changes in tax regimes; development and use of new technology; geological or technical difficulties; the actions of competitors; the actions of field partners; the actions of governments; relevant governmental approvals; industrial actions by workers; prolonged adverse weather conditions; natural disasters and other changes to business conditions. Additional information, including information on factors which may affect Statoil’s business, is contained in Statoil’s 2005 Annual Report on Form 20-F filed with the US Securities and Exchange Commission, which can be found on Statoil’s web site at www.statoil.com.

CONSOLIDATED STATEMENTS OF INCOME - USGAAP

CONSOLIDATED BALANCE SHEETS - USGAAP

CONSOLIDATED STATEMENTS OF CASH FLOWS - USGAAP

1. ORGANIZATION AND BASIS OF PRESENTATION

These consolidated interim USGAAP financial statements are unaudited, but reflect all adjustments that, in the opinion of management, are necessary to provide a fair presentation of the financial position, results of operations and cash flows for the dates and periods covered. All such adjustments are of normal and recurring nature. Interim period results are not necessarily indicative of results of operations or cash flows for a full-year period. The income statement and balance sheet as of and for the year ended December 31, 2005 have been derived from the audited financial statements at that date but do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in Statoil's financial statements for the year ended December 31, 2005. Certain reclassifications have been made to prior periods' figures to be consistent with the current period's classifications.

As of January 1, 2005, Statoil adopted Financial Accounting Standard Board (FASB) Staff Position FSP FAS 19-1, Accounting for Suspended Well Costs. Upon adoption of the FSP, the Company evaluated all existing capitalized exploratory well expenditures under the provisions of the FSP. The adoption did not have any effects on Statoil's Consolidated Statements of Income and financial position.

As of July 1, 2005 Statoil adopted FAS 153 Exchanges of Non-monetary Assets. Before adoption of FAS 153 Statoil recognized some exchanges at book value. After the adoption of FAS 153 only exchanges which lack commercial substance will be recognized at book value. The pronouncement is only required to be recognized prospectively and therefore no cumulative effect is recognized.

In March 2005, the FASB issued Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (FIN 47), which is effective for fiscal years ending after December 15, 2005. FIN 47 clarifies the requirement to record liabilities stemming from a legal obligation to retire assets, when a retirement depends on a future event. Statoil adopted FIN 47 in the fourth quarter of 2005. Application of the new interpretation resulted in an increase in net property, plant and equipment of NOK 35 million, an increase in accrued asset retirement obligation of NOK 95 million and a reduction in deferred tax of NOK 17 million. The increase represents the removal costs of retail stations. We consider that refining and processing plants that are not limited by an expected license period have indefinite lives and that there is no measurable asset retirement obligation. The implementation effect of NOK 43 million after tax is recorded as Operating expenses in the segment Other and eliminations.

As of January 1, 2006 Statoil adopted FAS 154 Accounting Changes and Error corrections as a replacement of APB Opinion No. 20 and FASB Statement No. 3. APB 20 required that most voluntary changes in accounting principle should be recognized in net income of the period of the change. The recognized effect should be the cumulative effect of changing to the new accounting principle. FAS 154, on the other hand, in general require retrospective application to prior periods' financial statements of changes in accounting principles. This Statement also requires that a change in depreciation, amortization or depletion method for long-lived, non-financial assets be accounted for as a change in accounting estimate effected by a change in accounting principle.

In June 2006 FASB issued FIN 48 Accounting for Uncertainty in Income Taxes an Interpretation of FASB Statement No. 109. This Interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, Accounting for Income Taxes. FIN 48 is effective for fiscal years beginning after December 15, 2006. Statoil will adopt FIN 48 in the first quarter of 2007. The effect on shareholders’ equity of implementation of this Interpretation is not expected to be significant.

On September 8, 2006 FASB issued FASB Staff Position (FSP) AUG AIR-1, Accounting for Planned Major Maintenance Activities. This FSP eliminates the accrue-in-advance method of accounting for planned major maintenance activities. This method of accounting for planned major maintenance activities was eliminated due to the FASB's belief that the resulting liability does not meet the definition of a liability in FASB Concepts Statement No. 6, Elements of Financial Statements. Statoil is using the accrue-in-advance method. As a result of the elimination of the accrue-in-advance method, the Airline Guide currently permits the use of one of the following three remaining methods: (1) direct expensing, (2) built-in overhaul, and (3) deferral. Statoil has elected the built-in overhaul method. The effective date of this FSP is an entity's first fiscal year beginning after December 15, 2006. Statoil will adopt the FSP on January 1, 2007. The effect of implementing the Staff Position is not expected to be significant.

On September 15, 2006 the FASB issued FAS 157 on fair value measurement. The Standard provides guidance for using fair value to measure assets and liabilities. The Standard also responds to investors’ requests for expanded information about the extent to which companies measure assets and liabilities at fair value, the information used to measure fair value, and the effect of fair value measurements on earnings. The Standard applies whenever other standards require (or permit) assets or liabilities to be measured at fair value. The Standard does not expand the use of fair value in any new circumstances. Statement 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. Early adoption is permitted. Statoil has not yet estimated the impact, if any, of the new standard.

On September 29, 2006 FASB issued FAS 158 Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans an Amendment of FASB Statements No. 87, 88, 106 and 132 (R). FAS 158 requires an employer to recognize the funded status of a defined benefit pension plan (other than a multi-employer plan) as an asset or liability in its statement of financial position with an offsetting amount to accumulated other comprehensive income and to recognize changes in that funded status in the year in which the changes occur through comprehensive income. Statoil previously deferred actuarial gains and losses and applied the corridor approach. Statoil is required to initially recognize the funded status of a defined benefit pension plan and to provide the required disclosures as of the end of the fiscal year ending December 31, 2006 and therefore adopted FAS 158 in the fourth quarter of 2006. Based on the funded status of Statoil’s plans, the adoption of FAS 158 resulted in an increase in Statoil’s pension liability of NOK 5.3 billion and a decrease to deferred tax liabilities and intangible assets of NOK 3.6 billion and NOK 0.3 billion, respectively. This resulted in a loss of NOK 1.9 billion being recognized in other comprehensive income.

The Standard also requires Statoil to measure the funded status of a plan as of the date of its year-end statement of financial position, with limited exceptions, as of December 31, 2008. However, since the Company already uses a measurement date of December 31 for its pension plans this requirement will have no impact.

In accordance with Norwegian requirements, Statoil will prepare its consolidated financial statements in accordance with International Financial Reporting Standards (IFRS) from January 1, 2007. Effective from that date, Statoil will also adopt IFRS as its primary accounting principles. Consequently, Statoil will from the same point in time reconcile its primary IFRS Financial Statements to USGAAP, representing a change from its current full USGAAP reporting.

2. SHAREHOLDERS' EQUITY

For the year ended December 31, 2006 there have been the following changes in shareholders' equity:


(in NOK million)	Total shareholders' equity


Shareholders' equity January 1, 2006	106,644
Net income for the year	40,615
Dividends paid	(17,756)
Treasury shares acquired for the employee share saving programs	(81)
Treasury shares acquired for annulment	(3,477)
Change in value of stock compensation plan	59
Change in foreign currency translation	(2,008)
Change in minimum pension liability and adoption of FAS 158	(1,881)
Change in available for sale securities	113


Shareholders' equity December 31, 2006	122,228

The following sets forth Statoil’s Comprehensive income for the periods shown:


	For the three months ended December 31,		For the year ended December 31,
	For the three months ended December 31,		For the year ended December 31,
(in NOK million)	2006	2005	2006	2005


Net income	12,012	8,523	40,615	30,730
Foreign currency translation adjustment	(2,005)	2,062	(2,008)	2,470
Minimum pension liability	(1,887)	(117)	(1,881)	(117)
Derivatives designated as cash flow hedges	0	254	0	77
Change in available for sale securities	113	0	113	0


Comprehensive income	8,233	10,722	36,839	33,160

On May 10, 2006 the annual General Meeting resolved to reduce the Company’s Share capital by a total of NOK 58,604,712.50 through the annulment of 23,441,885 own shares. After the annulment Statoil’s Share capital is NOK 5,415,359,287.50 comprised of 2,166,143,715 shares.

The annual General Meeting also authorized the Board of Directors to acquire own shares for subsequent annulment. The authorization is valid until the next ordinary General Meeting, and applies to the acquisition of up to 50,000,000 shares in the market, at a price of between NOK 50 and NOK 500 per share. Under an agreement with the Norwegian state, which currently has an ownership interest in Statoil of 70.9 per cent, a proportion of the state’s shares will later be redeemed and annulled, so that the state’s owner interest remains unchanged. The total annulment could thus involve up to 171,798,603 shares, or approximately 7.9 per cent of the company’s Share capital. The resolution to annul shares will be made by a later General Meeting, and requires a two-thirds majority vote of the aggregate number of votes cast, as well as a two-thirds majority of the Share capital represented at the General Meeting. Under its agreement with Statoil, the Norwegian state has also agreed to vote in favor of the annulment resolution. As of December 31, 2006 Statoil has acquired 5,867,000 shares in the open market according to this authorization. In addition Statoil is obligated to acquire 14,291,848 shares from the Norwegian state. Both the acquired shares and the firm obligation are included in Treasury shares.

On December 18, 2006 the Board of Directors of Statoil ASA (Statoil) and Norsk Hydro ASA (Hydro) agreed to recommend to their shareholders a merger of Hydro’s oil and gas activities with Statoil, see note 9. Hydro’s shareholders will hold 32.7 per cent and Statoil’s shareholders will hold 67.3 per cent of the new company. Hydro’s shareholders will receive 0.8622 shares in the new company for each Hydro share and continue as owners of Hydro. Statoil’s shareholders will maintain their holdings in the new company on a one-for-one basis. The Norwegian state will hold approximately 62.5 per cent in the merged entity. According to the agreement dated December 18, 2006 between Hydro and Statoil, Statoil will no longer be allowed to use the aforementioned authorization to acquire own shares for subsequent annulment.

3. SEGMENTS

Statoil operates in four segments; Exploration and Production Norway, International Exploration and Production, Natural Gas and Manufacturing and Marketing.

Operating segments are determined based on differences in the nature of their operations, geographic location and internal management reporting. The composition of segments and measure of segment profit are consistent with that used by management in making strategic decisions.

Segment data for the three months and the years ended December 31, 2006 and 2005 is presented below:


(in NOK million)	Exploration and Production Norway	International Exploration and Production	Natural Gas	Manufacturing and Marketing	Other and eliminations	Total




Three months ended December 31, 2006
Revenues third party (including Other income)	969	1,288	16,753	84,471	159	103,640
Revenues inter-segment	27,802	4,161	135	91	(32,189)	0
Income (loss) from equity investments	15	0	66	19	(5)	95


Total revenues	28,786	5,449	16,954	84,581	(32,035)	103,735


Income before financial items, income taxes and minority interest	21,081	1,295	2,331	1,141	211	26,059
Imputed segment income taxes	(15,746)	(954)	(1,475)	(202)	0	(18,377)


Segment net income	5,335	341	856	939	211	7,682


Three months ended December 31, 2005
Revenues third party (including Other income)	591	427	15,694	90,833	189	107,734
Revenues inter-segment	28,202	5,678	101	59	(34,040)	0
Income (loss) from equity investments	13	0	70	68	(48)	103


Total revenues	28,806	6,105	15,865	90,960	(33,899)	107,837


Income before financial items, income taxes and minority interest	22,538	826	2,435	2,692	(691)	27,800
Imputed segment income taxes	(17,290)	(664)	(1,669)	(244)	0	(19,867)


Segment net income	5,248	162	766	2,448	(691)	7,933


Year ended December 31, 2006
Revenues third party (including Other income)	3,814	6,953	60,264	353,294	431	424,756
Revenues inter-segment	113,075	17,690	652	597	(132,014)	0
Income (loss) from equity investments	78	0	218	133	(19)	410


Total revenues	116,967	24,643	61,134	354,024	(131,602)	425,166


Income before financial items, income taxes and minority interest	89,389	10,928	10,009	6,998	(443)	116,881
Imputed segment income taxes	(67,269)	(5,242)	(6,704)	(1,875)	0	(81,090)


Segment net income	22,120	5,686	3,305	5,123	(443)	35,791


Year ended December 31, 2005
Revenues third party (including Other income)	2,114	6,366	44,973	332,431	437	386,321
Revenues inter-segment	95,417	13,197	586	236	(109,436)	0
Income (loss) from equity investments	92	0	264	826	(92)	1,090


Total revenues	97,623	19,563	45,823	333,493	(109,091)	387,411


Income before financial items, income taxes and minority interest	74,132	8,364	5,901	7,593	(947)	95,043
Imputed segment income taxes	(56,030)	(3,027)	(4,013)	(1,288)	0	(64,358)


Segment net income	18,102	5,337	1,888	6,305	(947)	30,685

Imputed segment taxes in the segment International Exploration and Production in the fourth quarter of 2006 are influenced by significant exploration expenses for which valuation allowances have been provided. The imputed taxes in this segment in the fourth quarter of 2005 were influenced by the impairment charge of Statoil's share in the Iranian South Pars gas field project.

Borrowings are managed at a corporate level and financial items are not allocated to segments. Income tax is calculated on Income before financial items, income taxes and minority interest. Additionally, income tax benefit on segments with net losses is not recorded. As such, Imputed segment income tax and Segment net income can be reconciled to Income taxes and Net income per the Consolidated Statements of Income as follows:


	For the three months ended December 31,		For the year ended December 31,
	For the three months ended December 31,		For the year ended December 31,
(in NOK million)	2006	2005	2006	2005


Segment net income	7,682	7,933	35,791	30,685
Net financial items	2,811	(1,515)	4,814	(3,512)
Tax on financial items and other tax adjustments	1,608	2,286	730	4,322
Minority interest	(89)	(181)	(720)	(765)


Net income	12,012	8,523	40,615	30,730


Imputed segment income taxes	18,377	19,867	81,090	64,358
Tax on financial items and other tax adjustments	(1,608)	(2,286)	(730)	(4,322)


Income taxes	16,769	17,581	80,360	60,036

Included in Tax on financial items and other tax adjustments in the fourth quarter of 2006 is a one-time NOK 2 billion reduction of deferred tax liabilities relating to new tax rules for allocation of financial items with respect to the Norwegian Continental Shelf (NCS) activity and temporary differences on intercompany transactions.

The future effect of the new tax rules for allocation of financial items on Income taxes payable cannot be determined in advance as the final allocation will depend on a number of uncertain factors, including the level and nature of the financial items, especially foreign exchange fluctuations.

4. INVENTORIES

5. EMPLOYEE RETIREMENT PLANS

6. FINANCIAL ITEMS

7. CHANGE IN ESTIMATE OF ASSET RETIREMENT OBLIGATIONS

The asset retirement obligations have increased from NOK 20 billion to NOK 29 billion, mostly due to upward revisions of cost estimates related to removal complexity, rigs, marine operations and heavy lift vessels. The change has material effects on the Net property, plant and equipment and Other liabilities captions in the Consolidated Balance Sheets but only immaterial effects on the Consolidated statement of income for the periods presented. The changes are expected however to have a significant impact on future depreciation and accretion charges. The amount of increase in Depreciation is uncertain and will depend on future levels of production. Based on current production forecasts Depreciation is estimated to increase by NOK 1.6 billion in 2007. Accretion is estimated to increase by NOK 0.4 billion per year. These increases will mainly affect the Total expenses before financial items in Exploration and Production Norway segment.

8. COMMITMENTS AND CONTINGENT LIABILITIES

In 2004 Statoil, as an owner in BTC Co, entered into guarantee commitments for financing of the development of the BTC pipeline. At December 31, 2006 the maximum potential future amount of payment under these guarantee commitments amounts to USD 110 million (NOK 0.7 billion), and is subject to measurement requirements of FIN 45. The expected fair value of the guarantee has been recognized as a current liability in the Consolidated Balance Sheets and the cost has been recorded as other financial expenses.

Statoil Detaljhandel has issued guarantees amounting to a total of NOK 1.0 billion, the main part of which relates to guarantee commitments to retailers. The liability recognized under FIN 45 in the Consolidated Balance Sheets related to these guarantee commitments is immaterial at period-end.

The Ministry of Energy and Petroleum in Venezuela has challenged the production level and the royalty rates of the Sincor joint venture. Effective as of June 24, 2005 Sincor has been charged and has paid an increased royalty rate of 30 per cent related to production exceeding 114,000 barrels a day. Statoil and our partner have filed administrative appeals to annul the demand for such payments. At year-end 2006 the partners in the Sincor joint venture were Statoil with 15 per cent, PDVSA with 38 per cent and Total with 47 per cent. The Venezuelan Government has recently indicated that the state requires a majority of minimum 60 per cent for the state-owned PDVSA in the Sincor joint venture, which is to migrate into a mixed company, i.e. a company with a majority Venezuelan state-ownership share. The specifics and extent of such a transition and the level of compensation to be received by Statoil cannot be ascertained at this time. Statoil and our partner are communicating with the Ministry to find an overall solution for Sincor.

A group of Norwegian pensioners has brought legal proceedings against Statoil ASA over certain changes made to the pension fund articles of association in 2002, relating to the basis for adjustment of pension payments after that date. Stavanger District Court ruled in favor of Statoil in the first quarter of 2007. The verdict is not yet legally binding and may be subject to appeal. Depending on the final outcome of this case, the issue might impact certain assumptions used in the computation of Statoil's pension obligations as reflected in the Consolidated Financial Statements.

Statoil ASA issued a declaration to the Norwegian Ministry of Petroleum and Energy (MPE) in 1999 in connection with a dispute between four Åsgard partners and Statoil related to the construction of new facilities for the Åsgard development at the Kårstø Terminal. The declaration confirmed the MPE similar treatment as the four Åsgard partners with respect to the disputed issues, which had been resolved by 2004. The MPE has indicated that a claim will be presented based on the declaration.

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

The Norwegian National Authority for Investigation and Prosecution of Economic and Environmental Crime (Økokrim) conducted an investigation concerning an agreement which Statoil entered into in 2002 with Horton Investments Ltd for consultancy services in Iran. In June 2004, Økokrim informed Statoil that it had concluded that Statoil had violated the Norwegian Penal Code’s prohibitions on trading in influence, which became effective on July 4, 2003, and imposed a penalty of NOK 20 million (USD 3 million). In October 2004, Statoil agreed to accept the penalty without admitting or denying the charges by Økokrim.

On October 13, 2006, Statoil announced that it had reached agreements with the U.S. Securities and Exchange Commission (SEC), the U.S. Department of Justice (DOJ), and the United States Attorney’s Office for the Southern District of New York (USAO). Statoil has, in the agreements with the DOJ and USAO, accepted a penalty of USD 10.5 million for having violated the U.S. Foreign Corrupt Practices Act (FCPA), as well as accepting responsibility for bribery in connection with the payments under the consultancy services contract with Horton Investments Ltd, for accounting for those payments improperly in its books and records, and for having insufficient internal controls in place to prevent the payments. The NOK 20 million (USD 3 million) fine paid to Økokrim has been deducted, so that the fine actually paid by Statoil under this agreement is USD 7.5 million. Statoil has, in the agreement with the SEC, neither admitted nor denied the charges, but agreed to pay USD 10.5 million as disgorgement.

The settlement takes the form of a three-year deferred prosecution agreement with the DOJ and USAO and a Cease and Desist Order with the SEC. In the deferred prosecution agreement, Statoil has consented to the filing with the United States Court for the Southern District of New York of a criminal information charging violations of the anti-bribery and books and records provisions of the FCPA. If Statoil fulfills its obligations under the deferred prosecution agreement for three years the criminal charges will be dismissed and the Horton case will be closed.

Iranian authorities have been carrying out inquiries into the matter. In April 2004 the Iranian Consultative Assembly initiated an official probe into allegations of corruption in connection with the Horton matter with Iran. The probe was finalized for the parliamentary session at the end of May 2004. It was reported in the international press that at such time no evidence of wrongdoing by the subjects of the probe in Iran had been revealed by the probe.

9. SUBSEQUENT EVENTS AND SIGNIFICANT BUSINESS DEVELOPMENTS

On March 8, 2006 Statoil entered into an agreement to acquire a 25 per cent share in the license 218 in Blocks 6706/10 and 6706/12 in the Norwegian Sea. As a result of the agreement, Statoil increased its share to a 75 per cent interest in the license. Several discoveries have been made in this area, including the Luva discovery. The transaction was completed in the second quarter of 2006 and was recorded in the segment Exploration and Production Norway.

On September 15, 2006 Statoil entered into an agreement to acquire working interest in two US Gulf of Mexico deepwater discoveries and one exploration prospect at a cost of USD 700 million. The new assets are located in the Greater Tahiti and Walker Ridge areas. As a result of the agreement, Statoil has a 17.5 per cent working interest in the Caesar discovery, a 12.5 per cent working interest in the Big Foot discovery and a 12.5 per cent working interest in the Big Foot North prospect. The transaction was completed in the fourth quarter of 2006 and was recorded in the segment International Exploration and Production.

On November 3, 2006 Statoil entered into an agreement with Anadarko Petroleum Corporation to acquire two of Anadarko’s US Gulf of Mexico discoveries and one prospect at a cost of USD 901 million. The new assets are located in the Greater Tahiti and Walker Ridge areas. As a result of the agreement Statoil has a 27.5 per cent working interest in the Big Foot discovery and a 27.5 per cent working interest in the Big Foot North prospect, including the additions from the agreement mentioned above. In addition Statoil will have a 25 per cent working interest in the Knotty Head discovery. The transaction was completed in the first quarter of 2007 and will be recorded in the segment International Exploration and Production.

The Board of Directors of Statoil ASA and Norsk Hydro ASA have agreed to recommend to their shareholders a merger of Hydro’s oil and gas activities with Statoil. The proposed merger is subject to approval by the General Meetings of the two companies as well as by regulatory authorities. The General Meetings are expected to be held during second quarter of 2007. Final closing is expected to be in the third quarter of 2007. In the meantime, Hydro and Statoil will be managed as separate companies.

Assets held for sale and discontinuing operation
On January 31, 2006 Statoil ASA announced its decision to evaluate strategic options for its Irish downstream Retail and Commercial & Industrial business ("Statoil Ireland"), including a possible sale. This decision resulted from a review of the Retail Business Portfolio and the intention to accelerate strategic commitment to Scandinavian and Eastern European markets.

On June 21, 2006 Statoil entered into an agreement to sell Statoil Ireland to Topaz, a financial consortium lead by Ion Equity. The transaction was completed on October 31, 2006. The estimated gain from the transaction is NOK 0.6 billion before tax and is included in the Manufacturing and Marketing segment in the fourth quarter of 2006.

The result of the operations and the gain from the transaction are treated as discontinued operation for all periods presented. The net result is insignificant and is included in Selling, general and administrative expenses. Revenues are reduced by NOK 6.4 billion and NOK 5.9 billion for the year ended December 31, 2006 and the year ended December 31, 2005 respectively.

All assets held for sale were included in the Prepaid expenses and other current assets caption in the Consolidated Balance Sheets until the transaction was completed, and amounted to NOK 1.9 billion as at December 31, 2005.

All liabilities held for sale were included in the Accrued liabilities caption in the Consolidated Balance Sheets until the transaction was completed, and amounted to NOK 0.9 billion as at December 31, 2005.

10. RECONCILIATION BETWEEN USGAAP AND NGAAP

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.

PRESS RELEASE:

BEST ANNUAL INCOME EVER

The Statoil group had a net income of NOK 40.6 billion in 2006, compared to NOK 30.7 billion in 2005. Net income for the fourth quarter of 2006 was NOK 12.0 billion, compared to NOK 8.5 billion for the same period of 2005.

The increase in net income of NOK 3.5 billion from the fourth quarter of 2005 to the fourth quarter of 2006 was mainly due to higher financial income and lower income taxes.

”The annual income for 2006 is the best ever for Statoil. We maintain strong earnings and competitive returns, despite temporarily lower production overall,” says chief executive Helge Lund.

“Through the acquisition of two deepwater portfolios in the Gulf of Mexico (GoM) from Anadarko and Plains and the subsequent divestment of the retail operation in Ireland we have further upgraded our portfolio,” states the CEO.

“Both the fourth quarter and the year as a whole have been characterised by high exploration activity, both on the Norwegian continental shelf (NCS) and internationally. At the same time we have also secured new exploration acreage, put new fields on stream and launched new field development plans that support the group’s long-term growth ambition,” says Mr Lund.

The CEO points to the field development plans for Gjøa and Alve as good examples of the group’s efforts in further developing the NCS. During 2006, nine new fields came on stream. On the NCS, Statoil’s portfolio has been strengthened with the Norne K-template, Gimle, Fram East, Oseberg West Flank and Ringhorne East, while the international upstream position has been strengthened with production from In Amenas in Algeria, Dalia in Angola and East Azeri and Shah Deniz in Azerbaijan.

“On 18 December it was announced that the boards of directors of Statoil and Hydro recommend a merger of Hydro’s oil- and gas activities with Statoil. The processes that lead up to the necessary approvals of the merger are well under way. By combining the strengths from both companies, we will build a strong Norwegian based energy company, well positioned to succeed even better in the global competition,” says Mr Lund.

Return on average capital employed after tax (ROACE) (*) for the 12 months ended 31 December 2006 was 27.1%, compared to 27.6% for the 12 months ended 31 December 2005. The decrease in ROACE was mainly due to the increase in capital employed partly offset by higher net income. ROACE is defined as a non-GAAP financial measure (*).

In 2006, earnings per share were NOK 18.79 (USD 3.02) compared to NOK 14.19 (USD 2.10) in 2005. In the fourth quarter of 2006, earnings per share were NOK 5.58 (USD 0.90) compared to NOK 3.94 (USD 0.59) in the fourth quarter of 2005.

Statoil’s board of directors will propose to the annual general meeting an ordinary dividend of NOK 4.00 per share for 2006, as well as NOK 5.12 per share in special dividend. In 2005 the ordinary dividend was NOK 3.60 per share, while the special dividend amounted to NOK 4.60 per share.

Income before financial items, income taxes and minority interest in 2006 was NOK 116.9 billion compared to NOK 95.0 billion in 2005. The increase was mainly due to a 20% increase in the average oil price measured in NOK and a 32% increase in the gas price measured in NOK. The increase was partly offset by a reduction in lifted oil volumes and an increase in cost items.

Income before financial items, income taxes and minority interest decreased from NOK 27.8 billion in the fourth quarter of 2005 to NOK 26.1 billion in the same period of 2006. This was mainly related to a 9% decrease in the total oil and gas liftings, a 43% reduction in refining margins, and the tax-free capital gain of NOK 1.5 billion from the sale of Borealis in the fourth quarter of 2005. In addition, operating expenses increased by NOK 1.2 billion and exploration expenses increased by NOK 1.2 billion, mainly due to higher activity.

The decrease in income before financial items, income taxes and minority interest in the fourth quarter of 2006 was partly offset by an increased average gas price measured in NOK of 16%. Selling, general and administrative expenses decreased by NOK 1.3 billion in the fourth quarter, mainly due to decreased insurance cost of NOK 0.9 billion. The fourth quarter of 2005 included an insurance cost of NOK 0.5 billion due to insurance premium commitments and accruals related to liabilities in the two mutual insurance companies in which Statoil Forsikring participates. These accruals were partially reversed by NOK 0.4 billion in the fourth quarter of 2006. In addition, discontinuing operations in Ireland, including a pre-tax gain of NOK 0.6 billion, is reported net under selling, general and administrative expenses. Depreciations decreased by NOK 1.2 billion, mainly due to the write-down of the South Pars field in Iran in the fourth quarter of 2005 of NOK 2.2 billion, partly offset by increased depreciations related to producing fields.

USGAAP income statement

USGAAP income	Fourth quarter			Year ended 31 December
statement	2006	2005		2006	2005
(in millions)	NOK	NOK	Change	NOK	NOK	Change


Sales	103,591	106,142	(2%)	423,528	384,653	10%
Equity in net income of affiliates	95	103	(8%)	410	1,090	(62%)
Other income	49	1,592	(97%)	1,228	1,668	(26%)


Total revenues	103,735	107,837	(4%)	425,166	387,411	10%


Cost of goods sold	58,295	60,490	(4%)	239,544	230,721	4%
Operating expenses	9,818	8,643	14%	34,320	30,243	13%
Selling, general and administrative expenses	1,289	2,574	(50%)	6,990	7,189	(3%)
Depreciation, depletion and amortisation	6,357	7,592	(16%)	21,767	20,962	4%
Exploration expenses	1,917	738	160%	5,664	3,253	74%


Total expenses before financial items	77,676	80,037	(3%)	308,285	292,368	5%


Income before financial items, income taxes and minority interest	26,059	27,800	(6%)	116,881	95,043	23%

Net financial items	2,811	(1,515)	286%	4,814	(3,512)	237%


Income before income taxes and minority interest	28,870	26,285	10%	121,695	91,531	33%

Income taxes	(16,769)	(17,581)	(5%)	(80,360)	(60,036)	34%
Minority interest	(89)	(181)	(51%)	(720)	(765)	(6%)


Net income	12,012	8,523	41%	40,615	30,730	32%




Income before financial items, income taxes and minority	Fourth quarter			Year ended 31 December
interest for the segments	2006	2005		2006	2005
(in millions)	NOK	NOK	Change	NOK	NOK	Change


E&P Norway	21,081	22,538	(6%)	89,389	74,132	21%
International E&P	1,295	826	57%	10,928	8,364	31%
Natural Gas	2,331	2,435	(4%)	10,009	5,901	70%
Manufacturing & Marketing	1,141	2,692	(58%)	6,998	7,593	(8%)
Other	211	(691)	131%	(443)	(947)	53%


Income before financial items, income taxes and minority interest	26,059	27,800	(6%)	116,881	95,043	23%



Financial data


	Fourth quarter			Year ended 31 December
	2006	2005		2006	2005
	NOK	NOK	Change	NOK	NOK	Change


Weighted average number of ordinary shares outstanding	2,151, 148,995	2,165, 464,649		2,161, 028,202	2,165, 740,054
Earnings per share	5.58	3.94	42%	18.79	14.19	32%
ROACE (last 12 months)	27.1%	27.6%		27.1%	27.6%
Cash flows provided by operating activities (billion)	8.7	0.0	n/a	60.9	56.3	8%
Gross investments (billion)	15.7	9.1	72%	46.2	46.2	0%
Net debt to capital employed ratio	16.8%	15.1%		16.8%	15.1%



Operational data


	Fourth quarter			Year ended 31 December
	2006	2005	Change	2006	2005	Change


Average oil price (USD/bbl)	59.3	57.3	3%	64.4	53.6	20%
USDNOK average daily exchange rate	6.42	6.63	(3%)	6.42	6.45	0%
Average oil price (NOK/bbl) [*]	381	380	0%	413	345	20%
Gas prices (NOK/scm)	2.01	1.74	16%	1.91	1.45	32%
Refining margin, FCC (USD/boe) [*]	4.7	8.3	(43%)	7.1	7.9	(10%)
Total oil and gas production (1,000 boe/day) [*]	1,153	1,232	(6%)	1,135	1,169	(3%)
Total oil and gas liftings (1,000 boe/day) [*]	1,145	1,252	(9%)	1,133	1,166	(3%)
Reserve replacement rate (annual) [*]				73%	102%	(28%)
Reserve replacement rate 3-year average				94%	102%	(8%)
Proved reserves (mboe)				4,185	4,295	(3%)
Production cost (NOK/boe, last 12 months) [*]	26.6	22.3	20%	26.6	22.3	20%
Production cost normalised (NOK/boe, last 12 months) [*]	26.2	22.0	19%	26.2	22.0	19%

Total oil and gas liftings in 2006 were 1,133,000 boe per day compared to 1,166,000 boe per day in 2005. This indicates an average underlift of 2,000 boe per day in 2006, compared to an average underlift of 3,000 boe per day in 2005.

In the fourth quarter of 2006 total oil and gas liftings were 1,145,000 boe per day compared to 1,252,000 boe per day in the fourth quarter of 2005. This indicates an average underlift of 8,000 boe per day in the fourth quarter of 2006 compared to an average overlift of 20,000 boe per day in the fourth quarter of 2005.

Exploration expenditure in 2006 was NOK 7.5 billion, compared to NOK 4.3 billion in 2005. Exploration expenditure in the fourth quarter of 2006 amounted to NOK 2.0 billion, compared to NOK 1.1 billion in the fourth quarter of 2005. Exploration expenditure reflects the period's exploration activities.

Exploration expenses for the period consist of exploration expenditure adjusted for the period's change in capitalised exploration expenditure. Exploration expenses in 2006 amounted to NOK 5.7 billion, compared to NOK 3.3 billion in 2005. In the fourth quarter of 2006 exploration expenses amounted to NOK 1.9 billion, compared to NOK 0.7 billion in the fourth quarter of 2005. The increase both in exploration expenditure and exploration expenses was mainly due to higher exploration activity in 2006 compared to 2005. Exploration expenses also increased due to an increase in expense of previously capitalised licences and well expenditures.


	Fourth quarter			Year ended 31 December
Exploration	2006	2005		2006	2005
(in millions)	NOK	NOK	Change	NOK	NOK	Change


Exploration expenditure (activity)	1,980	1,093	81%	7,451	4,337	72%
Expensed, previously capitalised exploration expenditure	404	3	n/a	667	158	322%
Capitalised share of current period's exploration activity	(467)	(358)	(30%)	(2,454)	(1,242)	(98%)


Exploration expenses	1,917	738	160%	5,664	3,253	74%

In the fourth quarter of 2006, a total of seven exploration and appraisal wells were completed, four on the NCS and three internationally. Four wells resulted in discoveries, while one well awaits final evaluation. In addition, one exploration extension on the NCS was completed in the fourth quarter of 2006 and resulted in a discovery. Four exploration wells were completed in the fourth quarter of 2005.

Proved reserves at the end of 2006 were 4,185 million boe, compared to 4,295 million boe at the end of 2005, a decrease of 111 million boe. In 2006, 307 million boe were added, mostly through revisions, extensions and discoveries, compared to 453 million boe in 2005. Production in 2006 was 415 million boe compared to 427 million boe in 2005.

The reserve replacement ratio (*) was 73% in 2006, compared to 102% in 2005, while the average three-year replacement ratio was 94% in 2006, compared to 102% in of 2005.

Production cost per boe was NOK 26.6 for the 12 months ended 31 December 2006, compared to NOK 22.3 for the 12 months ended 31 December 2005 (*).

Normalised at a USDNOK exchange rate of 6.00 and adjusted for the estimated volume due to PSA effects based on an average oil price of USD 60 per bbl, the production cost for the 12 months ended 31 December 2006 was NOK 26.2 per boe, compared to NOK 22.0 per boe for the 12 months ended 31 December 2005 (*).

The production unit costs, both actual and normalised, have increased, mainly due to a higher activity level, temporary lower production, and increasing industry cost pressure.

Net financial items amounted to an income of NOK 4.8 billion in 2006 compared to an expense of NOK 3.5 billion in 2005. In the fourth quarter of 2006 net financial items were an income of NOK 2.8 billion, compared to an expense of NOK 1.5 billion in the fourth quarter of 2005.

The increased income in 2006 was mainly caused by increased currency gains, due to a weakening of the USD in relation to the NOK in 2006. Most of the currency gains relate to Statoil’s short-term NOK hedging policy and unrealised gains on long-term USD debt.


Exchange rates	31.12.2006	30.09.2006	31.12.2005	30.09.2005	31.12.2004

USDNOK	6.26	6.50	6.77	6.54	6.04

Income taxes in 2006 were NOK 80.4 billion, with a corresponding tax rate of 66.0%, compared to income taxes in 2005 of NOK 60.0 billion with a corresponding tax rate of 65.6%.

In the fourth quarter of 2006 income taxes were NOK 16.8 billion, equivalent to a tax rate of 58.1%. Income taxes in the fourth quarter of 2005 were NOK 17.6 billion, equivalent to a tax rate of 66.9%. Adjusted for the effect of the tax-free capital gain on the sale of shares in Borealis, the tax rate was 71.0%. Adjusted for the one-time NOK 2.0 billion reduction of deferred tax liabilities relating to new tax rules for allocation of financial items with respect to the NCS and temporary differences in intercompany transactions, the tax rate for the fourth quarter 2006 was 65.0%. The lower adjusted tax rate in the fourth quarter of 2006 compared with the fourth quarter of 2005 mainly relates to relatively higher income outside the NCS, which is taxed at a lower tax rate, and impact of financial items.

Health, safety and the environment (HSE)
There were no fatalities during 2006. The serious incident indicator has been halved since 2001, and has never been at a lower level. The indicators for personnel injuries have shown a slight increase from the record low results in 2005. The serious injuries have decreased from 22 in 2005 to 18 in 2006.

In 2006, Statoil started a major initiative to reduce incidents caused by dropped objects. There has been a significant reduction in serious incidents of 25% since 2005. The chief executive’s HSE prize 2006 was awarded to the zero dropped objects team, which is devoted to identifying and reducing the threat of dropped objects offshore.

The total volume of oil spills decreased from 2005 to 2006. There was one oil spill of some significance in 2006, in Nynäshamn in Sweden. The spill amounted to 104 standard cubic metres (scm). Statoil’s oil spill emergency response was efficient, and as a result only 10 scm spillage remains uncollected.

Our objective is zero harm to health, security and the environment. Sustained top management involvement, a strong focus on developing the right HSE attitude throughout the company, measures for upgrading skills, and cooperation with our contractors to further improve HSE results, will continue with undiminished strength.


	Fourth quarter		Year ended 31 December
HSE	2006	2005	2006	2005


Total recordable injury frequency	4.8	5.3	5.7	5.1
Serious incident frequency	2.4	1.8	2.1	2.3
Unintentional oil spills (number)	76	144	292	534
Unintentional oil spills (volume, scm)	30	350	157	442

* See end notes in the complete quarterly report.

Further information from:

Investor relations
Lars Troen Sørensen, senior vice president investor relations, + 47 90 64 91 44 (mobile), +47 51 99 77 90 ( office)
Geir Bjørnstad, vice president, US investor relations, + 1 203 978 6950

Press
Ola Morten Aanestad, vice president public affairs, +47 48 08 02 12 (mobile), +47 51 99 13 77 (office)

GROUP BALANCE SHEET

* Translated into US dollar at the rate of NOK 6.2287 to USD 1, the Federal Reserve noon buying rate in the City of New York on 29 December, 2006.

BUSINESS UPDATE 4Q 2006

Content
•Statoil group
•Technology & Projects
•Exploration
•E&P Norway
•E&P International
•NG slide

2 Although a gas field, the licence partners will receive their remuneration as condensate and LPG

Setting a bold example in the north
Snøhvit
•Advanced well-stream transport
•Pioneering approach
•Progress according to revised plan
•Challenging until completion

Breaking technology barriers
Tyrihans
•First subsea raw seawater injection system
•«From modem to broadband»
•Supplier cooperation securing capacity

Extending production in the North Sea
Statfjord Late Life
•Transforming producing platforms
•Increasing oil recovery to 68 per cent
•Increasing gas recovery to 75 per cent

Building blocks for more cost-efficient developments
Improved oil and gas recovery

Handling increasing complexity
Subsea field development
•Challenges:
–Low pressure reservoirs
–Longer distances
–Greater water depths
•Toolbox:
–Processing and compression
–Well stream transport
–All-electric systems

High pressure, high temperature (HPHT) fields Development in complexity
New developments internationally
• Gulf of Mexico
• Venezuela
New projects NCS
• Valemon
• Gudrun
• Morvin

World Class on IOR
. . . due to strong capabilities in reservoir management
Expected ultimate recovery factors

Exploration wells 2006
Completed or ongoing wells:
•17 wells was completed –11 Statoil operated –6 partner operated
• 6 wells ongoing at year-end –2 Statoil operated –4 Partner operated
•4 exploration extensions have been drilled in 2006
* Ongoing wells

Secured rig capacity
Added 10 rig years for the period
•2008 – 2012 during 4q
–Well covered for production drilling through 2q 2009
–Most of needed capacity for international operations covered through 2010
Aker newbuild

One shelf, distinct provinces
Capture frontier potential Crossing energy frontiers
Mature opportunities Options for the long term
Accelerate growth Strengthen strategic position
Leverage infrastructure Maximise value creation

APA (Awards in Predefined Areas) 2006
•Announcement was January 21, 2006
–192 blocks or part of blocks were announced
–11 more blocks were announced compared to APA2005
•UPN LET has evaluated the announced blocks to find new opportunities, and to secure new resources to existing infrastructure
•Application deadline was September 29, and Statoil applied for 6 new areas/licences, and 6 extensions of existing licences (9 as operator and 3 as partner), a total of 12 areas
•In January 2007 Statoil were awarded interests in eight production licences, including six operatorships, in the North and Norwegian Sea

Kristin – status 4Q
•Completed new well January 28th 2007
–8 out 12 wells completed
•Limitations on pressure depletion gives restrictions on production until all wells are completed
–New schedule for plateau production expected summer 2007

Kvitebjørn - temporary production decrease
•Kvitebjørn reduced production temporarily by 50 percent from December 23 2006 for a period of five months to:
–enable sound reservoir management and safe drilling operations
–enable drilling of three additional wells
•Troll gas flex (flexible production permit) will be utilized to counteract the curtailment and secure regular supply
•First of three remaining wells are now being drilled

E&P Norway 2006
•5 new project on stream
•5 projects sanctioned
•21 completed exploration wells from
–16 exploration wells
–1 appraisal wells
–4 extension wells
•10 discoveries from
–7 exploration wells
–1 appraisal wells
–2 extension well
•4 licences awarded

Strong production growth in Angola
•Current entitlement production above 70,000 boepd
•Several developments in progress
•Continued exploration success
•13.33% ownership in blocks 15, 17 and 31

Partner in key regional energy projects Azerbaijan
•Azeri-Chirag-Gunashli oil development:
–Phase I & II on stream
–Phase III on stream 2008
•Baku-Tblisi-Ceyhan oil pipeline
–First cargo loaded Ceyhan June 2006
•Shah Deniz phase I and SCP
–Start-up 4Q 2006 (production currently suspended)
–Assumed re-start by end 1Q 2007
–Additional phases under evaluation

Building a strong position in Algeria
•In Salah
–Algeria’s third largest gas development
–Production started July 2004
•In Amenas
–Algeria’s fourth largest gas development
–Production started June 2006
•Hassi Mouina
- exploration licence
–Drilling started November 2006
•Cooperation with Sonatrach
–LNG imports to Cove Point
–MoU for joint developments

Strengthening the Gulf of Mexico portfolio
Partner in eleven high quality discoveries in deepwater US GoM

A major gas player in Europe
Estimated market position
in 2007 based on current contracts*

Natural gas prices
Forward curve as of January 30, 2007
Source: German statistical office, P. Heren, IPE, Platts, NYMEX

Indigenous gas production
OECD Europe gas production 1995 - 2020
•Norway: largest producer in OECD Europe; and growing
•UK: uncertainty related to pace of reduction
•Netherlands, other OECD Europe on modest decline
Sources: Norway (MPE), otherwise Wood Mackenzie

Cove Point expansion approved
•FERC approval received 15 June, official ground-breaking took place on 5 October
•Agreement between Statoil and Dominion involves annual terminal capacity rights of approx 7.7 bcm of gas for a 20-year period
•Expansion expected to be in operation 1Q 2009
Statoil capacity increases
from 2.4 to 10.1 BCM/Year

Executing large and complex projects
Langeled pipeline project
•Precision in planning
•Delivered on time, NOK 3 bn under budget

Langeled
42” pipeline from Nyhamna to Sleipner
Tie in facilities at Sleipner Riser
44” pipeline from Sleipner to Easington UK
Terminal facilities Easington (Centrica)
Statoil share: 15%
Southern Leg operational from 01.10.06
Northern Leg operational from 01.10.07

PRESS RELEASE:

Synergy potential from the merger between Statoil and Hydro's oil and gas activities

Statoil (OSL: STL; NYSE: STO) has today 12 February 2007 presented its view on the synergy potential from the merger between Statoil and Hydro's (OSE: NHY; NYSE: NHY) oil and gas activities.

Synergies resulting from the merger will fall into the following three categories:

Lower costs, due to elimination of duplication and higher efficiency through economies of scale.
Higher revenues, by implementing best practice and deploying scarce resources and competencies more efficiently.
New growth opportunities because of improved international competitive position, larger portfolio and larger organisational and financial capacity.

“By combining the strengths of both organisations, the merged company will be able to pursue more opportunities and take on more tasks. In addition we will be able to realise cost synergies through more efficient operations and economies of scale.”

Hydro and Statoil operate as independent companies and are precluded from looking into each other’s books in order to carry out detailed analyses of potential synergies. Based on own activities and analyses by an external consultant, Statoil has estimated cost synergies for the new company when the merger is completed.

The total cost synergy potential for the combined company is estimated to be about NOK 4 billion per year before tax. The cost synergies include both increased efficiencies in development, operations and exploration activities, as well as within administration and business support activities.

Important measures to realise the operating cost synergies will be reduced external sourcing and internal redeployment of personnel. Parts of the synergies will be reflected in future CAPEX. The synergy potential will be realised after a few years, around 2009-2010, once the integration process has been fully completed. Any redundancies will be managed through natural attrition and other measures to be discussed with the trade unions.

The gross operator cost synergies are estimated to be significantly higher than NOK 4 billion. The gross synergies will however not only benefit the combined company, but also its partners through lower costs in Statoil and Hydro operated joint ventures.

It will not be possible to isolate the different synergy elements separately from other cost and revenue elements in the future financial statements of the combined company. The main reason is that a significant share of the cost synergies is to be achieved through redirection of resources to areas with scarcity of resources and growth potential.

Media:
Ola Morten Aanestad, vice president media relations, +47 48 08 02 12 (mobile), +47 51 99 13 77 (office)

Investor relations:
Lars Troen Sørensen, senior vice president investor relations, + 47 90 64 91 44 (mobile), +47 51 99 77 90 (office)
Geir Bjørnstad, vice president, US investor relations, + 1 203 978 6950

CAUTIONARY NOTE IN RELATION TO FORWARD-LOOKING INFORMATION
The matters set forth in this presentation, in particular statements as to the expected benefits of the merger such as synergies, efficiencies, cost savings, financial strength, and the competitive ability and position of the combined company are forward-looking statements. In some cases, we use words such as “believe”, “intend”, “expect”, “anticipate”, “plan”, “target” and similar expressions to identify forward-looking statements. These forward-looking statements reflect current, preliminary views with respect to 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. You should also note that some or all of the assumptions upon which such forward-looking statements are based are beyond our ability to control or estimate precisely and may in some cases be subject to rapid and material changes. 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 the possibility that cost synergies, new growth opportunities, improved performance and other anticipated benefits from the merger cannot be fully realized; required approvals by Statoil’s and Hydro’s shareholders and regulatory agencies; the possibility that costs or difficulties related to the integration of Hydro’s oil and gas activities and Statoil will be greater than expected; the ability to manage regulatory, tax and legal matters, including changes in tax rates; the impact of competition and other risk factors relating to the industry as detailed from time to time in Statoil’s reports filed with the SEC. You should not place undue reliance on these forward-looking statements, which speak only as of the date of this presentation. Unless we are required by law to update these statements, we will not necessarily update any of these statements after the date of this presentation, either to conform them to actual results or to changes in our expectations


Calculation of capital employed and net debt to capital employed ratio	31 December
(in NOK million)	2006	2005


Total shareholders' equity	122,228	106,644
Minority interest	1,465	1,492


Total equity and minority interest (A)	123,693	108,136


Short-term debt	5,515	1,529
Long-term debt	30,271	32,564


Gross interest-bearing debt	35,786	34,093


Cash and cash equivalents	(7,367)	(7,025)
Short-term investments	(1,031)	(6,841)


Cash and cash equivalents and short-term investments	(8,398)	(13,866)


Net debt before adjustments (B1)	27,388	20,227


Other interest-bearing elements	-	1,783
Adjustment for project loan	(2,443)	(2,723)


Net interest-bearing debt (B2)	24,945	19,287


Calculation of capital employed
Capital employed before adjustments to net interest-bearing debt (A+B1)	151,081	128,363
Capital employed (A+B2)	148,638	127,423


Calculated net debt to capital employed
Net debt to capital employed before adjustments (B1/(A+B1))	18.1%	15.8%
Net debt to capital employed (B2/(A+B2))	16.8%	15.1%


	At December 31,
(in NOK million)	2006	2005


ASSETS

Cash and cash equivalents	7,367	7,025
Short-term investments	1,031	6,841


Cash, cash equivalents and short-term investments	8,398	13,866

Accounts receivable	41,273	42,816
Inventories	11,872	8,369
Prepaid expenses and other current assets	15,538	12,815


Total current assets	77,081	77,866

Investments in affiliates	4,917	4,352
Long-term receivables	6,855	9,618
Net property, plant and equipment	209,601	180,669
Other assets	17,014	16,474


TOTAL ASSETS	315,468	288,979



LIABILITIES AND SHAREHOLDERS' EQUITY

Short-term debt	5,515	1,529
Accounts payable	22,373	22,518
Accounts payable - related parties	7,551	9,766
Accrued liabilities	12,148	14,030
Income taxes payable	30,219	29,752


Total current liabilities	77,806	77,595

Long-term debt	30,271	32,564
Deferred income taxes	44,987	43,314
Other liabilities	38,711	27,370


Total liabilities	191,775	180,843


Minority interest	1,465	1,492


Common stock (NOK 2.50 nominal value), 2,166,143,715 and 2,189,585,600 shares, respectively, authorized and issued	5,415	5,474
	5,415	5,474
Treasury shares	(54)	(60)
Additional paid-in capital	37,366	37,305
Additional paid-in capital related to Treasury shares	(3,605)	(96)
Retained earnings	88,262	65,401
Accumulated other comprehensive income (loss)	(5,156)	(1,380)


Total shareholders' equity	122,228	106,644


TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	315,468	288,979



See notes to the consolidated financial statements.


	For the year ended December 31,
(in NOK million)	2006	2005


OPERATING ACTIVITIES
Consolidated net income	40,615	30,730

Adjustments to reconcile net income to net cash flows provided by operating activities:
Minority interest in income	720	765
Depreciation, depletion and amortization	21,767	21,097
Exploration expenditures written off	667	158
(Gains) losses on foreign currency transactions	157	1,330
Deferred taxes	5,420	(5,078)
(Gains) losses on sales of assets and other items	(710)	(1,605)

Changes in working capital (other than cash and cash equivalents):
• (Increase) decrease in inventories	(3,441)	(1,664)
• (Increase) decrease in accounts receivable	1,708	(11,625)
• (Increase) decrease in prepaid expenses and other current assets	(3,669)	(1,842)
• (Increase) decrease in short-term investments	5,810	4,780
• Increase (decrease) in accounts payable	(3,454)	7,923
• Increase (decrease) in other payables	(4,209)	282
• Increase (decrease) in taxes payable	626	10,522

(Increase) decrease in non-current items related to operating activities	(1,094)	477


Cash flows provided by operating activities	60,913	56,250


INVESTING ACTIVITIES
Acquisitions, net of cash acquired	0	(13,154)
Additions to property, plant and equipment	(39,486)	(31,389)
Exploration expenditures capitalized	(2,454)	(1,242)
Change in long-term loans granted and other long-term items	(154)	(734)
Proceeds from sale of business	0	7,802
Proceeds from sale of assets	2,010	1,053


Cash flows used in investing activities	(40,084)	(37,664)


FINANCING ACTIVITIES
New long-term borrowings	97	422
Repayment of long-term borrowings	(1,428)	(3,187)
Distribution to minority shareholders	(741)	(910)
Dividends paid	(17,756)	(11,481)
Treasury shares purchased	(1,012)	0
Net short-term borrowings, bank overdrafts and other	304	(1,358)


Cash flows used in financing activities	(20,536)	(16,514)


Net increase (decrease) in cash and cash equivalents	293	2,072


Effect of exchange rate changes on cash and cash equivalents	49	(75)
Cash and cash equivalents at the beginning of the year	7,025	5,028


Cash and cash equivalents at the end of the year	7,367	7,025



See notes to the consolidated financial statements.


	At December 31,
(in NOK million)	2006	2005


Crude oil	7,231	4,383
Petroleum products	5,566	5,682
Other	1,574	1,124


Total - inventories valued on a FIFO basis	14,371	11,189
Excess of current cost over LIFO value	(2,499)	(2,820)


Total	11,872	8,369


	For the three months ended December 31,		For the year ended December 31,
	For the three months ended December 31,		For the year ended December 31,
(in NOK million)	2006	2005	2006	2005


Benefits earned during the period	360	272	1,359	1,066
Interest cost on prior periods' benefit obligation	256	251	1,026	1,001
Expected return on plan assets	(248)	(259)	(1,104)	(1,094)
Amortization of loss	21	10	102	48
Amortization of prior service cost	(1)	9	34	37


Net periodic benefit cost (defined benefit plans)	388	283	1,417	1,058
Defined contribution plans/multi-employer plans	92	22	201	73


Total net pension cost for the period	480	305	1,618	1,131

	STATOIL ASA (Registrant)
Dated: February 12, 2007	By:	/s/ Eldar Sætre Eldar Sætre Chief Financial Officer


	At 31 December, 2006	At 31 December, 2005	Change	At 31 December, 2006
(In millions)	NOK	NOK	%	USD*

Current assets	77,081	77,866	(1.01)	12,375
Non current assets	238,387	211,113	12.92	38,272
Total assets	315,468	288,979	9.17	50,647
Current liabilities	(77,806)	(77,595)	0.27	(12,492)
Long-term debt and long-term provisions	(113,969)	(103,248)	10.38	(18,297)
Equity including minority interest	(123,693)	(108,136)	14.39	(19,859)
Total liabilities and shareholders' equity	(315,468)	(288,979)	9.17	(50,647)

2001	2006
USD 25/bbl	USD 65+/bbl
Expected political stability	Increased political uncertainty
Cost and returns	Growth and reserves

	Type of field		Peak plateau in boepd1	Production start
In Amenas2	Gas	28 000		2006
Dalia	Oil	27 000
ACG East Azeri	Oil	20 000
Fram East	Oil	9 000
Shah Deniz, phase I	Gas	37 000
Ormen Lange	Gas	50 000		2007
Statfjord late-life	Gas	43 000
Snøhvit	Gas	40 000
Volve	Oil	30 000
Skinfaks/Rimfaks IOR	Oil	22 000
Gulltopp	Oil	11 000
Rosa	Oil	18 000
Tordis IOR	Oil	8 000
Agbami	Oil	40 000		2008
ACG, phase III	Oil	35 000
Alve	Gas	18 000
Tahiti	Oil	30 000
Sleipner B Compression	Gas	10 000

	1986	1996	2004	Current ambition
Statfjord	49%	61%	68%	70%
Gullfaks	46%	49%	61%	70%

Statoil of total (%)	Country
~20%	Germany
	France
	Belgium
	Ireland
10-15%	Austria
	Czech Rep
	Netherlands
5-10%	Spain
5-10%	UK
<5%	Italy
<5%	Turkey

Form 6-K

TABLE OF CONTENTS

BEST ANNUAL INCOME EVER

E&P NORWAY

INTERNATIONAL E&P

NATURAL GAS

MANUFACTURING & MARKETING

LIQUIDITY AND CAPITAL RESOURCES

USE AND RECONCILIATION OF NON-GAAP FINANCIAL MEASURES

FORWARD LOOKING STATEMENTS

CONSOLIDATED STATEMENTS OF INCOME - USGAAP

CONSOLIDATED BALANCE SHEETS - USGAAP

CONSOLIDATED STATEMENTS OF CASH FLOWS - USGAAP

1. ORGANIZATION AND BASIS OF PRESENTATION

2. SHAREHOLDERS' EQUITY

3. SEGMENTS

4. INVENTORIES

5. EMPLOYEE RETIREMENT PLANS

6. FINANCIAL ITEMS

7. CHANGE IN ESTIMATE OF ASSET RETIREMENT OBLIGATIONS

8. COMMITMENTS AND CONTINGENT LIABILITIES

9. SUBSEQUENT EVENTS AND SIGNIFICANT BUSINESS DEVELOPMENTS

10. RECONCILIATION BETWEEN USGAAP AND NGAAP

SIGNATURES

PRESS RELEASE:

BEST ANNUAL INCOME EVER

GROUP BALANCE SHEET

BUSINESS UPDATE 4Q 2006

PRESS RELEASE:

Synergy potential from the merger between Statoil and Hydro's oil and gas activities