SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 20-F
(Mark one)
_ | REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR 12 (g) OR |
X | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) For the fiscal year ended December 31, 2005 OR |
_ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE OR |
_ | SHELL COMPANY PURSUANT TO SECTION 13 OR 15(d) OF THE Date of event requiring this shell company report__________ |
For the Transition period from _________ to ____________
Commission File No. 1-15200
Statoil ASA
(Exact name of registrant as specified in its charter)
Norway
(Jurisdiction of incorporation or organization)
Forusbeen 50, N-4035 Stavanger, Norway
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code + 47 51 99 00 00
Securities to be registered pursuant to Section 12(b) of the Exchange Act:
Title of each class | Name of each exchange on which registered |
American Depositary Shares | New York Stock Exchange New York Stock Exchange* |
* Listed, not for trading, but only in connection with the registration of American Depositary Shares, pursuant to the requirements of the Securities and Exchange Commission
Securities to be registered pursuant to Section 12(g) of the Exchange Act: None
Securities for which there is a reporting obligation pursuant to Section 15 (d) of the Exchange Act: None
Indicate the number of outstanding shares of each of the issuer's classes of capital or common stock as of the close of the period covered by the Annual Report:
Ordinary shares of NOK 2.50 each | 2,165,377,388 |
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act Yes _X_ No __
If this report in an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. Yes __ No _X_
Indicate by check mark whether the registrant (1) has filed all reports to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2), has been subject to such filing requirements for the past 90 days. Yes _X_ No __
Indicate by check mark wether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer_X_ Accelerated filer __ Non-accelerated filer __
Indicate by check mark which statement item the registrant has elected to follow.
Item 17 __ Item 18 _X_
If this is an annual report, indicate by ckeck mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes __ No _X_
Table of contents
Terms and Measurements relating to the Oil and Gas Industry
Item 1 Identity of Directors, Senior Management and Advisors
Item 2 Offer Statistics and Expected Timetable
Item 4 Information on the Company
History and Development of the Company
Item 5 Operating and Financial Review and Prospects
Liquidity and Capital Resources
Use and Reconciliation of Non-GAAP Financial Measures
Item 6 Directors, Senior Management and Employees
Directors and Senior Management
Item 7 Major Shareholders and Related Party Transactions
Consolidated Statements and Other Financial Information
Item 10 Additional Information
Memorandum and Articles of Association
Exchange Controls and Other Limitations Affecting Shareholders
Report of DeGolyer and MacNaughton
Item 11 Quantitative and Qualitative Disclosures about Market Risk
Item 12 Description of Securities Other Than Equity Securities
Item 13 Defaults, Dividend Arrearages and Delinquencies
Item 14 Material Modifications to the Rights of Security Holders and Use of Proceeds
Item 15 Controls and Procedures
Item 16A Audit Committee Financial Expert
Item 16C Principal Accountant Fees and Services
Item 16D Exemptions from the Listing Standards for Audit Committees
Item 16E Purchases of Equity Securities by the Issuer and Affiliated Purchasers
Appendix A - Report of DeGolyer and MacNaughton
Terms and Measurements relating to the Oil and Gas Industry
References to:
• bbl means barrel
• mbbls means thousand barrels
• mmbbls means million barrels
• boe means barrels-of-oil equivalent
• mboe means thousand barrels-of-oil equivalent
• mmboe means million barrels-of-oil equivalent
• mmcf means million cubic feet
• bcf means billion cubic feet
• tcf means trillion cubic feet
• scm means standard cubic meter
• mcm means thousand cubic meters
• mmcm means million cubic meters
• bcm means billion cubic meters
• mmtpa means million tonnes per annum
• km means kilometer
• ppm means part per million
• one billion means one thousand million
Equivalent measurements are based upon:
• 1 barrel equals 0.134 tonnes of oil (33 degrees API)
• 1 barrel equals 42 U.S. gallons
• 1 barrel equals 0.159 standard cubic meters
• 1 barrel of oil equivalent equals 1 barrel of crude oil
• 1 barrel of oil equivalent equals 159 standard cubic meters of natural gas
• 1 barrel of oil equivalent equals 5,612 cubic feet of natural gas
• 1 barrel of oil equivalent equals 0.122 tonnes of NGLs
• 1 billion standard cubic meters of natural gas equals 1 million standard cubic meters of oil equivalent
• 1 cubic meter equals 35.3 cubic feet
• 1 km equals 0.62 miles
• 1 square kilometer equals 0.39 square miles
• 1 square kilometer equals 247.105 acres
• 1 cubic meter of natural gas equals one standard cubic meter of natural gas
• 1,000 standard cubic meters of natural gas equals 6.29 boe
• 1 standard cubic foot equals 0.0283 standard cubic meter
• 1 standard cubic foot equals 1,000 British thermal units (btu)
• 1 tonne of NGLs equals 1.3 standard cubic meters of oil equivalents
• 1 degree Celsius equals minus 32 plus five-ninths of the number of degrees Fahrenheit
Miscellaneous terms:
• Condensates means the heavier natural gas components, such as pentane, hexane, iceptane and so forth, which are liquid under atmospheric pressure - also called natural gasoline or naphtha
• Crude oil, or oil, includes condensate and natural gas liquids
• LNG, or liquefied natural gas, means lean gas - primarily methane - converted to liquid form through refrigeration to minus 163 degrees Celsius under atmospheric pressures
• LPG means liquefied petroleum gas and consists primarily of propane and butane, which turn liquid under a pressure of six to seven atmospheres. LPG is shipped in special vessels
• Naphtha is an inflammable oil obtained by the dry distillation of petroleum
• Natural gas is petroleum that consists principally of light hydrocarbons. It can be divided into
lean gas, primarily methane but often containing some ethane and smaller quantities of heavier hydrocarbons (also called sales gas) and
wet gas, primarily ethane, propane and butane as well as smaller amounts of heavier hydrocarbons; partially liquid under atmospheric pressure
• NGL means natural gas liquids light hydrocarbons consisting mainly of ethane, propane and butane which are liquid under pressure at normal temperature
• GTL, or gas to liquids, means the technology used for chemical conversion of natural gas into transportable liquids (diesel and nahptha) and specialty products (base oils)
• Petroleum is a collective term for hydrocarbons, whether solid, liquid or gaseous. Hydrocarbons are compounds formed from the elements hydrogen (H) and carbon (C). The proportion of different compounds, from methane and ethane up to the heaviest components, in a petroleum find varies from discovery to discovery. If a reservoir primarily contains light hydrocarbons, it is described as a gas field. If heavier hydrocarbons predominate, it is described as an oil field. An oil field may feature free gas above the oil and contain a quantity of light hydrocarbons, also called associated gas.
PART I
Item 1 Identity of Directors, Senior Management and Advisors
Not applicable.
Item 2 Offer Statistics and Expected Timetable
Not applicable.Item 3 Key Information
Selected Financial Data
The following tables set forth selected consolidated financial and statistical data of Statoil.You should read the following data together with Item 5–Operating and Financial Review and Prospects and Item 11–Quantitative and Qualitative Disclosures about Market Risk and our consolidated financial statements, including the notes to those financial statements included in this Annual Report on Form 20-F.
Solely for the convenience of the reader, the financial data for the twelve months ended December 31, 2005 has been translated into U.S. dollars at the rate of NOK 6.7444 to USD 1.00, the noon buying rate on December 30, 2005. The financial data has been derived from our financial statements, which have been prepared in accordance with generally accepted accounting principles in the United States, or U.S. GAAP.
(in million, except per share amounts) | Year ended December 31, | |||||
2005 | 2004 | 2003 | 2002 | 2001 | ||
NOK | USD | NOK | NOK | NOK | NOK | |
Income Statement |
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Revenues: |
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Sales | 390,540 | 57,906 | 303,756 | 248,527 | 242,178 | 231,712 |
Equity in net income (loss) of affiliates | 1,090 | 162 | 1,209 | 616 | 366 | 439 |
Other income | 1,668 | 247 | 1,253 | 232 | 1,270 | 4,810 |
Total revenues | 393,298 | 58,315 | 306,218 | 249,375 | 243,814 | 236,961 |
Expenses: |
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|
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|
Cost of goods sold | (235,722) | (34,951) | (188,179) | (149,645) | (147,899) | (126,153) |
Operating expenses | (30,327) | (4,497) | (27,350) | (26,651) | (28,308) | (29,422) |
Selling, general and administrative expenses | (7,803) | (1,157) | (6,298) | (5,517) | (5,251) | (4,297) |
Depreciation, depletion and amortization | (21,097) | (3,128) | (17,456) | (16,276) | (16,844) | (18,058) |
Exploration expenses | (3,253) | (482) | (1,828) | (2,370) | (2,410) | (2,877) |
Total expenses before financial items | (298,202) | (44,215) | (241,111) | (200,459) | (200,712) | (180,807) |
Income before financial items, other items, income taxes and minority interest | 95,096 | 14,100 | 65,107 | 48,916 | 43,102 | 56,154 |
Net financial items | (3,562) | (528) | 5,739 | 1,399 | 8,233 | 65 |
Other items | 0 | 0 | 0 | (6,025) | 0 | 0 |
Income before income taxes and minority interest | 91,534 | 13,572 | 70,846 | 44,290 | 51,335 | 56,219 |
Income taxes | (60,039) | (8,902) | (45,425) | (27,447) | (34,336) | (38,486) |
Minority interest | (765) | (113) | (505) | (289) | (153) | (488) |
Net income | 30,730 | 4,556 | 24,916 | 16,554 | 16,846 | 17,245 |
Ordinary and diluted earnings per share(1), | 14.19 | 2.10 | 11.50 | 7.64 | 7.78 | 8.31 |
Dividend paid per share,(2) | 8.20 | 1.22 | 5.30 | 2.95 | 2.90 | 26.69 |
(1) The weighted average number of shares outstanding was 2,165,740,054, 2,166,142,636, 2,166,143,693, 2,165,422,239 and 2,076,180,942 in 2005, 2004, 2003, 2002 and 2001, respectively.
(2) See Item 8–Financial Information–Dividend Policy and Item 3–Key Information–Dividends below for a description of how dividends are determined.
(in million) | At December 31, | |||||
2005 |
| 2004 | 2003 | 2002 | 2001 | |
NOK | USD | NOK | NOK | NOK | NOK | |
Balance Sheet |
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Assets: |
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Cash and cash equivalents | 7,025 | 1,042 | 5,028 | 7,316 | 6,702 | 4,395 |
Short-term investments | 6,841 | 1,041 | 11,621 | 9,314 | 5,267 | 2,063 |
Accounts receivable | 43,361 | 6,430 | 31,736 | 30,192 | 33,950 | 27,739 |
Inventories | 8,635 | 1,280 | 6,971 | 4,993 | 5,422 | 5,276 |
Prepaid expenses and other current assets | 10,989 | 1,629 | 9,713 | 7,354 | 6,856 | 9,184 |
Total current assets | 76,851 | 11,395 | 66,047 | 59,169 | 58,197 | 48,657 |
Investments in affiliates | 4,451 | 660 | 10,339 | 11,022 | 9,629 | 9,951 |
Long-term receivables | 9,691 | 1,437 | 8,176 | 14,261 | 7,138 | 7,166 |
Net properties, plants and equipments | 181,481 | 26,910 | 152,916 | 126,528 | 122,379 | 126,500 |
Other assets | 16,505 | 2,447 | 11,743 | 10,620 | 8,087 | 7,421 |
TOTAL ASSETS | 288,979 | 42,850 | 249,221 | 221,600 | 205,430 | 199,695 |
Liabilities and Shareholders’ Equity: |
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Short-term debt | 1,529 | 227 | 4,730 | 4,287 | 4,323 | 6,613 |
Accounts payable | 23,262 | 3,449 | 19,282 | 17,977 | 19,603 | 10,970 |
Accounts payable – related parties | 9,766 | 1,448 | 5,621 | 6,114 | 5,649 | 10,164 |
Accrued liabilities | 13,145 | 1,949 | 12,385 | 11,454 | 11,590 | 13,831 |
Income taxes payable | 29,750 | 4,411 | 19,117 | 17,676 | 18,358 | 16,618 |
Total current liabilities | 77,452 | 11,485 | 61,135 | 57,508 | 59,523 | 58,196 |
Long-term debt | 32,669 | 4,844 | 31,459 | 32,991 | 32,805 | 35,182 |
Deferred income taxes | 43,347 | 6,427 | 45,248 | 37,849 | 43,153 | 42,354 |
Other liabilities | 27,375 | 4,059 | 24,733 | 21,595 | 11,382 | 10,693 |
Total liabilities | 180,843 | 26,815 | 162,575 | 149,943 | 146,863 | 146,425 |
Minority interest | 1,492 | 221 | 1,616 | 1,483 | 1,550 | 1,496 |
Common stock (NOK 2.50 nominal value) 2,189,585,600 shares authorized and issued | 5,474 |
812 |
5,474 |
5,474 |
5,474 |
5,474 |
Treasury shares (1) | (156) | (23) | (60) | (59) | (59) | (63) |
Additional paid-in capital | 37,304 | 5,527 | 37,273 | 37,728 | 37,728 | 37,728 |
Retained earnings | 65,402 | 9,702 | 46,153 | 27,627 | 17,355 | 6,682 |
Accumulated other comprehensive income | (1,380) | 205 | (3,810) | (596) | (3,481) | 1,953 |
Total shareholders’ equity | 106,644 | 15,813 | 85,030 | 70,174 | 57,017 | 51,774 |
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | 288,979 |
42,850 | 249,221 | 221,600 | 205,430 | 199,695 |
(1) The number of treasury shares at year-end in each of the five years presented was 24,208,212; 23,452,876; 23,441,885; 23,441,885 and 25,000,000 in 2005, 2004, 2003, 2002 and 2001, respectively.
Other financial information | Year ended December 31, | ||||
2005 | 2004 | 2003 | 2002 | 2001 | |
Net debt to capital employed (GAAP basis) (1) |
15.8% | 18.4% | 22.4% | 30.2% | 39.9% |
Net debt to capital employed(2) | 15.3% | 19.0% | 22.6% | 28.7% | 39.0% |
After-tax return on average capital employed (GAAP basis)(3) | 27.6% | 23.6% | 18.6% | 14.7% | 19.7% |
After-tax return on average capital employed(4) | 27.6% | 23.5% | 18.7% | 14.9% | 19.9% |
(1) As calculated according to GAAP. Net debt to capital employed is the net debt divided by capital employed. Net debt is interest-bearing debt less cash and cash equivalents and short-term investments. Capital employed is net debt, shareholders’ equity and minority interest.
(2) As adjusted. In order to calculate the net debt to capital employed ratio that our management makes use of internally and which we report to the market, we make adjustments to capital employed as it would be reported under GAAP to adjust for project financing exposure that does not correlate to the underlying exposure (adjustments amounted to NOK 2,623 million in 2005, NOK 2,209 million in 2004, NOK 1,500 million in 2003, NOK 1,567 in 2002 and NOK 1,257 in 2001 and to add into the capital employed measure interest-bearing elements which are classified together with non-interest-bearing elements under GAAP of NOK 1,783 million in 2005, NOK 2,995 million in 2004 and NOK 1,758 million in 2003, with no corresponding adjustments in 2002 and 2001. See Item 5-Operating and Financial Review and Prospects-Use and Reconciliation of Non-GAAP Financial Measures for a reconciliation of capital employed and a description of why we make use of this measure.
(3) As calculated in accordance with GAAP. After-tax return on average capital employed (ROACE) is equal to net income before minority interest and before after-tax net financial items, divided by average capital employed over the last 12 months.
(4) As adjusted. This figure represents ROACE computed on the basis of capital employed, adjusted as indicated in footnote 2 above. See Item 5–Operating and Financial Review and Prospects–Use and Reconciliation of Non-GAAP Financial Measures for a reconciliation of return on average capital employed and a description of why we make use of this measure.
Summary Oil and Gas Production Information
The following table sets forth our Norwegian and international production of crude oil and natural gas for the periods indicated. The stated production volumes are the volumes that Statoil is entitled to in accordance with conditions laid down in concession agreements and production sharing agreements, or PSAs. The production volumes are net of royalty oil paid in kind and of gas used for fuel and flare. Our production is based on our proportionate participation in fields with multiple owners and does not include production of the Norwegian State’s oil and natural gas.
Production | Year ended December 31, | ||
2005 | 2004 | 2003 | |
Norway: |
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Crude oil (mmbbls)(1) | 205 | 229 | 241 |
Natural gas (bcf) | 865 | 751 | 677 |
Natural gas (bcm) | 24.5 | 21.3 | 19.2 |
Combined oil and gas (mmboe) | 359 | 363 | 362 |
International: |
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Crude oil (mmbbls)(1) | 52 | 37 | 32 |
Natural gas (bcf) | 87 | 31 | 5 |
Natural gas (bcm) | 2.5 | 0.9 | 0.1 |
Combined oil and gas (mmboe) | 67 | 42 | 33 |
Total: |
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Crude oil (mmbbls)(1) | 257 | 265 | 273 |
Natural gas (bcf) | 953 | 781 | 682 |
Natural gas (bcm) | 27.0 | 22.1 | 19.3 |
Combined oil and gas (mmboe) | 427 | 405 | 395 |
(1) Crude oil includes natural gas liquids (NGL) and condensate production. NGL includes both LPG and naphtha.
Sales Volume Information
In addition to our own volumes, we market and sell oil and gas owned by the Norwegian State through the Norwegian State’s share in production licenses, known as the State’s direct financial interest, or SDFI, together with our own production. For additional information see Item 7–Major Shareholders and Related Party Transactions. The following table sets forth SDFI and Statoil sales volume information for crude oil and natural gas, as applicable, for the periods indicated. The SDFI volumes shown below include royalty oil we sell on behalf of the Norwegian State. The payment of royalty obligations on the NCS was abolished on December 31 2005. The Statoil natural gas sales volumes include equity volumes sold by Natural Gas, natural gas volumes sold by International E&P and ethane volumes.
Sales Volumes | Year ended December 31, | ||
2005 | 2004 | 2003 | |
Statoil:(1) |
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Crude oil (mmbbls)(2) | 256 | 261 | 269 |
Natural gas (bcf) | 953 | 781 | 682 |
Natural gas (bcm)(3) | 27.0 | 22.1 | 19.3 |
Combined oil and gas (mmboe) | 426 | 400 | 391 |
Third party volumes:(4) |
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Crude oil (mmbbls)(2) | 229 | 220 | 219 |
Natural gas (bcf) | 93 | 139 | 70 |
Natural gas (bcm)(3) | 2.6 | 3.9 | 2.0 |
Combined oil and gas (mmboe) | 245 | 244 | 231 |
SDFI assets owned by the Norwegian State (including royalty):(5) |
| ||
Crude oil (mmbbls)(2) | 281 | 318 | 339 |
Natural gas (bcf) | 1,116 | 1,069 | 915 |
Natural gas (bcm)(3) | 31.6 | 30.3 | 25.9 |
Combined oil and gas (mmboe) | 480 | 508 | 502 |
Total: |
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Crude oil (mmbbls)(2) | 768 | 796 | 827 |
Natural gas (bcf) | 2,079 | 1,985 | 1,641 |
Natural gas (bcm)(3) | 58.9 | 56.2 | 46.8 |
Combined oil and gas (mmboe) | 1,138 | 1,150 | 1,123 |
(1) The Statoil volumes included in the table above assume that volumes sold were equal to lifted equity volumes in the relevant year.
(2) Sales volumes of crude oil include NGL and condensate. All sales volumes reported in the table above include internal deliveries to our manufacturing facilities.
(3) At a gross calorific value (GCV) of 40 MJ/scm.
(4) Third party volumes of crude oil include both volumes purchased from partners in our upstream operations and other cargos purchased in the market. The third party volumes are purchased either for sale to third parties or for our own use. Third party volumes of natural gas include third party LNG volumes related to our activities at the Cove Point regasification terminal in the U.S.
(5) The 2003 SDFI volumes have been restated in order to include SDFI LNG volumes related to our activities at the Cove Point regasification terminal in the USA.
Exchange Rates
The table below shows the high, low, average and end of period noon buying rates in The City of New York for cable transfers in foreign currencies as certified for customs purposes by the Federal Reserve Bank of New York for Norwegian kroner per USD 1.00. The average is computed using the noon buying rate on the last business day of each month during the period indicated.
Year ended December 31, | Low | High | Average | End of Period |
2001 | 8.5400 | 9.4638 | 9.0330 | 8.9724 |
2002 | 6.9375 | 9.1110 | 7.9253 | 6.9375 |
2003 | 6.6440 | 7.6560 | 7.0627 | 6.6660 |
2004 | 6.0551 | 7.1408 | 6.7241 | 6.0794 |
2005 | 6.0667 | 6.8023 | 6.4591 | 6.7444 |
The table below shows the high and low noon buying rates for each month during the six months prior to the date of this Annual Report on Form 20-F.
Year 2005 | Low | High |
September | 6.2125 | 6.5331 |
October | 6.4307 | 6.6155 |
November | 6.4591 | 6.7393 |
December | 6.5944 | 6.8023 |
Year 2006 | Low | High |
January | 6.5242 | 6.7483 |
February | 6.6416 | 6.8490 |
March (up to and including March 24) | 6.5276 | 6.7340 |
On March 24, 2006 the noon buying rate for Norwegian kroner was USD 1.00 = 6.6237 NOK
Fluctuations in the exchange rate between the Norwegian kroner and the U.S. dollar will affect the U.S. dollar amounts received by holders of American Depositary Shares (ADSs) on conversion of dividends, if any, paid in Norwegian kroner on the ordinary shares and may affect the U.S. dollar price of the ADSs on the New York Stock Exchange.
Dividends
Dividends in respect of the fiscal year are declared at our annual general meeting in the following year. Under Norwegian law, dividends may only be paid in respect of a financial period as to which audited financial statements have been approved by the annual general meeting of shareholders, and any proposal to pay a dividend must be recommended by the board of directors, accepted by the corporate assembly and approved by the shareholders at a general meeting. The shareholders at the annual general meeting may vote to reduce, but may not increase, the dividend proposed by the board of directors.Dividends may be paid in cash or in kind and are payable only out of our distributable reserves. The amount of our distributable reserves is defined by the Norwegian Public Limited Companies Act, which requires such reserves to be calculated under Norwegian GAAP and consist of:
• annual net income according to the income statement approved for the preceding financial year, and
• retained net income from previous years (adjusted for any reclassification of our equity),
after deduction for uncovered losses, book value of research and development, goodwill and net deferred tax assets as recorded in the balance sheet for the preceding financial year, and the aggregate value of treasury shares that we have purchased or been granted security in and of credit and security given by us pursuant to sections 8-7 to 8-9 of the Norwegian Public Limited Companies Act during preceding financial years.
We cannot distribute any dividends if our equity, according to the Statoil ASA unconsolidated balance sheet, amounts to less than 10 per cent of the total assets reflected on our unconsolidated balance sheet without following a creditor notice procedure as required for reducing the share capital. Furthermore, we can only distribute dividends to the extent compatible with good and careful business practice with due regard to any losses which we may have incurred after the last balance sheet date or which we may expect to incur.
Finally, the amount of dividends we can distribute is calculated on the basis of our unconsolidated financial statements. Retained earnings available for distribution is based on Norwegian accounting principles and legal regulations and amounted to NOK 80,952 million (before provisions for dividend for the year ended December 31, 2005 of NOK 17,756 million) at December 31, 2005.
Although we currently intend to pay annual dividends on our ordinary shares, we cannot assure you that dividends will be paid or as to the amount of any dividends. Future dividends will depend on a number of factors prevailing at the time our board of directors considers any
dividend payment.
See Item 8-Financial Information-Dividend Policy for a description of our dividend policy.
Dividends paid prior to 2002 include 100 per cent of the cash flows from the SDFI assets transferred from the Norwegian State, and a percentage of net income after tax (calculated on a Norwegian GAAP basis) for all other activities. The following table shows the amounts paid to the Norwegian State prior to 2002 and to all shareholders since 2002 on a per share basis and in the aggregate, as well as dividends proposed by our board of directors to be paid in 2006 on our ordinary shares for the fiscal year 2005.
| Per ordinary share | Total (in million) | ||||
| Ordinary dividend(3) | Special dividend(3) | Total dividend (3) | Total dividend |
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|
Year | NOK | NOK | NOK | USD(1) | NOK | USD(1) |
2001(2) | 26.69 |
| 26.69 | 3.96 | 55,415 | 8,216 |
2002 | 2.90 |
| 2.90 | 0.43 | 6,282 | 931 |
2003 | 2.95 |
| 2.95 | 0.44 | 6,390 | 947 |
2004 | 3.20 | 2.10 | 5.30 | 0.79 | 11,481 | 1,702 |
2005 | 3.60 | 4.60 | 8.20 | 1.22 | 17,756 | 2,633 |
(1) The USD amounts in the table above are based on the noon buying rate for Norwegian kroner on December 31, 2005, which was NOK 6.7444 to USD 1.00.
(2) Based on 2,076,180,942 shares, being the weighted average number of ordinary shares for 2001. Total dividends paid in 2001 include a cash settlement for the SDFI assets amounting to NOK 19.65 (USD 2.91) per share. An ordinary dividend for fiscal year 2001 of NOK 2.85 per share was declared on May 7, 2002.
(3) For the years 2005 and 2004 the total dividend per share consisted of an ordinary dividend and a special dividend. There is no distinction between ordinary and special dividends under Norwegian law. The 2005 dividend will be paid in late May 2006.
Dividends we paid in periods prior to 2002 reflected our status as wholly owned by the Norwegian State and should not be considered indicative of our existing dividend policy.
In 2004 the total dividend per share represented an ordinary dividend and a special dividend. The total dividend per share proposed by the board of directors for 2005 also includes an ordinary dividend and a special dividend. The special dividends paid in these years are the result of increased annual net income due to higher realized oil and gas prices. There is no guarantee that special dividends will be paid in the future, even if higher oil and gas prices are sustained over time. There is no distinction between ordinary and special dividends under Norwegian law.
Since we will only pay dividends in Norwegian kroner, exchange rate fluctuations will affect the U.S. dollar amounts received by holders of ADSs after the ADR depositary converts cash dividends into U.S. dollars.
Risk Factors
Risks Related to Our BusinessA substantial or extended decline in oil or natural gas prices would have a material adverse effect on us.
Historically, prices for oil and natural gas have fluctuated widely in response to changes in many factors. We do not and will not have control over the factors affecting prices for oil and natural gas. These factors include:
• global and regional economic and political developments in resource-producing regions, particularly in the Middle East and South America;
• global and regional supply and demand;
• the ability of the Organization of Petroleum Exporting Countries (OPEC) and other producing nations to influence global production levels and prices;
• prices of alternative fuels which affect our realized prices under our long-term gas sales contracts;
• Norwegian and foreign governmental regulations and actions;
• global economic conditions;
• price and availability of new technology; and
• weather conditions.
It is impossible to predict future oil and natural gas price movements with certainty. Declines in oil and natural gas prices will adversely affect our business, results of operations and financial condition, liquidity and our ability to finance planned capital expenditures. For an analysis of the impact on income before financial items, taxes and minority interest from changes in oil and gas prices, see Item 5–Operating and Financial Review and Prospects–Operating Results–Factors Affecting Our Results of Operations. Lower oil and natural gas prices also may reduce the amount of oil and natural gas that we can produce economically or reduce the economic viability of projects planned or in development.
Exploratory drilling involves numerous risks, including the risk that we will encounter no commercially productive oil or natural gas reservoirs, which could materially adversely affect our results.
We are exploring in various geographic areas, including new resource provinces such as the Norwegian Sea, the Barents Sea, onshore Algeria and Libya, as well as offshore Venezuela where environmental conditions are challenging and costs can be high. We are also considering exploration activities in additional international areas where costs may be high. In addition, our use of advanced technologies requires greater pre-drilling expenditures than traditional drilling strategies. The cost of drilling, completing and operating wells is often uncertain. As a result, we may incur cost overruns or may be required to curtail, delay, or cancel drilling operations because of a variety of factors, including unexpected drilling conditions, pressure or irregularities in geological formations, equipment failures or accidents, adverse weather conditions, compliance with governmental requirements and shortages or delays in the availability of drilling rigs and the delivery of equipment. For example, we have entered into long-term leases on drilling rigs which are not required for the originally intended operations and we cannot be certain that these rigs will be re-employed or at what rate they will be re-employed. Our overall drilling activity or drilling activity within a particular project area may be unsuccessful. Such failure will have a material adverse effect on our results of operations and financial condition.
If we fail to acquire or find and develop additional reserves, our reserves and production will decline materially from their current levels.
The majority of our proved reserves are on the Norwegian Continental Shelf (NCS), a maturing resource province. Except to the extent we conduct successful exploration and development activities or acquire properties containing proved reserves, or both, our proved reserves will decline as reserves are produced. In addition, the volume of production from oil and natural gas properties generally declines as reserves are depleted. For example, two of our major fields, Statfjord and Gullfaks, are dependent on satellite fields to maintain production, and, unless efforts to improve the development of satellite fields are successful, production will gradually decline. Our future production is highly dependent upon our success in finding or acquiring and developing additional reserves. If we are unsuccessful, we may not meet our long-term ambitions for growth in production, and our future total proved reserves and production will decline and adversely affect our results of operations and financial condition.
We encounter competition from other oil and natural gas companies in all areas of our operations, including the acquisition of licenses, exploratory prospects and producing properties.
The oil and gas industry is extremely competitive, especially with regard to exploration for, and exploitation and development of new sources of oil and natural gas.
Some of our competitors are much larger, well-established companies with substantially greater resources, and in many instances they have been engaged in the oil and gas business for much longer than we have. These larger companies are developing strong market power through a combination of different factors, including:
• diversification and reduction of risk;
• financial strength necessary for capital-intensive developments;
• exploitation of benefits of integration;
• exploitation of economies of scale in technology and organization;
• exploitation of advantages of expertise, industrial infrastructure and reserves; and
• strengthening of positions as global players.
These companies may be able to pay more for exploratory prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects, including operatorships and licenses, than our financial or human resources permit. For more information on the competitive environment, see Item 4–Information on the Company–Business Overview.
As we face a variety of challenges in executing our strategic objective of successfully exploiting growth opportunities available to us, the growth of our business may be compromised if we are unable to execute on our strategy and our financial and production targets may be revised as a result of acquisitions made in accordance with our strategy.
An important element of our strategy is to continue to pursue attractive growth opportunities available to us, both in enhancing our asset portfolio and expanding into new markets. The opportunities that we are actively pursuing may involve acquisitions of businesses or properties that complement or expand our existing portfolio. Our ability to implement this strategy successfully will depend upon a variety of factors, including our ability to:
• identify acceptable opportunities;
• negotiate favorable terms;
• develop the performance of new market opportunities or acquired properties or businesses promptly and profitably;
• integrate acquired properties or businesses into our operations; and
• arrange financing, if necessary.
As we pursue business opportunities in new and existing markets, we anticipate that significant investments and costs will be related to the development of such opportunities. We may incur or assume unanticipated liabilities, losses or costs associated with assets or businesses acquired. Any failure by us to pursue and execute new business opportunities successfully could result in financial losses, and could inhibit growth.
If we are successful in the pursuit of our strategy and the making of such acquisitions, and no assurances can be given that we will be, our ability to achieve our financial, capital expenditure and production targets may be materially affected. Any such new projects we acquire will require additional capital expenditure and will increase the cost of our finding and development. It is likely that such acquisitions will be in the exploratory or development phase and not in the production phase, which will have a material adverse effect on our net return in proportion to our average capital employed. These projects may also have different risk profiles than our existing portfolio. These and other effects of such acquisitions could result in us having to revise some or all of our targets with respect to ROACE, unit production costs and production.
In addition, the pursuit of acquisitions or new business opportunities could divert financial and management resources away from our day-to-day operations to the integration of acquired operations or properties. We have no current intention to issue additional equity; we may, however, require additional debt or equity financing to undertake or consummate future acquisitions or projects, which financing may not be available on terms satisfactory to us, if at all, and may, in the case of equity, be dilutive to our earnings per share.
Our development projects involve many uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.
Our development projects may be delayed or unsuccessful for many reasons, including cost overruns, lower oil and gas prices, equipment shortages, mechanical and technical difficulties and industrial action. These projects will also often require the use of new and advanced technologies, which can be expensive to develop, purchase and implement, and may not function as expected. In addition, some of our development projects will be located in deepwater or other hostile environments, such as the Barents Sea, or produced from challenging reservoirs, which can exacerbate such problems. There is a risk that development projects that we undertake may suffer from such problems, such as the Snøhvit project where we have encountered cost overruns and face a challenging timetable for the assembly and transportation of the LNG plant, and the Kristin development, where we are facing difficult drilling conditions.
Our development projects on the NCS also face the challenge of remaining profitable where we are increasingly developing smaller satellite fields in mature areas and our projects are subject to the Norwegian State’s relatively high taxes on offshore activities. Our other development projects in mature fields in Western Europe also face potentially higher operating costs. In addition, our development projects, particularly those in remote areas, could become less profitable, or unprofitable, if we experience a prolonged period of low oil or gas prices.
Many of our mature fields are producing increasing quantities of water with oil and gas. Our ability to dispose of this water in acceptable ways may impact our oil and gas production.
We may not be able to produce some of our oil and gas economically due to a lack of necessary transportation infrastructure when a field is in a remote location.
Our ability to exploit economically any discovered petroleum resources beyond our proved reserves will be dependent upon, among other factors, the availability of the necessary infrastructure to transport oil and gas to potential buyers at a commercially acceptable price. Oil is usually transported by tankers to refineries, and gas is usually transported by pipeline to processing plants and end-users. We may not be successful in our efforts to secure transportation and markets for all of our potential production.
Some of our international interests are located in politically, economically and socially unstable areas, which could disrupt our operations.
We have assets located in unstable regions around the world. For example, there was war and civil strife in the Caspian region through much of the 1990s. In addition, the states bordering the Caspian Sea dispute ownership and distribution of proceeds from the Caspian’s seabed and subsoil resources. Our activities in the Persian Gulf may be subject to disruption due to, for example, war and terrorism. Other countries, such as Venezuela, Nigeria and Angola, where we also have operations, have experienced expropriation or nationalization of property, civil strife, strikes, acts of war, guerrilla activities and insurrections. The occurrence of incidents related to political, economic or social instability could disrupt our operations in any of these regions, causing a decline in production that could have a material adverse effect on our results of operations or financial condition.
Our activities in Iran could lead to U.S. sanctions.
In August 1996, the United States adopted the Iran and Libya Sanctions Act, referred to as ILSA, which authorizes the President of the United States to impose sanctions (from a list that includes denial of financing by the export-import bank and limitations on the amount of loans or credits available from U.S. financial institutions) against persons found by the President to have knowingly made investments in Iran of USD 20 million or more that directly and significantly contribute to the enhancement of such countries’ ability to develop their petroleum resources. The Iran-Libyan Sanctions Act was adopted with the objective of denying Iran and Libya the ability to support acts of international terrorism and fund the development or acquisition of weapons of mass destruction. We might take part in certain exploration projects or study activities with respect to Iran. In October 2002, we signed a participation agreement with Petropars of Iran, pursuant to which we assumed the operatorship for the offs hore part of phases 6-7-8 of the South Pars gas development project in the Persian Gulf. At the end of 2005, we had invested USD 329 million in connection with the project. We cannot predict interpretations of or the implementation policy of the U.S. Government under ILSA with respect to our current or future activities in Iran or other areas. It is possible that the United States may determine that these or other activities will constitute activity covered by ILSA and will subject us to sanctions.
We are exposed to potentially adverse changes in the tax regimes of each jurisdiction in which we operate.
We operate in 32 countries around the world, and any of these countries could modify its tax laws in ways that would adversely affect us. Most of our operations are subject to changes in tax regimes in a similar manner as other companies in our industry. In addition, in the long term, the marginal tax rate in the oil and gas industry tends to change in correlation with the price of crude oil. Significant changes in the tax regimes of countries in which we operate could have a material adverse affect on our liquidity and results of operation.
We are not insured against all potential losses and could be seriously harmed by natural disasters or operational catastrophes.
Exploration for and production of oil and natural gas is hazardous, and natural disasters, operator error or other occurrences can result in oil spills, blowouts, cratering, fires, equipment failure, and loss of well control, which can injure or kill people, damage or destroy wells and production facilities, and damage property and the environment. Offshore operations are subject to marine perils, including severe storms and other adverse weather conditions, vessel collisions, and governmental regulations, as well as interruptions or termination by governmental authorities based on environmental and other considerations. Losses and liabilities arising from such events would significantly reduce our revenues or increase our costs and have a material adverse effect on our operations or financial condition.
The crude oil and natural gas reserve data in this Annual Report on Form 20-F are only estimates, and our future production, revenues and expenditures with respect to our reserves may differ materially from these estimates.
The reliability of proved reserve estimates depends on:
• the quality and quantity of our geological, technical and economic data;
• whether the prevailing tax rules and other government regulations, contracts, and oil, gas and other prices will remain the same as on the date estimates are made;
• the production performance of our reservoirs; and
• extensive engineering judgments.
Many of the factors, assumptions and variables involved in estimating reserves are beyond our control and may prove to be incorrect over time. Results of drilling, testing and production after the date of the estimates may require substantial upward or downward revisions in our reserve data. Any downward adjustment could lead to lower future production and thus adversely affect our financial condition, future prospects and market value.
We face foreign exchange risks that could adversely affect our results of operations.
Our business faces foreign exchange risks because a large percentage of our revenues and cash receipts are denominated in U.S. dollars while a significant portion of our operating expenses and income taxes accrue in Norwegian kroner, reflecting our operations on the NCS. Movements between the U.S. dollar and Norwegian kroner may adversely affect our business. While an increase in the value of the U.S. dollar against the Norwegian kroner can be expected to increase our reported earnings, such an increase would also be expected to increase our operating expenses and the value of our debt, which would be recorded as a financial expense, and, accordingly, would adversely affect our net income. See Item 5–Operating and Financial Review and Prospects–Liquidity and Capital Resources–Risk Management.
Public authorities in the United States are conducting investigations into a consultancy arrangement we entered into with respect to business development in Iran, which, if proceedings are brought and determined against us, could result in fines, penalties, sanctions or other restrictions that could have a material adverse effect on our business.
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., a Turks & Caicos Island company, for consultancy services in Iran. On June 28, 2004, Økokrim informed Statoil that it had concluded that Statoil violated section 276c, first paragraph (b) of the Norwegian Penal Code and imposed a penalty on Statoil of NOK 20 million. Statoil’s board decided on October 14, 2004 to accept the penalty without admitting or denying the charges by Økokrim. The U.S. Securities and Exchange Commission is conducting a formal investigation into this consultancy arrangement to determine if there have been any violations of U.S. federal securities laws, including the Foreign Corrupt Practices Act. The U.S. Department of Justice is also conducting a criminal investigation of the Horton matter jointly with the Office of the Unite d States Attorney for the Southern District of New York. The SEC staff informed Statoil on September 24, 2004 that it is considering recommending that the SEC authorize a civil enforcement action in federal court against Statoil for violations of various U.S. federal securities laws, including the anti-bribery and books and records provisions of the Foreign Corrupt Practices Act. See Item 8—Financial Information—Legal Proceedings.
We are continuing to provide information to the U.S. authorities in order to assist them in their ongoing investigations. Responding to the requests of the public authorities and cooperating with their investigations continues to divert management’s attention and resources, and any developments or requests by the authorities for additional information will engage more of management’s attention and resources. We cannot predict the outcome of these inquiries being conducted by public authorities in the United States or the resulting effect that they might have on our business. If proceedings are brought and determined against us in the United States this may result in fines, penalties, sanctions or restrictions that could have a material adverse effect on our business or financial results.
Risks Related to the Regulatory Regime
Competition is expected to increase in the European gas market, currently our main market for gas sales, as a result of European Union, or EU, directives which could adversely affect our ability to expand or even maintain our current market position or result in reduction in prices in our gas sales contracts.
Fundamental changes continue to occur in the organization and operation of the European gas market, with the objective of opening national markets to competition and integrating them into a single market for natural gas. This process started with the EU Gas Directive, which became effective in August 2000. The Directive was included in the EEA Agreement in June 2002, and all necessary changes in order to implement the Directive into Norwegian legislation were made during 2002. The Directive requires EEA states to take certain minimum steps to open their gas markets to greater competition. Each state must specify annually the wholesale and final gas customers inside its territory that have the legal capacity to contract for or be sold natural gas by the gas supplier of their choice.
The Directive also requires that eligible customers be given the right to negotiate agreements for using gas transport systems directly or rights of access based on tariffs or other mechanisms. In 2003, a new Gas Directive approved by the EU accelerated the requirements for market opening, allowing both large users and households to freely choose their supplier earlier than previously anticipated.
Most of our gas is sold under long-term gas contracts to customers in the EU, a gas market that will continue to be affected by changes in EU regulations and implementation of such regulations in EU member states. As a result of the Directives, our ability to expand or even maintain our current market position could be materially adversely affected and quantities sold under our gas sales contracts may be subject to a material reduction in gas prices.
We may incur material costs to comply with, or as a result of, health, safety and environmental laws and regulations.
Compliance with environmental laws and regulations in Norway and abroad could materially increase our costs. We incur and expect to continue to incur, substantial capital and operating costs to comply with increasingly complex laws and regulations covering the protection of the environment and human health and safety, including costs to reduce certain types of air emissions and discharges to the sea and to remediate contamination at various owned and previously-owned facilities and at third party sites where our products or wastes have been handled or disposed. The Norwegian Petroleum Safety Authority (PSA)was established on January 1, 2004, with the regulatory responsibility for safety, emergency preparedness and the working environment for all petroleum-related activities. Although existing regulations relating to HSE in petroleum activities continue with the PSA as the responsible authority, the PSA's sphere of responsibility was expanded. See Item 4–Information on the Company—Regulation.
In our capacity as holder of licenses on the NCS under the Norwegian Petroleum Act of November 29, 1996, we are subject to statutory strict liability in respect of losses or damages suffered as a result of pollution caused by spills or discharges of petroleum from petroleum facilities covered by any of our licenses. This means that anyone who suffers losses or damages as a result of pollution caused by operations at any of our NCS license areas can claim compensation from us without needing to demonstrate that the damage is due to any fault on our part.
Whether in Norway or abroad, new laws and regulations, the imposition of tougher requirements in licenses, increasingly strict enforcement of or new interpretations of existing laws and regulations, or the discovery of previously unknown contamination may require future expenditures to:
• modify operations;
• install pollution control equipment;
• perform site clean-ups; or
• curtail or cease certain operations.
In particular, we may be required to incur significant costs to comply with the 1997 Kyoto Protocol to the United Nations Framework Convention on Climate Change, known as the Kyoto Protocol, and other pending EU laws and directives. In addition, increasingly strict environmental requirements, including those relating to gasoline sulphur levels and diesel quality, affect product specifications and operational practices. Future expenditures to meet such specifications could have a material adverse effect on our operations or financial condition.
Political and economic policies of the Norwegian State could affect our business.
The Norwegian State plays an active role in the management of NCS hydrocarbon resources. In addition to its direct participation in petroleum activities through the SDFI and its indirect impact through tax and environmental laws and regulations, the Norwegian State awards licenses for reconnaissance, production and transportation and approves, among other things, exploration and development projects, gas sales contracts and applications for (gas) production rates for individual fields. The Norwegian State may also, if important public interests are at stake, direct us and other oil companies to reduce production of petroleum. Reductions of up to 7.5 per cent have been imposed in the past. By a royal decree of December 19, 2001, the Norwegian government decided that Norwegian oil production should be reduced by 150,000 barrels per day from January 1, 2002 until June 30, 2002. This amounted to roughly a 5 per cent reduction in output. Further, in the production licenses in which the SDFI holds an interest, the Norwegian State retains the ability to direct petroleum licensees’ actions in certain circumstances.
If the Norwegian State were to take additional action pursuant to its extensive powers over activities on the NCS or to change laws, regulations, policies or practices relating to the oil and gas industry, our NCS exploration, development and production activities and results of operations could be materially and adversely affected. For more information about the Norwegian State’s regulatory powers, see Item 4–Information on the Company—Regulation.
Risks Related to Our Ownership by the Norwegian State
The interests of our majority shareholder, the Norwegian State, may not always be aligned with the interests of our other shareholders, which may affect our decisions relating to the NCS.
The Norwegian Parliament, known as the Storting, and the Norwegian State have resolved that the Norwegian State’s shares in Statoil and the SDFI’s interests in NCS licenses must be managed pursuant to a coordinated ownership strategy for the Norwegian State’s oil and gas interests. Under this strategy, the Norwegian State has required us to continue to market the Norwegian State’s oil and gas together with our own as a single economic unit.
Pursuant to the coordinated ownership strategy for the Norwegian State’s shares in us and the SDFI, the Norwegian State requires us in our activities on the NCS to take account of the Norwegian State’s interests in all decisions which may affect the development and marketing of our own and the Norwegian State’s oil and gas.
The Norwegian State holds more than a two-thirds majority of our shares. Accordingly, the Norwegian State has the power to determine matters submitted for a vote of shareholders, including amending our articles of association and electing all of the members of the corporate assembly except employee representatives. The employees may claim the right to be represented by up to one-third of the members of the board of directors as well as the corporate assembly. The corporate assembly is responsible for electing our board of directors and communicates its recommendations concerning the board of directors’ proposals about the annual accounts, balance sheets, allocation of profits and coverage of losses of our company to the general meeting. The interests of the Norwegian State in deciding these and other matters and the factors it considers in exercising its votes, especially pursuant to the coordinated ownership strategy for the SDFI and our shares held by the Norwegian State, could be different from t he interests of our other shareholders. Accordingly, when making commercial decisions relating to the NCS, we have to take into account the Norwegian State’s coordinated ownership strategy and we may not be able to fully pursue our own commercial interests, including those relating to our strategy on development, production and marketing of oil and gas.
If the Norwegian State’s coordinated ownership strategy is not implemented and pursued in the future, then our mandate to continue to sell the Norwegian State’s oil and gas together with our own as a single economic unit is likely to be prejudiced. Loss of the mandate to sell the SDFI’s oil and gas could have an adverse effect on our position in our markets. For further information about the Norwegian State’s coordinated ownership strategy, see Item 7–Major Shareholders and Related Party Transactions–Major Shareholders.
Forward-Looking Statements
This Annual Report on Form 20-F contains forward-looking statements that involve risks and uncertainties, in particular under Item 4–Information on the Company and Item 5–Operating and Financial Review and Prospects. In some cases, we use words such as “believe”, “intend”, “expect”, “anticipate”, “plan”, “target” and similar expressions to identify forward-looking statements. All statements other than statements of historical facts, including, among others, statements regarding our future financial position, business strategy, budgets, reserve information, reserve replacement rates, reserve recovery factors, projected levels of capacity, oil and gas production forecasts,production growth, projected operating costs, exploration expenditure, estimates of capital expenditure, expected exploration and development activities and plans, start-up dates for upstream and downstream activities, HSE goals and objectives of management for future operations, are forward-looking statements. You should not place undue reliance on these forward-looking statements. Our actual results could differ materially from those anticipated in the forward-looking statements for many reasons, including the risks described above in Item 3–Key Information, below in Item 5–Operating and Financial Review and Prospects, and elsewhere in this Annual Report on Form 20-F.
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 com petitors; the actions of field partners; natural disasters and other changes to business conditions; and other factors discussed elsewhere in this report.
Although we believe that the expectations reflected in the forward-looking statements are reasonable, we cannot assure you that our future results, level of activity, performance or achievements will meet these expectations. Moreover, neither we nor any other person assumes responsibility for the accuracy and completeness of the forward-looking statements. Unless we are required by law to update these statements, we will not necessarily update any of these statements after the date of this Annual Report, either to conform them to actual results or to changes in our expectations.
Statements Regarding Competitive Position
Statements made in Item 4–Information on the Company, referring to Statoil’s competitive position, are based on our belief, and in some cases rely on a range of sources, including investment analysts’ reports, independent market studies and our internal assessments of market share based on publicly available information about the financial results and performance of market participants.
Item 4 Information on the Company
History and Development of the Company
Statoil ASA is a public limited company organized under the laws of Norway with its registered office at Forusbeen 50, N-4035 Stavanger, Norway. Our telephone number is +47 51 99 00 00. Our registration number in the Norwegian Register of Business Enterprises is 923 609 016. Statoil ASA was incorporated on September 18, 1972 under the name Den norske stats oljeselskap a.s. At an extraordinary general meeting held on February 27, 2001, it was resolved to change our company name to Statoil ASA and convert into a public listed company, or ASA.Business Overview
We are an integrated oil and gas company, headquartered in Stavanger, Norway. Based on both production and reserves we are a major international oil and gas company and the largest in Scandinavia. Our proved reserves as of December 31, 2005 consisted of 1,761 mmbbls of oil and 403 bcm (equivalent to 14.2 tcf) of natural gas, which represents an aggregate of 4,295 mmboe. Our operations commenced in 1972 with a primary focus on the exploration, development and production of oil and natural gas from the Norwegian Continental Shelf, or NCS. Since then, we have grown both domestically and internationally into a company with 25,644 employees and business operations in 32 countries as of December 31, 2005.We review our petroleum reserves routinely in the course of business from time to time as new information becomes available. This information can relate to remaining reserves, existing production performance, decisions related to development, production, acquisition and divestment of reserves and changes in economic conditions. In addition, information on proved oil and gas reserves, standardized measure of discounted net cash flows relating to proved oil and gas reserves, and other information related to proved oil and gas reserves reported in the Supplementary Information on Oil and Gas Producing Activities is collected and checked for consistency and conformity with applicable standards by a central group that is independent of the E&P business units. Although this group reviews the information centrally, each asset is responsible for ensuring that it is in compliance with the requirements of the SEC and our corporate standards. Before presenting the aggregated results to the responsible management of the relevant business units and the Chief Executive Officer for approval, this central group asks DeGolyer and MacNaughton, independent petroleum engineering consultants, to perform an independent evaluation of proved reserves, which was performed as of December 31, 2005 for our properties. The results obtained by DeGolyer and MacNaughton do not differ materially from those reported by us when compared on the basis of net equivalent barrels of oil. DeGolyer and MacNaughton has delivered to us its summary letter report describing its procedures and conclusions, a copy of which appears as Appendix A hereto. Reserve engineering is a process of forecasting the recovery and sale of oil and gas from a reservoir and is in part subjective. It is clearly associated with considerable uncertainty, often positive, but also negative. The accuracy of any reserve information is a function of the quality of available data and of engineering and requires interpretation and judgment. The requirements of the SEC with respe ct to the calculation of proved reserves set a standard for estimating reserves, which results in amounts that are reasonably certain technically, and consistent with the economic, regulatory and operating conditions at the time the estimates are made. See Supplementary Information on Oil and Gas Producing Activities beginning on page F-33 for further details of our proved reserves.
We are the leading producer of crude oil and gas on the technologically demanding NCS and are well positioned internationally, having participated in a number of high-quality discoveries outside the NCS. We are the largest supplier of natural gas from the NCS (including sales we make on behalf of the Norwegian State) to the growing Western European gas market. We are one of the market leaders, with a market share of approximately 23 per cent, in the retail gasoline business in Scandinavia. We are one of the largest net sellers of crude oil worldwide, including sales of crude oil purchased from the Norwegian State.
We divide our operations into four reporting business segments: Exploration and Production Norway, International Exploration and Production, Natural Gas, and Manufacturing and Marketing. In 2004 we established a new business area service unit, Technology and Projects (T&P), in order to develop distinct technology positions and strengthen our project execution. This centralized function will ensure effective project development and execution and will contribute to effective operations. The T&P unit is responsible for the execution of new development projects from the date of provisional project sanction through to production start-up. As of January 1, 2006, the T&P unit is responsible for the execution of the following projects: Snøhvit, Langeled, Statfjord Late Life, Tampen Link, Tyrihans, Volve, Huldra Tail End Production, Tordis IOR, Sleipner B Compression, Vigdis Extension Phase 2, Aldbrough Gas Storage and Skinfaks/Rimfaks IOR. Descriptions of these projects are included below accor ding to the business segment that will be responsible for the operation of the relevant projects following commencement of production.
The statements contained in this Item 4 regarding exploration and development projects and production estimates are forward-looking and subject to significant risks and uncertainties. Although we believe that the expectations reflected in the forward-looking statements are reasonable, we cannot assure you that our actual levels of activity, production or performance will meet these expectations. See Item 3—Key Information—Risk Factors.
The following table sets forth the income before financial items, income taxes and minority interest for each segment for the periods indicated.
(in millions) | Year ended December 31, | |||
2005 | 2004 | 2003 | ||
NOK | USD | NOK | NOK | |
Income before financial items, income taxes and minority interest of: | ||||
E&P Norway | 74,132 | 10,992 | 51,029 | 37,855 |
International E&P | 8,364 | 1240 | 4,188 | 1,781 |
Natural Gas | 5,901 | 875 | 6,784 | 6,005 |
Manufacturing and Marketing | 7,646 | 1134 | 3,921 | 3,555 |
Other | (947) | (140) | (815) | (280) |
Total | 95,096 | 14,100 | 65,107 | 48,916 |
The segment information included in this table and throughout this Annual Report on Form 20-F reflects the business segment split as at the date of filing. Prior periods have been adjusted for the transfer of Kollsnes from the E&P Norway business segment to the Natural Gas Business Segment and for other minor reorganizations that took place in 2004.
Further details on the financial results can be found in Item 5—Operating and Financial Review and Prospects—Operating Results.
Exploration and Production Norway. E&P Norway includes our exploration, development and production operations on the NCS. Our NCS operations are organized in four core areas, of which three are currently producing hydrocarbons - Troll/Sleipner, Halten-Nordland, and Tampen - and one, Tromsøflaket, which is expected to begin production in 2007. We operate 24 developed fields in our three producing core areas. These fields produced a total of 2.6 mmboe per day in 2005, 58 per cent of total NCS daily production. Throughout 2005, our daily equity oil and NGL production was 562 mboe of oil and daily equity gas production was 67 mmcm (2.4 bcf), totaling 985 mboe per day, compared to 625 mbbls of oil and daily equity gas production of 58 mmcm (2.1 bcf), totaling 991 mboe per day in 2004. We are also well positioned in three promising prospective areas: the Møre/Vøring and Lofoten areas in the Norwegian Sea and the Norwegian part of the Barents Sea. As of December 31, 2005, E&P Norway had proved reserves of 1,142 mmbbls of crude oil and 369 bcm (13.0 tcf) of natural gas, which represents an aggregate of 3,462 mmboe. Our experience over the last 30 years in the challenging NCS environment has helped us develop expertise in managing complex, integrated projects. We are continuously seeking to improve our returns through both cost efficiency and portfolio management.
International Exploration and Production. International E&P includes all upstream related activities of Statoil’s exploration, development and production operations outside Norway. We hold interests in 15 producing fields in North Africa (Algeria), Western Africa (Angola), the Caspian (Azerbaijan), Western Europe (UK), South America (Venezuela) and China. Statoil is involved in development projects in Algeria, Angola, Nigeria, Azerbaijan, Ireland, the Gulf of Mexico/USA and Iran. Exploration activities include projects in Algeria, Angola, Azerbaijan, Brazil, the Faroe Islands, Gulf of Mexico/USA, Ireland, Libya, Nigeria, the UK and Venezuela. As of December 31, 2005, International E&P had proved reserves of 619 mmbbls of crude oil and 34.0 bcm (1.2 tcf) of natural gas, which represents a total of 833 mmboe. In 2005, we produced 141.8 mbbls of oil and 6.8 mmcm (239 mmcf) of gas per day from our international operations, a total of 184.4 mboe per day, compared to 100 mmbbls of oil and 2.4 mmcm (84 mmcf) of gas, a total of 114.9 mboe per day in 2004.
Natural Gas. The Natural Gas business segment transports, processes and sells natural gas from our upstream positions on the NCS and certain assets abroad. We are one of the leading suppliers of natural gas to the European market and the largest corporate owner in the world’s largest offshore pipeline network. This network, Gassled, allows us flexibility in the way we source, blend and deliver our natural gas to any one of five landing points in Europe and through to the European gas transmission system. We have a 21.31 per cent interest in the Gassled joint venture. As from February 1, 2004, the Kollsnes Gas Plant was included in Gassled. In 2005, we sold approximately 58.9 bcm (2.1 tcf) of natural gas (at a gross calorific value of 40 MJ/scm), which includes natural gas sold by us on behalf of the Norwegian State, compared to 55.3 bcm (2.0 tcf) in 2004, also including natural gas sold by us on behalf of the Norwegian State.
Manufacturing and Marketing. The Manufacturing and Marketing segment comprises downstream activities including sales and trading of crude oil, NGL and petroleum products, refining, methanol production, retail and industrial marketing of oil. The internal retail unit was reorganized in 2005, integrating all of our retail operations in nine countries under unified management with the objective of optimizing the contribution from retail and identifying synergies both within the retail group and the rest of Statoil.
Strategy and Opportunities
Our strategic objective is to exploit the profitable options as an integrated oil and gas company with emphasis on maximizing value creation on the NCS and securing growth opportunities internationally while maintaining strict capital discipline.
In pursuit of our strategic objectives, we intend to:
Deliver growth and performance. We believe that we enjoy a strong position both strategically and financially, having shown significant improvements in recent years. We have developed specific strategies and plans that underpin our ambitions of long-term profitable growth. Our efforts to deliver on these ambitions are supported by a set of corporate initiatives that will support short-term deliveries and lay the basis for long-term growth. The corporate initiatives cut across the business areas and are intended to continue the development of the group’s strategic foundation. Ten of the corporate initiatives, together with associated ambitions, have been communicated externally, and fall into short-term and long-term categories. In addition, a number of improvement measures have been implemented by the business areas.
See Item 5—Operating and Financial Review and Prospects for a review of our 2005 performance. Specific details regarding our 2007 corporate targets can be found in Item 5—Operating and Financial Review and Prospects—Corporate Targets.
Drive new growth in E&P Norway. We are the leading operator and producer of oil and gas on the NCS, a region with significant remaining resources. We are maintaining a production target of 1.1 mmboe per day in 2007. Our portfolio of producing fields and new projects allows us to fulfill this target without being dependent on additional discoveries. As the majority of these resources is expected to be gas, we anticipate a gradual decrease in oil production and corresponding increase in gas production in the next ten to twenty years.
Our long-term ambition is to sustain a level of 1 mmboe per day beyond 2010. To realize this ambition, while at the same time managing the production decline of mature fields, we will intensify our effort to increase recovery, realize new projects and actively continue exploration.
During 2005, six development projects were completed; the three most important were Kristin, Urd and the pre-compression project on Troll. In 2005, we also sanctioned twelve new development projects. This, together with other already sanctioned projects under development, illustrates the high level of activity on the NCS.
Most of the undiscovered resources on the NCS are expected to be located in the Norwegian Sea and in the Barents Sea. Nevertheless, large volumes are also expected to be found in the North Sea. We foresee high exploration drilling activity in the years to come, both in areas close to existing infrastructure and in frontier areas. In the Barents Sea, we plan to start production from the Snøhvit LNG field during 2007.
Deliver International E&P production growth. Having targeted and concentrated our international exploration and production activities in selected areas, we are focusing our efforts on establishing significant production and increasing our influence in our producing areas: North Africa, Western Africa, the Caspian, Western Europe, and South America.
In May 2005, Statoil purchased all of EnCana's Gulf of Mexico assets, including its 25 per cent interest in the Tahiti field, other discoveries and exploration acreage. We are pursuing additional opportunities internationally that support our strategy and leverage our skills and competence from the NCS. These opportunities may include acquisitions of oil or gas assets in the development or production phase that complement or expand our existing portfolio.
Increase profits in the gas value chain. As a leading supplier of gas to Europe, we are well positioned to benefit from growing demand for gas and the deregulation of gas markets, and will adapt to new commercial opportunities. We intend to actively manage our upstream portfolio and transportation capacities to maximize the income from existing long-term natural gas contracts. We aim to exploit economies of scale in marketing of gas, and in particular, we intend to capitalize on the trading and optimization opportunities that will arise with the anticipated increase in demand for imports of gas in the United Kingdom, a market we are well positioned to supply. We will also increase our ability to realize additional margin and optimize synergies by extracting and commercializing NGL streams to meet internal and external demand for NGL. Moreover, we aim to build gas value chains from supply areas other than the Norwegian Continental Shelf into Europe, and proceed from our positions in the Caspian, Algeria and the Barents Sea (the Snøhvit LNG project). Our position in the Cove Point LNG terminal will enable us to build an Atlantic LNG business and a U.S. gas marketing business.
Strengthen our downstream performance and position. Emphasis will be placed on integration with our upstream businesses and more efficient distribution of our products to the end user. We are the largest retailer of gasoline in Scandinavia and we expect to be able to strengthen our position further with the integration of our Scandinavian and international retail operations. In refining, partially through our joint ventures with the Shell group at Mongstad and Pernis, we intend to continue with our cost reductions and productivity improvements to increase utilization and efficiency of existing capacity. In addition, we continuously need to develop the refineries in order to meet future product specification requirements.
Exploration and Production Norway
Introduction
E&P Norway is the cornerstone of our business, consisting of exploration, development and production operations on the NCS. We participate in the majority of the 49 producing oil and gas fields on the NCS and as of December 31, 2005, we were the operator for 24 of these fields.
We are the sole operator in the Tampen area. We are also the operator of the Troll gas field in the Troll/Sleipner area. Other major oil and gas fields in the Troll/Sleipner area include Sleipner, where we are operator, and Oseberg, which is operated by Norsk Hydro. The main producing fields in the Halten/Nordland area include Åsgard, Heidrun and Kristin, all of which we operate. E&P Norway reported Income before financial items, income taxes and minority interest of NOK 74,132 million, an increase of 43 per cent compared to 2004. In the year ended December 31, 2005, we produced 985 mboe per day compared with 991 mboe per day in 2004.
The following table presents key financial information about this business segment.
(in millions) | Year ended December 31, | |||
2005 | 2004 | 2003 | ||
NOK | USD | NOK | NOK | |
Revenues | 97,623 | 14,475 | 74,050 | 62,494 |
Depreciation, depletion and amortization | 11,450 | 1,698 | 12,381 | 11,969 |
Exploration expenditure | 2,188 | 324 | 1,092 | 1,215 |
Income before financial items, income taxes and minority interest | 74,132 | 10,991 | 51,029 | 37,855 |
Capital expenditure | 16,257 | 2,410 | 16,776 | 13,136 |
Long-term assets (excluding deferred tax assets) | 86,386 | 12,809 | 81,629 | 76,468 |
Further details on the financial results can be found in Item 5—Operating and Financial Review and Prospects—Operating Results.
The NCS. We are the leading exploration, production and transport company on the NCS. As of January 6, 2006, we held production and exploration licenses covering a total area of approximately 64,420 square kilometers, and production licenses in respect of 3,462 mmboe of proved reserves, compared to 3,401 mmboe as of December 31, 2004.
In five to ten years our current NCS production is expected to enter into a gradual decline. In order to counteract this and meet our targets and ambitions in coming years, our recovery rate must continue to improve, identified resources must be brought on stream and new oil and gas discoveries must be made. We believe that significant opportunities remain on the NCS. In addition to the possibility of large discoveries, production will come from a large number of smaller fields, many of which will be characterized by complex geology. These fields will require the innovative application of advanced technologies, for which we have a proven record of success. The map below indicates the location of the areas referred to within this section.
Core Producing Areas. We have three core producing areas on the NCS: Troll/Sleipner, Halten/Nordland and Tampen. The fields in each area use common infrastructure, such as production installations, and oil and gas transport facilities where possible, which together reduce the investment necessary to develop new fields. Our efforts in the core areas will also focus on developing smaller fields through the use of existing infrastructure and enhancing production by improving recovery factors. We are working actively to maximize reserves and economic return from our fields through improved reservoir management and application of new technology. Key elements in this effort include:
• seabed and time lapse seismic methods to map reservoirs more accurately and identify (bypassed) oil as targets for drilling of additional wells;
• drilling of extended-reach wells, horizontal wells and "designer" wells (wells drilled with a curve in the horizontal plane for optimal drainage of reservoirs);
• use of gas injection, combinations of water and gas injection and microbial recovery methods in order to improve the reservoir drainage; increased
• utilization of integrated operations (the intelligent field concept) with a focus on tools for planning, analysis and decision support, which will allow remote control of the technical processes in the fields; and
• quantification and use of alternative well solutions (monobore, Through Tubing Well Construction, well intervention technologies) with high potential for unit cost reduction.
Potential Producing Areas
Regarding exploration acreage outside our three producing core areas, we are well positioned in the central and southern parts of the North Sea, in the Møre/Vøring area in the Norwegian Sea and the Lofoten areas of the Norwegian Sea and in the Barents Sea, all of which we believe to have significant hydrocarbon resource potential.
North Sea. Total licensed acreage in the North Sea covers 26,753 square kilometers, of which we are the operator of 9,547 square kilometers. One license was relinquished in the central area in 2005. Thirteen new licenses, including additional acreage close to existing acreage, were awarded to us in the North Sea in 2005. This includes licenses awarded in annual licensing rounds in mature areas of the NCS (APA). We became operator for seven of these new licenses.
Norwegian Sea. We have interests in 28,110 square kilometers of licensed acreage in the Norwegian Sea of which we are the operator for 12,574 square kilometers. Two exploration wells were drilled in 2005 in this area. In the deepwater region we have interests in licenses covering approximately 18,150 square kilometers. The Lofoten area was not opened in 2005 for further exploration activities. This area, in which we have interests in 250 square kilometers of licensed acreage, is one of several major oil provinces left to explore on the NCS. However, the Norwegian Government decided late in 2003 not to allow further petroleum activity in the area due to its special character as a spawning ground for important fish stocks and as a fishing ground. The Government has found that, at present, it has not been demonstrated that adequate protection of the fisheries and the environment can be maintained if petroleum activities are allowed in the area. These issues will be considered again when the Norwegian government’s Integrated Management Plan discussing these areas is presented later in 2006.
Three licenses were relinquished in 2005, of which one was located in the deepwater area. Seven new licenses, including additional acreage to existing acreage, were awarded to us in the Norwegian Sea in 2005 (including APA 2005) and we became operator for five of them. In addition we increased our participating interest in three existing licenses and obtained approval from the Norwegian Ministry of Petroleum and Energy (MPE) to carve out acreage in one license. We reduced our participating interest in three existing licenses.
We applied for new exploration acreage in the Norwegian Sea in the 19th Licensing Round 2005. Awards are expected by early April, 2006.
Barents Sea. Our fourth core area, Tromsøflaket, includes our gas discovery Snøhvit, which is currently under development and has been rescheduled to be on stream in 2007. The acreage of this core area has been increased to 2,305 square kilometers. We have further interests in 7,252 square kilometers of licensed acreage and approximately 12,000 square kilometers consisting of three seismic option areas. The Government decided to allow for further all-year petroleum activity in the South Barents Sea, with some exceptions, and as a result, all existing licenses in the Barents Sea resumed their activities in 2005. There have been no relinquishments or awards of license acreage in 2005. We applied for new exploration acreage in the Barents Sea in the 19th Licensing Round 2005. Awards are expected by early April 2006.
Portfolio management
Statoil is using portfolio management as an active tool to optimize our license portfolio, strengthen our core areas and secure our long-term production targets. Discussions are ongoing with several companies regarding possible business opportunities based on our portfolio strategy.
In 2005 we swapped a share in the Hild licenses, PL040 and 043, to align the respective interests in the licenses for Total and Statoil.
We also arranged for a farm-in agreement with BG Norge in an exploration license, PL251 Tulipan, where BG Norge acquired 20 per cent of the license.
In February 2005, we completed a swap with Shell (Enterprise Oil) where Statoil, in addition to its existing ownership, acquired a 1.18 per cent interest in the Snorre field, a 6 per cent interest in Norne, a 10 per cent interest outside Norne and a 25 per cent interest in the Alve discovery. Shell received a 6.45 per cent interest in the Kvitebjørn field as part of the transaction. The transaction added long term production and reserves to our portfolio and strengthened our position as operator in Snorre.
Exploration and Development
We have been engaged in exploration and drilling on the NCS since 1975 and had drilled a total of 296 Statoil operated exploration wells as of December 31, 2005.
Our exploration and development program is designed to strengthen our position on the NCS through increasing reserves, leveraging existing infrastructure and enabling the development of new core areas. Approximately 70 per cent of all exploration wells that we drilled in the last three years have yielded discoveries or positive appraisals that have confirmed our assessments regarding hydrocarbons in place. We coordinate the development of new fields so as to minimize required new investments in infrastructure.
In 2005, we participated in nine exploration and appraisal wells and were the operator for four of these wells. In addition five exploration extensions on production wells were drilled of which three were operated by us. Hydrocarbons were discovered in six of the exploration and appraisal wells, and four of the exploration extensions – giving a success rate of 71 per cent. Six of the ten discoveries were operated by us. In 2004 we participated in six exploration wells, four operated by us, and drilled one exploration extension on a production well.
Within the North Sea region, five exploration and appraisal wells and five exploration extensions were drilled in 2005. The appraisal well, operated by us, confirmed the 2004 Gimle (previously known as Topas) oil discovery located in the Tampen core area. We also discovered oil in a new segment located south of the Vigdis field. Hydrocarbons were discovered in all three of the exploration extensions of development wells operated by us. An appraisal well is scheduled for drilling on this new discovery early in 2006. Norsk Hydro discovered oil in two exploration wells, one located at the Fram field (Astero) and one at the Oseberg South Unit (J-Sentral) and in an exploration extension at the Oseberg field (B-Sør).
In the Norwegian Sea, two new exploration wells were drilled. Norske Shell discovered gas in a well located just south of our Kristin field in the Halten/Nordland producing core area. Exploration and evaluation of the area will continue and an appraisal well located on the new discovery is scheduled for drilling in 2006. In the Møre/Vøring region, which is the deepwater part of the Norwegian Sea, we made a minor gas discovery. Evaluation of the find and surrounding areas will continue in 2006.
In the Barents Sea, two exploration wells were completed in 2005. In the eastern part of the area we drilled a dry well. Update of the potential in the area, based on new well-information, will continue in 2006. The second well, drilled by Norsk Hydro just north of Snøhvit, was also dry. In mid-January 2006, oil was discovered in a third well drilled by Eni. This appraisal well is located on the Goliath oil discovery.
Our exploration expenditure on the NCS in 2005, including expenditure in respect of field development costs, totaled NOK 2,188 million, of which NOK 528 million was capitalized. The corresponding figures for 2004 were NOK 1,092 million and NOK 376 million, respectively. The increase in exploration expenditure from 2004 was due to increased drilling costs and seismic activity, as well as early phase concept studies. Additionally, exploration expenditure of NOK 158 million, which was capitalized in earlier years, was expensed in 2005 compared to NOK 61 million in 2004.
Of our 2005 NCS exploration expenditures, 54 per cent was spent outside our three core producing areas, mostly in our potential production areas in the North Sea and Norwegian Sea.
Our expenditure on development on the NCS totaled NOK 15.1 billion in 2005 compared to NOK 15.4 billion in 2004. In 2005, we participated in 115 development wells, and in 2004 we participated in 94 development wells. Of our 2005 NCS development budget, approximately 75 per cent was spent in our three core producing areas and the remainder in our potential production areas in the Barents and Norwegian Seas.
The following table sets forth our exploratory and development wells drilled on the NCS, including a breakdown of successful or productive wells and dry wells, drilled by core area for each of the three years ended December 31, 2005, 2004 and 2003.
| Year ended December 31, | ||
2005 | 2004 | 2003 | |
North Sea |
|
|
|
Statoil Operated Exploratory |
|
|
|
Successful | 2 | 1 | 2 |
Dry | 0 | 0 | 1 |
Total | 2 | 1 | 3 |
Development | 30 | 39 | 49 |
|
|
|
|
Successful | 2 | 1 | 2 |
Dry | 1 | 0 | 1 |
Total | 3 | 1 | 3 |
Development | 51 | 41 | 39 |
|
|
|
|
Statoil Operated Exploratory |
|
|
|
Successful | 1 | 2 | 2 |
Dry | 0 | 1 | 1 |
Total | 1 | 3 | 3 |
Development | 26 | 14 | 11 |
|
|
|
|
Successful | 1 | 0 | 0 |
Dry | 0 | 1 | 0 |
Total | 1 | 1 | 0 |
Development | 0 | 0 | 0 |
|
|
|
|
Statoil Operated Exploratory |
|
|
|
Successful | 0 | 0 | 0 |
Dry | 1 | 0 | 0 |
Total | 1 | 0 | 0 |
Development | 8 | 0 | 0 |
|
|
|
|
Successful | 0 | 0 | 0 |
Dry | 1 | 0 | 0 |
Total | 1 | 0 | 0 |
Development | 0 | 0 | 0 |
|
|
|
|
Exploratory |
|
|
|
Successful | 6 | 4 | 6 |
Dry | 3 | 2 | 3 |
Total | 9 | 6 | 9 |
Development | 115 | 94 | 99 |
Statoil operated development projects
We are currently the operator of the following ongoing field development projects with sanctioned Plans for Development and Operations (PDOs) on the NCS. They are presented here in expected order of scheduled production: Tordis Increased Oil Recovery (IOR), Skinfaks/Rimfaks IOR, Volve, Statfjord Late Life, Snøhvit and Tyrihans. We also have interests in the Ormen Lange deepwater gas field, which is currently operated by Norsk Hydro in the development phase and with Norske Shell as operator in the production phase. In addition we have interests in ExxonMobil’s Ringhorne East, Talisman’s Enoch and Norsk Hydro’s Oseberg Delta and Fram East projects.
Tordis IOR. The Tordis field is situated in PL089 in the Tampen area. Statoil holds a 28.22 per cent interest in the license. The field is a subsea tie-in to the Gullfaks C platform. The Tordis IOR development covers installation of a subsea separation and water injection module as well as modifications at Gullfaks C for low pressure production. A revision of the Tordis PDO covering the IOR development was approved by the MPE in December 2005. Low pressure production is expected to start in the fourth quarter of 2006.
Skinfaks/Rimfaks IOR. The Skinfaks/Rimfaks IOR development in which we hold an interest of 61 per cent is located in the Tampen Area. Skinfaks, which consists of a number of oil/condensate segments, and Rimfaks IOR, which is an enhanced recovery opportunity of the Rimfaks field that came on stream in 2000, will be developed through the use of subsea facilities connected to the Gullfaks C platform for processing and offloading. The PDO was submitted to the authorities in December 2004 and approved by the MPE in February 2005. Production is scheduled to start in January 2007.
Volve. The oil field Volve, in which we hold an interest of 49.6 per cent, is located in PL046, which is the same license as the Sleipner gas fields. The PDO was submitted to the authorities in February 2005 and approved by the MPE in April 2005. Volve is being developed through use of a leased drilling and production platform to be supplied and operated by Mærsk Contractors Norge. The oil will be produced to a Floating Storage Unit (FSU) which is to be supplied and operated by Teekay Norge. Associated rich gas produced will be transported to the Sleipner A platform for further processing and export through existing transportation systems. The planned date for production start-up is the second quarter of 2007.
Statfjord Late Life (SFLL). In February 2005, Statoil submitted an amended PDO for a late life production period. The plan, which was approved by the MPE in June 2005, implies a change in the drainage strategy from the current reservoir pressure maintenance strategy to a significant reduction in reservoir pressure. This strategy will convert Statfjord to a mainly gas producing field. Export of the gas to the UK through a new pipeline connected to the existing pipelines to Flags and St. Fergus is scheduled to commence in late 2007. Total investments for the project are estimated to be NOK 16.1 billion, which implies incremental investments of about NOK 11.6 billion compared with a scenario with no late life development. The estimated pipeline investment is NOK 1.4 billion and is included in the total investment figure.
Snøhvit. Snøhvit is the largest gas field in the Norwegian sector of the Barents Sea. We are the operator of all the unitized licenses in the field, holding a 33.53 per cent ownership share. The field is being developed with subsea production installations connected to an onshore gas liquefaction plant. The main product, LNG, will be shipped to customers in purpose-built vessels. CO2 separated from the gas will be piped back to the field and reinjected. Some LPG and condensate will also be produced. Long-term sales contracts for the LNG were entered into in October 2001 and the Storting approved the PDO in March 2002. The total development costs for the project are estimated to be NOK 58.3 billion for all phases, of which NOK 32.6 billion had been invested as of December 31, 2005. Statoil increased the estimated development cost by NOK 7 billion in September 2005 after a detailed assessment of cost and progress. The updated development cost takes into consideratio n delayed engineering, quality flaws and delays in fabrication of modules from continental Europe, which in turn led to transfer of work to the onshore plant, underestimation of the scope of work and extra work at Melkøya that will prolong project execution and raise costs in the final stage. Two new vessels for transportation of the LNG from the processing and storage facilities at Hammerfest to the customers in Europe and the U.S. were delivered at the beginning of 2006. Two other vessels are currently under construction and are expected to be delivered in mid-2006. Due to the delays described above, initial gas deliveries have been delayed until June 2007, and the estimated start of regular gas deliveries has been delayed until December 2007. The production capacity is expected to reach about 17 mmcm (600 mmcf) of LNG per day by 2008. The field will be further developed with more wells and compression facilities beginning in 2011 and onwards. All phases are included in the PDO and Plan for Installa tion and Operation (PIO) and investment estimates.
Tyrihans. The Tyrihans development, in which we hold an interest of 46.8 per cent, is located on Haltenbanken. Tyrihans consists of two hydrocarbon accumulations, the Tyrihans South oil field (with associated gas) and the Tyrihans North gas field (with a thin oil zone). The PDO was submitted to the authorities in July 2005 and was approved by the Storting in February 2006. The fields will be developed as a subsea tie-in where the well-stream will be transported by pipeline to the Kristin platform for processing. The drainage strategy is based on pressure support by means of gas injection from the Åsgard B platform and sea water injection from a purpose-built subsea module. Production is scheduled to start in mid-2009. Total development costs are estimated at NOK 14.5 billion.
Partner operated development projects
Ormen Lange, which is a deepwater gas field in the Halten/Nordland area and the second largest gas field on the NCS, had the PDO approved by the Norwegian government in April 2004. Statoil holds an interest of 10.84 per cent with Norsk Hydro acting as the operator for the development phase. Norske Shell will act as operator in the production phase. Ormen Lange extends across three production licenses. The selected development concept is an extensive seabed development at depths ranging from 800 to 1,000 meters. The well stream will be transported to an onshore processing and export plant at Nyhamna. Sales gas will then be transported through a dry gas pipeline, named Langeled, which is currently under construction, via Sleipner to Easington in the UK. Total investments are estimated to be NOK 54.7 billion (excluding Langeled), of which NOK 15.4 billion had been invested by the project partners as of December 31, 2005. Current plans expect production to start in October 2007.
We are a partner with a 15.3 per cent interest in the Oseberg Delta development project, operated by Norsk Hydro. The project is a subsea development with tieback to the Oseberg Field Center and is expected to commence production in October 2007. The Fram East field, in which Statoil holds an interest of 20 per cent, is also operated by Norsk Hydro and will be developed through use of subsea facilities connected to existing infrastructure at Troll C. Production is expected to commence in October 2006. Statoil is also participating in other smaller development projects. The Tune South field, where production is expected to commence in March 2008, is a subsea development project with tieback to Oseberg Field Center. Statoil’s interest is 10 per cent. Statoil has an 11.78 per cent interest in the subsea development Enoch operated by Talisman which was approved by the UK and Norwegian authorities in the third quarter of 2005. The expected date for start up of production is in the fourth quarter of 2006. The ExxonMobil operated development project Ringhorne East has an expected start-up date for production in early 2006. Statoil’s interest is 3.12 per cent.
Other Statoil operated development projects
Gulltopp. A long reach well is being drilled from the Gullfaks A-platform to develop the Gulltopp field. Gulltopp was discovered in 2002 and is a small oil field. It is expected that oil production will commence in mid-2006.
Norne K-template. In May 2005 it was decided to install an additional subsea template (K-template) on the Norne field. Initially two new wells will be drilled from the four-slot template. Production from the first well is expected to commence in August 2006.
Gimle. The Gimle field is a small Brent structure located to the north of the Gullfaks field. A long reach exploration well was drilled to the structure in 2004 and sidetracked as a production well. After approval of a test production period, the well was in production from February 22, 2005 to December 15, 2005, and again from January 26, 2006 to February 21, 2006. The field is expected to be on normal production during April 2006.
Huldra Tail-end. At current depletion rates, Huldra production will cease in the autumn of 2006. A gas recompression unit that will increase recoverable reserves and extend the field life will be installed at Huldra. Planned start-up of the compressor is early 2007.
Vigdis Extension Phase 2. The Vigdis field is situated in PL089 in the Tampen Area. Phase 2 of an extension of the existing subsea facilities will create increased oil production from Vigdis East. We hold a 28.22 per cent ownership share in the development. Production is scheduled to commence in the second quarter of 2007.
Sleipner B Compression. A major modification at Sleipner B is planned, where pre-compression facilities will be installed. Planned start-up is October 2008.
Oil and Gas Reserves
As of the end of 2005, we had a total of 3,462 mmboe of proved reserves on the NCS, which consist of 33 per cent oil and 67 per cent natural gas.
The following table sets forth our Norwegian crude oil and natural gas proved reserves as of the end of the periods indicated. The data are stated net of royalties in kind, but including reserves attributable to our account based on our proportionate participation in fields with multiple participants. Royalty obligations from Statfjord were abolished effective January 1, 2003, and royalty obligations from Gullfaks and Oseberg were abolished as of December 31, 2005. Further details are given below under —Regulation—Taxation of Statoil—Royalty. No major discovery or other favorable or adverse event has occurred since December 31, 2005 that would cause a significant change in the estimated proved reserves as of that date. Further information on reserves can be found in the Financial Statements—Supplementary Information on Oil and Gas Producing Activities.
|
| Oil/NGL | Natural Gas | Total | |
| mmbbls | bcm | bcf | mmboe | |
2005 | Proved reserves end of year | 1,142 | 368.9 | 13,024 | 3,462 |
| of which, proved developed reserves | 787 | 264.8 | 9,348 | 2,453 |
2004 | Proved reserves end of year | 1,089 | 367.7 | 12,978 | 3,401 |
| of which, proved developed reserves | 782 | 263.9 | 9,316 | 2,442 |
2003 | Proved reserves end of year | 1,184 | 377.7 | 13,334 | 3,560 |
| of which, proved developed reserves | 876 | 271.4 | 9,582 | 2,584 |
Production
In Norway in 2005, our total equity oil production was 205 mmbbls, after deductions for royalty oil in kind, and gas production was 24.5 bcm (866 bcf), which represents an aggregate 359 mmboe (985 mboe per day). Currently, our production is in our three core producing areas of Troll/Sleipner, Halten/Nordland and Tampen. As of December 31, 2005, we participated in the majority of the 49 producing fields in the NCS and were the operator for 24 of them. Kristin, in which we hold a 41.3 per cent interest, commenced commercial gas deliveries on November 3, 2005. The Urd (Norne Satellites) fields Svale and Stær, in which Statoil holds a 50.45 per cent interest, commenced production in November 2005. Also, the Norsk Hydro operated Oseberg Sør J-structure, in which Statoil holds an interest of 15.3 per cent, started its production in June 2005. Several other large development projects commenced production in 2005: Visund Gas and Troll A pre-compression (October) and Åsgard Q-project (August). In addition, the Norsk Hydro operated Oseberg Vestflanke, in which Statoil holds a 15.3 per cent interest, commenced production in February 2006. We currently operate approximately 46 per cent of Norway’s current oil output and approximately 84 per cent of current gas output.
The following table shows the NCS production fields and field areas in which we currently participate. Amounts are stated net of royalties in kind. Field areas are groups of fields operated as a single entity.
Area | Statoil’s equity | Operator | On | License | Producing wells | Average daily | |
Oil | Gas | ||||||
Troll/Sleipner |
|
|
|
|
|
|
|
Sleipner East | 49.60 | ;Statoil | 1993 | 2014 | 0 | 18 | 23.9 |
Sleipner West | 49.50 | Statoil | 1996 | 2014 | 0 | 18 | 119.3 |
Glitne | 58.90 | Statoil | 2001 | 2013 | 6 | 0 | 8.4 |
Gungne | 52.60 | Statoil | 1996 | 2014 | 0 | 3 | 17.4 |
Huldra | 19.88 | Statoil | 2001 | 2015 | 0 | 6 | 8.5 |
Troll Phase 1 | 20.80 | Statoil | 1996 | 2030 | 0 | 39 | 101.3 |
Troll Phase 2 | 20.80 | Norsk Hydro | 1995 | 2030 | 109 | 0 | 51.0 |
Kvitebjørn | 43.55 | Statoil | 2004 | 2031 | 0 | 6 | 58.3 |
Veslefrikk | 18.00 | Statoil | 1989 | 2015 | 15 | 0 | 5.0 |
Oseberg | 15.30 | Norsk Hydro | 1988 | 2031 | 48 | 13 | 32.9 |
Oseberg South | 15.30 | Norsk Hydro | 2000 | 2031 | 16 | 1 | 11.1 |
Oseberg East | 15.30 | Norsk Hydro | 1999 | 2031 | 8 | 1 | 2.8 |
Heimdal | 20.00 | Norsk Hydro | 1985 | 2021 | 0 | 5 | 1.4 |
Ekofisk area | 0.95 | ConocoPhillips | 1971 | 2028 | 128 | 5 | 3.9 |
Brage | 12.70 | Norsk Hydro | 1993 | 2017 | 24 | 0 | 3.6 |
Sigyn | 50.00 | ExxonMobil | 2002 | 2018 | 1 | 2 | 18.9 |
Fram | 20.00 | Norsk Hydro | 2003 | 2024 | 4 | 1 | 6.3 |
Tune | 10.00 | Norsk Hydro | 2002 | 2032 | 0 | 4 | 7.2 |
Total Troll/Sleipner |
|
|
|
| 359 | 131 | 481.3 |
Halten/Nordland |
|
|
|
|
|
|
|
Kristin(5) | 41.30 | Statoil | 2005 | 2033 | 0 | 3 | 3.1 |
Urd | 50.45 | Statoil | 2005 | 2026 | 3 | 0 | 1.7 |
Heidrun | 12.41 | Statoil | 1995 | 2024 | 38 | 0 | 20.2 |
Åsgard | 25.00 | Statoil | 1999 | 2027 | 28 | 9 | 89.0 |
Norne | 31.00 | Statoil | 1997 | 2026 | 8 | 0 | 29.8 |
Mikkel | 33.97 | Statoil | 2003 | 2022 | 0 | 3 | 18.5 |
Total Halten/Nordland |
|
|
|
| 78 | 15 | 162.3 |
Tampen |
|
|
|
|
|
|
|
Statfjord Unit (Norwegian Part) | 51.88 | Statoil | 1979 | 2026 | 91 | 0 | 71.3 |
Statfjord North | 21.88 | Statoil | 1995 | 2026 | 7 | 0 | 9.1 |
Statfjord East | 25.05 | Statoil | 1994 | 2026(2) | 8 | 0 | 7.4 |
Sygna | 24.73 | Statoil | 2000 | 2026(3) | 3 | 0 | 3.0 |
Gullfaks | 61.00 | Statoil | 1986 | 2016 | 113 | 4 | 179.9 |
Snorre | 15.58 | Statoil | 1992 | 2024(4) | 36 | 0 | 24.2 |
Tordis area | 28.22 | Statoil | 1994 | 2024 | 9 | 0 | 16.5 |
Vigdis area | 28.22 | Statoil | 1997 | 2024 | 14 | 0 | 19.7 |
Visund | 32.90 | Statoil | 1999 | 2023 | 6 | 0 | 9.5 |
Murchison (Norwegian Part) | 51.88 | CNR | 1980 | 2009 | 20 | 0 | 0.7 |
Total Tampen |
|
|
|
| 307 | 4 | 341.3 |
Total NCS |
|
|
|
| 744 | 150 | 984.9 |
(1) Equity interest as at December 31, 2005.
(2) PL037 expires in 2026 and PL089 expires in 2024.
(3) PL037 expires in 2026 and PL089 expires in 2024.
(4) PL089 expires in 2024 and PL057 expires in 2015.
(5) Kristin equity reflects inclusion of Tofte reservoir.
The following table sets forth our average daily equity production for oil, including NGL and condensates, and natural gas for each of the years ended December 31, 2005, 2004 and 2003.
| Year ended December 31, | ||||||||
2005 | 2004 | 2003 | |||||||
Oil and NGL | Natural gas | mboe | Oil and NGL | Natural gas | mboe | Oil and NGL | Natural gas | mboe | |
Troll/Sleipner | 188 | 47 | 481 | 203 | 38 | 442 | 223 | 36 | 447 |
Halten-Nordland | 99 | 11 | 162 | 110 | 10 | 175 | 119 | 9 | 173 |
Tampen | 275 | 10 | 341 | 313 | 10 | 374 | 319 | 8 | 371 |
Total | 562 | 67 | 985 | 625 | 58 | 991 | 661 | 53 | 991 |
Troll/Sleipner
The Troll, Sleipner and Oseberg fields are the main oil and gas fields within this area. Statoil’s share of the area’s production in 2005 was 188 mbbls of oil, condensate and NGL and 47 mmcm (1,659 mmcf) of gas per day, or 481 mboe in total per day.
Troll. Troll lies in the North Sea and has large gas and oil reserves. Troll is the primary source of supply for gas sales from the NCS to Europe. Our interest in Troll is 20.80 per cent. The Troll field comprises two main structures: Troll East and Troll West. An oil layer underlies the whole Troll area but is substantial enough for commercial recovery in the Troll West region only. A staged development has therefore taken place with Phase 1 covering gas reserves in Troll East and Phase 2 focusing on the oil reserves in Troll West. Statoil is the operator of the Troll East facilities and Norsk Hydro is the operator of the Troll Phase 2 oil production in Troll West.
The Troll East development comprises the Troll A platform, the gas processing plant at Kollsnes, and the 60 km pipelines linking the Troll A platform with the onshore processing plant at Kollsnes. Two new compressors have been installed on Troll A, which started up in October 2005, increasing the export capacity on Troll A to approximately 120 mmcm (4.2 bcf) per day. The rich gas is transported to the Mongstad refinery. Production from the Troll A platform was temporarily reduced beginning in mid-March 2006 in order to carry out repairs on the compressors. The compressors are expected to be fully operational again beginning in mid-April.
Norsk Hydro is the operator for the oil production of Troll Phase 2 in Troll West. The Troll West development comprises the Troll B and Troll C floating production platforms. Crude oil is produced from the oil province with horizontal wells tied back to the two platforms. The oil produced from Troll B and Troll C is transported through Troll Oil Pipeline I and Troll Oil Pipeline II to the oil terminal at Mongstad. The associated gas from Troll B and Troll C is exported via Troll A to Kollsnes.
In connection with the decision to land the rich gas from the Kvitebjørn field at the Troll facilities at Kollsnes, the Troll owners decided to build a new NGL fractionation plant at Kollsnes. This plant came on stream at the end of September 2004. Processing capacity for the plant is 26 mmcm (918 mmcf) of gas per day.
Kvitebjørn. In July 2005, the Statoil equity share in Kvitebjørn was reduced from 50 per cent to 43.55 per cent due to a swap transaction with Enterprise Oil Ltd. Kvitebjørn came on stream at the end of September 2004. The field has been developed with a fixed steel platform for production, drilling and living quarters. There are plans for drilling 11 production wells, of which six wells have already been drilled. The remaining five wells will be drilled before mid-2007. Initial processed gas and condensate are transported in separate pipelines to receiving facilities for final processing and transport. Gas is transported through a pipeline to the NGL fractionation plant at Kollsnes. In addition, an oil pipeline connects Kvitebjørn to the Mongstad refinery in the same region. Total investment is estimated to be NOK 10.3 billion, which is in line with the PDO.
Sleipner. Sleipner includes Sleipner West, Sleipner East and Gungne and our interests are 49.50 per cent, 49.60 per cent and 52.60 per cent, respectively. We are the operator of all fields. Condensate from the Sleipner fields is transported to the gas processing plant at Kårstø. Sleipner East and Gungne are produced through the Sleipner A platform. Sleipner West is produced through the Sleipner B wellhead platform and the Alfa Nord subsea template. Unprocessed well streams from Sleipner B and Alfa Nord are piped to the Sleipner T gas treatment facility, which is linked by a bridge to Sleipner A. Sleipner West has large reserves of CO2-rich gas. We extract the CO2 at the field and re-inject it into a sand layer that lies underneath the seabed, thereby reducing the CO2 emissions into the air, which has environmental benefits and, insofar as it reduces environmental taxes, financial benefits.
Oseberg. Oseberg, the third main field in the Troll/Sleipner area, is operated by Norsk Hydro. We have a 15.30 per cent interest in all Oseberg licenses.
Glitne. Glitne is the smallest stand-alone field development on the NCS using a floating production system. Our interest in this field is 58.9 per cent.
Huldra. The Huldra field is located in the Viking Graben. The field is developed by a normally unmanned platform which is remotely controlled from the Veslefrikk field. The production strategy is based on pressure depletion. We hold a 19.87 per cent interest in the license.
Veslefrikk. Our interest in Veslefrikk is 18 per cent. Oil is exported to the Sture terminal via the Oseberg Transportation System (OTS) while gas is exported to Kårstø. In November 2001, Veslefrikk also started processing condensate from the Huldra field for further export through the OTS oil transportation system. Veslefrikk is undertaking comprehensive studies to increase field reserves, reduce cost and extend the field life.
Sigyn. Sigyn, operated by ExxonMobil, is a gas/condensate field located 12 km southeast of the Sleipner A installation. The gas is exported from Sleipner A and the condensate is delivered at Kårstø. Our interest is 50 per cent. The development consists of three production wells on one subsea template, with two pipelines and one umbilical connecting it to the Sleipner A platform.
Fram West. Our interest in the Fram oil field, operated by Norsk Hydro, is 20 per cent. The Fram field development is a subsea tieback to existing infrastructure (Troll C) for processing and transport.
In addition we have interests in the following partner operated producing fields: Brage (Statoil 12.7 per cent), Ekofisk (0.95 per cent), Heimdal (20 per cent) and Tune (10 per cent).
Halten/Nordland
Our producing fields in the Halten/Nordland area are Åsgard, Heidrun, Norne, Kristin, Urd and Mikkel, all of which we operate. Statoil’s share of the area’s production in 2005 was 99 mbbls per day of oil and 11 mmcm per day (388 mmcf per day) of gas, or 162 mboe per day in total.
This region is characterized by petroleum reserves located at water depths reaching between 250 and 500 meters. The reserves are to some extent under high pressure and at high temperatures. These conditions may make development and production more difficult and have challenged the participants to develop new kinds of platforms and new technology, such as floating processing systems with subsea production templates. We plan to increase efficiency by further coordinating our operations in the area and by stemming the declining production from the mature fields by increasing seismic activity and well maintenance. In addition, we will expand our activities by utilizing our installed production and transportation capacity before building new infrastructure.
Åsgard. The Åsgard field contains three structures: Smørbukk, Smørbukk South and Midgard. Our interest in the Åsgard development is 25 per cent. The field was developed with the Åsgard A production ship for oil, the Åsgard B semi-submersible floating production platform for gas and the Åsgard C storage vessel. The subsea production installations on the field are the most extensive in the world, with a total of 53 wells grouped in 18 seabed templates. Further, the Åsgard B platform is the largest floating gas processing center in the world, and Åsgard A is one of the largest floating production ships ever built. The first well in the Q subsea-template development came on stream in August 2005.
The Åsgard development links the Haltenbank area to Norway’s gas transport system in the North Sea. Gas from the field is piped through the Åsgard Transport pipeline to the processing plant at Kårstø and on to receiving terminals in Emden and Dornum in Germany. Oil produced at the Åsgard A vessel and condensate from the Åsgard C storage vessel are shipped from the field by shuttle tanker.
Heidrun. The Heidrun platform is the largest concrete tension leg platform ever built. Our interest in this field is 12.41 per cent. The field is producing from 28 platform and 8 sub-sea wells. Water injection is also done from 7 platform and 10 subsea wells. Most of the oil from Heidrun is shipped by shuttle tankers to our Mongstad crude oil terminal for onward transportation to customers. Gas from Heidrun provides the feedstock for the methanol plant at Tjeldbergodden, Norway. Additional gas volumes are exported through the Åsgard Transport pipeline.
Norne. Our interest in the Norne field is 31 per cent. In 2005, Statoil acquired an additional six per cent interest in the field from Enterprise. The field is being developed with a production and storage ship tied to subsea templates. This ship carries processing facilities on its deck and storage tanks for oil. Processed crude oil can be transferred over the stern to shuttle tankers. Like Heidrun, Norne is connected to gas markets in continental Europe through a link with the Åsgard Transport system. The Norne production vessel (FPSO) also processes oil and gas from the Urd fields.
Urd (Norne Satellites). The Urd fields Svale and Stær, in which Statoil holds an interest of 50.45 per cent, are located 10 km and 5 km north of the Norne field, respectively. In 2005, Statoil acquired an additional 10 per cent interest in the Urd fields from Enterprise. Oil and gas from the fields is produced through subsea facilities with well stream tied back to the Norne FPSO. Production from the first two Urd wells commenced in November 2005.
Mikkel. Mikkel is a gas and condensate field in which we hold a 33.97 per cent interest. Production commenced in October 2003. Production from two seabed templates is tied to the subsea installation at Midgard for onward transport to the Åsgard B gas-processing platform.
Kristin. Kristin, in which we hold a 41.30 per cent interest, is a gas condensate field in the southwestern part of the Halten/Nordland area. Statoil’s ownership share was reduced in 2004 from 41.60 per cent to 41.30 per cent, due to a re-calculation in accordance with the Unit agreement. The Kristin development, will drain a reservoir almost 5,000 meters beneath the seabed through the use of 12 subsea production wells. The Kristin project is the first high temperature/ high pressure (HTHP) field developed with subsea installations. To reduce the pressure, the well stream is choked down at the subsea production stations before transportation through infield pipelines and flexible risers to a floating processing platform. The stabilized condensate is exported to a joint Åsgard and Kristin storage vessel and the rich gas is transported to shore via the Åsgard Transportation pipeline to the gas processing facility at Kårstø. Commercial gas deliveries commenced November 3, 2005. Taking into account the challenging nature of the reservoir, a new drilling strategy was implemented in 2004 in order to maintain the field’s recovery factor. In addition, the investment estimate was increased in March 2005 to NOK 20.8 billion, including an extraordinary project reserve of NOK 0.5 billion. A total of NOK 18.9 billion has been invested as of December 31, 2005. In connection with the Kristin development, it was decided to develop the Tofte formation, which is a discovery made during drilling of the Kristin production wells. The Tofte well was started in November 2005, but has recently been shut down and is awaiting a work-over before being put into production again. The maximum production capacity on Kristin is expected to reach 18 mmcm (636 mmcf) of natural gas per day and 126 mbbls condensate per day by the third quarter of 2006. A possible development of the other discoveries in the area using the Kristin processing facilities as a field center is under evaluation.
Tampen
The Tampen area offers rich petroleum resources in a compact geographic area where Statoil is the sole operator. The main producing fields in the Tampen area are Statfjord, Gullfaks, Snorre, Visund, Tordis and Vigdis. Statoil’s share of the area’s production in 2005 was 275 mbbls per day of oil and 10 mmcm per day (353 mmcf per day) of gas, or 341 mboe per day in total. Tampen is the leading oil producing area on the NCS, and even after twenty years of production we believe substantial opportunities for increased value creation are still remaining. New fields were developed in this area according to a schedule to allow existing infrastructure to be used continuously at near peak capacity, thereby limiting the need for new infrastructure.
We have taken several initiatives to identify and implement measures to increase and prolong production from the Tampen area. These initiatives have resulted in a prolonged planned production beyond the present license period, which expires in 2016 for the Gullfaks field. The prolonged planned production for the Tampen area is due to a combination of cost reduction and IOR. There are also identified opportunities for synergy of operations, such as better utilization of drilling completion units, common contracts and common logistics and transportation services. Taking over as operator for Snorre, Visund and PL089 in January 2003 was an important step in an area optimization of the production operations in the area. We are also looking at introducing new drainage strategies for producing field and area solutions starting with the Statfjord Late Life project and continuing with increased IOR efforts on Snorre and Gullfaks.
Statfjord. Statfjord has been developed with three fully integrated platforms supported by gravity base structures featuring concrete storage cells. Each platform is tied to offshore loading systems for loading oil into tankers. Three satellite fields (Statfjord North, Statfjord East and Sygna) have been developed and are each tied back to the Statfjord C platform. An amended PDO for the late life production period for Statfjord was submitted to the MPE in February 2005 and approved in June 2005. In July 2005 the MPE granted a license extension for the Statfjord area from 2009 to 2026. Our interest in the Statfjord Unit is 44.34 per cent.
Gullfaks. Gullfaks has been developed with three large concrete production platforms. Oil is loaded directly into shuttle tankers on the field, while associated gas is piped to our Kårstø gas processing plant and then on to continental Europe. Three satellite fields, Gullfaks South, Rimfaks and Gullveig, have been developed with subsea wells remotely controlled from the Gullfaks A and C platforms. Our interest in Gullfaks is 61 per cent.
Snorre. The field has been developed with two platforms and one subsea production system connected to one of the platforms (Snorre A). Oil and gas is exported to Statfjord for final processing, storage and loading. Our interest in the field is 15.58 per cent after Statoil’s acquisition of Enterprise’s interest (1.18 per cent) in 2005. Statoil took over as operator of the Snorre field from Norsk Hydro in January 2003. One satellite field, Vigdis, has been developed with a subsea tieback to Snorre A. Production from Vigdis Extension, connected to Snorre A, started in October 2003, while a second phase is expected to begin in mid-2007. Production at Snorre A and Vigdis was closed down from November 28, 2004 due to an incident on Snorre A. The production restarted gradually from January 21, 2005 and will continue to produce until 2029, seven years longer than originally planned. Estimated deferred volume due to the shutdown for Snorre A and Vigdis for the year 2005 was 1.0 mmboe (Statoil share).
Visund. The development of the Visund field was separated into an oil production phase, which came on stream in 1999, and a later gas production phase. Statoil took over as operator of the Visund field from Norsk Hydro in January 2003 and gas export commenced in October 2005. The field has been developed with one platform and two subsea satellite wells. The oil is exported to Gullfaks A for storage and loading. The gas produced is partly injected into the reservoirs, and partly exported to Kollsnes via the Kvitebjørn pipeline. Our interest in Visund is 32.9 per cent. Production has been haulted since a gas leak on January 19, and is expected to resume in June 2006.
PL089. The asset includes the Vigdis field and the fields in the Tordis Area. The Tordis area is developed with seven subsea satellites and two templates tied back to Gullfaks C where the oil and gas is processed and stored for offshore loading and export. The Vigdis reservoir was developed in 1997 with three subsea templates with well stream through pipelines connected to Snorre A where the oil is stabilized and exported to Gullfaks for storage and loading. Vigdis was further developed through the Vigdis Extension Project with two additional four-slot production and water injection templates and two single satellite wells tied into Snorre A via the subsea production facilities previously installed on Vigdis. The oil is exported to Gullfaks A for storage and loading. Our interest in the PL089 asset is 28.22 per cent. We took over as operator of the PL089 assets from Norsk Hydro in January 2003.
Decommissioning
The Norwegian government has set forth strict procedures for the removal and disposal of offshore oil and gas installations under the Convention for the Protection of the Marine Environment of the Northeast Atlantic, or the OSPAR Convention. There has been no decommissioning of Statoil operated fields during the last three years. On partner operated fields there has been removal activity on Frigg and Ekofisk.
Domestic Production Costs Data
Production costs are influenced by the distribution between new and mature fields in the portfolio and the cost effectiveness of the different installations. We calculate this indicator as annual production-related costs compared with the volume of oil and gas produced in the same period. As the figures below show, in 2005 we reduced our cost per barrel in NOK and, based on industry benchmarks, we believe that we are one of the lowest cost producers on the NCS.
The following table sets forth our average production costs per boe consistent with FASB statement 69, our average sales price per barrel of oil, and average sales price by Statoil per scm of gas sold for the years ended December 31, 2005, 2004 and 2003.
Production costs data | Year ended December 31, | ||
2005 | 2004 | 2003 | |
Average cost per boe |
|
|
|
NOK | 21.59 | 22.45 | 21.93 |
USD | 3.35 | 3.34 | 3.10 |
Average sales price per barrel of oil |
|
|
|
NOK | 348.7 | 256.4 | 206.0 |
USD | 54.1 | 38.0 | 29.1 |
Average sales price per scm of gas |
|
|
|
NOK | 1.45 | 1.10 | 1.02 |
USD | 0.22 | 0.16 | 0.14 |
NOK/USD (average daily exchange rate) | 6.45 | 6.74 | 7.08 |
Oil and Gas Transportation
We, together with other Norwegian oil and gas producers, have built an extensive transportation infrastructure network to transport crude oil and gas produced on the Norwegian Continental Shelf to terminals in Norway, the UK and the continental Europe. For information about our interests in gas pipelines held through Gassled, see Natural Gas—Norwegian Gas Transportation System and other Facilities below.
Most of our oil production is lifted offshore by shuttle tankers and transported to oil terminals in Norway and abroad. Troll and Oseberg crude oil is transported by pipeline to the Mongstad and Sture terminals, respectively, and Ekofisk production is transferred by pipeline to Teesside, UK.
The following are oil pipelines in which E&P Norway has an ownership interest:
Troll Oil Pipelines I and II. The Troll Oil Pipeline I transports oil from the Troll B platform to the terminal at Mongstad near Bergen. The Troll Oil Pipeline II carries oil from Troll C to the terminal at Mongstad. The Troll Oil Pipelines I and II have a transport capacity of 265 and 300 mbbls per day, respectively. We are the operator and 20.85 per cent owner of Troll Oil Pipelines I and II.
Kvitebjørn oil pipeline. The Kvitebjørn oil pipeline is a separate joint venture which runs from the Kvitebjørn platform to the Troll Oil Pipeline II. In July 2005 the Statoil equity share was reduced from 50 per cent to 43.55 per cent due to a swap transaction with Enterprise Oil Ltd. The pipeline has identical participation interests and voting rules as the Kvitebjørn field. Statoil is the operator of the pipeline, which has a capacity of 10 mcm per day. The pipeline has been designed at both ends to accept future connections.
Sleipner Condensate pipeline. The Sleipner Condensate pipeline (20-inch, design capacity 1048 Sm3/h) is owned by the Sleipner East Group. The unstable condensate from Sleipner East, Sleipner West and Gungne is mixed at Sleipner A and transported to Kårstø where it is processed into stable condensate, NGL products (propane, i-butane, n-butane) and ethane.
Norpipe Oil AS. In October 2005 Statoil’s ownership in Norpipe Oil AS was reduced from 20 per cent to 15 per cent, with five per cent being handed over to the SDFI. This reduction was decided by the MPE in 1995 in connection with the extension of the license period for Ekofisk and several changes in ownership interests in the pipelines from Ekofisk to the UK and Germany. The ConocoPhillips operated Norpipe oil pipeline starts at Ekofisk Center and crosses the UK continental shelf to come ashore at Teesside in the UK. It has a transport capacity of 900 mbbls per day.
Oseberg Transportation System (OTS). The OTS transports oil from Veslefrikk, Brage, Oseberg Unit, Oseberg South, Oseberg East, Tune and Huldra via Oseberg A to Sture. The Grane field has a separate pipeline to the onshore facilities. Our interest in the OTS is 14 per cent. The OTS has a capacity of 765 mbbls per day.
Frostpipe. Frostpipe, in which we hold a 20 per cent interest, was used to transport oil and condensate from Frigg to Oseberg until March 2001. Frostpipe is no longer in use.
International Exploration and Production
Introduction
International E&P includes production, development and exploration outside of Norway. We are focusing our efforts on establishing significant production in our main activity areas while we actively pursue growth opportunities in other areas that support our strategy and leverage our skills and competence from the NCS.
We hold interests in 15 producing fields in North Africa (Algeria), Western Africa (Angola), the Caspian (Azerbaijan), Western Europe (UK), South America (Venezuela) and China.
Statoil is involved in development projects in Algeria, Angola, Nigeria, Azerbaijan, Ireland, the Gulf of Mexico/USA and Iran. Exploration activity includes projects in Algeria, Angola, Azerbaijan, Brazil, the Faroe Islands, Gulf of Mexico/USA, Ireland, Libya, Nigeria, the UK and Venezuela.
Key financial information
International E&P reported Income before financial items, income taxes and minority interest of NOK 8,364 million in 2005 compared to NOK 4,188 million in 2004. In the year ended December 31, 2005, we produced 184 mboe per day compared with 115 mboe per day in 2004.
The following table presents key financial information about this business segment. The changes from 2004 to 2005 are primarily a result of increased production and higher realized oil and gas prices.
(in millions) | Year ended December 31, | ||||
2005 | 2004 | 2003 | |||
NOK | USD | NOK | NOK | ||
Revenues | 19,563 | 2,901 | 9,765 | 6,615 | |
Depreciation, depletion and amortization | 6,273 | 930 | 2,215 | 1,784 | |
Exploration expenditure | 2,149 | 319 | 1,374 | 1,230 | |
Income before financial items, income taxes and minority interest | 8,364 | 1,240 | 4,188 | 1,781 | |
Capital expenditure | 25,295 | 3,751 | 18,987 | 8,019 | |
Long-term assets (excluding deferred tax assets) | 62,163 | 9,217 | 37,457 | 31,366 |
Further details on the financial results can be found in Item 5—Operating and Financial Review and Prospects—Operating Results.
Portfolio management
We continue to build our international interests to focus on areas where we own quality assets and can develop new attractive commercial opportunities and optimize our capital employed.
In June 2003, Statoil agreed to acquire direct ownership interests in two Algerian assets: In Salah (31.85 per cent) and In Amenas (50 per cent). Both transactions were approved by the Algerian Council of Ministers during 2004.
In May 2005, Statoil closed a deal to purchase all of EnCana's Gulf of Mexico/USA assets, including its 25 per cent interest in the Tahiti field and several discoveries and exploration leases.
During 2005, Statoil also bought a 12.25 per cent stake in the Suilven discovery from Amerada Hess. This asset is located in the UK adjacent to the Schiehallion field.
Oil and Gas reserves
In 2005, we decreased our proved reserves by 6 per cent. The change principally reflects the effects on proved reserves under Production Sharing Agreement (PSA) contracts, where applying the increased year end prices for 2005 had the effect of decreasing proved reserves. Under PSA contracts, the volumes of entitlement oil are reduced when oil prices increase, which in turn reduces the amount of booked proved reserves. At the end of 2005, our international proved oil and NGL reserves were 619 mmbbls of oil, and we had 34.0 bcm (1.2 tcf) of proved natural gas reserves, a total of 833 mmboe.
The following table sets forth our total international proved reserves as of December 31 of each of the last three years. Further information on reserves can be found in the Supplementary Information on Oil and Gas Producing Activities contained in our consolidated financial statements beginning on page F-1.
Year |
| Oil/NGL | Natural Gas | Total | |
| mmboe | bcm | bcf | mmboe | |
2005 | Proved reserves at end of year | 619 | 34.0 | 1,202 | 833 |
| Of which, proved developed reserves | 202 | 4.3 | 150 | 229 |
2004 | Proved reserves at end of year | 632 | 40.7 | 1,437 | 888 |
| Of which, proved developed reserves | 170 | 6.6 | 234 | 212 |
2003 | Proved reserves at end of year | 605 | 15.7 | 552 | 703 |
| Of which, proved developed reserves | 163 | 0.7 | 25 | 167 |
Production
Statoil’s petroleum production outside Norway amounted to an average of 184.4 mboe per day in 2005. Total annual production in 2005 was approximately 67 mmboe compared to 42 mmboe in 2004. The following table sets forth our total international production for each of the last three years. The new fields that came on stream in 2005 are ACG-Central and West Azeri in Azerbaijan, Kizomba B in Angola and the re-start of the Lufeng field in China.
| Year ended December 31, | ||
2005 | 2004 | 2003 | |
Average daily oil (mbbls) | 141.8 | 100.0 | 86.5 |
Average daily natural gas (mmcm/mmcf) | 6.8/239 | 2.4/84 | 0.4/14 |
Average daily boe (mboe) | 184.4 | 114.9 | 89.1 |
The following table shows the producing fields in which we currently participate and the producing wells as of, and production for the year ended, December 31, 2005.
Field | Statoil’s equity | Operator | On stream | License | Producing | Average daily production (1) |
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Algeria: In Salah | 31.85 | Sonatrach /BP/ Statoil | 2004 | 2027 | 24 | 40.7 |
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Angola: Girassol and Jasmim | 13.33 | Total | 2001 | 2022 | 23 | 27.5 |
Angola: Xikomba | 13.33 | ExxonMobil | 2003 | 2027 | 5 | 5.0 |
Angola: Kizomba A | 13.33 | ExxonMobil | 2004 | 2024 | 17 | 28.1 |
Angola: Kizomba B(2) | 13.33 | ExxonMobil | 2005 | 2027 | 13 | 13.8 |
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Azerbaijan: Azeri-Chirag-Gunashli | 8.56 | BP | 1997 | 2024 | 21 | 19.6 |
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UK: Alba | 17.00 | Chevron | 1994 | 2018 | 35 | 9.9 |
UK: Schiehallion | 5.88 | BP | 1998 | 2017 | 19 | 4.0 |
UK: Merlin | 2.35 | Shell | 1997 | 2017 | 3 | 0.0 |
UK: Dunlin | 28.76 | Shell | 1978 | 2017 | 13 | 1.6 |
UK: Jupiter | 30.00 | ConocoPhillips | 1995 | 2010 | 14 | 1.9 |
UK: Caledonia | 21.32 | Chevron | 2003 | 2018 | 1 | 0.5 |
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Venezuela: LL652 reactivation | 27.00 | Chevron | 1998 | 2018 | 146 | 0.9 |
Venezuela: Sincor(3) | 15.00 | Sincor JV | 2001 | 2037 | 322 | 24.3 |
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China: CA 17/22 Lufeng(3) | 75.00 | Statoil | 1997 | 2013 | 5 | 6.9 |
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| 637 | 184.4 |
(1) Production figures are after deductions for royalties, production sharing and profit sharing.
(2) Production commenced on Kizomba B in July 2005.
(3) Production re-started on June 9, 2005, after an almost one year suspension for re-drilling of three production wells.
Main Areas
We are currently active in the following areas: North Africa, Western Africa, Caspian, Western Europe, Middle East, South America, the Gulf of Mexico/USA and China. In all areas our business is conducted in accordance with our values and business principles.
North Africa
Statoil’s current asset portfolio in North Africa comprises two development projects and one exploration opportunity in Algeria (In Salah, In Amenas and Hassi Mouina) and two exploration opportunities in Libya (Kufra and Cyrenaica).
Algeria
Statoil's position as a significant gas seller in Europe, our ambition to serve this market from multiple sources, and the short distance to the southern European gas market makes Algeria an attractive country to pursue new opportunities. The decision to enter into Algeria is, by nature, based on a long-term perspective and includes an assessment of both the security and political situation. Statoil recognizes the need for a different level of protection for personnel and property compared with many European countries. To reduce the risk of injury and serious incidents, it is considered necessary to make additional security arrangements in line with those of other international companies. Statoil evaluates the risk level as acceptable, subject to the precautions that have been taken, and we remain committed to conducting our business in accordance with our core values.
In Salah. The In Salah gas project, in which Statoil has a 31.85 per cent interest, is Algeria’s third largest gas project. A Contract of Association, including mechanisms for revenue sharing, governs the rights and obligations of the joint operatorship between Sonatrach, BP and Statoil. A joint marketing company sells the gas produced in the project, and all gas produced until 2017 has been sold under long-term contracts. Production commenced in July 2004 and the field is currently producing at plateau levels.
In Amenas. The In Amenas development project is the fourth largest gas development in Algeria containing significant liquid volumes. Statoil has a 50 per cent interest in the In Amenas project. This project is built and operated through a joint operatorship between Sonatrach, BP and Statoil. The rights and obligations are governed by a production-sharing contract, giving the contractors access to liquid volumes only. Production is expected to commence by the end of the second quarter of 2006. The postponed start-up is related to delays in project execution due to site relocation. The field’s gross plateau production is estimated to reach approximately 200 mboe per day in 2008 assuming 2005 year-end prices.
Hassi Mouina. On July 28, 2004, Statoil was awarded operatorship for the Hassi Mouina exploration acreage. Statoil has a 75 per cent share in the block (Sonatrach 25 per cent), which is approximately 22,990 square kilometers. The work program is for two wells (one exploration and one appraisal) and 400 kilometers of two-dimensional seismic during a three-year exploration period. The work program commenced in 2005 with the acquisition of seismic data, and drilling activities are expected to start in 2006. In January 2005, the Algerian Council of Ministers approved the Hassi Mouina license, and the final approval (gazettal) was issued in February 2005.
Libya
Statoil was awarded two exploration licenses in the EPSA IV bid round on October 2, 2005. The licenses, both Statoil operated, were ratified on December 12, 2005, initiating the five year exploration period. During this exploration period Statoil has committed to the following:
License 94 (100 per cent Statoil) covers an area of 9,849 square kilometers on the south eastern Cyrenaica Platform with a commitment of one exploration well and 3,000 kilometers two-dimensional seismic.
License 171 (50 per cent Statoil, 50 per cent BG) covers an area of 11,305 square kilometers in the Kufra Basin with a work commitment of two exploration wells and 2,000 kilometers two-dimensional seismic.
The exploration work program in 2006 for the two areas includes regional work as a preparation for the seismic acquisition programs scheduled in 2007. In addition, environmental impact studies must be performed in both licenses.
West Africa
Statoil has interests in blocks 15, 17 and 31 offshore Angola and production license (OML 128, 129) as operator, in addition to exploration licenses (OPL 324 and 315) offshore Nigeria. The production activities in block 15 and 17 in Angola represent approximately 40 per cent of the group’s international production in 2005.
Angola
Statoil holds a 13.33 per cent interest in the deepwater blocks 15, 17 and 31 offshore Angola.
Block 15. Interests in block 15, operated by ExxonMobil, currently comprise the producing fields at Kizomba A, Kizomba B and Xikomba, as well as the development projects Marimba North and Kizomba C. A total of 21 exploration wells and nine appraisal wells have been drilled to date with 18 discoveries announced. All exploration commitments in the PSA have been met. In addition, one exploration well was spudded in block 15 at the end of 2005.
Kizomba A, which encompasses the Hungo and Chocalho discoveries, reached peak production of 250 mbbls of oil per day in August 2005. The average total production for Kizomba A during 2005 was 234.6 mbbls per day. Kizomba B, which encompasses the Kissanje and Dikanza discoveries, commenced production on July 7, 2005, which was ahead of the expected start up in the third quarter 2005. Peak production of 250 mbbls per day was reached in September 2005, well ahead of the previous expectation of year end 2006. The average total production for Kizomba B during 2005 was 114.6 mbbls per day. Xikomba, a small isolated discovery being developed and produced by a leased FPSO, had an average production of 66.6 mbbls per day during 2005. First oil was achieved in 2003. The development of Marimba North was sanctioned in mid-September 2005. The field, discovered in 1998, will be developed as a tie-in to Kizomba A. Production start-up is expecte d in December 2007. Kizomba C, which encompasses Mondo and Saxi-Batuque, was sanctioned by Statoil in December 2005. The project consists of two FPSO’s, each with a design capacity of 100 mbbls per day, one located on each of the Mondo and Saxi-Batuque discoveries. Expected production start-up is mid-year 2008. Sonangol's final approval of the contracts is expected within the first half of 2006.
Block 17. Interests in block 17, operated by Total, currently comprise production at Girassol and Jasmim and the development projects Dalia and Rosa. To date, a total of 26 exploration and appraisal wells have been drilled, and, as a result, all exploration commitments in the PSA have been met, and exploration acreage handed back.
The Girassol and Jasmim development areas were merged in 2005. Girassol and Jasmim are currently producing at a plateau level of 240 mbbls of oil per day. The development project Dalia, sanctioned in April 2003, consists of a planned total of 67 subsea wells. First oil from Dalia is expected in the third quarter of 2006. Dalia is scheduled to reach a plateau production of 225 mbbls of oil per day by 2007. Rosa, a subsea tieback to the Girassol FPSO, was sanctioned in July 2004 and consists of a planned total of 25 subsea wells. First oil from Rosa is expected in the first quarter of 2007 and peak production is expected to reach 150 mbbls per day in 2008. In 2005 exploration drilling confirmed the reserves in the Pazflor project, which includes the Perpetua, Acacia, Zinia and Hortensia discoveries. Development studies have been done and an FPSO with a capacity of 200 mbbls of oil per day has been identified as the developm ent solution. Sanction is expected in the first quarter of 2007.
Block 31. This ultra deepwater block, operated by BP, is located west of Block 15 at the northern end of Angola’s continental shelf at a water depth between 1,600 and 2,500 meters. In 2005, six wells were drilled and five discoveries made, and to date a total of 13 exploration wells have been drilled in the block. Well number 13 was spudded in December 2005 and completed in February 2006, and now awaits final evaluation. The exploration period ends June 1, 2008, and all commitments have already been met. The licensees are actively planning a common development of the first four discoveries in the northern part of the block (Plutao, Saturno, Venus and Marte).
Nigeria
Nigeria’s political development has been affected in the past by political unrest and violence, which have led to difficulties and disruptions for the oil industry in the Delta area. Projects on the Nigerian continental shelf may also be influenced by potential political instability.
Agbami, sanctioned by Statoil in August 2004, will be developed with subsea wells tied back to a floating production and storage ship and is scheduled to come on stream in mid-2008. The Unitization agreement for the field was signed by all parties in February 2005. Chevron is the operator of the unitized field.
All of our activities are in the deepwater areas off Nigeria, and currently include exploration operations on block OML 128 and OML 129, where Statoil is operator with a 53.85 per cent share, and partner obligations in block OPL 324 (25 per cent) and in OPL 315 (45 per cent), in addition to the Agbami development.
In February 2005, the exploration licenses on block OML 128 and 129 were converted to production licenses with a term of 20 years. To date, a total of seven exploration wells have been drilled in the two license areas, resulting in one oil discovery, Ekoli in block OML 128 (Agbami), one gas discovery, Nnwa, and one condensate discovery, Bilah in block OML 129. On this discovery, OML 129, an extensive subsurface evaluation is in progress with a possible decision on further appraisal drilling to be made in 2006.
The Nnwa discovery extends into the Shell operated Block 219 (known as the Doro structure). Under an MOU with Shell, the Nigerian Government and other companies, a feasibility study for floating LNG was completed in 2003. The Nigerian Government has recently submitted fiscal terms for the development of gas in Nigeria, and these terms are currently being reviewed and discussed between the oil industry and the Government.
In 2004 one exploration well was spudded and completed in block OPL 324. Phase II of exploration, including a drilling campaign, is currently underway. The latest addition to Statoil’s Nigeria portfolio was in the 2005 licensing round, where Statoil was awarded an interest in block OPL 315 with Petrobras as operator. The contract was signed in early 2006 where Statoil committed to perform a workprogram over the next five years that consist of one well and approximately 833,000 square meters of three-dimensional seismic coverage.
Caspian
Statoil’s current interests in the Caspian area comprises projects in Azerbaijan and activities in Kazakhstan.
Azerbaijan
We established a presence as one of the first international oil companies in the Caspian Sea in 1992. Since then, we have entered into three PSAs in Azerbaijan, and we are among the largest foreign oil companies in the country in terms of proved reserves and production. At present, we hold interests in three PSAs offshore in the Azeri sector of the Caspian Sea: the Azeri-Chirag-Gunashli, or ACG oil field, the Shah Deniz gas and condensate field and the Alov, Araz and Sharg prospects.
The Caspian region has long been viewed as an area with substantial risks for increased economic, social and political instability. Although the general situation has improved, in both Azerbaijan and Georgia there are still political disputes that remain unsolved, and the existing risks should not be underestimated.
Ongoing negotiations over the Caspian. A binding legal regime governing the division of the Caspian Sea among the five border states of Azerbaijan, Iran, Kazakhstan, Turkmenistan and Russia is yet to be found. This has on occasion led to disputes over rights to hydrocarbon resources between Azerbaijan and Iran and between Turkmenistan and Azerbaijan. There are currently bilateral agreements in place between Russia, Kazakhstan and Azerbaijan. Turkmenistan and Iran have to date been unwilling to enter into similar agreements.
ACG. Statoil is a partner with an 8.56 per cent equity share in the BP operated ACG PSA. ACG is being developed in three phases in addition to the Early Oil Production phase (EOP). We estimate overall investments for the ACG full field development to be approximately USD 15 billion, of which almost USD 10 billion had been spent by December 31, 2005. This estimate covers all three phases of upstream development and early oil production, but excludes the BTC Pipeline. ACG is being developed in three phases in addition to the Early Oil Production phase (EOP). We expect overall daily production from ACG to exceed 1 mmbbls per day by 2010.
ACG – EOP. The Chirag platform, as a part of EOP, has been producing since November 1997 and is currently producing at plateau levels.
ACG Phase I. Phase I is close to completion and Central Azeri commenced production in the first quarter of 2005.
ACG Phase II. Phase II construction activities are at an advanced stage and West Azeri started production at the end of 2005, while East Azeri is expected to start production in 2007. By December 31, 2005, the combined annual production level from EOP, Phases I and II was almost 400 mbbls per day. Oil is currently transported through a dedicated 850-kilometre pipeline, the Western Route, from the Sangachal terminal processing and storage facility to Supsa for tanker shipment through the Turkish Straits and the Mediterranean to the international markets.
ACG Phase III. In 2005 work and pre-drilling program commenced on Phase III (Deep Water Gunashli), which was sanctioned by the partners and the Government of Azerbaijan in September 2004. All construction work continues on schedule and further efforts are being made to accelerate production and increase ultimate recovery from the field. An upgrade of Chirag facilities to increase handling capacities and improve efficiency and safety is proposed during 2006-07. The sanctioning of further subsea water injection facilities to improve sweep is also planned during the first half of 2006.
Export of hydrocarbons. The Caspian Sea is landlocked without direct access to open sea. The export of oil is therefore dependent on onshore pipelines. Currently, crude oil from ACG is transported to the Black Sea through two pipelines (to Supsa in Georgia and to Novorossiysk in Russia) and by rail (to Batumi in Georgia). The export capacity of the current infrastructure is expected to become constrained as the ACG production volumes increase. To secure transportation capacity, we are participating in the BTC Pipeline with an 8.71 per cent share. Development of the 1,760-kilometer BTC Pipeline will ensure export flexibility through multiple pipelines, and thereby diversify risk involved in commercializing the land-locked upstream resources. The BTC Pipeline was sanctioned in 2002. Linefill commenced in May 2005 and is expected to be completed in the second quarter of 2006. First tanker loading at the Ceyhan Marine Terminal at the Mediterranean Sea shore is planned for the second quarter of 2006. The pipeline is estimated to cost USD 4.8 billion including the cost of line fill.
Shah Deniz. The Shah Deniz area covers 860 square kilometers and lies in a water depth between 50 and 500 meters. We have completed a four-year exploration phase involving a three-dimensional seismic survey and the drilling of three wells. The partnership submitted a Notification of Discovery and its commerciality in March 2001 and entered into a 30-year development and production period. Statoil has been named commercial operator covering gas sales, contract administration and business development for the Shah Deniz gas and condensate field. This appointment also covers the South Caucasus Pipeline system for gas transport to markets in Azerbaijan, Georgia and Turkey. BP is field operator and Statoil holds a 25.5 per cent interest. The Stage I development on the east flank of the reservoir and a 680 kilometer-long, 42-inch pipeline, from the landing terminal through Azerbaijan and Georgia to the Turkish border (the South Caucasus Pipeline (SCP)), was sanctioned by the partnership in February 2003, and Statoil was appointed as commercial operator of the pipeline.
Construction works for the Shah Deniz Stage I project are progressing according to schedule to meet the target of delivering gas to the market before winter 2006. The plateau production level of Stage I is expected to be approximately 8.5 bcm (300 bcf) per year and is expected to be reached after two to three years of production. The SCP system will be prepared for expanded capacity to facilitate future development stages.
Alov, Araz and Sharg. Statoil signed an exploration, development and production sharing agreement, with BP as operator, covering the structures Alov, Araz and Sharg in July 1998. We have a 15 per cent interest in this PSA, which is located roughly 150 kilometers southeast of the Azeri capital of Baku. The contract area covers about 1,400 square kilometers and is located at water depths of 450 to 800 meters. The structures are located in the area of the Caspian Sea that is disputed between Azerbaijan and Iran, and Iran has claimed parts of the area to be in Iranian waters since the contract was signed. Work has ceased following an Iranian naval intervention in 2001. The first well out of three commitment wells in the area is planned to be drilled within 12 to 18 months after settlement of the border issue. Negotiations with SOCAR have granted an extension of the exploration period until six months after the completion of the third well.
Kazakhstan
Statoil continued to promote future cooperation with KazMunayGaz (KMG), the national oil and gas company of Kazakhstan, by signing an MOU in 2005. This memorandum was entered into with the aim of creating a framework for negotiating a Caspian exploration and development project. The two companies aim to reach a final agreement on the main technical and commercial aspects of a joint venture in the Caspian Sea in 2006.
Western Europe
We have interests in the UK, the Faroes and Ireland. The Rosebank/Lochnagar discovery in the UK confirmed our view that there is a potential for future oil and gas discoveries on the Atlantic Margin, the outer part of the continental shelf running from Norway’s Lofoten Islands to west of Ireland. We have an exploration portfolio of licenses on the Atlantic Margin with gross acreage exceeding 20,000 square kilometers.
United Kingdom.
The UK portfolio comprises the fields Schiehallion, Alba, Caledonia, Dunlin, Merlin and Jupiter. Most of our UK fields are currently in tail-end production with an average daily total net production rate in 2005 of approximately 18 mboe per day.
Statoil is a partner in a Chevron operated exploration license west of Shetland. During the summer of 2005, the operator drilled a well on this license on the Rosebank/Lochnagar prospect and made a significant oil and gas discovery. Three additional wells are planned to appraise the discovery in 2006. In September 2005, during the UK 23rd Round, the partnership was awarded three small licenses comprising four blocks surrounding the prospect.
Faroes
The Statoil operated License 006 lies on the East Faroe Ridge, and was awarded during 2000 for a period of nine years. Statoil hold a 37.5 per cent interest. The license obligation required us to perform seismic surveys. In 2003, we negotiated a two-year extension to the first phase of the license and acquired a three-dimensional survey over the crestal areas of the Brugdan prospect, a large four-way dip-closed feature lying beneath thick basalts. The Statoil License 003 and the Hess License 001 Groups have agreed to farm-in to License 006 and will partly fund a well on the Brugdan Prospect in 2006. Statoil's equity will be reduced to 27.15 per cent after the well is drilled.
On January 17, 2005, through the second Licensing Round in the Faroes, Statoil was awarded Licenses 010 and 011 as a sole licensee, License 009 as operator with a 50 per cent interest and License 008 with a 30 per cent interest, where Chevron is operator with a 40 per cent interest. Statoil has completed its commitment to perform seismic coverage in licenses 008, 010 and 011, with license 009 still to be completed.
Ireland
Corrib. The Corrib gas field, in which we have a 36.5 per cent interest, lies on the Atlantic Margin northwest of Ireland. The Corrib field development, operated by Shell, was sanctioned in February 2001, and the production license was granted in late 2001 with a 30-year duration.
The development will incorporate seven subsea wells and the gas will be transported through a pipeline to an onshore gas processing terminal to be constructed on the west coast of Ireland. The gas will be exported from the terminal via a new pipeline that is currently being installed, to the existing Irish gas grid. The Irish Planning Authorities granted planning permission for the gas terminal on October 22, 2004. The project execution has been temporarily suspended since July 2005 due to blockades of the work sites by protestors. The project is also awaiting a new safety review of the onshore pipeline that is being completed by the Irish Authorities. This pipeline safety review is expected to be completed in early 2006 with an expected re-start of project activities to occur in the second quarter of 2006.
We also have interests in two exploration licenses, including operatorship of one large exploration license, 5/94 (Slyne-Erris), with an interest of 58.7 per cent immediately north of the Corrib field development in which we are a partner.
Middle East
Statoil is pursuing business development options in the Middle East region and has representative offices in Tehran (Iran), Riyadh (Saudi Arabia), Abu Dhabi, Doha (Qatar) and Amman (Jordan, covering Iraq).
Iran
South Pars phases 6-7-8. On December 12, 2002, Statoil became operator for the development of the offshore part of the South Pars phases 6-7-8 project with up to a 40 per cent share during the development phase. The South Pars phases 6-7-8 offshore project's scope consists of three wellhead platforms with three pipelines, condensate loading line and associated single buoy mooring, drilling of 27 production wells, hook-up of 3 pre-drilled wells, and required reservoir management.
All three jackets were installed during the first part of 2004 in a water depth of 65 meters in the Persian Gulf. Drilling operations are also completed. The condensate line and two pipelines were coated and loaded out by Sadra, an Iranian company, and laid by Allseas, a Swiss company, during the second half of 2004. Sadra continues to work with coating of pipes for the third pipeline and completion of their pipe-laying barge to be used for the third pipeline. Fabrication of topsides, also by Sadra, is significantly behind schedule due to late delivery of materials and low productivity on site. As a consequence, Statoil has decided to write down the book value of its share in the project by USD 329 million.
See Item 8—Financial Information—Legal Proceedings for information on the penalty imposed by the Norwegian National Authority for Investigation and Prosecution of Economic and Environmental Crime (Økokrim) and the investigations by the Securities and Exchange Commission, the Department of Justice, and other regulatory bodies into the consulting agreement that Statoil entered into in 2002 with Horton Investments Ltd. See also Item 3—Key Information—Risk Factors.
See Item 3—Key Information—Risk Factors for additional information concerning the risk of U.S. sanctions because of our activities in Iran.
Iraq
In 2005, the Norwegian Ministry of Petroleum and Energy signed a Memorandum of Understanding (MOU) with its Iraqi counterpart. Statoil will participate in an institutional and technical assistance program under this MOU. In addition, Statoil has signed its own agreement with the Iraq Ministry of Oil. Under this agreement, we will carry out joint exploration and field development studies, as well as provide technological assistance and transfer. These activities will be managed from our offices in Amman, Jordan.
South America
Venezuela
The political situation in the country resulted in a general strike at the end of 2002 and early 2003 that caused serious disruptions in the production and shipment of oil. In August 2004, a referendum on the continuance of Hugo Chavez as President resulted in confirmation of his mandate until the next presidential election in December 2006.
A new Hydrocarbon Law was introduced on January 1, 2002 to define the legal framework for liquid hydrocarbon and associated gas activities. It prescribes higher taxes and royalties of 30 per cent for oil producing activities, as well as a minimum 51 per cent national participation in traditional upstream activities.
In October 2004, the Venezuelan Government announced the early termination of the grace period during which the royalty rate for projects in the Orinoco belt had been reduced from 16.67 per cent to one per cent. The arguments provided by the government to justify this measure include higher oil prices, good acceptance of the synthetic crude qualities in the international markets, and technological developments that allow higher than planned production rates per well.
In early 2005, the Venezuelan Government issued statements questioning the legal structure of operating agreements and the authorizations of heavy oil projects awarded from 1992 to 1997. Sincor and LL652, in which Statoil has participating interests, are included in these allegations. The Venezuelan National Assembly created a commission to investigate these allegations but as of the date of this annual report has not issued any formal findings.
LL652. Statoil has a 27 per cent interest in the Chevron operated LL652 oil field located in Venezuela’s Lake Maracaibo. In April 2005, the Venezuelan government issued instructions to conform the structure of operating agreements, including LL652, to the requirements of the 2002 Hydrocarbon Law. As a consequence, the Venezuelan Government would increase its participation to at least 51 per cent and Chevron and Statoil would have to reduce their respective participating interests accordingly. In October 2005, the Venezuelan Government announced that as of January 1, 2006, it would direct the operations of LL652. In December 2005, Chevron and Statoil signed a transitory agreement with the Venezuelan Government that would give the government a right to start negotiation for a transition of the agreement under the Hydrocarbon Law.
Sincor. The Sincor project involves producing heavy crude oil in the Orinoco Belt, transporting the crude to the coast and upgrading it into a light, low-sulphur syncrude. Statoil holds a 15 per cent interest in the project, which is a strategic joint venture with PDVSA and Total. Sincor is the operator and is responsible for development, operation, upgrading and oil marketing of its products.
In May 2005, the Venezuelan Government issued statements indicating that Sincor operates outside the scope of the Congressional authorization of 1993. In June 2005, the Venezuelan Government informed Sincor that certain activities carried out by Sincor, including production above 114 mbbls, were outside of the Congressional authorization and therefore Sincor should pay a 30 per cent royalty as provided in the 2002 Hydrocarbon Law, instead of 16 2/3 per cent. In November 2005, the Venezuelan Government informed Sincor that changes could be made to the way royalty is paid and suggested that Sincor may have to pay royalty in kind.
We believe that Sincor has all the necessary authorizations to continue operating the project as it has done until now. As from June 2005 Statoil has paid the higher royalty on production above 114 mbbls but has reserved its rights under protest and initiated administrative proceedings seeking the reversal of the Venezuelan Government measures. See Item 8—Financial Information—Legal Proceedings for more details.
Plataforma Deltana. In February 2003, Statoil was awarded the operatorship for block four in Plataforma Deltana off the eastern coast of Venezuela. Statoil committed to drill three exploration wells during the four-year license period to establish the resource potential in the block. The first well Ballena was spudded on January 1, 2005. Due to technical problems with the rig, the well was suspended in June 2005 without having reached the planned objectives. In order to comply with the license commitments, the three wells have to be completed by February 27, 2007. Statoil therefore intends to use two drilling rigs for the remaining program, starting operations in summer 2006.
In January 2005, a farm-in agreement was signed between Statoil and Total for block four, giving Total a 49 per cent interest. Statoil will remain operator, with 51 per cent. The agreement was approved by the Venezuelan Ministry of Energy & Petroleum on January 26, 2006, and executed on March 1, 2006.
Brazil
In 2002, Statoil acquired a 40 per cent interest in Block BM-J-3 with Petrobras as operator. A three-dimensional seismic survey was acquired and processed in 2004. During 2005, the partnership entered the second phase of the license (three years), which carries a two well commitment, and relinquished 50 per cent of the original area of the block.
In 2002 we completed a 30 per cent farm-in to the ConocoPhillips operated block BM-ES-11 in the Espirito Santo Basin. Statoil has now acquired the remaining additional 70 per cent of the equity in the block, increasing its holding to 100 per cent, and has taken over the operatorship. During 2005, 64 per cent of the original area of the block was relinquished and further studies are ongoing to decide the future of the license.
In 2004, Statoil was awarded three exploration licenses comprising six blocks in the Camamu-Alamada basin offshore Brazil. These are BM-CAL-8 (where Statoil is the sole licensee), BM-CAL-10 (Statoil is operator with a 60 per cent interest) and BM-CAL-7 (Statoil has a 40 per cent interest in this license, with Petrobras as operator holding the remaining 60 per cent). The awards commit Statoil to carry out a seismic survey program, which commenced in 2005, and to drill at least two exploration wells.
In 2005, Statoil was awarded non-operated interests in two exploration licenses: 50 per cent in BM-C-33 in Campos with RepsolYPF as operator, which carries a two well commitment, and 40 per cent in BM-ES-32 in Espirito Santo with Petrobras as operator, which carries a seismic commitment. The contracts were signed in early 2006.
U.S. Gulf of Mexico
In December 2003, Statoil signed an agreement with Chevron that enabled Statoil to secure up to 25 per cent equity in a small number of selected deepwater exploration opportunities in the Gulf of Mexico. This led to Statoil's participation in the Tiger discovery well during the first quarter of 2004. Through participation in this well Statoil earned equity in two prospects in the same area: Canaan (12.5 per cent) and Ontario (12.5 per cent).
In April 2005, Statoil acquired EnCana's entire deepwater U.S. Gulf of Mexico portfolio for USD two billion. The portfolio comprises a number of high quality discoveries, and exploration opportunities.
This transaction makes the Gulf of Mexico a new area for Statoil, and expands Statoil’s global deepwater position. The portfolio comprises an average 40 per cent working interest in 239 gross blocks, covering 1.4 million acres. The core of the portfolio is the Tahiti development and the Tonga (25 per cent), Fox (25 per cent), Jack (25 per cent), St. Malo (6.25 per cent) and Sturgis (25 per cent) discoveries. The new acreage acquired provides significant additional medium- and long-term growth for Statoil. It also positions the company well for future license opportunities. A production test is planned for Jack during 2006.
During 2005, Statoil entered into two exploration arrangements with ExxonMobil. Statoil and ExxonMobil, together with our partners, plan to drill one or more exploration wells in Alaminos Canyon. Separately, Statoil and ExxonMobil are jointly evaluating exploration acreage in the Walker Ridge area.
Tahiti. Statoil holds a 25 per cent interest in the Chevron operated field. The field will be developed in several phases, and the first phase was sanctioned in August 2005. The field is designed to have a daily production capacity of 125 mbbls and 70 mmcf of natural gas. First production is expected by mid-2008. Estimated total investment for the first phase is more than USD 1.8 billion.
Other Areas:
China
We operate the Lufeng oil field and hold a 75 per cent interest in the project. Our partner is the China National Offshore Oil Company. Lufeng suspended production on June 28, 2004 after six and a half years of production in order to carry out a sidetrack drilling project. Cumulative production from the field since first oil is 33 mmbbls.
Production re-started on June 9, 2005, after an almost one year suspension for redrilling of three production wells. Total production for 2005 was 3.6 mmbbls. The current plan is to extend the production life until April 2008, followed by well abandonment operation.
Russia
Statoil has been present in Russia since the early 1990s with a representative office in Moscow. Business development activity in Russia increased in 2005, focusing on access to both exploration acreage and existing projects. Statoil considers Russia to have natural long-term potential and believes that there are significant resources still to be discovered in the Barents Sea which it views as a natural growth area as an extension of its present position on the NCS.
On September 8, 2004, Statoil signed a Memorandum of Understanding with the Russian gas company Gazprom and the Russian state oil company Rosneft on the possible cooperation in development of the Shtokman field. Statoil was short-listed by Gazprom in September 2005 as a potential partner in development of the Shtokman field. Gazprom has stated that it plans to select final partners in April 2006.
Natural Gas
Introduction
Our Natural Gas business segment transports, processes and sells natural gas. In 2005, we sold on our own behalf 27.3 bcm (964 bcf) of natural gas (at a gross calorific value of 40 MJ/scm), as well as approximately 31.6 bcm (1116 bcf) on behalf of the Norwegian State, including both equity and third party gas. We are the largest exporter and marketer of Norwegian natural gas. Our volumes and volumes sold on behalf of the Norwegian State represent approximately 60 per cent of the entire NCS contract portfolio.
We have a significant interest in the world’s largest offshore gas pipeline transportation system that extends more than 6,600 kilometers. This extensive network links Norway’s offshore gas fields with gas treatment plants on the Norwegian mainland and to terminals at five landing points located in France, Germany, Belgium and the United Kingdom, providing us with flexible access to customers throughout Europe.
Effective January 1, 2003, the ownership of all of these transportation and processing facilities with third party access was unitized into a single joint venture - Gassled - with Gassco as operator. The technical operation of most of the natural gas transport system (including the Kårstø Gas Treatment Plant), such as system maintenance, is still carried out by us on a cost-recovery basis. As from February 1, 2004, the Kollsnes Gas Plant was included in Gassled. See below under -Regulation—The Norwegian Gas Sales Organization. In 2005, the Kårstø Expansion Project (KEP2005) was completed, expanding the daily gas processing capacity at the plant by 13.5 mcm/day.
Nearly all midstream and downstream gas projects associated with our international activities are organized in the Natural Gas division. This includes midstream and commercial activities in Shah Deniz, downstream activities in Turkey and our position at Cove Point in the U.S.
Statoil has a large long-term gas sales contract portfolio, described below, and is currently evaluating midstream and downstream opportunities to take further advantage of our existing infrastructure, large supply and experience in marketing natural gas. Our downstream strategies may differ from region to region depending on our particular position in the area. In Europe, we intend to extract greater efficiency from our existing supply portfolio in order to deliver larger volumes and to enter into a wider range of sales arrangements in order to reach a broader customer base. The Natural Gas business segment intends to focus on supplying the commercial, industrial and wholesale markets.
The Natural Gas business segment was reorganized with a new organizational structure as of January 1, 2005. The organization was changed from a geographical to a functional structure.
The following table sets forth key financial information about this business segment.
(in millions) | Year ended December 31, | ||||
2005 | 2004 | 2003 | |||
NOK | USD | NOK | NOK | ||
Revenues | 45,823 | 6,795 | 33,326 | 25,452 | |
Depreciation, depletion and amortization | 775 | 115 | 652 | 619 | |
Income before financial items, income taxes and minority interest | 5,901 | 875 | 6,784 | 6,005 | |
Capital expenditure | 2,542 | 377 | 2,368 | 860 | |
Long-term assets (excluding deferred tax assets) | 19,237 | 2,852 | 17,535 | 15,772 |
Further details on the financial results can be found in Item 5—Operating and Financial Review and Prospects—Operating Results.
European Gas Market
According to the International Energy Agency (IEA) annual natural gas consumption in OECD Europe was 523 bcm (18.5 tcf) in 2004. Preliminary figures from IEA for the first three quarters of 2005 show an estimated growth of 3.9 per cent for 2005 as compared to the same period in 2004. The estimated annual growth in gas consumption in the period 2003-2020 is 1.7 per cent. The gas share of total primary energy consumption is approaching 25 per cent in the OECD countries in Europe. Around 60 per cent of the growth in gas consumption in the period is expected to come from the electricity sector. The IEA expects a growth in demand for all sub-sectors of the European natural gas market.
Statoil markets and sells its gas together with the Norwegian State’s natural gas, and taken together, we are one of the four major suppliers to the European market. The other major suppliers are Gazprom from Russia, Sonatrach from Algeria and Gasunie from the Netherlands. We believe that the Norwegian natural gas we market is competitive because of its reliability, access to the transportation infrastructure and proximity to the European market.
The UK has long been the largest producer of natural gas in Europe outside of Russia. However, gas production has started to decline, and analysis indicates that a significant and sustained drop in indigenous supplies will trigger the need for significant gas imports. Given our current and planned infrastructure, we believe that we are well positioned to take advantage of the UK’s increased demand for imported natural gas and to participate in Europe’s largest and most liberalized natural gas market. A joint venture has been created, building a new export pipeline, Langeled, from the NCS to Easington in the UK, of which Statoil and the Norwegian State will have approximately 48 per cent of the capacity. Langeled is scheduled to be operational from the fourth quarter of 2006. Another new infrastructure project is the Tampen link, a pipeline from the Statfjord field on the NCS and the existing Flaggs pipeline on the UKCS.
As the European energy market undergoes deregulation and structural changes, we believe that natural gas will play an increasingly important role. In particular, the use of natural gas as a source for electricity generation is growing. Although we expect to face a more competitive downstream natural gas market in continental Europe as the EU Gas Directive concerning deregulation and market liberalization takes increased effect, we believe that our established market positions, long-term relationships with large customers, experience in the marketing of natural gas and established points of entry will place us in a strong competitive position. For more information about the EU Gas Directive, please refer to -Regulation below.
Gas Sales and Marketing
Our major export markets for NCS gas are Germany, France, the United Kingdom, Belgium, Italy and the Netherlands. Our customers are mainly large national or regional gas companies, such as E.ON Ruhrgas, Gaz de France, ENI Gas & Power, British Gas Trading (a subsidiary of Centrica), Distrigaz and Gasunie. In addition, we sell to large end users. Natural gas is sold to these customers mostly under long-term, take-or-pay contracts. Our long-term contract portfolio, including sales of SDFI gas, is expected to increase by approximately 35 per cent from 2005 to 2010.
Statoil carries out gas sales and marketing activities of NCS gas for the benefit of Statoil and the SDFI. In addition, Statoil markets gas sourced from producing areas other than the NCS, both towards markets already penetrated by Statoil and the SDFI and toward new markets.
Statoil entered into several new long-term contracts in 2005. A 10-year agreement to deliver 0.5 bcm of gas per annum from October 2007 was concluded with Scottish Power, a gas and electricity supplier in the UK. A 10-year agreement to deliver approximately 0.3 bcm of gas per annum for a new Norwegian power station was concluded with electricity generator Statkraft. Deliveries to the planned Naturkraft installation at Kårstø north of Stavanger are scheduled to commence in October 2007. The contract represents a significant increase in Statoil’s gas sales to mainland Norway. The gas sales contract to Germany’s Verbundnetz Gas (VNG) was extended by six years, corresponding to total additional deliveries of 12 bcm up to 2022. Two billion cubic meters of gas have been supplied annually by Statoil to VNG since 1996, and an option to extend this contract has now been exercised.
In the United Kingdom, we market our gas towards large industrial customers, power generators and wholesalers, and participate in the UK spot market. Our group-wide gas trading activity is mainly focused around the UK gas market, which is a significant market in terms of size and one of the most progressive in terms of deregulation when compared with other European markets.
In 2004, Statoil (U.K.) Limited and SSE Hornsea Limited (subsidiary companies of Statoil and Scottish and Southern Energy Plc) signed a Joint Participation Agreement and entered into a joint venture for the development, operation and maintenance of a salt cavern gas storage facility near Aldbrough, on the east coast of Yorkshire close to the Easington terminal (delivery point for Langeled). On completion the storage facility will comprise nine underground caverns. Statoil (U.K) Limited owns one third of the storage capacity being developed, of which 57.7 per cent is being paid for by the SDFI. The facility brings together two sets of Planning Consents granted to the parties in 2000 and will be developed and operated by SSE Hornsea Limited. Construction work started in the first quarter of 2004 and all site work preparations have been completed. At the end of 2005, 8 wells had been drilled and the debrining had started on the first tranche of 5 caverns, and all major contracts had been awarded. The storage facility is expected to begin commercial operation by the fourth quarter of 2007 with full commercial operation of the nine cavern facility, with a capacity of 420 mcm (total capacity), in 2009. Statoil’s share of the total development cost is estimated to be NOK 1.6 billion, of which 57.7 per cent will be covered by the SDFI. Development responsibility for this asset has been transferred to the Technology and Projects business area.
In Germany, we hold a 23.1 per cent stake in the Norddeutsche Erdgas-Transversale, or Netra, overland gas transmission pipeline, a 20.1 per cent stake in Etzel Gas Storage and a 16.6 per cent interest in EuroHub GmbH (formerly HubCo North West European Hub Service Company).
The Natural Gas business segment is responsible for the midstream and commercial activities related to the Shah Deniz project in Azerbaijan. Turkey is the main market for gas from Stage 1 of the Shah Deniz development. The gas will be transported to the customers through the South Caucasus Pipeline (SCP) running through Azerbaijan and Georgia to the Georgian/Turkish border, sanctioned for development in conjunction with the Shah Deniz project. The SCP development project is on track to begin operations in October 2006.
In the U.S., we market gas to local distribution companies, industrial customers and power generators. LNG is imported from Algeria, Egypt and Trinidad and regasified through the Cove Point LNG terminal in Maryland. We have entered into a long-term contract expiring in 2023 with the operator Dominion Resources Inc., securing us capacity rights of 2.4 bcm per year at the Cove Point terminal and pipeline. The terminal and pipeline interconnect with three interstate pipelines allowing gas to be directed to the Mid-Atlantic and North-East markets. The SDFI uses and pays for a proportionate share of capacity in the terminal and pipeline. We also source some pipeline gas domestically, mainly for optimization purposes. When Snøhvit comes on stream, Statoil Natural Gas (SNG), a subsidiary of Statoil, will market NCS gas in the U.S..
Statoil has signed a new contract with Dominion Resources Inc. for access to additional import capacity of 7.7 bcm per year at the Cove Point LNG terminal, for a 20-year period from November 2008, when the Cove Point Expansion is scheduled to be completed. The transaction is subject to approval by the U.S. Federal Energy Regulatory Committee, upon which construction of the additional infrastructure for the Cove Point Expansion can commence.
The Snøhvit project has experienced an estimated extended delay of eight months. This means that Snøhvit LNG will not be available before summer 2007, while delivery commitments under long-term sales contracts are required to begin in October 2006. Statoil is now working together with our buyers and potential suppliers to find solutions to mitigate our commitments during the period prior to first delivery of LNG from Snøhvit.
Norwegian Gas Transportation System and Other Facilities
In order to transport Norwegian natural gas to European customers, we and other Norwegian gas producers have built an extensive gas pipeline system, connecting gas fields to gas processing plants on the Norwegian mainland and to receiving terminals in Europe.
As from January 1, 2003, the ownership interests of the Zeepipe, Franpipe, Europipe II, Åsgard Transport, Statpipe, Oseberg Gas Transport and Vesterled joint ventures and Norpipe AS were transferred to a new joint venture called Gassled. This also includes the terminals in Statpipe and Vesterled, the Europipe Receiving Facilities and the Europipe Metering Station. The ownership interests in Zeepipe Terminal JV and Dunkerque Terminal DA have been adjusted. As from February 1, 2004, the Kollsnes Gas Plant was included in Gassled. Our interests in Gassled and other pipelines and terminals are listed in the tables below.
As from October 1, 2005, the Kårstø Expansion Project was included in Gassled with subsequent adjustments in ownership interest. Further adjustments of Gassled owner shares will take place upon inclusion of Langeled in October 2006 and Tampen Link in October 2007. Etanor DA was planned to be included in 2005, but has been postponed to 2006.
From January 1, 2011, our ownership interest in Gassled will be reduced due to an increased ownership interest for the SDFI. Similar adjustments of the ownership interest in Zeepipe Terminal JV and Dunkerque Terminal DA will also be made. In addition, our ownership interest in Gassled may change as a result of the inclusion of existing or new infrastructure or if Gassled undertakes further investments without participation from its owners in the same ratio as their ownership interests in Gassled. Gassled has a license period that extends to 2028.
The Gassled-system is operated by Gassco AS. Gassco is wholly owned by the Norwegian State, and holds no ownership in Gassled or in gas production. In 2005, the system transported 82.4 bcm (2.9 tcf) of Norwegian gas and has additional capacity to transport 14 to 18.5 bcm (0.5 to 0.6 tcf) per year.
In December 2004 Statoil and ConocoPhillips agreed to establish a joint operating company, GasPort KG, for the receiving terminals and the metering station in Emden and Dornum in Germany, with effect from January 1, 2005. Gassco AS operates these facilities, with Statoil and ConocoPhillips as technical service providers (TSPs).
To cater for existing commitments and expected new gas sales to the UK, increased transportation capacity will be required. The construction of a new dry gas pipeline, Langeled, from the Ormen Lange field via Sleipner to Easington in the UK, commenced in 2004. The development of the Langeled pipeline and terminal facilities is being carried out by Statoil, on assignment from the field development operator Norsk Hydro. It is anticipated that Ormen Lange will account for approximately 20 per cent of Norwegian gas export capacity in 2010 bringing the capacity to a level of approximately 115 bcm per year. The southern leg (Sleipner to Easington) is due to be completed during the fourth quarter of 2006 and the northern leg (Nyhamna to Sleipner) is due to be completed during the fourth quarter of 2007. Our ownership in this pipeline is 15.0 per cent. On completion of the southern leg, the ownership of Langeled will be transferred into Gassled.
Gassled is divided into five areas; area A is the Statfjord–Kårstø pipeline, area B is the Åsgard–Kårstø Pipeline, area C is the Kårstø Gas Treatment Plant, area D is all the dry gas pipelines and area E is the Kollsnes Gas Plant, as illustrated in the figure below. The figure below does not include specific details for all fields within each area and should be considered as illustrative only.
Our ability to transport our own supply of natural gas from our various field interests enables us to provide regular and reliable gas deliveries to our customers. The pipelines intersect at platforms, tie-in locations and processing plants, providing a flexible network to transport natural gas from various fields and gas processing plants to our entry points into the European market, depending on our customers’ contracted daily and annual natural gas sales requirements. Each field operates with an account system, permitting fields to borrow and repay gas volumes as needed to meet their supply needs.
The major costs associated with running a pipeline system are maintenance and compression costs that result from operating compression facilities to increase gas throughput. Most transport agreements are based on a tariff per unit transported which covers the operating cost of the transport system and provides a return on the capital invested. The Ministry of Petroleum and Energy sets such tariffs. The pipelines are maintained under an annual maintenance plan approved by the Norwegian Petroleum Directorate.
The following table sets out the major NCS gas transportation systems in which we have an interest, the transportation routes and capacities. All of the pipelines and terminals are operated by Gassco AS.
Transportation systems included in Gassled
Former Joint Venture | Startup | Product | Start point |
End point | Transport capacity(1) mmcm/day |
Zeepipe |
|
|
|
|
|
Zeepipe 1 | 1993 | Dry gas | Sleipner riser platform | Zeebrugge | 40.9 |
Zeepipe 2A | 1996 | Dry gas | Kollsnes | Sleipner riser platform | 72.0 |
Zeepipe 2B | 1997 | Dry gas | Kollsnes | Draupner E | 71.0 |
Europipe 1 | 1995 | Dry gas | Draupner E | Dornum/Emden | 44.5 |
Franpipe | 1998 | Dry gas | Draupner E | Dunkerque | 52.4 |
Europipe II | 1999 | Dry gas | Kårstø | Dornum | 64.6 |
Norpipe AS | 1977 | Dry gas | Norpipe Y (Ekofisk Area) | Emden | 43.1 |
Åsgard Transport | 2000 | Rich gas | Åsgard | Kårstø | 70.4 |
Statpipe |
|
|
|
|
|
Zone 1 | 1985 | Rich gas | Statfjord | Kårstø | 26.8 |
Zone 4A | 1985 | Dry gas | Heimdal | Draupner S | 33.3 |
|
|
| Kårstø | Draupner S | 20.1 |
Zone 4B | 1985 | Dry gas | Draupner S | Norpipe Y (Ekofisk Area) | 30.0 |
Oseberg Gas Transport | 2000 | Dry gas | Oseberg | Heimdal | 39.9 |
Vesterled (Frigg transport) | 2001 | Dry gas | Heimdal | St. Fergus | 36.0 |
(1) We use committable capacity as a measurement for transport capacity. Committable capacity is defined as the capacity available for stable deliveries.
Terminals included in Gassled
Terminal facilities | Startup date | Product | Location |
Zeepipe JV |
|
|
|
Europipe receiving facilities | 1995 | Dry gas | Dornum, Germany |
Europipe metering station | 1995 | Dry gas | Emden, Germany |
Norsea Gas AS | 1977 | Dry gas | Gas Terminal, Emden, Germany |
Statpipe JV (Kårstø gas treatment plant) | 1985 | Dry gas/NGL | Kårstø, Norway |
Etanor DA (Ethane plant at Kårstø) | 2000 | Ethane | Kårstø, Norway |
Vesterled JV (Frigg terminal) | 1978 | Dry gas | St. Fergus, Scotland |
Kollsnes Gas Plant | 1996 | Dry gas/NGL | Kollsnes, Øygarden Norway |
Pipelines not included in Gassled
Joint Venture | Startup | Product | Start point | End point | Transport capacity | Statoil |
Norne gas transportation system | 2001 | Rich gas | Norne field | Åsgard transport | 11.0 | 25.00 |
Haltenpipe | 1996 | Rich gas | Heidrun field | Tjeldbergodden/ Åsgard transport | 7.1 | 19.06 |
Sleipner Condensate Pipeline(1) | 1993 | Unstabilized condensate | Sleipner field | Kårstø | km3/day | 49.60 |
Troll Oil Pipeline I(1) | 1995 | Oil | Troll B | Mongstad | 42.5 | 20.85 |
Troll Oil Pipeline II(1) | 1999 | Oil | Troll C | Mongstad | 40.0 | 20.85 |
(1) Owned by E&P Norway.
Terminals not included in Gassled(1)(2)
Terminal | Startup date | Product | Location | Statoil share in % | Statoil share in % | Statoil share in % |
Zeepipe terminal JV(4) | 1993 | Dry gas | Zeebrugge, Belgium | 10.37526 | 10.44594 | 8.98182 |
Dunkerque terminal DA(5) | 1998 | Dry gas | Dunkerque, France | 13.76310 | 13.85686 | 11.91466 |
(1) These interests include Statoil’s 25 per cent interest in Norsea Gas AS.
(2) The changes in ownership structure over time are caused by changes in the underlying ownership in Gassled.
(3) Change effective October 1, 2005.
(4) This interest is held through our ownership in Gassled. Gassled owns 49 per cent of the terminal.
(5) This interest is held through our ownership in Gassled. Gassled owns 65 per cent of the terminal.
Ownership structure Gassled
| Period 2003-2005(1) | Period 2005-2010(2) | Period 2011-2028(2) |
Petoro AS(3) | 38.293% | 38.627% | 48.173% |
Statoil ASA | 20.379% | 20.557% | 17.676% |
Norsk Hydro | 11.134% | 11.186% | 9.571% |
Total | 9.038% | 8.672% | 6.980% |
ExxonMobil | 9.755% | 9.755% | 8.297% |
Shell | 4.681% | 4.440% | 3.517% |
Norsea Gas AS | 3.018% | 3.045% | 2.617% |
ConocoPhillips | 2.033% | 2.030% | 1.725% |
Eni | 1.669% | 1.688% | 1.455% |
Statoil interest including 25 per cent of Norsea Gas AS | 21.133% | 21.318% | 18.330% |
(1) Change effective October 1, 2005.
(2) Expected ownership share. Langeled, Tampen Link joint ventures and Etanor DA are not included in the above ownership structure for 2005-2010 and 2011-2028. Changes in the ownership structure including Langeled and Etanor DA will have effect from October 1, 2006, while Tampen Link will be included as from October 10, 2007.
(3) Petoro holds the participating interest on behalf of the SDFI.
Kårstø Gas Treatment Plant (Area C)
Statoil, as TSP, is responsible for the operation, maintenance and further development of the Kårstø gas treatment plant, on behalf of the operator Gassco. Kårstø processes rich gas and condensate, or light oil, from the NCS received via the Statfjord–Kårstø pipeline (area A), the Åsgard-Kårstø pipeline (area B) and the Sleipner condensate pipeline. Products produced at Kårstø include ethane, propane, iso-butane, normal butane and naphtha and stabilized condensate. In 2005, Kårstø produced 0.6 million tonnes of ethane, 4.5 million tonnes of LPG and 3.3 million tonnes of condensate/naphtha exported to customers worldwide.
The Kårstø Expansion Project has been carried out primarily to accommodate gas from the Kristin field from October 1, 2005. The expansion has increased extraction capacity by 13.5 mmcm/day, accommodated for removal of CO2 from sales gas, and increased ethane recovery. The project was completed according to schedule on October 10, 2005.
Kollsnes Gas Treatment Plant (Area E)
Statoil, as TSP, is responsible for operation, maintenance and further development of the Kollsnes gas treatment plant, on behalf of the operator Gassco. The plant was built to receive gas landed from the Troll field through two 36-inch pipelines. The current gas processing capacity is approximately 146 mmcm per day. At Kollsnes, the Troll gas is dried and compressed for export to Europe. Kollsnes was upgraded in 2005 as it now receives gas from Visund and Kvitebjørn. As part of this expansion NGLs are extracted and transported through a pipeline to the Mongstad refinery for further processing.
Gas Sales Agreements
Statoil is instructed by the Norwegian State to manage, transport and sell the gas owned by the SDFI, resulting in Statoil managing, transporting and marketing approximately 60 per cent of all NCS gas.
Due to the relatively large size of NCS gas fields and the extensive cost in developing new fields and gas transportation pipelines, most of Statoil’s gas sales contracts are long-term contracts in which the purchasers agree to take daily and annual quantities of gas and, if the gas is not taken, are obliged to pay for the contracted quantity. Our long-term contracts generally run for 10 to 20 years or more. A significant portion of our current long-term sales contracts reach plateau level between 2005 and 2008.
Prices in these contracts are generally tied to a formula based on prevailing prices of a customer’s principal alternative fuels to natural gas, mainly heavy fuel oil and gas oil. Consequently, there can be significant price fluctuations during the life of the contract. Prices in these contracts are generally adjusted quarterly and are calculated on the basis of prices prevailing in the three to nine months prior to the date of adjustment as published in reference indices. By contrast, recent long-term gas sales contracts in the UK are priced with reference to a daily UK market gas price index. The price formula, calling for monthly or quarterly adjustment, however, is not able to capture all trends in the marketplace in either the gas or competing fuel markets, i.e., changes in taxation of gas and competing fuels imposed by national governments. Therefore, most of our long-term gas contracts contain contractual price adjustment mechanisms that can be triggered at regular intervals by either the buy er or the seller. Under our long-term sales contracts either party has the right to initiate a price review process under certain circumstances as set forth in these contracts. In 2005, Statoil was involved in commercial discussions (in lieu of price review) or in formal price review processes for 60 per cent of the volumes of our long-term sales contracts. Most of these have been settled.
Manufacturing and Marketing
Introduction
The Manufacturing and Marketing business segment comprises our downstream activities, including sales and trading of crude oil and refined products, refining and methanol production, retail and industrial marketing of oil.
The following table sets forth key financial information about this business unit.
| Year ended December 31, | |||
| 2005 | 2004 | 2003 | |
(in millions) | NOK | USD | NOK | NOK |
Revenues | 339,380 | 50,320 | 267,177 | 218,642 |
Depreciation, depletion and amortization | 2,207 | 327 | 1,719 | 1,419 |
Income before net financial items, income taxes and minority interest | 7,646 | 1,134 | 3,921 | 3,555 |
Capital expenditure | 1,630 | 247 | 4,162 | 1,546 |
Long-term assets (excluding deferred tax assets) | 23,163 | 3,434 | 30,055 | 23,226 |
Further details on the financial results can be found in Item 5—Operating and Financial Review and Prospects—Operating Results.
Oil Sales, Trading and Supply
We are one of the largest net sellers of crude oil in the world, operating out of sales offices in Stavanger, London, Singapore and Stamford, Connecticut, selling and trading crude oil, NGL and refined products. We market and sell the Norwegian State’s crude oil together with our own. In 2005, we sold 669 mmbbls of crude, or above 1.8 mmbbls per day, including sales to our own refineries and other internal divisions. Crude oil sales in 2005 were 5 per cent lower than sales in 2004 as a result of lower production on the NCS. Our main crude oil market is in northwest Europe, and we also sell large volumes into North America and Asia. Most of our crude oil volumes are sold on spot market terms, based on worldwide prices and quotations. Of the volumes we sold in 2005, approximately 33 per cent were our own volumes. We purchase crude oil from third parties in order to obtain other qualities of oil for sale and blending, and to increase our flexibility with respect to shipping and storage.
The main markets for our refined products, NGLs and condensate are in northwest Europe and the countries around the Baltic Sea rim. We are a large supplier of condensate in Europe, providing this very light crude oil to refiners and the petrochemical industry. In addition, condensate cargoes are sold in the U.S. market. In 2005, we sold approximately 29.7 million tonnes of refined oil products, the majority of which were refined at our refineries at Mongstad and Kalundborg, and approximately 12.1 million tonnes of NGL, including condensate.
Manufacturing
We are majority owner (79 per cent) and operator of the Mongstad refinery in Norway, which has a crude oil distillation capacity of 179 mbbls per day, and sole owner and operator of the Kalundborg refinery in Denmark, which has a crude oil and condensate distillation capacity of 118 mbbls per day. In addition, we have the right to 10 per cent of the production capacity at the Shell operated refinery in Pernis, The Netherlands, which has a crude oil distillation capacity of 400 mbbls per day. Our methanol operations consist of our 81.7 per cent stake in Europe’s newest gas-based methanol plant at Tjeldbergodden, Norway, which has a design capacity of 946,000 tonnes per year.
The following table gives operating characteristics of the plants at Mongstad, Kalundborg and Tjeldbergodden. We had planned turnarounds (major maintenance shutdowns) at Mongstad and Tjeldbergodden in 2004, and at Kalundborg in 2005.
All data in the following table is for the year ended December 31,
| Throughput (1) | Distillation capacity (2) | On stream factor (3) | Utilization rate(4) | ||||||||
Refinery | 2005 | 2004 | 2003 | 2005 | 2004 | 2003 | 2005 | 2004 | 2003 | 2005 | 2004 | 2003 |
Mongstad | 11.1 | 9.3 | 9.8 | 8.7 | 8.7 | 8.7 | 98.5 | 96.0 | 98.2 | 98.7 | 96.1 | 98.1 |
Kalundborg | 4.9 | 4.9 | 5.0 | 5.5 | 5.5 | 5.5 | 97.8 | 92.6 | 94.4 | 89.6 | 90.7 | 90.2 |
Tjeldbergodden | 0.90 | 0.85 | 0.92 | 0.95 | 0.95 | 0.94 | 99.1 | 97.5 | 98.6 | 96.3 | 98.3 | 99.2 |
(1) Actual throughput of crude oils, condensates, feed and blendstock, measured in millions of tonnes.
(2) Nominal crude oil and condensate distillation capacity, and methanol production capacity, measured in millions of tonnes.
(3) Composite factor for all processing units, excluding turnarounds.
(4) Composite rate for all processing units, stream day utilization.
Mongstad. The Mongstad refinery is directly linked to offshore fields through two crude oil pipelines and indirectly linked through an NGL/condensate pipeline from the crude oil terminal at Sture and the gas terminal at Kollsnes, making Mongstad an attractive site for landing and processing hydrocarbons and for further development of our oil and gas reserves. The main facilities at Mongstad, in addition to the refinery, are a crude oil terminal, owned 65 per cent by Statoil, and an NGL terminal, owned by Vestprosess, in which Statoil has an ownership share of 17 per cent.
The other 21 per cent interest in Mongstad is owned by Shell. We have a service agreement with Shell Global Solutions, Shell’s subsidiary, which provides technical operational support, project development support and general technical advice for Mongstad.
The Mongstad refinery, built in 1975 and significantly expanded and upgraded in the late 1980s, is a medium-sized, modern and sophisticated refinery. The products are principally high value light products such as naphtha, gasoline, jet fuel, diesel and light heating oil. The refinery does not produce low value residue because this crude oil component is upgraded to gasoline and gasoils in the residue cracker and the delayed coker. More recent upgrading projects include an NGL/condensate project involving a pipeline from Kollsnes to Mongstad, an NGL terminal and refinery expansion and revamp at Mongstad and a cracker naphtha desulphurization project that commenced production in March 2003. In 2004 the NGL/condensate plant (Vestprosess) capacity was doubled and more efficient stream boilers were installed. Tie-ins and modifications were completed during the 2004 maintenance shutdown.
Approximately 40 per cent of Mongstad’s total production is delivered to the Scandinavian markets and 60 per cent is exported to northwest Europe and the United States. Although the transportation costs are higher than those of refineries located closer to these markets, Mongstad’s overall competitive position benefits from its proximity to feedstock supplies, which results in lower transportation costs included in the cost of feedstock.
The following table sets forth approximate quantities of refined products (in thousands of tonnes) manufactured by Mongstad for the periods indicated. In addition to crude, as shown below, the Mongstad refinery upgrades large volumes of fuel feedstock (up to one million tonnes per year), Oseberg and Tune NGL, and Troll, Kvitebjørn and Visund condensate.
Mongstad product yields and feedstock | Year ended December 31, | |||||
2005 | 2004 | 2003 | ||||
LPG | 335 | 3% | 286 | 3% | 351 | 4% |
Gasoline/naphtha | 4,647 | 42% | 3,999 | 43% | 4,095 | 42% |
Jet/kero | 705 | 6% | 558 | 6% | 503 | 5% |
Gasoil | 4,247 | 38% | 3,580 | 38% | 3,819 | 39% |
Fuel oil | 225 | 2% | 156 | 2% | 212 | 2% |
Coke/sulphur | 239 | 2% | 190 | 2% | 233 | 2% |
Fuel, flare and loss | 694 | 6% | 554 | 6% | 597 | 6% |
Total throughput | 11,092 | 100% | 9,323 | 100% | 9,810 | 100% |
North Sea crude oils: |
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Troll, Heidrun (FOB crude oils) | 4,999 | 45% | 2,965 | 32% | 2,722 | 28% |
Other North Sea crude oils (CIF crude oil) | 3,336 | 30% | 4,288 | 46% | 5,273 | 54% |
Residue | 1,256 | 11% | 894 | 10% | 867 | 9% |
Other fuel and blendstock | 1,501 | 14% | 1,176 | 13% | 948 | 10% |
Total feedstock | 11,092 | 100% | 9,323 | 100% | 9,810 | 100% |
Note: Changes in throughput and yields are partly due to maintenance shutdowns. There was a planned maintenance shutdown in 2004.
The Mongstad refinery is geared for efficient production of commodity fuels and has considerable flexibility in producing products to different specifications through its ability to do in-line blending during ship loading. Given the stricter EU and U.S. product specifications implemented in 2005, we decided to invest significantly in improvements at Mongstad. The costs incurred in bringing the facilities up to these requirements were approximately NOK 1 billion. This work was completed in 2004. We are currently assessing whether a new diesel desulphurization project will be required in order to meet anticipated requirements.
We have a cost improvement program in place, which focuses on maintenance, procurement and cost management. We are also identifying measures in order to improve energy efficiency. The refinery reliability in 2003 and 2005 was the highest ever, since the refinery was upgraded in the 1980s. The 2004 reliability was lower than the 2003 level, mainly due to three unplanned maintenance shutdowns, one of which was caused by a fire.
Kalundborg. Kalundborg produces products such as gasoline, jet fuel, diesel oil, propane, and fuel oil to supply markets in Denmark and Sweden. The refinery is connected through a pipeline to our terminal at Hedehusene close to Copenhagen. Kalundborg’s refined products are also supplied to the northwest European market, mainly Germany and France.
The following table gives approximate quantities of refined products (in thousands of tonnes) manufactured by Kalundborg for the periods indicated.
Kalundborg product yields and feedstock | Year ended December 31, | ||||||
2005 | 2004 | 2003 | |||||
LPG | 95 | 2% | 93 | 2% | 110 | 2% | |
Gasoline/naphtha | 1,537 | 31% | 1,478 | 30% | 1,517 | 30% | |
Jet/kero | 236 | 5% | 289 | 6% | 265 | 5% | |
Gasoil | 2,038 | 42% | 1974 | 40% | 1,991 | 40% | |
Fuel oil | 759 | 16% | 886 | 18% | 922 | 18% | |
Coke/sulphur | 5 | 0% | 5 | 0% | 5 | 0% | |
Fuel, flare and loss | 195 | 4% | 185 | 4% | 183 | 4% | |
Total throughput | 4,865 | 100% | 4,911 | 100% | 4,993 | 100% | |
North Sea crude oils: |
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Sleipner, Åsgard, other condensates | 1,010 | 21% | 1,168 | 24% | 1,215 | 24% | |
Other North Sea crude oils | 3,639 | 75% | 3,527 | 72% | 3,481 | 70% | |
Other fuel and blendstock | 216 | 4% | 216 | 4% | 297 | 6% | |
Total feedstock | 4,865 | 100% | 4,911 | 100% | 4,993 | 100% |
Note: Changes in throughput and yields are partly due to maintenance shutdowns and expansions. In 2003 there was a longer shutdown in September/October in the crude unit due to consequential damages after power failures in Sweden and Denmark in late September 2003. In 2004 there were unplanned maintenance shutdowns and a planned shutdown to complete the diesel/jet project. In 2005 there was a planned turnaround in the condensate unit, and also some longer, unplanned shutdowns.
Although it is a relatively small and simple refinery, Kalundborg is a plant with high-energy efficiency and relatively low operating costs for a plant of its size and configuration. The refinery has improved its performance significantly in recent years through several small investment projects to increase flexibility and improve yield/product quality. It produces high quality products including low sulphur gasoline in accordance with EU specifications.
Tjeldbergodden. Our methanol operations at Tjeldbergodden, Norway, of which we own 81.7 per cent, have a maximum proven capacity of 0.95 mmtpa and actual output during 2005 was 0.90 mmtpa. The reliability in 2005 was at a historical high. Actual output in 2005 equaled approximately 14 per cent of Western European consumption.
We also hold 50.9 per cent of Tjeldbergodden Luftgassfabrikk DA, the largest Air Separation Unit (ASU) in Scandinavia, which also owns the first Norwegian natural gas liquefaction plant located at Tjeldbergodden with an annual gas (methane) capacity of 36 mmcm (1.3 bcf). Our partners are AGA (37.8 per cent) and ConocoPhillips (11.3 per cent). The ASU supplies oxygen to the methanol plant and AGA markets and sells industrial gases produced.
Nordic Energy
Our Nordic Energy unit, with approximately 1,300 employees, consists of three national sales organizations for refined products to consumer and industrial markets in Scandinavia. Nordic Energy sells Statoil-branded refined products for heating, such as fuel oil, LPG, wood pellets, transportation fuel, such as diesel, jet fuel, marine fuel and lubricants. We also have operations for lubricants and LPG in Poland and the Baltic States. In addition, we manage the logistics of petrol delivery for Statoil-branded service stations in Scandinavia. We have a strong market position in Scandinavia based on our approximately 350,000 customers and annual sales of approximately 6.0 billion liters. In the LPG market, we have approximately 40 per cent of the Scandinavian market share. Our portfolio also includes ownership interests in gas distribution companies. We are a significant provider of wood pellets in Scandinavia with a production capacity of 200,000 tonnes.
Retailing
Our retail distribution network consists of almost 2,000 Statoil-branded service stations in nine countries. We are market leaders in Norway, Sweden, Ireland, Latvia and Estonia. The full service stations provide automotive fuels, car accessories and simple vehicle service, and nearly all offer goods as well as fast food, convenience products and basic groceries. In 2005, these stations sold approximately 5.9 billion liters of petrol and diesel.
The following table lists these retail outlets by region or country as of December 31, 2005, and our volume of automotive fuel sales for the year ended December 31, 2005.
| Scandinavia | Ireland | Poland | Baltics | Russia | Total |
Statoil owned and operated | 275 | 36 | 166 | 151 | 6 | 634 |
Statoil owned and dealer-operated | 557 | 4 | 0 | 1 | 0 | 562 |
Dealer owned and Statoil operated | 0 | 33 | 6 | 0 | 0 | 39 |
Dealer owned and operated | 403 | 135 | 11 | 7 | 0 | 556 |
Automated stations | 178 | 0 | 12 | 17 | 0 | 207 |
Total | 1413 | 208 | 195 | 176 | 6 | 1998 |
Fuel volumes: | 2182 | 560 | 300 | 363 | 22 | 3426 |
Diesel (millions of liters) | 1218 | 717 | 220 | 275 | 2 | 2431 |
Total | 3400 | 1277 | 520 | 638 | 24 | 5858 |
Scandinavia is our home retail market, where Statoil-branded stations have a petrol market share of approximately 27 per cent in Norway, 24 per cent in Sweden and 16 per cent in Denmark. Statoil’s other service stations are located in Ireland, Poland, Russia and the Baltics, which includes Estonia, Lithuania and Latvia. We rank as a market leader, measured by fuel volumes sold, in Ireland, Estonia and Latvia with approximately 16 per cent, 30 per cent and 21 per cent, respectively, of the local retail petrol market in 2005.
Following a review of our retail business portfolio, we have recently initiated a process to evaluate a possible sale of our Irish retail and commercial & industrial business.
Borealis
In 2005, Statoil sold its 50 per cent holding in the Borealis petrochemicals group to the International Petroleum Investment Company (IPIC) from Abu Dhabi and OMV Aktiengesellschaft from Austria, who since 1998 have owned the other 50 per cent of the company. Borealis is, after the sale, now owned 65 per cent by IPIC and 35 per cent by OMV. The sale price was EUR 1 billion (NOK 7.8 billion), which gave Statoil a tax-free capital gain of approximately NOK 1.5 billion.
Health, Safety and Environment
Our operations are subject to a number of environmental laws and regulations in each of the jurisdictions in which we operate, governing, among other things, air emissions, wastewater discharges and discharges to the sea, the use, handling and disposal of hazardous substances and wastes, soil and groundwater contamination and employee health and safety. As with our competitors, liability risks are inherent in our operations. Requirements under environmental laws and regulations can be expected to increase in the future. We also have long-term obligations concerning the decommissioning of operational facilities and the remediation of soil or groundwater at certain of our facilities and liability for waste disposal or contamination on properties owned by others. We have established financial reserves for estimated environmental liabilities based on our current information with respect to those liabilities. We have also made significant expenditures to comply with environmental regulations. However, significant additional financial reserves or compliance expenditures could be required in the future due to changes in law, new information on environmental conditions or other events, and those expenditures could have a material adverse effect on our financial condition or results of operations.Health, safety and the environment, or HSE, comprises health and working environment, safety, emergency preparedness, the environment, business integrity services and security. Statoil’s management system for HSE forms an integrated part of the group’s total management system. Statoil’s management system relating to corporate governance is certified to the international ISO 9001 standard. In addition, all central operating units are certified according to the same standard, and also to the environmental standard ISO 14001 (an updated list of certified operating units is available at www.statoil.com.) Statoil is included in the Dow Jones sustainability index (DJSI) and the FTSE4Good Index. In August 2005 Statoil was again ranked as the world’s best energy company in terms of sustainability by the Dow Jones Sustainability World Index (DJSI World). Statoil has been part of the Dow Jones Sustainability Index (top 10 per cent in each sector in terms of sustainability) for four years. In previous years Statoil has been ranked first (2004), third (2003) and fifth (2002).
Our approach to HSE is risk-based, which means that risks are identified, appropriate criteria are established and measures are implemented in order to meet these criteria. We aim to carry out our operations without harm to the environment and according to the principles for sustainable development.
Our corporate indicators for environmental performance include:
• number of unintentional oil spills;
• volume of unintentional oil spills (cubic meters);
• CO2 emissions, total (tonnes);
• NOx emissions, total (tonnes); and
• waste recovery ratio.
In addition, Statoil facilities are compliant with SO2 regulations.
The EU Directive on Sulphur (99/32/EC) is intended to reduce emissions of sulphur dioxide resulting from the combustion of certain types of liquid fuels (heavy fuel oil and heating oil). The EU member states and EEA countries must ensure that the use of heavy fuel and gas oil falls below specific levels of sulphur content within their territory. The sulphur limit for heating oil has been set to 0.11 wt% from January 1, 2008. Lower levels of sulphur content than stipulated in the Directive for heavy fuel and gas oil may be imposed by the EU member states separately.
The EU is also imposing stricter requirements for automotive fuels. Statoil delivered products with a maximum of 10 ppm beginning on January 1, 2005, and will meet the EU requirements that will become effective in 2009.
Our CO2 emissions (from Statoil operations) totaled 10.3 million tonnes in 2005 compared to 9.8 million tonnes emitted in 2004. Our NOx emissions were 34,700 tonnes in 2005, against 31,100 tonnes in 2004. Historically, our NCS emissions of CO2 and NOx, measured in tonnes per delivered quantity, have been below the NCS average. Compared to other oil regions in the world the NCS is the area with the lowest relative emissions, with an average of 7.1 kg CO2/boe produced, compared to an industry average of 18.5 kg CO2/boe produced. Changes in laws regulating greenhouse gas emissions could cause us to incur additional expenditures for pollution control equipment.
Our industry has been working closely with the Norwegian authorities in order to prevent harmful discharges (and in particular chemical discharges) to the sea caused by operations. In 2003 we submitted a plan to the Norwegian authorities committing to implementation of certain measures intended to achieve an 80 per cent planned reduction in environmental risk by 2005. By the end of 2005 we had received an 89 per cent reduction.
The total number of unintentional oil spills in the Statoil group in 2005 amounts to 534 with a corresponding volume of 442 cubic meters. For 2004 the corresponding numbers were 487 spills and 186 cubic meters for the group. The increase in volume in 2005 is mainly the result of one sizeable spill of 340 cubic meters on the Norne field in the Norwegian Sea.
Our corporate indicators within safety are currently:
• fatal accidents;
• frequency of total recordable injuries;
• frequency of lost-time injuries; and
• frequency of serious incidents.
Two fatalities were suffered by contractors working for Statoil in 2005. The number of serious incidents (undesirable events of a very serious nature) in 2005 was 242, down from 340 in 2004. The serious incident frequency (the number of incidents per million working hours) was 2.3 in 2005, down from 3.2 in 2004. The total recordable injury frequency (the number of injuries per million working hours) was 5.1 in 2005, which is a decrease from 5.9 in 2004. The lost-time injury frequency (the number of total recordable injuries causing loss of time at work per million working hours) was 1.5 in 2005 against 2.3 in 2004. Our safety indicators include both Statoil employees and contractors working for Statoil.
Statoil has been a leader in developing a systematic approach to reviewing and monitoring the condition of technical safety barriers. The developed methodology is in compliance with the latest regulations issued by the Petroleum Safety Authority in Norway. When a new facility is operational a full review of technical safety barriers is undertaken. In subsequent years, we perform annual reviews on all plants and facilities that cover approximately 20 per cent of the applicable safety barriers. In this way a full review is effectively completed over a rolling five year period.
Within the health and working environment area, our principal objective is to secure a sound, challenging and rewarding working environment for the benefit of both the employee and Statoil. The corporate indicator within the health and working environment is the percentage of sickness absences, which, for the Statoil group, came to 3.5 per cent in 2005, against 3.2 per cent in 2004 (including self certification and medical certificate of sickness). The general level in Norway averaged 6.7 per cent according to official statistics for the first three quarters of 2005. We also carry out regular health and working environment and organization surveys to track our working environment.
Two penalties were incurred in 2005 for violations within the HSE area. A penalty of NOK 80 million was imposed as a result of the Snorre A gas leakage incident. Another penalty of NOK 1.5 million was imposed as a result of a fire at the Mongstad refinery in 2004.
Technology, Research and Development
Background
The success of our business is closely related to our access to and application of advanced technological expertise, which has largely been developed through exploration and production activities on the NCS. Many major challenges have been addressed, not least operating under the harsh weather and environmentally sensitive conditions in the Norwegian Sea, transporting oil and gas across the deep Norwegian trench, and draining complex petroleum reservoirs characterized by high pressures and high temperatures.
The greater majority of Statoil’s technology needs are met by the Technology & Projects business area (T&P), which includes among others a research and development (R&D) department of about 300 staff. The department is primarily based at the group’s research center in Trondheim, although some of its activities are also carried out in Stavanger and at K-lab (Statoil’s Gas Metering and Technology Laboratory at Kårstø).
R&D expenditure amounted to NOK 1,066 million in 2005, NOK 1,027 million in 2004 and NOK 1,004 million in 2003, part of which was financed by partners of Statoil operated activities. When these figures are expressed as a fraction of annual production volumes, Statoil emerges as a leading R&D investor in the petroleum industry. However, in absolute terms our annual R&D expenditures are significantly less than several of the major oil and gas companies with whom we compete. Even so, we are recognized as a ‘technology company’ that continues to deliver innovative solutions.
Our long-term technology strategy is focused on meeting the following business challenges and improving our competitiveness:
• Increasing the value of existing business and securing platforms for further growth;
• Preparing for operations in new environments (the Arctic, deep-water, heavy oil); and
• Developing platforms for future business.
The five areas where we intend to concentrate further technological development are described below.
Environmental technologies: Statoil has developed the Environmental Impact Factor (EIF) methodology to assess potential harm to the environment of discharges to the sea. The methodology is also being extended to discharges from drilling operations, onshore facilities and emissions to air. Statoil has also developed a strategy for carbon dioxide (CO2) capture and long-term storage – the Sleipner East field being the only offshore example so far where large volumes of CO2 are injected into saline aquifers below ground. The potential for using CO2 to improve offshore oil recovery using industrial sources is also under investigation.
We are also in the planning stages of developing a Hydrogen Technology Research Centre in Trondheim with our partners Statkraft and Det Norske Veritas. The facility will be used to develop processes for the reforming of water and natural gas to hydrogen that may result in zero emissions.
Exploration technology: Statoil’s exploration technology has largely been developed through NCS operations, but is now being applied to different geological settings in our international operations. Statoil intends to continue to pursue improvements in exploration technology in order to compete more effectively with other international oil and gas companies.
Our commercialized electromagnetic seabed logging technique to identify the presence of hydrocarbons prior to drilling has been extensively tested and used in prospect evaluation (and may be extended for onshore application in the future). We also intend to further develop and operationalize our petroleum systems analysis concept, which suggests that most of the world’s hydrocarbons occur in reservoirs within a single, definable temperature zone. The fusion of advanced geoscientific knowledge and approaches is increasingly being pursued to improve subsurface imaging and better predict rock types and fluids, while clean drilling technologies are being developed to permit exploration in environmentally sensitive areas.
Reservoir management: Statoil’s success in improved oil recovery from NCS reservoirs has been due to the merger of our capabilities in geological reservoir characterization, reservoir simulation and modeling, time-lapse seismic (4D), recovery processes, and drilling and well production technology. Two current R&D projects - tail production and subsea increased oil recovery - have been designed to assist Statoil in achieving increased average recovery for declining, platform-based fields and subsea fields.
Four technologies are regarded as key enablers in this process: (i) integrated operations, involving onshore operation centers and the integration of real-time data related to reservoir performance and drilling; (ii) advanced and effective well construction (including smart well technologies, through tubing drilling and light well intervention); (iii) improved reservoir characterization and monitoring using the latest ocean bottom and well seismic techniques; and (iv) the development of advanced recovery processes, including those for increasing the recovery of heavy oil.
Subsea field development: We have significant experience with platform-based production systems and are one of the world’s largest subsea field operators with over 280 subsea wells. We are also engaged in flow assurance, especially long-distance multiphase flow (e.g., Snøhvit), and expect to make significant progress in subsea processing technology. Our expertise and capabilities have been developed in close cooperation with Norwegian subsea technology suppliers and the use of proprietary experimental facilities.
Recent advances include the completion of an extensive qualification program for a subsea separation, boosting and injection (SSBI) system for the North Sea Tordis field to increase oil recovery and the culmination of several research and specialist technical service projects when the high pressure/high temperature Kristin field came on stream in 2005. The latter involves the direct heating of pipelines to prevent the formation of flow-blocking gas hydrates, the implementation of a new steel corrosion protection system, and the qualification of flow line materials and flexible risers. Work is also progressing on the remote operation of the Tyrihans field and the installation of an untreated subsea seawater injection system to boost recovery.
Gas chain technologies: We also have significant experience in gas pipeline transport, having been the original developer and operator of the world’s largest submarine gas trunk line system, and presently serve as a TSP for Gassco. Statoil has been involved in commercial gas conversion since 1997 when methanol production started at the Tjeldbergodden plant. Two other gas conversion initiatives that have been the subject of significant research and development are the anticipated delivery of LNG from the Snøhvit field in the Barents Sea and the proprietary Fischer-Tropsch gas-to-liquids (GTL) technology, which is currently undergoing tests to determine its commercial viability. Work is now proceeding on the development and optimization of a floating LNG concept through an alliance with Linde and Aker Kværner.
A diver-less remote hot tapping system has been manufactured, tested and qualified for use in water depths of up to 1000 meters during the first phase of a joint industry project involving Statoil, Gassco and Norsk Hydro. This enables the addition of branch lines via pre-installed T-junctions while the parent pipeline is transporting gas under full pressure. The second phase of the project is aimed at retrofitting T-junctions and extending the operational water depth to 2000 meters.
Regulation
Introduction
The principal Norwegian legislation applying to petroleum activities in Norway and on the NCS is currently the Norwegian Petroleum Act of November 29, 1996, and a number of regulations promulgated thereunder, as well as the Petroleum Taxation Act of June 13, 1975. The Petroleum Act states the principle that the Norwegian State is the owner of all subsea petroleum on the NCS, that the exclusive right to resource management is vested in the Norwegian State and that the Norwegian State alone is authorized to award licenses concerning the petroleum activities.
Under the Petroleum Act, the Norwegian Ministry of Petroleum and Energy is responsible for resource management and for administering petroleum activities on the NCS. The main task of the Ministry of Petroleum and Energy is to ensure that petroleum activities are conducted in accordance with the applicable legislation, the policies adopted by the Storting, and relevant decisions of the Norwegian State. The Ministry of Petroleum and Energy primarily implements petroleum policy through its power to administer the award of licenses and approve operators’ field and pipeline development plans, as well as petroleum transport and gas sales contracts. Only those plans that conform to the policies and regulations set by the Storting are approved. As set forth in the Petroleum Act, if a plan involves an important principle or will have a significant economic or social impact, it must also be submitted to the Storting for acceptance before being approved by the Ministry of Petroleum and Energy.
We are not required to submit any decisions relating to our operations to the Storting. However, the Storting’s role with respect to major policy issues in the petroleum sector may affect us in two ways: first, when the Norwegian State acts in the capacity as the majority owner of our shares and second, when the Norwegian State acts in its capacity as regulator:
• The Norwegian State’s shareholding in Statoil is managed by the Ministry of Petroleum and Energy. The Ministry of Petroleum and Energy will normally determine how the Norwegian State will vote its shares on proposals submitted to general meetings of the shareholders. However, in certain exceptional cases, it may be necessary for the Norwegian State to seek approval from the Storting before voting on a certain proposal. This will normally be the case if we issue additional shares and such issuance would significantly dilute the Norwegian State’s holding, or if such issuance would require a capital contribution from the Norwegian State in excess of government mandates.
• The Norwegian State exercises important regulatory powers over us, as well as over other companies and corporations. As part of our business, we, or the partnerships to which we are a party, frequently need to apply for licenses and other approvals of various types from the Norwegian State. In respect of certain important applications, such as approvals of major plans for operation and development of fields, the Ministry of Petroleum and Energy must obtain the consent of the Storting before it can approve our or the relevant partnership’s application. This may take additional time and affect the content of the decision.
Although Norway is not a member of the European Union, or EU, it is a member of the European Free Trade Association (EFTA). The EU and its member states have entered into the Agreement on the European Economic Area, referred to as the EEA Agreement, with the members of EFTA (except Switzerland).
The EEA Agreement makes certain provisions of EU law binding as between the states of the EU and the EFTA states, and also as between the EFTA states themselves. An increasing volume of regulation affecting us is adopted within the EU and is then applied to Norway under the EEA Agreement. As a Norwegian company operating both within EFTA and the EU, our business activities are regulated by both EU law and EEA law to the extent that EU law has been accepted into EEA law under the EEA Agreement.
The Norwegian Licensing System
The most important type of license awarded under the Petroleum Act is the production license. The Ministry of Petroleum and Energy holds executive discretionary power to award a production license and to determine the terms of that license. In exercising this power, the Ministry of Petroleum and Energy is obliged to implement the policy and objectives of the relevant Storting reports. The Government is not entitled to award a license in an area until the Storting has decided to open the area in question for exploration. A company refusing to abide by the terms of the Ministry of Petroleum and Energy’s decision, the Petroleum Act or the license conditions may face severe consequences, including a refusal by the Ministry of Petroleum and Energy to grant a production license or the revocation of a license already granted.
A production license grants the holders an exclusive right to explore for and produce petroleum within a specified geographical area. The licensees become the owners of the petroleum produced from the field covered by the license. Notwithstanding the exclusive rights granted under a production license, the Ministry of Petroleum and Energy has the power to, in exceptional cases, permit third parties to carry out exploration in the area covered by a production license. For a list of our shares in production licenses, see –Business Overview–Operations–Exploration and Production Norway above.
Production licenses are normally awarded through licensing rounds. The first licensing round for NCS production licenses was announced in 1965. The award of the first licenses covered areas in the North Sea. Over the years the award of licenses has moved northwards and covers areas both in the Norwegian Sea and in the Barents Sea. In recent years, the principal licensing rounds have mainly included licenses in the Norwegian Sea. From 2003, the Norwegian government changed its policy on mature areas and introduced a scheme for award of production licenses named “Award in Predefined Areas” (APA) in mature parts of the Norwegian Continental Shelf. The award of licenses in the predefined areas has taken place every year since 2003. The Ministry of Petroleum and Energy has, in a report to the Storting, announced that this policy will continue.
Traditionally, the Norwegian State only accepted license applications from individual companies, and, therefore, companies were not able to choose their partners in an individual block. In recent years, however, the Norwegian State has, to a larger degree, permitted group applications, enabling us to choose our exploration and development partners.
Production licenses are awarded to joint ventures consisting of several companies. The members of the joint venture are jointly and severally responsible to the Norwegian State for obligations arising from petroleum operations carried out under the license. Once a production license is awarded, the licensees are required to enter into a joint operating agreement and an accounting agreement which regulate the relationship between the partners. The Ministry of Petroleum and Energy decides the form of the joint operating agreements and accounting agreements.
The governing body of the joint venture is the management committee. Each member is entitled to one seat on the management committee. The management committee’s tasks are set out in the joint operating agreement and include setting guidelines for the operator of the field, exercising control over the activities of the operator, and making decisions on the activities of the joint venture. Votes in the management committee are counted by a combination of the number of members in the joint venture and their ownership interest. The number of votes required to make a decision varies from license to license, but a decision is normally reached when a certain number of the members and a percentage of the ownership interests, specified individually in each license, have voted in favor of a proposal. The voting rules are structured so that a licensee holding more than 50 per cent of a license normally cannot vote through a proposal on its own, but will need the support of one or more of the other licensees. I n licenses awarded since 1996 where the SDFI holds an interest, the Norwegian State, acting through the SDFI management company, may veto decisions made by the joint venture management committee, which, in the opinion of the Norwegian State, would not be in compliance with the obligations of the license as to the Norwegian State’s exploitation policies or financial interests. This veto right has never been used.
Under the joint operating agreements covering licenses awarded prior to 1996, the management company that supervises the Norwegian State’s SDFI interest, Petoro AS, has the power, with certain exceptions, to make decisions unilaterally in matters which are assumed to be of political or principal importance, or which may have significant social or socio-economic consequences, if Petoro AS is acting under the direction of its shareholder. Prior to the establishment of the SDFI management company, Statoil held this right, which was exercised three times, most recently in 1988. In autumn 2002, the Storting began to allow individual license groups to substitute this special voting rule for the SDFI with a veto rule similar to the veto rules which have applied to licenses awarded since 1996. Such a substitution is subject to approval from the Ministry of Petroleum and Energy.
The day-to-day management of a field is the responsibility of an operator appointed by the Ministry of Petroleum and Energy. The operator is in practice always a member of the joint venture holding the production license, although this is not legally required. The terms of engagement of the operator are set out in the joint operating agreement. Under the joint operating agreement, an operator may normally terminate its engagement upon six months’ notice. The management committee may, however, with the consent of the Ministry of Petroleum and Energy, instruct the operator to continue performing its duties until a new operator has been appointed. The management committee can terminate the operator’s engagement upon six months’ notice on an affirmative vote by all members of the management committee other than the operator. A change of operator requires the consent of the Ministry of Petroleum and Energy. In special cases the Ministry of Petroleum and Energy can order a change of operator.
Licensees are required to submit a plan for development and operation, or PDO, to the Ministry of Petroleum and Energy for approval. In respect of fields of a certain size, the Storting has to accept the PDO before it is formally approved by the Ministry of Petroleum and Energy. Until the PDO has been approved by the Ministry of Petroleum and Energy, the licensees cannot, without the prior consent of the Ministry of Petroleum and Energy, undertake material contractual obligations or commence construction work.
Production licenses are normally awarded for an initial exploration period which is typically six years, but which can be either for a shorter period or for a maximum period of ten years. During this exploration period the licensees must meet a specified work obligation set out in the license. The work obligation will typically include seismic surveying and/or exploration drilling. If the licensees fulfill the obligations set out in the production license, they are entitled to require that the license be prolonged for a period specified at the time when the license is awarded, typically 30 years. The right to prolong the license does not apply as a main rule to the whole of the geographical area covered by the initial license, but only to a percentage, typically 50 per cent. The size of the area which must be relinquished is determined at the time the license is awarded. In special cases, the Ministry of Petroleum and Energy may extend the duration of a production license.
If natural resources other than petroleum are discovered in the area covered by a production license, the Norwegian State may decide to delay petroleum production in the area. If such a delay is imposed, the licensees are, with certain exceptions, entitled to a corresponding extension of the period of the license. To date, such a delay has never been imposed.
The Norwegian State may, if important public interests are at stake, direct us and other licensees on the NCS to reduce production of petroleum. From July 15, 1987 until the end of 1989, licensees were directed to curtail oil production by 7.5 per cent. Between January 1, 1990 and June 30, 1990, licensees were directed to curtail oil production by 5 per cent. In 1998, the Norwegian State resolved to reduce Norwegian oil production by about 3 per cent, or 100 mbbls per day. In March 1999, the Norwegian State decided to increase the reduction to 200 mbbls per day. In the second quarter of 2000, the reduction was brought back to 100 mbbls per day. On July 1, 2000, this restriction was removed. By a royal decree of December 19, 2001, the Norwegian government decided that Norwegian oil production should be reduced by 150 mbbls per day from January 1, 2002 until June 30, 2002. This amounted to roughly a 5 per cent reduction in output.
Licensees may buy or sell interests in production licenses subject to the consent of the Ministry of Petroleum and Energy and the approval of the Ministry of Finance of a corresponding tax treatment position. The Ministry of Petroleum and Energy must also approve indirect transfers of interest in a license, including changes in the ownership of a licensee, if they result in a third party obtaining a decisive influence over the licensee. There are in most licenses no pre-emption rights in favor of the other licensees. The SDFI, or the Norwegian State, as appropriate, however, still holds pre-emption rights in all licenses.
A license from the Ministry of Petroleum and Energy is also required in order to establish facilities for transport and utilization of petroleum. When applying for such licenses, the owners, which are in practice licensees under a production license, must prepare a plan for installation and operation. Licenses to establish facilities for transport and utilization of petroleum will normally be awarded subject to certain conditions. Typically, these conditions require the facility owners to enter into a participants’ agreement. The ownership of most facilities for transport and utilization of petroleum in Norway and on the NCS are organized as a joint venture of a group of license holders, and the participants’ agreements are similar to the joint operating agreements entered into among the members of joint ventures holding production licenses.
Licensees are required to prepare a decommissioning plan before a production license or a license to establish and use facilities for transportation and utilization of petroleum expires or is relinquished, or the use of a facility ceases. The decommissioning plan must be submitted to the Ministry of Petroleum and Energy no sooner than five and no later than two years prior to the expiry of the license or the cessation of the use of the facility, and must include a proposal for the disposal of facilities on the field. On the basis of the decommissioning plan, the Ministry of Petroleum and Energy makes a decision as to the disposal of the facilities.
The Norwegian State is entitled to take over the fixed facilities of the licensees when a production license expires, is relinquished or revoked. In respect of facilities on the NCS, the Norwegian State decides whether any compensation will be payable for facilities thus taken over. If the Norwegian State should choose to take over onshore facilities, the ordinary rules of compensation in connection with expropriation of private property apply.
Licenses for the establishment of facilities for transport and utilization of petroleum typically include a clause whereby the Norwegian State can require that the facilities be transferred to it free of charge at the expiration of the license period.
The Norwegian Gas Sales Organization
Until recently, gas sales contracts with buyers for the supply of Norwegian gas were required by Norwegian authorities to be concluded with the Gas Negotiation Committee, known as the Gassforhandlingsutvalget or GFU.
The structural changes taking place in the European gas market prompted the Norwegian State to consider whether changes to the gas resource management system on the NCS could contribute to further enhancing the efficiency for Norwegian gas producers. Accordingly, the Norwegian State, by royal decree dated June 1, 2001, abandoned the GFU system and put in place a system whereby the individual licensees can manage the disposal of their own gas. Necessary adjustments in legislation, license agreements and other existing contracts in order to implement the new system were finalized during 2002.
From January 1, 2003 the ownership of the Zeepipe, Franpipe, Europipe II, Åsgard Transport, Statpipe, Oseberg Gas Transport and Vesterled joint ventures and Norpipe AS was transferred to a new joint venture called Gassled. As from February 1, 2004, the Kollsnes Plant has also been included in Gassled.
Together with the approval of Gassled, Norwegian authorities have by a royal decree of December 20, 2002 issued regulations for access to and tariffs for capacity in the upstream gas transportation system. There are three main considerations behind the regulations. Firstly it shall, together with the law adopted by the Storting in June 2002, implement the Gas Directive of the European Union. Further, it shall establish a system for access to the upstream gas transportation system that is compatible with company based gas sales from the Norwegian Continental Shelf. Thirdly, it provided for the new ownership structure of the upstream gas transportation system (Gassled).
Parts of the regulations have a general application and parts – including the tariffs – are applicable only to the upstream gas transportation system owned by the Gassled joint venture.
The regulations set the main principles for access to the upstream gas transportation system. The access regime consists of a regulated primary market where the right to book free capacity, in accordance with regulations, is allocated to users with a duly substantiated reasonable need for transportation of natural gas. Further, the access regime consists of a secondary market where the capacity can be transferred between the users after the allocation in the primary market if the need for transportation changes.
The capacity in the primary market will be released and booked through Gassco AS on the internet. Spare capacity will be released for pre-defined time periods at announced points in time and with specific time limits for reservations. If the reservations exceed the spare capacity, the spare capacity will be allocated based on a distribution formula. However, consideration shall in case of spare capacity first be given to the owners' duly substantiated needs for capacity, which is limited to twice the owner's equity interest in the upstream pipeline network in question.
Based on authorization given under the regulations, tariffs for use of capacity in Gassled are determined by the Ministry of Petroleum and Energy. The Ministry’s policy for determining the tariffs is to avoid excessive returns being created on the capital invested in the transportation system, allowing the return on the Norwegian petroleum activity to be taken out on the fields instead of in the transportation systems. The tariffs are to be paid for booked capacity and not in respect of the actually transported volume.
HSE Regulation
Petroleum operations in Norway are subject to extensive regulation with regard to health, safety and the environment, or HSE. Under the Petroleum Act, which is in this respect administered by the Ministry of Labor and Government Administration, all petroleum operations must be conducted in compliance with a reasonable standard of care, taking into consideration the safety of employees, the environment and the economic values represented by installations and vessels. The Petroleum Act specifically requires that petroleum operations be carried out in such a manner that a high level of safety is maintained and developed in accordance with technological developments.
Licensees and other persons engaged in petroleum operations are required to maintain at all times a plan to deal with emergency situations. During an emergency, the Ministry of Labor and Government Administration may decide that other parties should provide the necessary resources, or otherwise adopt measures to obtain the necessary resources, to deal with the emergency for the account of the licensees.
The Petroleum Safety Authority Norway (PSA) was established on January 1, 2004. The PSA has the regulatory responsibility for safety, emergency preparedness and the working environment for all petroleum-related activities. This responsibility was transferred from the Norwegian Petroleum Directorate (NPD) effective January 1, 2004. With the establishment of the PSA, regulations relating to HSE in petroleum activities continue with the PSA as the responsible authority. In addition, the PSA's sphere of responsibility has been expanded to include supervision of safety, emergency preparedness and the working environment at the petroleum facilities and connected pipeline systems on land such as Kårstø, Kollsnes, Tjeldbergodden, Mongstad, and Melkøya, as well as potential future integrated petroleum facilities.
In our capacity as a holder of licenses under the Petroleum Act, we are subject to strict statutory liability in respect of losses or damages suffered as a result of pollution caused by spills or discharges of petroleum from petroleum facilities covered by any of our licenses. This means that anyone who suffers losses or damages as a result of pollution caused by any of our NCS license areas can claim compensation from us without needing to demonstrate that the damage is due to any fault on our part. If the pollution is caused by a force majeure event, a Norwegian court may reduce the level of damages to the extent it considers reasonable.
Taxation of Statoil
We are subject to ordinary Norwegian corporate income tax as well as to a special petroleum tax relating to our offshore activities. We are also subject to a special carbon dioxide emissions tax. Under our production licenses we are obligated to pay royalties and an area fee to the Norwegian State. Set forth below is a summary of certain key aspects of the Norwegian tax rules that apply to our operations.
Corporate income tax. Our profits, both from offshore oil and natural gas activities and from onshore activities, are subject to Norwegian corporate income tax. The corporate income tax rate is currently 28 per cent. Our profits are computed in accordance with ordinary Norwegian corporate income tax rules, subject to certain modifications that apply to companies engaged in petroleum operations. Gross revenue from oil production and the value of lifted stocks of oil are determined on the basis of norm prices which are decided on a monthly basis by the Petroleum Price Board, a body whose members are appointed by the Ministry of Petroleum and Energy, and published quarterly. The Petroleum Taxation Act provides that the norm prices shall correspond to the prices that could have been obtained in case of a sale of petroleum between independent parties in a free market. When adopting norm prices, the Petroleum Price Board takes into consideration a number of factors, including spot mark et prices and contract prices within the industry.
The maximum rate for depreciation of development costs related to offshore production installations and pipelines is 16 2/3 per cent per year. The depreciation starts when the expense is incurred. Exploration costs may be deducted in the year in which they are incurred. Most financial items are allocated to onshore and offshore activities in proportion to the remaining tax balances of assets related to onshore and offshore activities, respectively. There is an adjustment factor allowing companies with an equity ratio of more than 0.2 to allocate a higher share of net financial items to the offshore tax regime.
Any NCS losses may be carried forward indefinitely against subsequent income earned. Any onshore losses may be carried forward for 10 years. From 2006 onshore losses may be carried forward indefinitely. Fifty per cent of losses relating to activity conducted onshore in Norway may be deducted from NCS income subject to the 28 per cent tax rate. Losses from foreign activities may not be deducted against NCS income. Losses from offshore activities are fully deductible against onshore income.
By use of group contributions between Norwegian companies in which we hold more than 90 per cent of the shares and the votes, tax losses and taxable income can, to a great extent, be offset. Group distributions are not deductible in our offshore income.
Since January 1, 2004, dividends received have not been subject to tax in Norway. Exemptions exist for dividends from low-tax countries or portfolio investments outside the EEA.
Since March 26, 2004, capital gains on realization of shares have not been taxable and losses have not been deductible. Exemptions exist for shares held in companies domiciled in low-tax countries or portfolio investments outside the EEA.
Special petroleum tax. A special petroleum tax is levied on profits derived from petroleum production and pipeline transportation on the NCS. The special petroleum tax is currently levied at a rate of 50 per cent. The special tax is applied to relevant income in addition to the standard 28 per cent income tax, resulting in a 78 per cent marginal tax rate on income subject to petroleum tax. The basis for computing the special petroleum tax is the same as for income subject to ordinary corporate income tax, except that onshore losses are not deductible against the special petroleum tax, and a tax-free allowance, or uplift, is granted at a rate of 7.5 per cent per year. The uplift is computed on the basis of the original capitalized cost of offshore production installations. The uplift may be deducted from taxable income for a period of four years, starting in the year in which the capital expenditures are incurred. Unused uplift may be carried forward indefinitely. Special provisio ns apply to investments made prior to 1992.
Abandonment costs. In June 2003 the taxation treatment of abandonment costs was changed from a system with Government grant to a system with tax deduction. Abandonment costs incurred after June 19, 2003 can be deducted as operating expenditures. Provisions for abandonment costs are not tax deductible.
Carbon dioxide emissions tax. A special CO2 emissions tax applies to petroleum activities on the NCS. The tax is NOK 0.78 in year 2005 and NOK 0.79 in year 2006 per standard cubic meter of gas burned or directly released, and per liter of oil burned.
Area fee. After the expiration of the initial exploration period, the holders of production licenses are required to pay an area fee. The amount of the area fee is set out in regulations promulgated under the Petroleum Act. In respect of most of the production licenses, the initial annual area fee is currently NOK 7,000 per square kilometer. The annual area fee is increased yearly by NOK 7,000 until it reaches NOK 70,000 per square kilometer.
Royalty. Through December 31, 2005, we and other oil companies operating on the NCS had an obligation to pay a royalty to the Norwegian State for oil produced on fields for which a plan for development and operation was approved prior to January 1, 1986. The royalty varied from 8 per cent to 16 per cent of the gross production value, and increased with the level of production. The royalty was paid in kind. No royalty is charged on natural gas or NGL production.
The obligation to pay royalty applied only to the Gullfaks and Oseberg fields in 2005. The obligation to pay royalty on the NCS was abolished completely at the end of 2005.
EU Regulation
EU Gas Directive
Fundamental changes continue to occur in the organization and operation of the European gas market, with the objective of opening up national markets to competition and integrating them into a single internal market for natural gas. It is difficult to predict the effect of liberalization measures on the evolution of gas prices, but the main objective of the single gas market is to bring greater choice and reduced prices for customers through increased competition.
The EU Gas Directive was included in the EEA Agreement in June 2002 and was incorporated into Norwegian legislation in 2002.
On June 26, 2003, the EU approved a new Gas Directive, Directive 2003/55/EC. The Directive is not yet incorporated into Norwegian legislation.
The new Directive accelerates the requirements for market opening, meaning that both large users and households will be free to choose their supplier earlier than previously anticipated. Large users have been free to choose their supplier since July 2004, and households will be free to do so beginning in July 2007.
COMPETITION
In the oil and gas industry there is intense competition for customers, production licenses, operatorships, capital and experienced human resources. In recent years, the oil and gas industry has experienced consolidation, as well as increased deregulation and integration in strategic markets. Statoil competes with major integrated oil and gas companies, as well as independent and government-owned companies for the acquisition of assets and licenses for the exploration, development and production of oil and gas, and for the refining, marketing and trading of crude oil, natural gas and related products. Key factors affecting competition in the oil and gas industry are oil and gas prices, demand, the cost of exploration and production, global production levels, alternative fuels and governmental and environmental regulations. Statoil’s ability to remain competitive will require, among other things, management’s continued focus on reducing unit costs and improving efficiency, maintaining long-term growth in our reserves and production through continued technological innovation and our ability to capture international opportunities in areas where our competitors may also be actively pursuing exploration and development opportunities. The company believes that it is in a position to compete effectively in each of its business segments.
Organizational Structure
The following table sets forth our significant subsidiaries owned directly by the parent company in alphabetical order, equity interest and the subsidiaries’ country of incorporation. In all cases our voting interest is equivalent to our equity interest.
Subsidiary | Equity interest in % | Country of incorporation |
AS Eesti Statoil | 100 | Estonia |
Latvija Statoil SIA | 100 | Latvia |
Offtect Invest AS | 100 | Norway |
Mongstad Refining DA | 79 | Norway |
Mongstad Terminal DA | 65 | Norway |
SDS Holding AS | 100 | Norway |
Statholding AS | 100 | Norway |
Statoil AB | 100 | Sweden |
Statoil Angola AS | 100 | Norway |
Statoil Angola Block 15 AS | 100 | Norway |
Statoil Angola Block 17 AS | 100 | Norway |
Statoil Apsheron AS | 100 | Norway |
Statoil Asia Pacific Pte. Ltd | 100 | Singapore |
Statoil Azerbaijan Alov AS | 100 | Norway |
Statoil Azerbaijan AS | 100 | Norway |
Statoil BTC Finance AS | 100 | Norway |
Statoil Coordination Center N.V. | 100 | Belgium |
Statoil Danmark A/S | 100 | Denmark |
Statoil Deutschland GmbH | 100 | Germany |
Statoil do Brasil Ltda | 100 | Brazil |
Statoil Exploration Ireland Ltd | 100 | Ireland |
Statoil Forsikring AS | 100 | Norway |
Statoil Hassi Mouina AS | 100 | Norway |
Statoil Innovation AS | 100 | Norway |
Statoil Iran AS | 100 | Norway |
Statoil Ireland Ltd | 100 | Ireland |
Statoil Kazakstan AS | 100 | Norway |
Statoil Latin America AS | 100 | Norway |
Statoil Marine Holding AS | 100 | Norway |
Statoil Metanol ANS | 82 | Norway |
Statoil Nigeria AS | 100 | Norway |
Statoil Nigeria Deep Water AS | 100 | Norway |
Statoil Nigeria Outer Shelf AS | 100 | Norway |
Statoil Norge AS | 100 | Norway |
Statoil North Africa Gas AS | 100 | Norway |
Statoil North Africa Oil AS | 100 | Norway |
Statoil North America Inc. | 100 | United States of America |
Statoil Orient Inc AG | 100 | Switzerland |
Statoil Pernis Invest AS | 100 | Norway |
Statoil Plataforma Deltana | 100 | Norway |
Statoil Polen Invest AS | 100 | Norway |
Statoil Russia AS | 100 | Norway |
Statoil Sincor AS | 100 | Norway |
Statoil SP Gas AS | 100 | Norway |
Statoil UK Ltd | 100 | Great Britain |
Statoil Venezuela AS | 100 | Norway |
Tjeldbergodden Luftgassfabrikk DA | 51 | Norway |
UAB Lietuva Statoil | 100 | Lithuania |
Property, Plant and Equipment
Our principal executive offices are located at Forusbeen 50, N-4035, Stavanger, Norway, and comprise approximately 103,000 square meters of office space, and are owned by Statoil.We have interests in real estate in numerous countries throughout the world, but no one individual property is significant to us as a whole. We have no significant ongoing construction projects or plans to add new office space. See Item 4—Information on the Company for a description of our significant reserves and sources of oil and natural gas.
Item 5 Operating and Financial Review and Prospects
You should read the following discussion of our financial condition and results of operations in connection with our audited financial statements and relevant notes and the other information contained elsewhere in this Annual Report on Form 20-F.
Operating Results
Overview of Our Results of Operations
In the year ended December 31, 2005, we had total revenues of NOK 393.3 billion and net income of NOK 30.7 billion. In the year ended December 31, 2005, we produced 256 million barrels of oil and 27.0 bcm (953 bcf) of natural gas, resulting in a total production of 426 million boe. Our proved reserves as of December 31, 2005 consisted of 1,761 mmbbls of crude oil and NGL and 403 bcm (14.2 tcf) of natural gas, resulting in a total of 4,295 mmboe.
We divide our operations into the following four business segments:
• Exploration and Production Norway (E&P Norway), which includes our exploration, development and production operations relating to crude oil and natural gas on the NCS;
• International Exploration and Production (International E&P), which includes all of our exploration, development and production operations relating to crude oil and natural gas outside of Norway;
• Natural Gas, which is responsible for the processing, transport and sales of natural gas from our upstream operations on the NCS, from our upstream operations in the UK, as well as third party natural gas and sales of natural gas on behalf of SDFI. Natural Gas is also responsible for certain of our international mid- and downstream activities;
• Manufacturing and Marketing, which comprises downstream activities including sales and trading of crude oil, NGL and refined products, refining, methanol production and sales, retail and industrial marketing. Manufacturing and Marketing sells Statoil equity oil volumes, third party oil volumes and SDFI oil volumes.
Portfolio changes. We engage in portfolio management in order to optimize the value of our asset portfolio. This has resulted in the restructuring of our asset portfolio both in Norway and internationally. The list below summarizes important acquisitions and dispositions that have taken place in recent years. See Item 4–Information on the Company–Business Overview under the description of each business segment for further details.
• Acquisition of EnCana’s deepwater assets in Gulf of Mexico in 2005
• Acquisition of ownership interests in the two Algerian fields In Salah and In Amenas in 2003 (approved by Algerian authorities in 2004).
• Sale of our holding of 50 per cent of the shares in the petrochemical company Borealis in 2005.
• Several ownership interest adjustments, primarily on the NCS in 2005, 2004 and 2003.
• Acquisition of the 50 per cent share of Statoil Detaljhandel Skandinavia (SDS) from ICA/Ahold in 2004.
• Sale of the shipping activity in Navion in 2003, and the subsequent sales of our 50 per cent share in the shipowning company Partsrederiet West Navigator DA and the multi-purpose vessel MST Odin in 2004.
• Sale of our shares in the German natural gas merchant company VNG (Verbundnetz Gas AG) in 2004.
Factors Affecting Our Results of Operations
Our results of operations substantially depend on:
• the level of crude oil and natural gas contract prices;
• trends in the exchange rate between the U.S. dollar, in which the trading price of crude oil is generally stated and to which natural gas prices are frequently related, and NOK, in which our accounts are reported and a substantial portion of our costs are incurred; and
• our oil and natural gas production volumes, which in turn depend on entitlement volumes under PSAs and available petroleum reserves, and our own as well as our partners’ expertise and co-operation in recovering oil and natural gas from those reserves.
Our results will also be affected by trends in the international oil industry, including:
• possible actions by the governments and other regulatory authorities in the jurisdictions where we operate, or possible or continued actions by members of the Organization of Petroleum Exporting Countries (OPEC) affecting price levels and volumes;
• refining margins;
• increasing competition for exploration opportunities and operatorships; and
• deregulation of the natural gas markets, which may cause substantial changes to the existing market structures and to the overall level and volatility of prices.
The following table shows the yearly average quoted Brent Blend crude oil prices, natural gas contract prices, FCC margins and NOK/USD exchange rates for 2005, 2004 and 2003.
Yearly average | 2005 | 2004 | 2003 |
Crude oil (USD/bbl Brent Blend) | 54.5 | 38.3 | 28.8 |
Natural gas (NOK per scm)(1) | 1.45 | 1.10 | 1.02 |
FCC margins (USD/bbl)(2) | 7.9 | 6.4 | 4.4 |
NOK/USD average daily exchange rate | 6.45 | 6.74 | 7.08 |
(1) From the Norwegian Continental Shelf.
(2) Refining margin.
The following table illustrates how certain changes in the crude oil price, natural gas contract prices, the fluid catalytic cracking (FCC)(refining) margins and the NOK/USD exchange rate, if sustained for the full year, may impact our Income before financial items, income taxes and minority interest and our Net income assuming activity at levels achieved in 2005.
Sensitivities on 2005 results
(in NOK billion) | Change in Income before financial items, income taxes and minority interest | Change in Net income |
Oil price (+/- USD 1/bbl) | 1.6 | 0.5 |
Gas price NCS (+/- NOK 0.1/scm) | 2.5 | 0.5 |
Refining margins (+/- USD 1/bbl) | 0.8 | 0.5 |
U.S. dollar exchange rate impact on revenues and costs (+/- NOK 0.50) | 6.3 | 2.0 |
U.S. dollar exchange rate impact on financial debt (+/- NOK 0.50)(1) | n/a | 1.3 |
(1) The U.S. dollar exchange rate impact on financial debt has an opposite effect on net income than the U.S. dollar exchange rate impact on revenues and costs.
The sensitivities on our financial results shown in the table above would differ from those that would actually appear in our consolidated financial statements because our consolidated financial statements would also reflect the effect on proved reserves, and consequently on depreciation, depletion and amortization, trading margins in the Natural Gas and Manufacturing and Marketing business segments, our exploration expenditure, development and exploration success rate, inflation, potential tax system changes, and the effect of any hedging programs in place.
Our oil and gas price hedging activities are designed to assist our long-term strategic development and attainment of targets by protecting financial flexibility and cash flow, allowing the company to be able to undertake profitable projects and acquisitions and avoiding forced divestments during periods of adverse market conditions. For the oil price, we entered into a downside protection structure for some of our production, reducing price risk below USD 16 per barrel for 2003. No such protection was entered into for 2004, but in 2004 we bought downside protection for prices below USD 18 per barrel for some of our production for the last three quarters of 2005. Approximately 20 per cent of the refining margin was hedged to reflect our view of the markets for 2005. Mainly due to the increased financial robustness of Statoil and market development, Statoil has not entered into any hedging arrangements for the oil and gas price risk or refining margin risk for 2006 or later.
Fluctuating foreign exchange rates can have a significant impact on our operating results. Our revenues and cash flows are mainly denominated in or driven by U.S. dollars, while our operating expenses and income taxes payable accrue to a large extent in NOK. We seek to manage this currency mismatch by issuing or swapping long-term debt into U.S. dollars. This debt policy is an integrated part of our total risk management program. We are also engaging in foreign currency hedging to cover our non-USD needs, which are primarily in NOK. We manage the risk arising from our interest rate exposures through the use of interest rate derivatives, primarily interest rate swaps, based on a benchmark for the interest reset profile of our long-term debt portfolio. See —Liquidity and Capital Resources—Risk Management and Item 11—Quantitative and Qualitative Disclosures about Market Risk. In general, an increase in the value of the U.S. dollar against the NOK can be expected to increase our reported ear nings. However, because currently our debt outstanding is in U.S. dollars, the benefit to Statoil would be offset in the near term by an increase in the value of our debt, which would be recorded as a financial expense and, accordingly, would adversely affect our net income. A decrease in the exchange rate would have an opposite effect, and hence cause decreased earnings, which would be offset by financial income in the near term. See —Liquidity and Capital Resources—Risk Management and Item 11—Quantitative and Qualitative Disclosures about Market Risk.
Statoil sells the Norwegian State’s share of oil and natural gas production from the Norwegian Continental Shelf (NCS). Amounts payable to the Norwegian State for these purchases are included as Accounts payable - related parties in the consolidated balance sheets. Pricing of the crude oil is based on market reflective prices. NGL prices are based on either achieved prices, market value or market reflective prices.
Statoil is, in its own name, but for the Norwegian State's account and risk, selling the State's natural gas production. This sale, as well as related expenses refunded by the State, is shown net in Statoil's financial statements. Expenses refunded by the State include expenses incurred related to activities and investments necessary to obtain market access and to optimize the profit from the sale of the Norwegian State’s natural gas. For sales of the Norwegian State’s natural gas, both for our own use and to third parties, the payment to the Norwegian State is based on achieved prices, a net back formula or market value. Statoil purchases a small share of the Norwegian State’s gas. For further details see Item 7–Major Shareholders and Related Party Transactions–Major Shareholders–Marketing and Sale of the SDFI’s Oil and Gas.
Total purchases of oil and NGL from the Norwegian State by Statoil amounted to NOK 97,078 million (281 mmboe), NOK 81,487 million (319 mmboe) and NOK 68,479 million (336 mmboe) in 2005, 2004 and 2003, respectively. Purchases of natural gas from the Norwegian State amounted to NOK 262 million, NOK 237 million and NOK 255 million in 2005, 2004 and 2003, respectively. See Item 7—Major Shareholders and Related Party Transactions—Major Shareholders—Marketing and Sale of the SDFI's Oil and Gas.
High oil prices have contributed to considerably higher earnings and profitability in international projects with PSAs than previously anticipated. Under a PSA, the partners are generally entitled to production volumes that cover the development costs and an agreed share of the remaining volumes. When oil prices are high, this means that these projects will move from a phase where earnings cover development costs to a phase where profits are generated at an earlier point in time. In PSA contracts, the higher the oil price as soon as the field is profitable, the smaller the share of production that goes to the partners. The actual effect varies between different agreements and countries. See -Corporate Targets below for a description of the impact of the PSA effect on our ability to achieve our corporate targets.
Up to December 31, 2005, we were required to pay a royalty to the Norwegian State for NCS oil produced from certain fields approved for development prior to January 1, 1986. Oil fields in our portfolio that paid royalty in 2005 were Gullfaks and Oseberg. The fields from which royalty was paid together represented approximately 11 per cent, 13 per cent and 16 per cent of our total NCS production in 2005, 2004 and 2003, respectively. The royalty was paid in kind by delivery of petroleum or purchased at a calculated market price, which varied in 2005 from 1.4 per cent to 1.7 per cent of the total oil production from the fields. We include the costs of purchase and the proceeds from the sale of the royalty oil, which we resell or refine, in our Cost of goods sold and Sales, respectively. Royalty obligations from Gullfaks and Oseberg were abolished at the end of 2005.
In Venezuela we pay a royalty to the Venezuelan State for production from the Sincor field. The royalty is paid in cash. The royalty is calculated based upon the value of the heavy oil production prior to the upgrade to Syncrude. From the commencement of commercial production in March 2002 to September 2004, we paid 1 per cent royalty. Commencing in October 2004, the royalty was increased to 16.7 per cent. As of June 24, 2005, the Venezuelan State increased the royalty payment to 30 per cent for production exceeding 114.5 mboe per day based on total production from the Sincor field. The increase in royalty payments made by Statoil from 2004 to 2005 was due to this increase imposed by the Venezuelan State. See Item 4-Information on the Company-Business Overview-International Exploration and Production-Venezuela.
Historically, our revenues have largely been generated from the production of oil and natural gas from the NCS. Norway imposes a 78 per cent marginal tax rate on income from offshore oil and natural gas activities. See Item 4—Information on the Company—Business Overview—Regulation—Taxation of Statoil—Corporate Income Tax. Our earnings volatility is moderated as a result of the significant amount of our Norwegian offshore income that is subject to a 78 per cent tax rate in profitable periods and the significant tax assets generated by our Norwegian offshore operations in any loss-making periods. A prevailing part of the taxes we pay are paid to the Norwegian State. From January 1, 2004, dividends received are not subject to tax in Norway. Exemptions exist for dividends from low-tax countries or portfolio investments outside the EEA. For details, see Item 4—Information on the Company—Business Overview—Regulation—Taxation of Statoil.
Combined Results of Operations
The following table shows certain income statement data, expressed in each case as a percentage of total revenues.
Consolidated Statements of Income | Year ended December 31, | ||
2005 | 2004 | 2003 | |
Revenues: |
|
|
|
Sales | 99.3% | 99.2% | 99.7% |
Equity in net income of affiliates | 0.3% | 0.4% | 0.2% |
Other income | 0.4% | 0.4% | 0.1% |
Total revenues | 100% | 100% | 100% |
Expenses: |
|
|
|
Cost of goods sold | 59.9% | 61.5% | 60.0% |
Operating expenses | 7.7% | 8.9% | 10.7% |
Selling, general and administrative expenses | 2.0% | 2.1% | 2.2% |
Depreciation, depletion and amortization | 5.4% | 5.7% | 6.5% |
Exploration expense | 0.8% | 0.6% | 1.0% |
Total expenses before financial items | 75.8% | 78.7% | 80.4% |
Income before financial items, other items, income taxes and minority interest | 24.2% | 21.3% | 19.6% |
Years ended December 31, 2005, 2004 and 2003
Sales. Statoil markets and sells the Norwegian State’s share of oil and natural gas production from the NCS. All purchases and sales of SDFI oil production are recorded as Cost of goods sold and Sales, respectively.
All oil received by the Norwegian State as royalty in kind from fields on the NCS is purchased by Statoil. Statoil includes the costs of purchase and proceeds from the sale of this royalty oil in its Cost of goods sold and Sales, respectively.
Our sales revenue totaled NOK 390.5 billion in 2005, compared to NOK 303.8 billion in 2004 and NOK 248.5 billion in 2003.
The 29 per cent increase in sales revenues from 2004 to 2005 was mainly due to a 34 per cent increase in the average oil price measured in NOK and a 31 per cent increase in the realized price of our natural gas sold to the European markets measured in NOK, as well as increased sales of equity natural gas. The oil price of the group is a volume-weighted average of the segment prices of oil and NGL, including a margin for oil trading and sales of NOK 0.70 per boe. The increase in sales revenues was partly offset by the reduction of oil volumes sold, mainly related to a decrease in volumes sold on behalf of SDFI.
The 22 per cent increase in sales revenues from 2003 to 2004 was mainly due to a 25 per cent increase in the average oil price measured in NOK and an 8 per cent increase in the realized price of our natural gas sold to the European markets measured in NOK, as well as increased sales of equity natural gas. The increase in our ownership of SDS to 100 per cent contributed approximately NOK 5 billion in increased sales revenues. Increased prices and higher volumes in the downstream activity also contributed to increased sales revenues in 2004 compared to 2003. The increase in sales revenues was partly offset by the reduction of oil volumes sold, mainly related to a decrease in volumes sold on behalf of SDFI.
Our average daily oil production (lifting) decreased from 712,600 barrels in 2004 to 701,000 barrels in 2005. The 2 per cent decrease in average daily oil production from 2004 to 2005 was primarily due to lower production from declining fields including Statfjord, Gullfaks, Åsgard and Troll oil, as well as reduced production caused by more frequent and larger maintenance turnarounds in 2005 compared with 2004. This reduction was partly offset by increased oil production from several new international fields such as the Central Azeri part of the ACG field and Kizomba B, which came on stream in the first quarter and the third quarter of 2005, respectively, as well as a ramping-up of production from the Kizomba A field, which came on stream in the third quarter of 2004, and increased production from the Lufeng field following the completion of a sidetrack drilling program in the second quarter of 2005. At the end of 2005, we were in an underlift position of approximately 3,000 boe per day comp ared to an underlift position of approximately 12,000 boe per day in 2004.
Our average daily oil production (lifting) decreased from 737,500 barrels in 2003 to 712,600 barrels in 2004. The 3 per cent decrease in average daily oil production from 2003 to 2004 was primarily due to lower production from declining fields including Statfjord, Norne and Lufeng. Some operational difficulties and the well incident at Snorre reduced regularity of production somewhat in 2004 compared to 2003. This reduction was partly offset by production from the Kizomba A field coming on stream in the third quarter of 2004. At the end of 2004, we were in an underlift position of approximately 12,000 boe per day compared to an underlift position of approximately 9,000 boe per day in 2003.
Our natural gas volumes sold of Statoil produced natural gas were 27.0 bcm (953 bcf) in 2005, 22.1 bcm (782 bcf) in 2004 and 19.3 bcm (683 bcf) in 2003. Natural gas volumes increased primarily due to an increase in long-term contracted natural gas volumes to continental Europe as well as an increase in short-term sales, mainly to the UK. Natural gas volumes in 2005 and 2004 also include natural gas from the International E&P business segment, mainly from the Algerian field In Salah, which commenced production in July 2004. In 2005 2.5 bcm (87 bcf) of our natural gas volumes sold came from our international operations.
We record revenues from sales of production based on lifted volumes. The term “production” as used in this section means lifted volumes. The term “production” as used in Item 4—Information on the Company, means produced volumes, which include lifted volumes, adjusted for under- and overlifting. Overlifting and underlifting positions are a result of Statoil lifting either a higher or a lower volume of oil within the period than that represented by our total production of entitlement volumes in that period.
Equity in net income (loss) of affiliates. Equity in net income (loss) of affiliates principally includes our 50 per cent equity interest in Borealis, which was sold in 2005, our 50 per cent equity interest in Statoil Detaljhandel Skandinavia (SDS), which was increased to 100 per cent in July 2004, our 50 per cent equity interest in the drill ship West Navigator, which was sold in 2004, and miscellaneous other affiliates. Our share of Equity in net income of affiliates was NOK 1.1 billion in 2005, NOK 1.2 billion in 2004 and NOK 0.6 billion in 2003. The increase from 2003 to 2004 was primarily due to an increased contribution from Borealis, as a result of increased margins and volumes.
Other income. Other income was NOK 1.7 billion in 2005, NOK 1.3 billion in 2004 and NOK 0.2 billion in 2003. The NOK 1.7 billion income in 2005 was mainly related to the sale of our shares in Borealis. The NOK 1.3 billion income in 2004 was mainly related to the sale of our shares in Verbundnetz Gas (VNG), sales of our shares in the technology companies Electro Magnetic Geo Services AS (EMGS) and Advanced Production and Loading AS (APL) and sales of a portion of our ownership interest in the fields Kristin and Mikkel on the NCS. The NOK 0.2 billion income in 2003 was mainly related to the sale of Navion.
Cost of goods sold. Our Cost of goods sold includes the cost of the SDFI oil and NGL production that we purchase from the Norwegian State pursuant to the owner’s instruction. See —Factors Affecting Our Results of Operations above and Item 7–Major Shareholders and Related Party Transactions–Major Shareholders–Marketing and Sale of the SDFI’s Oil and Gas for more information.
Cost of goods sold increased to NOK 235.7 billion in 2005 from NOK 188.2 billion in 2004 and NOK 149.6 billion in 2003.
The 25 per cent increase in 2005 compared to 2004 and the 26 per cent increase in 2004 compared to 2003 were mainly due to increased oil prices measured in NOK. This was partly offset by reduced oil volumes purchased from the SDFI.
Operating expenses. Our operating expenses include production costs in fields and transport systems related to our share of oil and natural gas production. Operating expenses in 2005 were NOK 30.3 billion, as compared to NOK 27.4 billion in 2004 and NOK 26.7 billion in 2003. The increase from 2004 to 2005 was primarily due to increased activity.
The increase from 2003 to 2004 was primarily due to the consolidation of SDS into Statoil’s accounts.
Selling, general and administrative expenses. Our selling, general and administrative expenses include costs related to the selling and marketing of our products, including business development costs, payroll and employee benefits. Our selling, general and administrative expenses were NOK 7.8 billion in 2005, compared to NOK 6.3 billion in 2004 and NOK 5.5 billion in 2003.
The increase from 2004 to 2005 was primarily due to increased activity, as well as NOK 0.4 billion in increased insurance costs. This increase was due to insurance premium commitments in the two mutual insurance companies in which Statoil Forsikring participates. The increase was mainly due to the hurricanes Katrina and Rita in the U.S.
The increase from 2003 to 2004 was mainly due to SDS being consolidated into the group’s accounts. Insurance premiums increased in 2004 compared to 2003, but the increase was partly offset by reduced rig accruals.
Depreciation, depletion and amortization expenses. Our depreciation, depletion and amortization expenses include depreciation of production installations and transport systems, depletion of fields in production, amortization of intangible assets and depreciation of capitalized exploration expenditure as well as write-down of impaired long-lived assets. Depreciation, depletion and amortization expenses were NOK 21.1 billion in 2005, compared to NOK 17.5 billion in 2004 and NOK 16.3 billion in 2003.
The increase from 2004 to 2005 was mainly related to increased depreciation, depletion and amortization expenses in our international E&P business segments due to a NOK 2.2 billion write-down of the book value of Statoil’s share in phases 6-7-8 of the South Pars project, higher lifting from existing international fields, new fields coming on stream internationally, and a reduction in the proved reserves estimate for the calculation of depreciation in the fourth quarter of 2005, reflecting a decrease in proved reserves due to the effect of higher oil prices on production for international projects under PSAs.
The increase from 2003 to 2004 was mainly related to new fields coming on stream, both on the NCS and internationally, write-downs of NOK 0.3 billion on some fields, and increases due to changes in depreciation related to retirement obligations and changes due to the repeal of the Removal Grants Act as described under -Other items below.
Exploration expenditure. Our exploration expenditure is capitalized to the extent our exploration efforts are deemed successful, or awaiting such determination, and is otherwise expensed. Our exploration expense consists of the expensed portion of our current-period exploration expenditure and write-offs of exploration expenditure capitalized in prior periods. Exploration expense was NOK 3.3 billion in 2005, NOK 1.8 billion in 2004 and NOK 2.4 billion in 2003.
Year ended December 31, | ||||
Exploration (in NOK million) | 2005 | 2004 | 2003 | |
Exploration expenditure (activity) | 4,337 | 2,466 | 2,445 | |
Expensed, previously capitalized exploration costs | 158 | 110 | 256 | |
Capitalized share of current period's exploration activity | (1,242) | (748) | (331) | |
Exploration expense | 3,253 | 1,828 | 2,370 |
The increase of 78 per cent in exploration expense from 2004 to 2005 was mainly due to higher exploration activity, higher costs related to seismic and generally more expensive wells. A total of 20 exploration and appraisal wells were completed in 2005, nine on the Norwegian Continental Shelf (NCS) and 11 internationally. Of these wells, 14 resulted in discoveries, while one well awaits final evaluation.
The reduction of 23 per cent in exploration expense from 2003 to 2004 was mainly due to a NOK 0.4 billion increase in capitalization of exploration activity. Exploration expenditure capitalized in previous years but written off in 2004 was NOK 0.1 billion lower than in 2003. A total of 12 exploration and appraisal wells were completed in 2004, of which nine resulted in discoveries.
Income before financial items, other items, income taxes and minority interest. Income before financial items, other items, income taxes and minority interest totaled NOK 95.1 billion in 2005, NOK 65.1 billion in 2004 and NOK 48.9 billion in 2003.
The 46 per cent increase from 2004 to 2005 was mainly due to a 34 per cent increase in the average oil price measured in NOK, a 31 per cent increase in gas prices measured in NOK, a 7 per cent increase in oil and gas liftings and a net increase of NOK 0.9 billion from sale of shares. In addition, increased margins and regularity from the refineries was the main contributor to the increase in results from the downstream business.
The increase in Income before financial items, other items, income taxes and minority interest in 2005 was partly offset by an increase in cost items, which was mainly related to increased activity and increased insurance costs.
The 33 per cent increase from 2003 to 2004 was mainly due to a 25 per cent increase in oil prices measured in NOK, an increase in natural gas prices measured in NOK of 8 per cent, changes in the provisions relating to fixed price drilling rig contracts amounting to NOK 1.2 billion, and a 2 per cent increase in combined lifting of oil and natural gas. The gain from the sale of the shares in VNG in the first quarter of 2004 also contributed to an increase of NOK 0.6 billion in the results. Exploration costs were reduced by NOK 0.5 billion in 2004 compared to 2003, mainly because of increased capitalization of exploration activity in 2004 compared to 2003. Among other factors, high refinery and petrochemical margins contributed with NOK 1.3 billion in increased results in 2004 compared to 2003.
The increase in Income before financial items, other items, income taxes and minority interest in 2004 was partly offset by NOK 1.2 billion in increased depreciation and write-downs, mainly due to increased liftings, new fields coming on stream, and increased depreciation related to future removal expenditures. Accruals for increased insurance premium commitments related to damages incurred in the two mutual insurance companies in which Statoil participates, and reduced results by NOK 0.4 billion. The increased contribution from downstream activities was somewhat reduced due to the loss of Navion income, which amounted to NOK 0.5 billion in 2003, as well as NOK 0.3 billion in reduced contribution from Oil Sales, Trading and Supply (O&S) in 2004 compared to 2003, mainly due to currency effects. Statoil Detaljhandel Skandinavia AS (SDS) was consolidated into Statoil’s accounts as of July 2004.
In 2005, 2004 and 2003, our Income before financial items, other items, income taxes and minority interest, measured as a percentage of revenues was approximately 24 per cent, 21 per cent and 20 per cent, respectively, and was impacted by the various factors described above.
Net financial items. In 2005 we reported a net financial items expense of NOK 3.6 billion, compared to a net financial items income of NOK 5.7 billion in 2004 and a net financial items income of NOK 1.4 billion in 2003. The changes from year to year resulted principally from changes in currency gains and losses on the U.S. dollar portions of our long-term debt outstanding and currency gains and losses on U.S. dollar short-term balances linked to our NOK hedging policy, in both cases due to changes in the NOK/USD exchange rate. Currency swaps are used for risk management purposes, to ensure that the long-term interest bearing debt is recorded in U.S. dollars. As a result, our long-term debt is exposed to changes in the NOK/USD exchange rate. The NOK weakened by NOK 0.73 during 2005 and strengthened by NOK 0.64 during 2004, as compared to the U.S. dollar.
Interest income and other financial income amounted to NOK 1.4 billion in 2005, compared to NOK 1.0 billion in 2004 and NOK 1.2 billion in 2003. The increase from 2004 to 2005 was mainly due to increased dividends received.
The reduction in net financial items from 2003 to 2004 was mainly due to lower interest income following the general reduction in interest rates in the period.
Interest costs and other financial costs amounted to NOK 0.6 billion in 2005, as compared to NOK 0.3 billion in 2004. The increased costs from 2004 to 2005 were mainly due to an increase in short-term costs, which was partly offset by an increase in capitalized interests. In 2003, interest costs and other financial costs amounted to NOK 0.9 billion.
The result from management of the portfolio of security investments provided a gain of NOK 1.4 billion in 2005, compared to zero in 2004, mainly related to equity securities held by our insurance captive Statoil Forsikring AS and commercial papers held by Statoil ASA.
The Central Bank of Norway’s closing rate for NOK/USD was 6.77 on December 31, 2005, 6.04 on December 31, 2004 and 6.68 on December 31, 2003. These exchange rates have been applied in Statoil’s financial statements.
Other items. There are no Other items in 2005, as in 2004. The Storting decided in June 2003 to replace grants for costs related to the removal of installations on the NCS with an equivalent tax deduction for such costs. Previously, removal costs were refunded by the Norwegian State based on a percentage of the taxes paid over the productive life of the removed installation. As a consequence of the changes in legislation, we charged the receivable of NOK 6.0 billion from the Norwegian State related to the refund of removal costs to income under Other items in the second quarter of 2003. Furthermore, the resulting deferred tax benefit of NOK 6.7 billion was recognized. As a result, the net effect on income in 2003 was NOK 0.7 billion.
Income taxes. Our effective tax rates were 65.6 per cent, 64.1 per cent and 62.0 per cent in 2005, 2004 and 2003, respectively. Adjusted for the effect of the tax-free capital gain on the sale of shares in Borealis, the tax rate in 2005 would have been 66.7 per cent.
The tax rate in 2004 was strongly influenced by the positive tax effects due to the change in Norwegian tax legislation relating to dividends received by companies (the Exemption Method) and the acceptance by the Norwegian tax authorities of our method of allocating office costs to be deductible under the offshore tax regime. Adjusted for these non-recurring tax effects, the tax rate in 2004 would have been 66.7 per cent. In 2003, the tax rate would have been 67.9 per cent after having adjusted for the effect of the repeal of the Removal Grants Act.
Our effective tax rate is calculated as income taxes divided by income before income taxes and minority interest. Fluctuations in the effective tax rates from year to year are principally a result of non-taxable items (permanent differences), changes in the components of income between Norwegian oil and gas production, taxed at a marginal rate of 78 per cent, other Norwegian income, including the onshore portion of net financial items, taxed at 28 per cent, and income in other countries taxed at the applicable income tax rates.
Minority interest. Minority interest in net profit in 2005 was NOK 0.8 billion, compared to NOK 0.5 billion in 2004 and NOK 0.3 billion in 2003. Minority interest consists primarily of Shell’s 21 per cent interest in the Mongstad crude oil refinery.
Net income. Net income in 2005 was NOK 30.7 billion, compared to NOK 24.9 billion in 2004 and NOK 16.6 billion in 2003 for the reasons discussed above.
Business Segments
The following table details certain financial information for our four business segments. In combining segment results, we eliminate inter-company sales. These include transactions recorded in connection with our oil and natural gas production in the E&P Norway or International E&P segments and also in connection with the sale, transport or refining of our oil and natural gas production in the Manufacturing and Marketing or Natural Gas segments. E&P Norway produces oil, which it sells internally to Oil Sales, Trading and Supply (O&S) in the Manufacturing and Marketing business segment, which then sells the oil in the market. E&P Norway also produces natural gas, which it sells internally to our Natural Gas business segment, also to be sold in the market. A large share of the oil and a small share of the natural gas produced by International E&P is also sold in the same way as the oil and the natural gas produced by E&P Norway. Statoil has established a market price-based transfer pricing policy whereby we set an internal price at which our E&P Norway business segment sells oil and natural gas to the Manufacturing and Marketing and the Natural Gas business segments.For sales of oil from E&P Norway to Manufacturing and Marketing, the transfer price of oil is the applicable market reflective price less a margin of NOK 0.70 per barrel. The transfer price of sales of natural gas from E&P Norway to Natural Gas is NOK 0.32 per scm adjusted quarterly by the average USD oil price over the previous six months in proportion to USD 15 per barrel. The average transfer price for natural gas per standard cubic meter amounted to NOK 1.04 in 2005, NOK 0.71 in 2004 and NOK 0.59 in 2003.
The table below sets forth certain financial information for our business segments, including inter-company eliminations for each of the years in the three-year period ending December 31, 2005. Deferred Long-Term Tax Assets are excluded from Long-Term Assets by business area, while included in Long-Term Assets under Other and Eliminations.
(in million) | Year ended December 31, | |||
2005 | 2004 | 2003 | ||
NOK | USD | NOK | NOK | |
E&P Norway |
|
|
|
|
Revenues | 97,623 | 14,475 | 74,050 | 62,494 |
Income before financial items, other items, income taxes and minority interest | 74,132 | 10,992 | 51,029 | 37,855 |
Long-Term Assets | 86,386 | 12,809 | 81,629 | 76,468 |
|
|
|
|
|
Revenues | 19,563 | 2,901 | 9,765 | 6,615 |
Income before financial items, other items, income taxes and minority interest | 8,364 | 1,240 | 4,188 | 1,781 |
Long-Term Assets | 62,163 | 9,217 | 37,956 | 31,875 |
|
|
|
|
|
Revenues | 45,823 | 6,794 | 33,326 | 25,452 |
Income before financial items, other items, income taxes and minority interest | 5,901 | 875 | 6,784 | 6,005 |
Long-Term Assets | 19,237 | 2,852 | 17,535 | 15,772 |
|
|
|
|
|
Revenues | 339,380 | 50,320 | 267,177 | 218,642 |
Income before financial items, other items, income taxes and minority interest | 7,646 | 1,134 | 3,921 | 3,555 |
Long-Term Assets | 23,163 | 3,435 | 30,055 | 23,226 |
|
|
|
|
|
Revenues | (109,091) | (16,175) | (78,100) | (63,828) |
Income before financial items, other items, income taxes and minority interest | (947) | (140) | (815) | (280) |
Long-Term Assets | 21,012 | 3,115 | 15,999 | 15,090 |
Exploration and Production Norway
The following table sets forth certain financial and operating data regarding our E&P Norway business segment and percentage change for each of the years in the three–year period ended December 31, 2005.
Income statement data (in NOK million) | Year ended December 31, | ||||
2005 | 2004 | Change | 2003 | Change | |
Total revenues | 97,623 | 74,050 | 32% | 62,494 | 18% |
Operating, general and administrative expenses | 10,223 | 9,863 | 4% | 11,305 | (13%) |
Depreciation, depletion and amortization | 11,450 | 12,381 | (8%) | 11,969 | 3% |
Exploration expense | 1,818 | 777 | 134% | 1,365 | (43%) |
Income before financial items, other items, income taxes and minority interest | 74,132 | 51,029 | 45% | 37,855 | 35% |
Oil price (USD/bbl)(1) | 54.1 | 38.4 | 41% | 29.1 | 32% |
Production (lifting): |
|
|
|
|
|
Oil (mbbl/day) | 561.6 | 612.8 | (8%) | 651.9 | (6%) |
Natural gas (mmcf/day) | 2,372 | 2,051 | 16% | 1,857 | 11% |
Total Production (lifting) (mboe/day) | 984.2 | 978.3 | 1% | 982.4 | 0% |
Unit Production (lifting) Cost (USD/boe)(2) | 3.35 | 3.34 | 0% | 3.10 | 8% |
Unit Production (lifting) Cost (NOK/boe)(2) | 21.59 | 22.45 | (4%) | 21.93 | 2% |
(1) In 2005 and 2004 the oil price of the E&P Norway business segment is a volume-weighted average of the prices of oil and NGL lifted by the segment. For 2003 the price does not include NGL.
(2) Our unit production (lifting) cost is calculated by dividing operating costs relating to the production of oil and natural gas by total production (lifting) of petroleum in a given year.
Years ended December 31, 2005, 2004 and 2003
E&P Norway generated total revenues of NOK 97.6 billion in 2005, compared to NOK 74.1 billion in 2004 and NOK 62.5 billion in 2003.
The 32 per cent increase in revenues from 2004 to 2005 resulted primarily from a 41 per cent increase in the average oil price in USD of oil sold from E&P Norway to Manufacturing and Marketing, a 47 per cent increase in the transfer price in NOK of natural gas sold from E&P Norway to Natural Gas and an increase in lifted volume of natural gas. This was partly offset by an 8 per cent reduction in lifted volumes of oil.
The 18 per cent increase in revenues from 2003 to 2004 resulted primarily from a 32 per cent increase in the average oil price in USD of oil sold from E&P Norway to Manufacturing and Marketing, a 20 per cent increase in the transfer price in NOK of natural gas sold from E&P Norway to Natural Gas, and an increase in lifted volumes of natural gas. This was partly offset by a 5 per cent decrease in the NOK/USD exchange rate and a 6 per cent reduction in lifted volumes of oil.
Average daily oil production (lifting) in E&P Norway decreased to 561,600 barrels in 2005, from 612,800 barrels in 2004 and from 651,900 barrels in 2003.
The 8 per cent decrease in average daily oil production from 2004 to 2005 of 63,000 bbl was mainly related to a continuing decline on the Statfjord, Gullfaks, Åsgard and Troll oil fields, as well as reduced production caused by more frequent and larger maintenance turnarounds in 2005 compared with 2004. This decline was only partially offset by new fields coming on stream, including Kvitebjørn, Sleipner Vest Alfa Nord in late 2004 and Kristin, Urd and Visund gas in late 2005.
The 6 per cent decrease in average daily oil production from 2003 to 2004 was primarily due to a decline on the Statfjord, Norne and Troll fields, technical problems at Glitne throughout the year, the rig strike and lockout, and the Snorre incident. This decline was only partially offset by production from the new fields Kvitebjørn and Sleipner Vest Alfa Nord, both of which commenced production in the fourth quarter of 2004.
Average daily gas production was 67.2 mmcm (2,372 mmcf) in 2005, as compared to 58.1 mmcm (2,051 mmcf) in 2004 and 52.6 mmcm (1,857 mmcf) in 2003.
The 16 per cent increase from 2004 to 2005 and the 11 per cent increase from 2003 to 2004 were primarily due to increases in long-term contracted gas volumes and high off-take from existing contracts.
Unit production cost was USD 3.35 per boe in 2005, USD 3.34 per boe in 2004 and USD 3.10 per boe in 2003. The increase from 2003 to 2004 was due primarily to the effect of the weaker USD against the NOK since costs were primarily incurred in NOK, increased pension cost and increased cost of goods sold due to higher oil price. The unit of production cost measured in NOK increased from NOK 21.93 per boe in 2003 to NOK 22.45 per boe in 2004 and was reduced to NOK 21.59 per boe in 2005.
Operating, general and administrative expenses were NOK 10.2 billion in 2005, NOK 9.9 billion in 2004 and NOK 11.3 billion in 2003. The 4 per cent increase from 2004 to 2005 was mainly due to an increase in platform costs of NOK 0.6 billion, an increase in transportation of NGL costs of NOK 0.3 billion and reversal of rig accruals by NOK 0.4 billion in 2005 compared with NOK 1.0 billion in 2004, which was partly offset by a realized loss on rig accruals of NOK 0.3 billion. In January 2005 Cost of goods related to purchases of third party NGL were reclassified as a reduction in sales revenues. The Cost of goods sold relating to these volumes of NGL amounted to NOK 0.7 billion in 2004 and NOK 0.5 billion in 2003.
The 13 per cent decrease from 2003 to 2004 was mainly due to the reversal of rig accruals by NOK 1.0 billion in 2004 while these increased by NOK 0.4 billion in 2003, which was partly offset by a realized loss on rig accruals of NOK 0.3 billion. In addition, the platform costs were reduced by NOK 0.2 million in 2004.
Depreciation, depletion and amortization expenses were NOK 11.5 billion in 2005, NOK 12.4 billion in 2004 and NOK 12.0 billion in 2003. The reduction from 2004 to 2005 was mainly due to increased reserves on several fields, which reduced the rate of depreciation, and the write-down on Murchison in 2004. This was partly offset by commencement of production from the new fields Kvitebjørn and Tune in late 2004 and Kristin, Urd and Visund gas in late 2005.
The increase from 2003 to 2004 was mainly due to the write-down on Murchison, depreciation of assets related to retirement obligations following the repeal of the Removal Grants Act, and commencement of production from the new fields Kvitebjørn and Tune in late 2004 and Fram Vest, Mikkel and Vigdis Extension in late 2003. This was partly offset by increased reserves and lower lifted oil volumes.
Exploration expenditure (activity) was NOK 2.2 billion in 2005, compared to NOK 1.1 billion in 2004 and NOK 1.2 billion in 2003.
The 100 per cent increase from 2004 to 2005 was mainly due to more wells being drilled and more seismic activity, as well as generally more expensive wells. The 8 per cent decrease from 2003 to 2004 was mainly due to fewer wells being drilled.
Exploration expense was NOK 1.8 billion in 2005, compared to NOK 0.8 billion in 2004 and NOK 1.4 billion in 2003. The increased exploration expense from 2004 to 2005 was mainly due to higher exploration activity in 2005 than in 2004 and higher expenditure capitalized in previous years, but written off in 2005 than in 2004. This was partly offset by higher capitalized exploration expenditure in 2005 than in 2004. The reduced exploration expense from 2003 to 2004 was mainly due to higher capitalized exploration expenditure in 2004 than in 2003 and lower expenditure capitalized in previous years, but written off in 2004 than in 2003. Exploration expense in 2005 included NOK 0.2 billion written off in 2005 relating to expenditures capitalized in previous years, compared to NOK 0.1 billion of expenditure written off in 2004 and NOK 0.3 billion of expenditure written off in 2003.
In 2005 nine exploration and appraisal wells were completed, six of which resulted in discoveries. In addition, five extensions on production wells were completed in 2005, four of which resulted in discoveries. In 2004 six exploration and appraisal wells were completed, four of which resulted in discoveries. In addition, four extensions on production wells were completed in 2004, all of which resulted in discoveries. However these extensions were not funded by exploration expenditure. In 2003 nine exploration and appraisal wells were completed, of which six resulted in discoveries.
A reconciliation of exploration expenditure to exploration expense is shown in the table below.
Exploration (in NOK million) | 2005 | 2004 | 2003 |
Exploration expenditure (activity) | 2,188 | 1,092 | 1,215 |
Expensed, previously capitalized exploration expenditure | 158 | 61 | 256 |
Capitalized share of current period’s exploration activity | (528) | (376) | (106) |
Exploration expenses | 1,818 | 777 | 1,365 |
Income before financial items, other items, income taxes, and minority interest for E&P Norway was NOK 74.1 billion in 2005, as compared to NOK 51.0 billion in 2004 and NOK 37.9 billion in 2003. The 45 per cent increase in income from 2004 to 2005 was primarily the result of an increase in revenues due to the 35 per cent increase in the average oil price measured in NOK and a 47 per cent increase in the transfer price in NOK of natural gas. Depreciation, depletion and amortization expenses were reduced by NOK 8 per cent, but this reduction was partly offset by a 134 per cent increase in exploration expense and a 4 per cent increase in operating, general and administrative expenses.
The 35 per cent increase in income from 2003 to 2004 was primarily the result of an increase in revenues due to the 26 per cent increase in the average oil price measured in NOK and a 20 per cent increase in the transfer price in NOK of natural gas. Operating expenses were reduced by 13 per cent and exploration expense by 43 per cent, but these reductions were partly offset by a 3 per cent increase in depreciation, depletion and amortization expenses.
International Exploration and Production
The following table sets forth certain financial and operating data regarding our International E&P business segment and percentage change for each of the years in the three–year period ending December 31, 2005.
Income statement data (in NOK million) | Year ended December 31, | ||||
2005 | 2004 | Change | 2003 | Change | |
Total revenues | 19,563 | 9,765 | 100% | 6,615 | 48% |
Operating, general and administrative expenses | 3,491 | 2,311 | 51% | 2,045 | 13% |
Depreciation, depletion and amortization | 6,273 | 2,215 | 183% | 1,784 | 24% |
Exploration expense | 1,435 | 1,051 | 37% | 1,005 | 5% |
Income before financial items, other items, income taxes and minority interest |
8,364 | 4,188 | 100% | 1,781 | 135% |
Oil price (USD/bbl)(1) | 51.0 | 35.7 | 43% | 27.6 | 29% |
Production (lifting): |
|
|
|
|
|
Oil (mbbl/day) | 139.5 | 99.8 | 40% | 85.6 | 17% |
Natural Gas (mmcf/day) | 239.2 | 84.7 | 185% | 16.8 | 397% |
Total Production (lifting) (mboe/day) | 182.0 | 114.8 | 59% | 88.2 | 30% |
Unit Production (lifting) Cost (USD per boe)(2) |
3.90 | 4.59(3) | (15%) | 3.88 | 18% |
(1) In 2005 and 2004 the oil price for the International E&P business segment is a volume-weighted average of the internal transfer price and external sales price of oil sold.
(2) The unit production (lifting) cost is calculated by dividing operating costs relating to the production of oil and natural gas by total production (lifting) of petroleum in a given year.
(3) The previously reported unit production cost of USD 4.74 per boe in 2004 was inclusive of the royalty paid on Sincor, which does not constitute part of operating costs relating to the production of oil and natural gas.
Adjusted for the Sincor royalty, unit production cost in 2004 was USD 4.59 per boe.
Years ended December 31, 2005, 2004 and 2003
International E&P generated total revenues of NOK 19.6 billion in 2005, compared to NOK 9.8 billion in 2004 and NOK 6.6 billion in 2003.
The 100 per cent increase from 2004 to 2005 was mainly due to a 59 per cent increase in lifted volumes, contributing NOK 4.8 billion, and a 37 per cent increase in realized oil prices for International E&P measured in NOK, contributing NOK 4.5 billion.
The 48 per cent increase from 2003 to 2004 was mainly due to higher lifting and higher prices in USD for crude oil and natural gas contributing to an increase of NOK 1.9 billion each. The price effect was partly offset by an adverse currency effect of NOK 0.5 billion caused by the weakening of the USD measured against the NOK.
Average daily oil production (lifting) was 139,500 barrels per day in 2005, compared to 99,800 barrels per day in 2004 and 85,600 barrels per day in 2003. The 40 per cent increase in average daily production of oil from 2004 to 2005 came primarily from new fields such as the Central Azeri part of the ACG field and Kizomba B, which came on stream in the first quarter and the third quarter of 2005, respectively. In addition, the ramp-up of production from the Kizomba A field, which came on stream in the third quarter of 2004, and re-start of production from the Lufeng field in the second quarter of 2005 contributed to increased production in 2005. These increases were partly offset by reduced PSA entitlement production from the Xikomba and Girassol/Jasmim fields in Angola, as well as lower production from the Alba and Schiehallion fields in the UK.
The 17 per cent increase in average daily production of oil from 2003 to 2004 came primarily from the Kizomba A field and the Xikomba and Jasmim fields, which had their first full year of production during 2004. These increases were partly offset by lower production from the Alba and Schiehallion fields in the UK, as well as the Girassol field in Angola.
Average natural gas production in 2005 was 6.8 mmcm per day (239 mmcf per day), compared to 2.4 mmcm per day (84 mmcf per day) in 2004 and 0.4 mmcm per day (14 mmcf per day) in 2003. The large increase in gas production from 2003 to 2004 and 2004 to 2005 was attributable to gas sales from the In Salah field in Algeria, which commenced production in July 2004.
Depreciation, depletion and amortization expenses were NOK 6.3 billion in 2005, compared to NOK 2.2 billion in 2004 and NOK 1.8 billion in 2003. The 183 per cent increase in 2005 as compared to 2004 was largely due to a NOK 2.2 billion write-down of the book value of Statoil’s share in phases 6-7-8 of the South Pars project. Higher lifting from existing fields and new fields coming on stream also contributed to the increase in depreciation, depletion and amortization. The increase was also partly due to a reduction in the proved reserves estimate, which is used for the calculation of depreciation, in the fourth quarter of 2005. This reflects a decrease in proved reserves due to the impact of high oil prices on production entitlements for international projects under PSAs.
The 24 per cent increase in 2004 as compared to 2003 was due to increased lifting, partly offset by the NOK 0.2 billion write-down of the Dunlin oil field in the UK in 2003.
Unit production cost on a 12-month average in 2005 was USD 3.90 per boe, compared to a unit production cost in 2004 of USD 4.59 per boe, a decrease of 15 per cent. The decrease was primarily due to increased lifting as a result of the ramp-up of production from large fields such as In Salah, Kizomba A, Kizomba B and ACG. The 18 per cent increase in the unit production cost from 2003 to 2004 was primarily driven by the increased operating costs on Lufeng, where the floating production vessel lease rate was linked to the oil price, and on Sincor due to a planned maintenance shutdown that takes place every third year.
Operating, general and administrative expenses. Due to higher lifting, new fields in production and an upward cost pressure, operating costs increased by NOK 1.2 billion from 2004 to 2005. A NOK 0.3 billion increase from 2003 to 2004 was due to higher lifting and higher average operating cost.
Exploration expenditure (activity) was NOK 2.1 billion in 2005, compared to NOK 1.4 billion in 2004 and NOK 1.2 billion in 2003. The increase from 2004 to 2005 was mainly due to increased activity, higher cost of wells and seismic data acquisition.
Exploration expense was NOK 1.4 billion in 2005, compared to NOK 1.1 billion in 2004 and NOK 1.0 billion in 2003.
In total, 11 exploration and appraisal wells were completed in 2005, and as of year end eight wells were considered as discoveries. One well awaits final evaluation. Six exploration and appraisal wells were completed in 2004, of which five wells were considered as discoveries at year end 2004. In total, 14 exploration and appraisal wells were completed in 2003, of which 11 resulted in discoveries and remained capitalized.
A reconciliation of exploration expenditure to exploration expense is shown in the table below.
Exploration (in NOK million) | 2005 | 2004 | 2003 |
Exploration expenditure (activity) | 2,149 | 1,374 | 1,230 |
Expensed, previously capitalized exploration expenditure | 0 | 49 | 0 |
Capitalized share of current period’s exploration activity | (714) | (372) | (225) |
Exploration expenses | 1,435 | 1,051 | 1,005 |
Income before financial items, other items, income taxes and minority interest for International E&P in 2005 was NOK 8.4 billion, compared to NOK 4.2 billion in 2004 and NOK 1.8 billion in 2003. Increased revenues were caused by higher lifting and higher prices for crude oil and natural gas. Total costs increased by NOK 5.6 billion from 2004 to 2005, due to increased depreciation, depletion and amortization because of the write-down of Statoil’s share in phases 6-7-8 of the South Pars project and higher operating costs as a result of higher lifting. Exploration expense and sales, administration and business development costs also increased from 2004 to 2005 due to increased activities in all areas.
The 135 per cent increase in Income before financial items, other items, income taxes and minority interest for International E&P from 2003 to 2004 was caused by increased revenues due to higher lifting and higher prices for crude oil and natural gas, decreased business development costs, and the NOK 0.2 billion write-down of the Dunlin oil field in the UK in 2003. Operating cost and depreciation, depletion and amortization increased in 2004 compared to 2003 due to higher lifting.
Natural Gas
The following table sets forth certain financial and operating data for our Natural Gas business segment and percentage change for each of the years in the three–year period ending December 31, 2005.
Income statement data (in NOK million) | Year ended December 31, | ||||
2005 | 2004 | Change | 2003 | Change | |
Total revenues | 45,823 | 33,326 | 37 % | 25,452 | 31% |
Natural gas sales(1) | 41,565 | 29,703 | 40 % | 22,041 | 35% |
Processing and transportation | 4,258 | 3,623 | 18 % | 3,411 | 6% |
Cost of goods sold | 30,826 | 19,350 | 59 % | 12,932 | 50% |
Operating, selling and administrative expenses | 8,321 | 6,540 | 27 % | 5,896 | 11% |
Depreciation, depletion and amortization | 775 | 652 | 19 % | 619 | 5% |
Income before financial items, other items, income taxes and minority interest | 5,901 | 6,784 | (13 %) | 6,005 | 13% |
Prices:(2) |
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Average natural gas price (NOK/scm)(3) | 1.45 | 1.10 | 31 % | 1.02 | 8% |
Average transfer price natural gas (NOK/scm) | 1.04 | 0.71 | 47 % | 0.59 | 20% |
Volumes marketed:(4) |
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For our own account (bcf)(5) | 964 | 881 | 9 % | 744 | 18% |
For the account of the SDFI (bcf) | 1,116 | 1,069 | 4 % | 915 | 15% |
For our own account (bcm) | 27.3 | 25.0 | 9 % | 21.1 | 18% |
For the account of the SDFI (bcm) | 31.6 | 30.3 | 4 % | 25.9 | 15% |
(1) Revenue from sale of shares in VNG of NOK 0.6 billion is included in natural gas sales for 2004.
(2) Gas prices are volume weighted averages.
(3) Calculation of the average natural gas price excludes revenues from third party sales in the U.S., ethane and volumes reported by the International E&P business segment.
(4) All volumes measured assuming a gross calorific value of 40 MJ/scm.
(5) Excluding natural gas volumes sold by the International E&P business segment, but including third-party volumes sold by Natural Gas.
Years ended December 31, 2005, 2004 and 2003
Total revenues in the Natural Gas business consist mainly of gas sales derived from long-term gas sales contracts and tariff revenues from transportation and processing facilities. Natural Gas generated revenues of NOK 45.8 billion in 2005, compared to NOK 33.3 billion in 2004 and NOK 25.5 billion in 2003. The 37 per cent increase from 2004 to 2005 was mainly due to increased gas sales, higher natural gas prices measured in NOK, and higher revenues from processing and transportation.
The 31 per cent increase in 2004 over 2003 was mainly due to increased gas sales and higher natural gas prices measured in NOK, sale of shares in VNG, higher revenues from sales of ethane, and higher revenues from processing and transportation.
Natural gas sales were 27.3 bcm (962 bcf) in 2005, 25.0 bcm (881 bcf) in 2004 and 21.1 bcm (744 bcf) in 2003. The 9 per cent increase in gas volumes sold from 2004 to 2005 was mainly due to high customer off-take under existing contracts, an increase in the contracted gas sales portfolio, increased production permits, and increased third party gas sales in the U.S.
The 18 per cent increase in gas volumes sold from 2003 to 2004 was mainly due to high customer off-take, an increase in the contracted gas sales portfolio, and increased third party gas sales in the U.S.
Of the total natural gas sales in 2005 Statoil produced 24.6 bcm (865 bcf). Average gas prices for our European gas sales were NOK 1.45 per scm in 2005 compared to NOK 1.10 per scm in 2004, an increase of 32 per cent, compared to NOK 1.02 per scm in 2003, an increase of 8 per cent. The increased price from year to year was mainly due to increased prices on oil products and other competing energy sources, as well as higher gas prices on the National Balancing Point (NBP) in the UK. Natural gas from In Salah is not sold by the Natural Gas business segment, and hence Statoil’s sales volumes from this field are not included in the sales reported by the Natural Gas business segment.
Cost of goods sold increased by 59 per cent from 2004 to 2005, and by 50 per cent from 2003 to 2004. This was caused by a higher transfer price paid to E&P Norway for natural gas and higher prices paid for volumes that were resold in the U.S., as well as the purchase of higher volumes of both Statoil produced gas to be sold in Europe and third party gas to be sold in the U.S.
Operating, selling and administrative expenses increased by 27 per cent from 2004 to 2005, and by 11 per cent from 2003 to 2004. This was mainly due to higher transportation costs caused by increased natural gas sales volumes.
Income before financial items, other items, income taxes and minority interest for Natural Gas in 2005 was NOK 5.9 billion, compared to NOK 6.8 billion in 2004 and NOK 6.0 billion in 2003. The 13 per cent decrease from 2004 to 2005 was primarily due to an increase in cost of goods sold. The sale of shares in VNG also contributed to higher income before financial items, other items, income taxes and minority interest in 2004.
The 13 per cent increase in Income before financial items, other items, income taxes and minority interest from 2003 to 2004 was primarily a result of the sale of shares in VNG. Increased sales and an 8 per cent increased external gas sales price were offset by an increase in cost of goods sold, due to a higher transfer price for natural gas, together with higher gas volumes sold.
Manufacturing and Marketing
The following table sets forth certain financial and operating data for our Manufacturing and Marketing business segment and percentage change for each of the years in the three–year period ending December 31, 2005.
| Year ended December 31 | ||||
Income statement data (in NOK million) | 2005 | 2004 | Change | 2003 | Change |
Total revenues | 339,380 | 267,177 | 27 % | 218,642 | 22 % |
Cost of goods sold | 313,125 | 246,971 | 27 % | 200,453 | 23 % |
Operating, selling and administrative expenses | 16,402 | 14,566 | 13 % | 13,215 | 10 % |
Depreciation, depletion and amortization | 2,207 | 1,719 | 28 % | 1,419 | 21 % |
Income before financial items, other items, income taxes and minority interest | 7,646 | 3,921 | 95 % | 3,555 | 10 % |
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FCC-margin (USD/bbl) | 7.9 | 6.4 | 23 % | 4.4 | 45 % |
Contract price methanol (EUR/tonne) | 225 | 213 | 6 % | 226 | (6 %) |
Petrochemical margin (EUR/tonne) | 161 | 153 | 5 % | 119 | 29 % |
Years ended December 31, 2005, 2004 and 2003
Manufacturing and Marketing generated revenues of NOK 339.4 billion in 2005 compared to NOK 267.2 billion in 2004 and NOK 218.6 billion in 2003. The 27 per cent increase from 2004 to 2005 resulted mainly from higher prices in USD for crude oil, but was partly offset by the strengthening of the NOK versus the USD and a decrease in total volumes of crude oil sold by 3 per cent. Manufacturing and Marketing sells Statoil equity oil volumes, third party oil volumes and SDFI oil volumes.
Cost of goods sold increased from NOK 200.5 billion in 2003 to NOK 247.0 billion in 2004, and to NOK 313.1 billion in 2005. The increase from 2004 to 2005 resulted primarily from higher prices paid in USD for crude oil and SDS being consolidated in the group’s accounts for 12 months in 2005, compared to only six months in 2004. The consolidation of SDS into the group’s accounts contributed to an increase in cost of goods sold of 6 per cent in 2004 compared to 2003.
Operating, selling and administrative expenses increased by 13 per cent in 2005 compared to 2004 mainly due to the full-year effect from the SDS consolidation and restructuring costs in Marketing. In 2004, compared to 2003, operating, selling and administrative expenses increased by 10 per cent, mainly due to the consolidation of SDS assets into the group’s accounts.
Depreciation, depletion and amortization totaled NOK 2.2 billion in 2005, compared to NOK 1.7 billion in 2004 and NOK 1.4 billion in 2003. The increase from 2004 to 2005 was mainly due to depreciation of SDS assets, which were consolidated in the group’s accounts for 12 months in 2005 compared to six months in 2004.
Income before financial items, other items, income taxes and minority interest for Manufacturing and Marketing was NOK 7.6 billion in 2005, compared to NOK 3.9 billion in 2004 and NOK 3.6 billion in 2003. The gain from the sale of Statoil’s shares in Borealis and higher margins combined with higher regularity within Manufacturing were the main reasons for the increase in income of NOK 3.7 billion from 2004 to 2005. Navion was sold in 2003, which contributed NOK 0.5 billion to income in 2003.
In Manufacturing, Income before financial items, other items, income taxes and minority interest increased by NOK 1.7 billion from 2004 to 2005 mainly due to higher refining margins and higher regularity levels. Higher refining margins increased profits by NOK 0.6 billion from 2003 to 2004. In 2005, the average refining margin (FCC margin) was 23 per cent higher than in 2004, equivalent to USD 1.5 per barrel. The average contract price on methanol was about 6 per cent higher measured in NOK in 2005 than in 2004.
In Oil Sales, Trading and Supply (O&S), Income before financial items, other items, income taxes and minority interest increased by NOK 0.7 billion in 2005 compared to 2004, mainly due to good results from trading operations and currency gains on commercial storage, which were partly offset by a lower contribution from the contingent compensation arrangements relating to the sale of the Melaka refinery. Income before financial items, other items, income taxes and minority interest decreased by NOK 0.3 billion in 2004 compared with 2003, mainly due to currency effects and changes in the market value of economic hedge positions related to inventories. This was partially offset by the recording of a contingent compensation from the sale of the Melaka refinery. The final payment of contingent compensation from the sale of the Melaka refinery is expected to be received in the second quarter of 2006.
The Marketing Income before financial items, other items, income taxes and minority interest decreased slightly in 2005 compared with 2004, and by NOK 0.2 billion in 2004 compared with 2003. The decrease from 2004 to 2005 was due to lower margins, particularly in Sweden, and restructuring costs.
The contribution from Borealis to Manufacturing and Marketing’s Income before financial items, other items, income taxes and minority interest was an income of NOK 2.2 billion in 2005, NOK 0.8 billion in 2004 and NOK 0.1 billion in 2003. The contribution from Borealis increased from 2004 to 2005 due to the gain from the sale in 2005 of Statoil’s 50 per cent holding in Borealis to International Petroleum Investment Company (IPIC) and OMV Aktiengesellschaft. Statoil received EUR 1 billion (NOK 7.8 billion) for the transaction, which gave a tax-free capital gain of NOK 1.5 billion that was recorded as profit in the fourth quarter of 2005. The increase from 2003 to 2004 was due to very high margins, increased volumes and improved operational performance.
Other operations
Years ended December 31, 2005, 2004 and 2003
Our other operations consist of the activities of Corporate Services, Corporate Center, Group Finance and the corporate technical service provider Technology and Projects. In connection with our other operations, we recorded a loss before financial items, other items, income taxes and minority interest of NOK 0.9 billion in 2005, compared to a loss of NOK 0.8 billion in 2004 and a loss of NOK 0.3 billion in 2003. The segment Other includes increased insurance costs of NOK 0.8 billion in 2005, due to extra insurance premiums and liabilities in the two mutual insurance companies in which Statoil Forsikring participates. The corresponding increase for 2004 is NOK 0.4 billion.
Liquidity and Capital Resources
Cash Flows Provided by Operating Activities
Our primary source of cash flow is funds generated from operations. Net funds generated from operations for 2005 were NOK 56.3 billion, as compared to NOK 38.8 billion in 2004 and NOK 30.8 billion in 2003.
The increase in cash flows provided by operating activities of NOK 17.4 billion in 2005, compared to 2004, was mainly due to an increase in cash flows from underlying operations contributing NOK 27.5 billion. Short-term investments contributed NOK 7.1 billion. Increased taxes paid reduced the cash flows from operations by NOK 15.5 billion, while changes in working capital and long-term items related to operations reduced the cash flows from operations by NOK 1.6 billion.
The increase of NOK 8.0 billion from 2003 to 2004 was primarily due to an increase of NOK 17.6 billion in cash flows due to higher prices and margins, which was partly offset by increased taxes paid of NOK 4.7 billion, as well as NOK 4.9 billion reduced cash flows due to changes in working capital items and long-term items (excluding taxes payable, short-term interest-bearing debt, short-term investments and cash) in 2004 as compared to 2003.
Cash Flows used in Investing Activities
Net cash flows used in investing activities amounted to NOK 37.7 billion in 2005, as compared to NOK 32.0 billion in 2004 and NOK 23.2 billion in 2003.
Gross investments, defined as additions to property, plant and equipment and capitalized exploration expenditure increased to NOK 46.2 billion in 2005 from NOK 42.8 billion in 2004 and NOK 24.1 billion in 2003. Gross investments also include investments in intangible assets and investments in affiliates. The increase from 2004 to 2005 was mainly related to the acquisition of the deepwater Gulf of Mexico assets from EnCana for NOK 13.2 billion.
The increase from 2003 to 2004 was mainly related to increased investments in the E&P Norway and International E&P business segments as a result of an increased number of development projects.
The difference of NOK 8.5 billion between cash flows used in investing activities of NOK 37.7 billion and gross investments in 2005 of NOK 46.2 billion was mainly related to the sale of the group’s shares in Borealis and NCS portfolio transactions.
Cash Flows used in Financing Activities
Net cash flows used in financing activities amounted to NOK 16.5 billion in 2005, as compared to NOK 9.1 billion for 2004 and NOK 7.9 billion for 2003. New long-term borrowing in 2005 decreased by NOK 4.2 billion compared to 2004 and repayment of long-term debt decreased by NOK 3.4 billion in 2005.
The NOK 7.5 billion increase in cash flows used in financing activities from 2004 to 2005 was mainly due to a reduction in new long-term borrowings and an increase in dividend paid, but was partly offset by a decrease in repayment of long-term borrowings. The amount reported in 2005 includes a dividend paid to shareholders of NOK 11.5 billion, while the dividend paid to shareholders was NOK 6.4 billion in 2004 and NOK 6.3 billion in 2003.
Working Capital
Working capital (total current assets less current liabilities) was reduced by NOK 4.5 billion from 2004 to 2005, from a positive working capital of NOK 3.9 billion as of December 31, 2004 to a negative working capital of NOK 0.6 billion as of December 31, 2005, mainly due to an increase in income taxes payable due to higher oil prices. Working capital as of December 31, 2003 was NOK 1.7 billion.
We believe that, taking into consideration Statoil's established liquidity reserves (including committed credit facilities), credit rating and access to capital markets, we have sufficient liquidity and working capital to meet our present and future requirements. Our sources of liquidity are described below.
Liquidity
Our cash flow from operations is highly dependent on oil and gas prices and our levels of production, and is only to a small degree influenced by seasonality and maintenance. Fluctuations in oil and gas prices, which are outside of our control, will cause changes in our cash flows. We will use available liquidity to finance Norwegian petroleum tax payments (due April 1 and October 1 each year), any dividend payment and investments. Our investment program is spread across the year. The investments in the coming years are expected to remain high at a level of NOK 110-115 billion for the period 2005 to 2007 (excluding the purchase in 2005 of the Gulf of Mexico assets from EnCana for NOK 13.2 billion). There may be a gap between funds from operations and funds necessary to fund investments, depending on the level of oil and gas prices as well as levels of production. However, Statoil currently expects that cash flow from operations will be sufficient to meet its liquidity needs for 2006. It is our intention to keep ratios related to net debt at levels consistent with our objective of maintaining our long-term credit rating in the A category (for current rating levels, see below).
As of December 31, 2005, we had liquid assets of NOK 13.9 billion, including approximately NOK 6.8 billion of short-term investments (domestic and international capital market investments), and NOK 7.0 billion in cash and cash equivalents. As of December 31, 2005, approximately 18 per cent of our liquid assets were held in NOK-denominated assets, 75 per cent in U.S. dollars and 7 per cent in other currencies, before the effect of currency swaps and forward contracts. Capital market investments decreased by NOK 4.8 billion during 2005, as compared to year end 2004. Cash and cash equivalents decreased by NOK 2.0 billion during 2005, as compared to year end 2004.
As of December 31, 2004, we had liquid assets of NOK 16.6 billion, including approximately NOK 11.6 billion of domestic and international capital market investments, primarily government bonds, but also other investment grade short-term debt securities, and NOK 5.0 billion in cash and cash equivalents. As of December 31, 2004, approximately 25 per cent of our cash and cash equivalents were held in NOK-denominated assets, 70 per cent in U.S. dollars and 5 per cent in other currencies, before the effect of currency swaps and forward contracts. As part of our diversification into new investment alternatives like international commercial paper markets, the share of USD-denominated assets (swapped from NOK) has increased since 2003.
As of December 31, 2003, we had liquid assets of NOK 16.6 billion, including approximately NOK 9.3 billion of domestic and international capital market investments, and NOK 7.3 billion in cash and cash equivalents. As of December 31, 2003, approximately 70 per cent of our cash and cash equivalents were held in NOK, 10 per cent in U.S. dollars, 15 per cent in euro and 5 per cent in other currencies, before the effect of currency swaps and forward contracts.
Our general policy is to maintain a liquidity reserve in the form of cash and cash equivalents on our balance sheet, and committed, unused credit facilities and credit lines to ensure that we have sufficient financial resources to meet our short-term requirements. Long-term funding is raised when we identify a need for such financing based on our business activities and cash flows as well as when market conditions are considered favorable.
As of December 31, 2005, the group had available USD 2.0 billion in a committed revolving credit facility from international banks, including a USD 500 million swing-line facility. The facility was entered into by us in 2004, and is available for draw-downs until December 2009. At year end 2005 no amounts had been drawn under the facility. In addition, a EUR 200 million line of credit has been established in our favor on a bilateral basis by an international financial institution. Until June 2006 this line of credit, which we may only utilize with at least 15 days notice, is available for draw-downs in one or more tranches. The final maturity of such tranches may vary from 3 to 7 years. Our long-term rating from Moody’s was upgraded to Aa2 in June 2005 as Moody’s introduced a new rating methodology for Government Related Issuers (GRI). The short-term rating from Moody’s is P-1. Our short-term and long-term ratings from Standard & Poor’s are A and A-1, respectively.
Interest-bearing debt
Gross interest-bearing debt was NOK 34.2 billion at the end of 2005, as compared to NOK 36.2 billion at the end of 2004. Despite high investments and an increased NOK/USD exchange rate, interest-bearing debt was reduced, mainly due to increased cash flows from operations, the disposal of our ownership share in Borealis and debt repayments exceeding the borrowing needs. At December 31, 2003, gross interest-bearing debt was NOK 37.3 billion.
Net interest-bearing debt is calculated as the difference between gross interest-bearing debt and cash, cash equivalents and short-term investments. Net interest-bearing debt was NOK 19.5 billion as of December 31, 2005, compared to NOK 20.3 billion as of December 31, 2004. The reduction was mainly due to reduced gross interest-bearing debt as referred to above, which was partly offset by a NOK 1.6 billion reduction of adjusted liquid assets. At December 31, 2003, net interest-bearing debt was NOK 20.9 billion. For a reconciliation of net interest-bearing debt to gross debt, see —Use and Reconciliation of Non-GAAP Financial Measures—Net debt to capital employed ratio below.
Net debt to capital employed ratio, defined as net interest-bearing debt to capital employed, was 15.3 per cent as of December 31, 2005, compared to 19.0 per cent as of December 31, 2004 and 22.6 per cent as of December 31, 2003. The decrease in the net debt to capital employed ratio was mainly due to increased shareholders’ equity. Our methodology of calculating the net debt to capital employed ratio makes certain adjustments outlined below and may therefore be considered to be a Non-GAAP financial measure. The net debt to capital employed ratio without adjustments was 15.8 per cent in 2005, compared to 18.4 per cent in 2004 and 22.4 per cent in 2003. See —Use and Reconciliation of Non-GAAP Financial Measures—Net debt to capital employed ratio below.
The group’s borrowing needs are mainly covered through short-term and long-term securities issues, including utilization of a U.S. Commercial Paper Program and a Euro Medium Term Note (EMTN) Program (the program limits being USD 2 billion (increased from USD 1 billion in January 2006) and USD 3 billion, respectively), and through draw-downs under committed credit facilities and credit lines. Apart from draw-downs of approximately USD 45 million under the BTC project financing described below, no long-term borrowing took place during 2005.
Statoil is a party to a project loan agreement amounting to USD 225 million, of which USD 32 million is provided from the bank market and the balance through a sponsor loan in Statoil’s own name. The purpose of this financing is to cover part of Statoil's obligations in respect of its participating share in the BTC pipeline project in Azerbaijan, Georgia and Turkey. The project loan is fully guaranteed by Statoil until construction of the pipeline is complete and certain operational conditions have been fulfilled. As at the end of 2005, approximately USD 212 million had been disbursed under this agreement. The project loan is expected to be fully repaid by 2015.
As of December 31, 2005, our long-term debt portfolio totaled NOK 32.7 billion, with a weighted average maturity of approximately 10.6 years and a weighted average interest rate of approximately 5.4 per cent per annum. As of December 31, 2004, our long-term debt portfolio totaled NOK 31.5 billion, with a weighted average maturity of approximately 11 years and a weighted average interest rate of approximately 5.0 per cent per annum. As of December 31, 2003, our long-term debt portfolio totaled NOK 33.0 billion, with a weighted average maturity of approximately 11 years and a weighted average interest rate of approximately 4.8 per cent per annum.
After the effect of currency swaps, our borrowings are 100 per cent in U.S. dollars.
Our financing strategy onsiders funding sources, maturity profile, currency mix, interest rate risk management instruments and the liquidity reserve, and we use a multicurrency liability model (MLM) to manage debt-related risks. Accordingly, in general, we select the currencies of our debt obligations, either directly when borrowing or through currency swap agreements, in order to optimize our debt portfolio based on underlying cash flow. Our borrowings are denominated in, or have been swapped into, U.S. dollars, because the most significant part of our net cash flow is denominated in that currency. In addition, we hedge our interest rate exposures through the use of interest rate derivatives, primarily interest rate swaps, based on an approved range for the interest reset profile of our total loan portfolio.
New long-term borrowings totaled NOK 0.4 billion in 2005, NOK 4.6 billion in 2004 and NOK 3.2 billion in 2003. We repaid approximately NOK 3.2 billion in 2005, approximately NOK 6.6 billion in 2004 and approximately NOK 2.8 billion in 2003. At December 31, 2005, NOK 1.1 billion of our borrowings was due for repayment within one year, NOK 8.7 billion was due for repayment between two and five years and NOK 24.0 billion was due for repayment after five years. This compares to NOK 3.0 billion, NOK 8.9 billion and NOK 22.5 billion, respectively, as of December 31, 2004, and NOK 3.2 billion, NOK 9.3 billion and NOK 23.7 billion, respectively, as of December 31, 2003.
The corporate financing, project financing and treasury functions provide a centralized service for overall funding activities, foreign exchange and interest rate management. Treasury operations are conducted within a framework of policies, risk limits and guidelines authorized and reviewed regularly by our Chief Financial Officer. Our liability management is conducted in cooperation with our corporate risk management department, and we use a number of derivative instruments. The internal control is reviewed regularly for risk assessment by our internal auditors. Further details regarding our risk management are provided in —Risk Management below.
Table of Principal Contractual Obligations and Other Commitments
The following table summarizes our principal contractual obligations and other commercial commitments as at December 31, 2005. The table below includes contractual obligations, but excludes derivatives and other hedging instruments. Obligations payable by Statoil to unconsolidated equity affiliates are included gross in the table below. Where Statoil has both an ownership interest and transport capacity cost for a pipeline in the consolidated accounts, the amounts in the table include the transport commitments that exceed Statoil’s ownership share. See also Item 11—Quantitative and Qualitative Disclosures about Market Risk.
| As at December 31, 2005 | ||||
| Payment due by period | ||||
Contractual obligations (in NOK million) | Total | Less than | 1-3 | 4-5 | After |
Long-term debt | 33,800 | 1,131 | 4,512 | 4,142 | 24,015 |
Finance lease obligations | 680 | 54 | 72 | 47 | 507 |
Operating leases | 15,184 | 3,121 | 5,601 | 3,017 | 3,445 |
Transport capacity and similar obligations | 48,874 | 4,853 | 9,333 | 7,563 | 27,125 |
Total contractual obligations | 98,538 | 9,159 | 19,518 | 14,769 | 55,092 |
Contractual obligations in respect of capital expenditure amounted to NOK 23 billion as at December 31, 2005, of which payments of NOK 13.5 billion are due within one year.
The projected pension benefit obligation of the group was NOK 22.6 billion and the fair value of plan assets amounted to NOK 20.3 billion as at December 31, 2005. Total prepaid pensions net of unrealized losses and unrealized prior service cost amounted to NOK 1.8 billion as at December 31, 2005.
Impact of Inflation
Our results in recent years have not been substantially affected by inflation. Inflation in Norway as measured by the general consumer price index during the years ended December 31, 2005, 2004 and 2003 was 1.8 per cent, 1.1 per cent and 0.5 per cent, respectively.
Critical Accounting Policies and Estimates
The consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States, which require us to make estimates and assumptions. We believe that of its significant accounting policies (see Note 2 to the consolidated financial statements), the following may involve a higher degree of judgment and complexity, which in turn could materially affect the net income if various assumptions were changed significantly.
Proved oil and gas reserves. Our oil and gas reserves have been estimated by our experts in accordance with industry standards under the requirements of the U.S. Securities and Exchange Commission (SEC). An independent third party has evaluated Statoil’s proved reserves estimates, and the results of such evaluation do not differ materially from our estimates. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements but not on escalations based upon future conditions.
Proved reserves are used when calculating the unit of production rates used for depreciation, depletion, and amortization. Reserve estimates are also used when testing upstream assets for impairment. Future changes in proved oil and gas reserves, for instance as a result of changes in prices, could have a material impact on unit of production rates used for depreciation, depletion and amortization and for decommissioning and removal provisions, as well as for the impairment testing of upstream assets, which could have a material adverse effect on operating income as a result of increased deprecation, depletion and amortization or impairment charges.
Exploration and leasehold acquisition costs. In accordance with Statement of Financial Accounting Standards (FAS) No. 19, we temporarily capitalize the costs of drilling exploratory wells pending determination of whether the wells have found proved oil and gas reserves. We also capitalize leasehold acquisition costs and signature bonuses paid to obtain access to undeveloped oil and gas acreage. Judgments on whether these expenditures should remain capitalized or expensed in the period may materially affect the operating income for the period.
Unproved oil and gas properties are assessed quarterly and unsuccessful wells are expensed. Exploratory wells that have found reserves, but classification of those reserves as proved depends on whether a major capital expenditure can be justified, may remain capitalized for more than one year. The main conditions are that either firm plans exist for future drilling in the license or a development decision is planned in the near future.
To illustrate the size of the applicable balance sheet item (capitalized exploratory drilling expenditures) subject to the judgments described above and the recorded effects of our judgment on amounts capitalized in prior years, we have included the following table, which provides a summary of capitalized exploration costs on assets in the exploration phase and the amount of previously capitalized exploration costs on assets in the exploration phase that have been expensed during the year:
Capitalized exploratory drilling expenditures that are pending the determination of proved reserves:
(In NOK million) | 2005 | 2004 | 2003 |
Capitalized January 1 | 2,277 | 2,747 | 2,550 |
Additions | 1,236 | 935 | 365 |
Reclassified to wells, equipment and facilities based on the determination of proved reserves(1) | (480) | (1,235) | (63) |
Expensed, previously capitalized exploration costs | (149) | (61) | (59) |
Foreign currency translation | 146 | (109) | (46) |
Capitalized December 31(2) | 3,030 | 2,277 | 2,747 |
(1) In addition, in 2004 NOK 238 million in exploration expenditure related to unproved reserves was reclassified to construction in progress due to the fact that the development activity commenced prior to the recognition of proved reserves in 2005.
(2) Capitalized exploration costs in suspense exclude signature bonuses and other acquired exploration rights of NOK 11,071 million, NOK 609 million and NOK 1,045 million as at the end of 2005, 2004 and 2003, respectively.
Impairment. We have significant investments in long-lived assets such as property, plant and equipment and intangible assets, and changes in our expectations of future value from individual assets may result in some assets being impaired, and the book value written down to estimated fair value. Making judgments of whether an asset is impaired or not is a complex decision that rests on a high degree of judgment and to a large extent on key assumptions.
Complexity is related to the modeling of relevant undiscounted future cash flows, to the determination of the extent of the asset for which impairment is to be measured, to consistent application throughout the group of relevant assumptions, and, in cases where the first test of undiscounted cash flows exceeding book value is not met, to establishing a fair value of the asset in question.
Impairment testing also requires long-term assumptions to be made concerning a number of often volatile economic factors such as future market prices, currency exchange rates and future output, among others, in order to establish relevant future cash flows. Long-term assumptions for major factors are made at group level, and there is a high degree of reasoned judgment involved in establishing these assumptions, in determining other relevant factors such as forward price curves or in estimating production outputs, and in determining the ultimate termination value of an asset. Likewise, establishing a fair value of the asset, when required, will require a high degree of judgment in many cases where there is no ready third party market in which to obtain the fair value of the asset in question.
The following is a summary of certain long-lived assets in our balance sheet at year end and the cost of impairments recorded during the years 2005, 2004 and 2003, respectively:
(in NOK million) | 2005 | 2004 | 2003 |
Net book value of property plant and equipment | 181,481 | 152,916 | 126,528 |
Net book value of intangible assets | 2,388 | 2,374 | 2,156 |
Impairment charged to profit and loss in the period | 2,211 | 315 | 182 |
Decommissioning and removal liabilities. We have significant legal obligations to decommission and remove offshore installations at the end of the production period. Legal obligations associated with the retirement of long-lived assets are to be recognized at their fair value at the time the obligations are incurred. Upon initial recognition of a liability, that cost is capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset.
It is difficult to estimate the costs of these decommissioning and removal activities, which are based on current regulations and technology. Most of the removal activities are many years into the future and the removal technology and costs are constantly changing. As a result, the initial recognition of the liability and the capitalized cost associated with decommissioning and removal obligations, and the subsequent adjustment of these balance sheet items, involve the application of significant judgment. As at year end 2005, Statoil had recognized NOK 3.6 billion in increased assets and liabilities related to asset retirement obligations amounting to NOK 20.0 billion.
Employee retirement plans. When estimating the present value of defined pension benefit obligations that represent a gross long-term liability in the consolidated balance sheet, and indirectly, the period’s net pension expense in the consolidated statement of profit and loss, we make a number of critical assumptions affecting these estimates. Most notably, assumptions made on the discount rate to be applied to future benefit payments, the expected return on plan assets and the annual rate of compensation increase have a direct and material impact on the amounts presented. Significant changes in these assumptions between periods can likewise have a material effect on the accounts.
Accumulated gains and losses in excess of 10 per cent of the greater of the projected benefit obligation (PBO) or the fair value of assets are amortized over the remaining service period of active plan participants. The implication of this is that although changes in balance sheet items may be significant due to changes in the assumptions described above, changes to the amounts amortized in the period are therefore not as significant.
Below is a specification of net losses not yet amortized, the annual amortizations of net losses due to assumptions made, and the key assumptions made for each year:
(in NOK million) | 2005 | 2004 | 2003 |
Unrecognized net loss (an asset in the balance sheet) | 3,811 | 2,685 | 4,248 |
Amortization of loss (an expense in the period) | 53 | 175 | 54 |
Weighted average assumptions for the year ended (balance sheet items) | 2005 | 2004 | 2003 |
Weighted average discount rate | 4.75% | 5.50% | 5.50% |
Weighted average expected return on assets | 5.75% | 6.50% | 6.00% |
Weighted average rate of compensation increase | 3.00% | 3.50% | 3.50% |
Derivative financial instruments and hedging activities. Statoil recognizes all derivatives on the balance sheet at fair value. Changes in fair value of derivatives that do not qualify as hedges are included in income.
The application of relevant rules requires extensive judgment and the choice of designation of individual contracts as qualifying hedges can impact the timing of recognition of gains and losses associated with the derivative contracts, which may or may not correspond to changes in the fair value of our corresponding physical positions, contracts and anticipated transactions, which are not required to be recorded at market value in accordance with Statement No. 133. Establishment of non-functional currency swaps in our debt portfolio to match expected underlying cash flows may result in gains or losses in the profit and loss statement as hedge accounting is not allowed, even if the associated economical risk of the transactions is considered.
When not directly observable in the market or available through broker quotes, the fair value of derivative contracts must be computed internally based on internal assumptions as well as directly observable market information, including forward and yield curves for commodities, currencies and interest. Although the use of models and assumptions are according to prevailing guidelines provided by FASB and best estimates, changes in internal assumptions and forward curves could have material effects on the internally computed fair value of derivative contracts, particularly long-term contracts, resulting in corresponding income or loss in the statement of profit and loss.
See —Risk Management below and Item 11—Quantitative and Qualitative Disclosures about Market Risk for details on the extent to which we assess market values of derivatives on sources other than quoted market prices and the sensitivities of recognized assets and liabilities to market risks.
Corporate income taxes. Statoil annually incurs significant amounts of corporate taxes payable to various jurisdictions around the world, and also recognizes significant changes to deferred tax assets and deferred tax liabilities, all according to our current interpretations of applicable laws, regulations and relevant court decisions. The quality of these estimates is highly dependent upon our ability to properly apply at times very complex sets of rules, to recognize changes in applicable rules and, in the case of certain valuation allowances, our ability to project future earnings from activities that may apply loss carry forward positions against future income taxes.
The following is a summary of income tax assets and liabilities recognized in the consolidated balance sheet, as well as the annual tax expense recorded in the consolidated statement of profit and loss:
(in NOK million) | 2005 | 2004 | 2003 |
Taxes payable in the balance sheet | 29,750 | 19,117 | 17,676 |
Short-term deferred tax assets | 3,733 | 0 | 0 |
Long-term deferred tax assets | 372 | 205 | 626 |
Long-term deferred tax liabilities | 43,347 | 44,270 | 37,849 |
Tax expense in the year | 60,039 | 45,425 | 27,447 |
Off-Balance Sheet Arrangements
As a condition for being awarded oil and gas exploration and production licenses, participants may be committed to drill a certain number of wells. At the end of 2005, Statoil was committed to participate in 16 wells off Norway and 16 wells abroad, with an average ownership interest of approximately 50 per cent. Statoil’s share of estimated expenditures to drill these wells amounts to approximately NOK 4 billion. Additional wells that Statoil may become committed to participating in depending on future discoveries in certain licenses are not included in these numbers.
Statoil has entered into agreements for pipeline transportation for most of its prospective gas sale contracts. These agreements ensure the right to transport the production of gas through the pipelines, but also impose an obligation to pay for booked capacity. In addition, the group has entered into certain obligations for entry capacity fees and terminal, processing, storage and vessel transport capacity commitments. The corresponding expense for 2005 was NOK 4.5 billion.
In 2004, Statoil signed an agreement with the U.S.-based energy company Dominion regarding additional capacity at the Cove Point LNG terminal in the U.S. The agreement involves annual terminal capacity of approximately 7.7 billion cubic meters of gas for a 20-year period with planned start-up in 2008, and is subject to approval from U.S. authorities. Pending such approval, no obligations related to the additional Cove Point capacity have been included in –Liquidity and Capital Resources–Table of Principal Contractual Obligations and Other Commercial Commitments at year end 2005.
Transport capacity and other minimum nominal obligations at December 31, 2005 are also included in -Liquidity and Capital Resources–Table of Principal Contractual Obligations and Other Commercial Commitments at year end 2005.
Risk Management
Overview. We are exposed to a number of different market risks arising from our normal business activities. Market risk is the possibility that changes in currency exchange rates, interest rates, refining margins and oil and natural gas prices will affect the value of our assets, liabilities or expected future cash flows. We are also exposed to operational risk, which is the possibility that we may experience, among others, a loss in oil and gas production or an offshore catastrophe. Accordingly, we use a “top-down” approach to risk management, which highlights our most important market and operational risks, and a sophisticated risk optimization model to manage these risks.
We have developed a comprehensive model, which encompasses our most significant market and operational risks and takes into account correlation, different tax regimes, capital allocation on various levels and value at risk, or VaR, figures on different levels, with the goal of optimizing risk exposure and return. Our model also utilizes Sharpe ratios, which provide a risk-adjusted return measure in the context of a specific risk taken, rather than an absolute rate of return, to measure the potential risks of various business activities. See details of our financing strategy above concerning the objective of our debt portfolio to mitigate currency exchange risks. Our Corporate Risk Committee, which is headed by our Chief Financial Officer and which includes, among others, representatives from our principal business segments, is responsible for reviewing, defining and developing our strategic market risk policies. The Corporate Risk Committee meets monthly to determine our risk management strategies, includ ing hedging and trading strategies and valuation methodologies.
We divide risk management into insurable risks which are managed by our captive insurance company operating in the Norwegian and international insurance markets, tactical risks, which are short-term trading risks based on underlying exposures and which are managed by line management, and strategic risks, which are long-term fundamental risks and are monitored by our Corporate Risk Committee, which advises and recommends specific actions to our Executive Committee. To address our tactical and strategic market risks, we have developed policies aimed at managing the volatility inherent in certain of these natural business exposures and in accordance with these policies we enter into various transactions using derivative financial and commodity instruments (derivatives). Derivatives are contracts whose value is derived from one or more underlying financial instruments, indices or prices, which are defined in the contract.
Strategic Market Risks. We are exposed to strategic risks, which we define as long-term risks fundamental to the operation of our business. Strategic market risks are reviewed by our Corporate Risk Committee with the objective of avoiding sub-optimization, reducing the likelihood of experiencing financial distress and supporting the group’s ability to finance future growth even under adverse market conditions. Based on these objectives, we have implemented policies and procedures designed to reduce our overall exposure to strategic risks. For example, our multicurrency liability management model discussed under —Liquidity above seeks to optimize our debt portfolio based on expected future corporate cash flow and thereby serves as a significant strategic risk management tool.
Tactical Market Risks. All tactical risk management activities occur within and are continuously monitored against established mandates.
Commodity price risk. Commodity price risk constitutes our most important tactical risk. To minimize the commodities price volatility and match costs with revenues, we enter into commodity-based derivative contracts, which consist of futures, options, over-the-counter (OTC) forward contracts, market swaps and contracts for differences related to crude oil, petroleum products, natural gas and electricity.
Derivatives associated with crude oil and petroleum products are traded mainly on the International Petroleum Exchange (IPE) in London, the New York Mercantile Exchange (NYMEX), in the OTC Brent market, and in crude and refined products swaps markets. Derivatives associated with natural gas and electricity are mainly OTC physical forwards and options, Nordpool forwards, and futures traded on the NYMEX and IPE.
Foreign exchange and interest rate risk. We are also subject to interest rate risk and foreign exchange risk. Interest rate risk and currency risk are assessed against mandates based on a pre-defined scenario. In market risk management and in trading, we use only well-understood, conventional derivative instruments. These include futures and options traded on regulated exchanges, and OTC swaps, options and forward contracts.
Foreign exchange risk. Fluctuations in exchange rates can have significant effects on our results. Our cash flows are largely in currencies other than NOK, primarily U.S. dollars. Cash receipts in connection with oil and gas sales are mainly in foreign currencies, while cash disbursements are to a large extent in NOK. Accordingly, our exposure to foreign currency rates exists primarily with U.S. dollars versus Norwegian kroner, European euro, Danish kroner, Swedish kroner and UK pounds sterling. We enter into various types of foreign exchange contracts in managing our foreign exchange risk. We use forward foreign exchange contracts primarily to risk manage existing receivables and payables, including deposits and borrowing denominated in foreign currencies.
Interest rate risk. The existence of assets and liabilities earning or paying variable rates of interest expose us to the risk of interest rate fluctuations. We enter into various types of interest rate contracts in managing our interest rate risk. We enter into interest rate derivatives, particularly interest rate swaps, to alter interest rate exposures, to lower funding costs and to diversify sources of funding. Under interest rate swaps, we agree with other parties to exchange, at specified intervals, the difference between interest amounts calculated by reference to an agreed notional principal amount and agreed fixed or floating interest rates.
Fair market values of financial and commodity derivatives. Fair market values of commodity based futures and exchange traded option contracts are based on quoted market prices obtained from NYMEX or IPE. The fair values of swaps and other commodity OTC arrangements are established based on quoted market prices, estimates obtained from brokers, and other appropriate valuation techniques. Where Statoil records elements of long-term physical delivery commodity contracts at fair market value under the requirements of FAS 133, such fair market value estimates are based on quoted forward prices in the market, underlying indexes in the contracts, and assumptions of forward prices and margins where market prices are not available. Fair market values of interest and currency swaps and other instruments are estimated based on quoted market prices, estimates obtained from brokers, prices of comparable instruments, and other appropriate valuation techniques. The fair value estimates approximate the gai n or loss that would have been realized if the contracts had been closed out at year end, although actual results could vary due to assumptions used.
The following table contains the net fair market value of OTC commodity and financial derivatives as so accounted for under FAS 133, as at December 31, 2005, based on maturity of contracts and the source of determining the fair market value of contracts, respectively:
Source of Fair Market Value | Net Fair Market Value | ||||
(in NOK million) | Maturity less | Maturity | Maturity | Maturity in excess of 5 years | Total net |
Commodity based derivatives: |
|
|
|
|
|
195 | (2) | 0 | 0 | 193 | |
Prices provided by other external sources | (64) | (9) | (4) | 0 | (77) |
Prices based on models or other valuation techniques | 0 | 0 | 0 | 0 | 0 |
Total commodity based derivatives | 131 | (11) | (4) | 0 | 116 |
Financial derivatives: |
|
|
|
|
|
Prices actively quoted | (2,033) | 896 | 1,302 | 1,235 | 1,400 |
Prices provided by other external sources | 0 | 0 | 0 | 0 | 0 |
Prices based on models or other valuation techniques | 0 | 0 | 0 | 0 | 0 |
Total financial derivatives | (2,033) | 896 | 1,302 | 1,235 | 1,400 |
In the above table, other external sources for commodities mainly relate to broker quotes. The fair market values of interest and currency swaps and other financial derivatives are computed internally by means of standard financial system models and based consistently on quoted market yield and currency curves.
The following table contains a reconciliation of changes in the fair market values of all commodity and financial derivatives, including exchange traded derivatives in the books at either December 31, 2005, or December 31, 2004, net of margin calls. Derivatives entered into and subsequently terminated during the course of the year 2005 have not been included in the table.
(in NOK million) | Commodity derivatives | Financial derivatives |
Net fair value of derivative contracts outstanding as at December 31, 2004 | 623 | 6 978 |
(599) | (2 452) | |
Fair value of new contracts entered into during the period | 3 | (1 944) |
Changes in fair value attributable to changes in valuation techniques or assumptions | 0 | (1 182) |
Other changes in fair values | (28) | 0 |
Net fair value of derivative contracts outstanding as at December 31, 2005 | (1) | 1 400 |
For further information, see Item 11–Quantitative and Qualitative Disclosures about Market Risk.
Derivatives and Credit risk. Futures contracts have little credit risk because organized exchanges are the counter-parties. The credit risk from Statoil’s OTC commodity-based derivative contracts derives from the counter-party to the transaction. Brent forwards, other forwards, swaps and all other OTC instruments are traded subject to internal assessment of creditworthiness of counter-parties, which are primarily oil and gas companies and trading companies.
Credit risk related to derivative instruments is managed by maintaining, reviewing and updating lists of authorized counter-parties by assessing their financial position, by monitoring credit exposure for counter-parties, by establishing internal credit lines for counter-parties, and by requiring collateral or guarantees when appropriate under contracts and required by internal policies. Collateral will typically be in the form of cash or bank guarantees from first class international banks. As at year end 2005, we had called and received a total of NOK 1.8 billion in cash as collateral for unrealized gains on OTC derivatives.
Credit risk from interest rate swaps and currency swaps, which are OTC transactions, derive from the counter-parties to these transactions. Counter-parties are highly-rated financial institutions. The credit ratings are, at a minimum, reviewed annually and counter-party risk is monitored to ensure exposure does not exceed credit lines and complies with internal policies. Non-debt related foreign currency swaps usually have terms of less than one year, and the terms of debt related interest swaps and currency swaps are up to 24 years, in line with that of corresponding hedged or risk managed long-term loans.
The following table contains the fair market value of OTC commodity and financial derivative assets, net of netting agreements and collateral as at December 31, 2005, split by our assessment of the counter-party’s credit risk:
(in NOK million) | Fair market value |
Counterparty-rated: |
|
Investment grade, rated A or above | 2,416 |
Other investment grade | 144 |
Non-investment grade or not rated | 83 |
Credit rating categories in the table above are based on the Statoil group’s internal credit rating policies, and do not correspond directly with ratings issued by the major credit rating agencies. Internal ratings are harmonized with external ratings where available, but could occasionally vary somewhat due to internal assessments. Consistent with Statoil policies, commodity derivative counter-parties have been assigned credit ratings corresponding to those of their respective parent companies, while there will not necessarily be a parent company guarantee from such parent companies if highly rated.
Operational Risks. We are also exposed to operational risks, including reservoir risk, risk of loss of oil and gas production and offshore catastrophe risk. In addition to our upstream installations which are insured at replacement cost, business interruption is covered for the majority of our production through our captive insurance company, which also has a reinsurance program. Under this reinsurance program, as of December 31, 2005, approximately 64 per cent of the approximately NOK 205 billion total insured amount was reinsured in the international reinsurance markets. Our captive insurance company also works with our corporate risk management department to manage other insurable operational risks.
The group’s downstream plants are also covered through our captive insurance company, which reinsures a major part of the risk in the international insurance market. Approximately 29 per cent of the risk is retained.
Like any other licensee, Statoil has unlimited liability for possible compensation claims arising from its offshore operations, including transport systems. Statoil has taken out insurance to cover this liability up to approximately USD 0.8 billion (NOK 4.8 billion) for each incident, including liability for claims arising from pollution damage.
Statoil Forsikring a.s is a member of two mutual insurance companies, Oil Insurance Ltd. and sEnergy Insurance Ltd. Membership of these companies means that Statoil Forsikring is liable for its proportionate share of any losses which might arise in connection with the business operations of the companies. Members of the mutual insurance companies have joint and several liability for any losses that arise in connection with the insured operations of the member companies.
Research and Development
In addition to the technology developed through field development projects, a substantial amount of our research is carried out at our research and technology development center in Trondheim, Norway. Our internal research and development is done in close cooperation with Norwegian universities, research institutions, other operators and the supplier industry.
Research expenditures were NOK 1,066 million, NOK 1,027 million and NOK 1,004 million in 2005, 2004 and 2003, respectively. See Item 4–Information on the Company–Business Overview-Technology, Research and Development for a further description of our research and development activity.
Corporate Targets
We use corporate targets in order to measure our progress in enhancing production, utilizing capital efficiently and enhancing operational efficiency. In late 2004 the executive committee set forth new targets for the fiscal year 2007 for the measures normalized return on average capital employed (normalized ROACE), production and normalized production cost. This section contains a discussion of those target measures and reports the results of those measures for the current period. For a discussion of historical and projected gross investments, see —Trend Information below.
The following discussion of corporate targets uses several measures which are “Non-GAAP financial measures”. Non-GAAP financial measures are defined by the U.S. Securities and Exchange Commission as measures that either exclude or include amounts that are not excluded or included in comparable measures calculated and estimated according to GAAP. These are return on average capital employed (ROACE), normalized return on average capital employed (normalized ROACE), normalized production cost per barrel and net debt to capital employed ratio. For more information on these measures and for a reconciliation of these measures to measures calculated in accordance with U.S. GAAP, see —Use and Reconciliation of Non-GAAP Financial Measures below.
Summary of targets 2007
We are targeting:
• a ROACE of 13.0 per cent on a normalized basis for the year 2007, assuming an average realized oil price of USD 22 per barrel, natural gas price of NOK 0.90 per scm, refining margin (FCC) of USD 5.0 per barrel, Borealis margin of EUR 140 per tonne and a NOK/USD exchange rate of 6.75. The normalization assumption related to Borealis margin is only relevant when reporting on achieved normalized ROACE for 2005 compared to the 2007 target. All prices and margins are adjusted for inflation from 2004; and
• oil and natural gas production of 1,400 mboe per day in 2007.
Further, we are committed to enhancing operational efficiency through 2007 by:
• reducing unit production costs to lower than NOK 22 per boe, normalized at a NOK/USD exchange rate of 6.75 for the international portfolio.
The 2007 targets represent Statoil’s assets as at the end of 2004. However, on a going-forward basis the 2007 targets are based on continued organic development of Statoil and exclude possible effects related to any additional major acquisitions or dispositions that were not known at the time the 2007 targets were set. Such major transactions may affect our targets materially and cause us to revise our targets as a result of the impact of such acquisitions or dispositions.
The forecasted production growth to 2007 is based on the current understanding of our reservoirs, our planned investments and development projects. There are a number of factors that could cause actual results and developments to differ materially from the targets included here, including, but not limited to, 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; natural disasters and other changes to business conditions. One of the main factors which could cause results to differ from our expectations would be possible delays in sanctioned development projects. For further discussion, see Item 3–Key information-Risk Factors.
The production target for 2007 of 1,400,000 boe per day is based on an average oil price of about USD 30 per barrel in the period 2005-07. If the oil price remains at today’s level (USD 60 per barrel) throughout the whole of 2006 and 2007, the PSA effect in 2007 will be in the order of 50,000 to 60,000 boe per day. Statoil will therefore make adjustments for PSA effects when reporting on production and production unit costs up to 2007.
The high oil price will also lead to increased exploration activity and higher investments as certain prospects become economic to develop in a higher oil price environment. This will have a negative effect on ROACE, where the effect of a high oil price is normalized. It is therefore probable that, given the assumptions for normalization which were set in 2004, the normalized ROACE in 2007 will be somewhat lower than the target of 13 per cent.
Return on Average Capital Employed
Our business is capital intensive. Furthermore, our capital expenditures include several significant projects that are characterized by lead times of several years and expenditures that individually may involve large amounts. Given this capital intensity, we use return on average capital employed, or ROACE, as a key performance indicator to measure our success in utilizing capital. We define ROACE as follows:
Return on Average Capital Employed = | Net Income + Minority Interest - After Tax Net Financial items |
Net Financial Debt + Shareholders’ Equity + Minority Interest |
Average capital employed reflects an average of capital employed at the beginning and the end of the financial period. In the calculation of average capital employed, Statoil makes certain adjustments to net interest-bearing debt, which makes the figure a Non-GAAP financial measure. For a reconciliation of the adjusted net interest-bearing debt to the most comparable GAAP measure, see —Use and Reconciliation of Non-GAAP Financial Measures below. Our historic ROACE using average capital employed with these adjustments for 2005, 2004 and 2003 was 27.6 per cent, 23.5 per cent and 18.7 per cent and, respectively.
ROACE and normalized ROACE are Non-GAAP financial measures. See –Use and Reconciliation of Non-GAAP Financial Measures.
For purposes of measuring our performance against our 2007 ROACE target, we assume an average realized oil price of USD 22 per barrel, natural gas price of NOK 0.90 per scm, refining margin (FCC) of USD 5.0 per barrel, Borealis margin of EUR 140 per tonne, and a NOK/USD exchange rate of 6.75. All prices and margins are adjusted for inflation from 2004. In the calculation of the normalized return, adjustments are made to exclude items of a non-frequent nature. These items are viewed as activities or events which management considers as being of such a nature that their inclusion into the ROACE calculation will not provide a meaningful indication of the company’s underlying performance. These assumptions do not reflect actual prices and margins at the time the assumptions were set or at any specific point in time and do not comprise our expectations with respect to the future movements of such prices and margins, but are based on movements over a broader time frame and function to allow comparability across periods. The 2007 target is based on organic development and therefore the effects of major acquisitions or dispositions not known at the time the targets were set will be excluded. Normalization is done in order to exclude factors that Statoil cannot influence from its performance targets. For reconciliation of the ROACE and normalized ROACE figures to items calculated in accordance with GAAP, see the table “ROACE calculation” in –Use and Reconciliation of Non-GAAP Financial Measures below.
Normalized ROACE was 11.7 percent in 2005.
In order to achieve our set of targets for 2007, including ROACE, and support our longer term ambitions, we continue to aim to allocate capital only to those projects that meet our financial return criteria.
Our ROACE in any financial period and our ability to meet our target ROACE will be affected by our ability to generate net income. Our level of net income is subject to numerous risks and uncertainties as described above. These risks include, among others, fluctuation in demand, retail margin, changes in our oil and gas production volumes and trends in the international oil industry.
Production cost per boe for the last 12 months was USD 3.44 per boe for the year 2005, USD 3.46 per boe for the year 2004 and USD 3.17 per boe for the year 2003. Correspondingly, the production costs in NOK were NOK 22.2 per boe for the year 2005, NOK 23.3 per boe for the year 2004 and NOK 22.4 per boe for the year 2003. Normalized production cost is a Non-GAAP financial measure as a result of its normalization at a set NOK/USD exchange rate. See —Use and Reconciliation of Non-GAAP Financial Measures.
For purposes of measuring our performance against our 2007 production unit cost target, we have been assuming a NOK/USD exchange rate of 6.75. Normalized production unit cost in 2005 was 22.3 NOK per boe.
Reserves replacement ratio
Proved oil and gas reserves were estimated to be 4,295 million boe at the end of 2005, compared to 4,289 million boe at the end of 2004 and 4,264 million boe at the end of 2003.
Proved reserves and changes to proved reserves are estimated in accordance with SEC definitions. The reserves replacement ratio is defined as the sum of proved reserves additions and revisions, divided by produced volumes in any given period.
Changes in proved reserves estimates most commonly originate from revisions of estimates due to observed production performance, extensions of proved areas through drilling activities, or inclusion of proved reserves in new discoveries through sanctioning of development projects. These are sources of proved reserves additions that result from continuous business processes, and could be expected to continue to add reserves at some level in the future.
Proved reserves may also be added or subtracted through the acquisition or disposition of assets.
Changes in proved reserves may also originate from factors outside of management control, such as changes in oil and gas prices. While higher oil and gas prices normally allow more oil and gas to be recovered from the accumulations, Statoil’s proved oil and gas reserves under PSAs and similar contracts will generally decrease as a result. This reflects the fact that we will receive smaller quantities of oil and gas under the cost recovery and profit sharing arrangements of these contracts as a result of the increased oil and gas prices. These changes are included in the revisions category in the table below.
Reserves in new discoveries are normally booked only when regulatory approval has been received, or when such approval is imminent. Most of the reserve additions are expected to be produced over the next 5-10 years, with some projects having time spans of up to 20-25 years.
Below is a table showing the reserves additions in each change category relating to the reserve replacement ratio for the period 2003-2005.
Line Item (mmboe) | 2005 | 2004 | 2003 |
Revisions and improved recovery | 141 | 165 | 206 |
Extensions and discoveries | 292 | 46 | 186 |
Purchases of reserves-in-place | 20 | 246 | 0 |
Sales of reserves-in-place | (19) | (29) | 0 |
Total reserve additions | 434 | 428 | 392 |
Production | (427) | (402) | (395) |
Net change in proved reserves | 7 | 26 | (3) |
A total of 434 mmboe proved reserves was added during 2005, of which 77 mmboe were proved developed reserves. The remaining 357 mmboe were proved undeveloped reserves.
The reserves replacement rate was 102 per cent in 2005, compared to 106 per cent in 2004 and compared to 99 per cent in 2003. The average replacement rate for the last three years was 102 per cent, including purchases and sales.
Reserves replacement ratio (three-year average) | 2005 | 2004 | 2003 |
Corporate | 1.02 | 1.01 | 0.95 |
E&P Norway | 0.84 | 0.76 | 0.79 |
International E&P | 2.46 | 3.60 | 2.96 |
Management aims for a reserves replacement ratio above 1 over time, but does not regard the reserves replacement ratio as a target measure against which the company’s progress is measured on an annual basis. The usefulness of this measure is limited by the volatility of oil prices, the influence of oil and gas prices on PSA reserve booking, the sensitivity relating to the timing of project sanctions, and the time lag between exploration expenditure and booking of reserves. Therefore this measure is not included in the set of corporate targets for 2007.
Production
Total average daily oil and natural gas production was 1,169,000 boe in 2005, compared to 1,106,000 boe in 2004 and 1,080,000 boe in 2003.
Our expected production growth through 2007 is based on the current characteristics of our reservoirs, our planned investments and development projects. The production target for 2007 is set at 1,400,000 boe per day, adjusted for PSA-effects as described above.
Trend information
Achieving the targeted growth in the coming years will require an increase in investments from the current level which will consequently depress ROACE in 2006. All of the projects expected to contribute to reaching this production target of 1,400,000 boe per day for 2007 have already been sanctioned. However, the PSA effect is expected to reduce produced volumes if today’s price level (USD 60 per barrel) is sustained, as described under -Corporate Targets above. If today’s price level is maintained throughout 2006, Statoil’s production in 2006 is expected to be about 1,200,000 boe per day. Based on the oil price assumption we made in 2004 (USD 30 per barrel), output was expected to be about 25,000 boe higher per day in 2006.Capital Expenditures
Set forth below are our capital expenditures in our four principal business segments for 2003-2005, including the allocation per segment as a percentage of gross investments.
Capital expenditures per segment in the years ended December 31, 2003-2005:
(in million NOK) | 2005 | % of total | 2004 | % of total | 2003 | % of total |
E&P Norway | 16,257 | 35 | 16,776 | 39 | 13,136 | 55 |
International E&P | 25,295 | 55 | 18,987 | 44 | 8,019 | 33 |
Natural Gas | 2,542 | 6 | 2,368 | 6 | 860 | 4 |
Manufacturing and Marketing | 1,630 | 4 | 4,162 | 10 | 1,546 | 6 |
Other | 470 | 1 | 551 | 1 | 530 | 2 |
Total | 46,194 | 100 | 42,844 | 100 | 24,091 | 100 |
Future capital expenditures are expected to amount to approximately NOK 110-115 billion over the three year period from 2005-2007, excluding NOK 13.2 billion related to the purchase of the deepwater assets in Gulf of Mexico in April 2005
The group had a step-up in exploration activities in 2005, and exploration expenditure in 2005 amounted to NOK 4.3 billion. A further step-up to a level of approximately NOK 6.5 billion is expected in 2006 and 2007. The group expects to participate in the drilling of 30-40 wells in 2006. However, no guarantees can be given with regards to the number of wells drilled, the cost per well and the results of drilling. Uncertainty related to the results of past and future drilling will influence the amount of exploration expenditure capitalized and expensed. See -Critical Accounting Principles and Estimates–Exploration and leasehold acquisition costs above.
Statoil uses the "Successful efforts" method of accounting for oil and natural gas producing activities. Expenditures to drill and equip exploratory wells are capitalized until it is clarified whether there are proved reserves. Expenditures to drill exploratory wells that do not find proved reserves, and geological and geophysical and other exploration expenditure are expensed. Unproved oil and gas properties are assessed quarterly; unsuccessful wells are expensed. Exploratory wells that have found reserves, but classification of those reserves as proved depends on whether a major capital expenditure can be justified, may remain capitalized for more than one year. The main conditions are that either firm plans exist for future drilling in the license or a development decision is planned in the near future.
Production cost per barrel is expected to increase on the NCS as a result of tail-end production at mature fields, if no measures are taken to reduce costs. The corporate initiatives introduced in 2004 are, among other things, expected to reduce cost levels. New international fields are expected in aggregate to reduce the group’s production cost per barrel.
This section describes our estimated capital expenditure for 2006 in respect of potential capital expenditure requirements for the principal investment opportunities available to us and other capital projects currently under consideration. The figure is based on an organic development of Statoil and excludes possible expenditures related to acquisitions. Therefore, the expenditure estimates and descriptions with respect to investments in the segment descriptions below could differ materially from the actual expenditures.
E&P Norway. A substantial portion of our 2006 capital expenditure is allocated to the ongoing development projects in Snøhvit and Ormen Lange, Gullfaks IOR and the satellites Skinfaks and Rimfaks which will be tied back to Gullfaks C, and Tyrihans, which will be tied to Kristin, as well as the late-life projects at Statfjord and Gullfaks. For more information on these projects, see Item 4–Information on the Company–Business Overview–Exploration and Production Norway.
International E&P. We currently estimate that a substantial portion of our 2006 capital expenditure will be allocated to the following ongoing and planned development projects: Agbami, Tahiti, Shah Deniz, In Amenas and ACG. For more information on these projects, see Item 4–Information on the Company–Business Overview–International Exploration and Production.
Natural Gas. The pipelines Langeled and Tampen link and the South Caucasus pipeline related to the Shah Deniz field pipelines are the projects requiring a high share of investment in the segment in 2006. We will continue focusing on increasing the capacity and flexibility of our gas transportation and processing infrastructure. This will be done through the expansion of the Kårstø processing plant, the Aldbrough gas storage project on the east coast of England and other investments. For more information on these projects, see Item 4–Information on the Company–Business Overview–Natural Gas.
Manufacturing and Marketing. We are focusing our capital expenditure on our retail network and upgrading of our refineries to increase flexibility and increase the value of the refined products.
Finally, it should be noted that we may alter the amount, timing or segmental or project allocation of our capital expenditures in anticipation or as a result of a number of factors outside our control including, but not limited to:
• exploration and appraisal results, such as favorable or disappointing seismic data or appraisal wells;
• cost escalation, such as higher exploration, production, plant, pipeline or vessel construction costs;
• government approvals of projects;
• government awards of new production licenses;
• partner approvals;
• development and availability of satisfactory transport infrastructure;
• development of markets for our petroleum and other products including price trends;
• political, regulatory or tax regime risk;
• accidents such as rig blowups or fires, and natural hazards;
• adverse weather conditions;
• environmental problems such as development restrictions, costs of regulatory compliance or the effects of petroleum discharges or spills; and
• acts of war, terrorism and sabotage.
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.
The following financial measures may be considered Non-GAAP financial measures:
• Return on Average Capital Employed (ROACE).
• Normalized Return on Average Capital Employed (normalized ROACE).
• Normalized 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, other 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.
Statoil uses normalized ROACE to measure the return on the capital employed, while excluding the effects of market developments over which Statoil has no control. Effects of changes in oil price, natural gas price, refining margin, Borealis margin and the NOK/USD exchange rate are therefore excluded from the normalized figure.
This measure is viewed by the company as providing a better understanding of Statoil’s underlying performance over time and across periods, by excluding from the performance measure factors that Statoil cannot influence. Statoil management makes regular use of this measure to evaluate its operations.
Beginning in 2005, the figures used for calculating the normalized ROACE are (each adjusted for an assumed annual inflation of 2.5 per cent from the basis year 2004):
• oil price of USD 22 per barrel
• natural gas price of NOK 0.90 per scm
• FCC refining margin of USD 5.0 per barrel
• petrochemical margin of EUR 140 per tonne
• NOK/USD exchange rate of 6.75
By keeping certain prices which are key value drivers, as well as the important NOK/USD exchange rate constant, Statoil is able to utilize this measure to focus on operating cost and efficiency improvements, and is able to measure performance on a comparable basis across periods. Such a focus would be more challenging to maintain in periods in which prices are high and exchange rates are favorable. Normalized results, however, should not be seen as an alternative to measures calculated in accordance with GAAP when measuring financial performance. The company reviews both realized and normalized results, when measuring performance. However, the company finds the normalized results to be especially useful when realized prices, margins and exchange rates are above the normalized set of assumptions.
Statoil also defines certain items to be of such a nature that they will not provide a good indication of the company’s underlying performance when included in the key indicators. These items are therefore excluded from calculations of adjusted and normalized ROACE.
Normalized ROACE is based on organic development and the figures for 2005 exclude the gain from the sale of the group’s shares in Borealis of NOK 1.5 billion and the write-down on South Pars of NOK 1.6 billion after tax. The capital employed is normalized for the effect of the acquisition of the assets in the Gulf of Mexico from EnCana in the second quarter of 2005, including the follow-up investments in the Tahiti development project.
The following table shows our ROACE calculation based on reported figures and normalized figures:
Calculation of nominator and denominator used in ROACE calculations (in NOK million) | 2005 | 2004 | 2003 |
Net income for the last 12 months | 30,730 | 24,916 | 16,554 |
Minority interest for the last 12 months | 765 | 505 | 289 |
| 937 | (1,947) | (496) |
Net income adjusted for minority interest and after tax net financial items (A1) | 32,432 | 23,474 | 16,347 |
Numerator adjustments for gain on sale of Borealis | (1,518) | n/a | n/a |
Numerator adjustments for South Pars write-down | 1,593 | n/a | n/a |
Effect of normalized prices and margins | (20,220) | n/a | n/a |
Effect of normalized NOK/USD exchange rate | 679 | n/a | n/a |
Normalized net income (A2) | 12,966 | n/a | n/a |
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Average capital employed (B1)(1) | 117,327 | 99,246 | 88,016 |
Adjusted average capital employed (B2)(1) | 117,300 | 99,768 | 87,361 |
Denominator adjustments 2005 on average capital employed for GoM transaction(2) | (6,838) | n/a | n/a |
Average capital employed adjusted for the GoM transaction (B3) | 110,462 | n/a | n/a |
ROACE calculation | 2005 | 2004 | 2003 |
Calculated ROACE using average capital employed (A1/B1) | 27.6% | 23.6% | 18.6% |
Calculated ROACE using adjusted average capital employed (A1/B2) | 27.6% | 23.5% | 18.7% |
Normalized ROACE (A2/B3) | 11.7% | n/a | n/a |
(1) See Use and Reconciliation of Non-GAAP Financial Measures–Net debt to capital employed below for a reconciliation of average capital employed and adjusted average capital employed. Average capital employed used when calculating ROACE is the average of the opening and closing balance of a year.
(2) The capital employed related to this acquisition was included in the closing balance of the period, but not in the opening balance, which entails an effect on average capital employed of approximately 50 per cent of this amount.
Normalized production cost per barrel in NOK 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 NOK/USD exchange rate is held constant.
Normalized production costs per boe is reconciled in the table below to the most comparable GAAP measure, production cost per boe.
Production costs per boe | 2005 | 2004(1) | 2003 |
Total production costs last 12 months (in NOK million) | 9,429 | 9,336 | 8,747 |
Lifted volumes last 12 months (million boe) | 426 | 400 | 391 |
Average NOK/USD exchange rate | 6.44 | 6.74 | 7.07 |
Production cost per boe (USD/boe) | 3.44 | 3.46 | 3.17 |
Calculated production cost (NOK/boe) | 22.2 | 23.3 | 22.4 |
Total production costs last 12 months (in NOK million) | 9,429 | ||
Production costs last 12 months International E&P (in USD million) | 259 | ||
Normalized exchange rate (NOK/USD) | 6.75 | ||
Production costs last 12 months International E&P (in NOK million), normalized at 6.75 | 1,747 | ||
Total production costs last 12 months in NOK (normalized) | 9,501 | ||
Lifted volumes last 12 months (million boe) | 426 | ||
Production cost (NOK/boe) normalized at NOK/USD 6.75 | 22.3 |
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 additional adjustments are made for two different reasons:
• Since different legal entities in the group lend to and borrow from banks, project financing through an external bank or similar will not be netted in the balance sheet, and will over-report the debt stated in the balance sheet compared to the underlying exposure in the group.
• Some interest–bearing elements are classified together with non-interest-bearing elements, and are therefore included when calculating the net interest-bearing debt.
The net interest-bearing debt adjusted for these two items is included in the average capital employed, which is also used in the calculation of ROACE and normalized ROACE.
The table below reconciles net interest-bearing debt, capital employed and net debt to capital employed ratio to the most directly comparable financial measure or measures calculated in accordance with GAAP.
Calculation of capital employed (in NOK million) | 2005 | 2004 | 2003 |
Total shareholders’ equity | 106,644 | 85,030 | 70,174 |
Minority interest | 1,492 | 1,616 | 1,483 |
Total equity and minority interest (A) | 108,136 | 86,646 | 71,657 |
Short-term debt | 1,529 | 4,730 | 4,287 |
Long-term debt | 32,669 | 31,459 | 32,991 |
Gross interest-bearing debt | 34,198 | 36,189 | 37,278 |
Cash and cash equivalents | (7,025) | (5,028) | (7,316) |
Short-term investments | (6,841) | (11,621) | (9,314) |
Cash, cash equivalents and short-term investments | (13,866) | (16,649) | (16,630) |
Net interest-bearing debt (B1) | 20,332 | 19,540 | 20,648 |
Capital employed (A+B1) | 128,468 | 106,186 | 92,305 |
Average capital employed | 117,327 | 99,246 | 88,016 |
Net debt to capital employed (B1/(A+B1)) | 15.8% | 18.4% | 22.4% |
Calculation of adjusted net interest-bearing debt |
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Adjustment of net interest-bearing debt for project loan(1) | (2,623) | (2,209) | (1,500) |
Adjustment of net interest-bearing debt for other items(2) | 1,783 | 2,995 | 1,758 |
Net interest-bearing debt after adjustments (B2) | 19,492 | 20,326 | 20,906 |
Calculation of adjusted capital employed |
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Adjusted capital employed (A+B2) | 127,628 | 106,972 | 92,563 |
Average adjusted capital employed | 117,300 | 99,768 | 87,361 |
Net debt to capital employed (B2/(A+B2)) | 15.3% | 19.0% | 22.6% |
(1) Adjustment for inter-company project financing through an external bank.
(2) Adjustment made for deposits received for financial derivatives. Although these deposits are classified as liquid assets, they are interest-bearing and are therefore not excluded from gross interest-bearing debt when calculating our net interest-bearing debt.
Item 6 Directors, Senior Management and Employees
Directors and Senior Management
Management
Our management is vested in our board of directors and our Chief Executive Officer. The Chief Executive Officer is responsible for the day-to-day management of our company in accordance with the instructions, policies and operating guidelines set out by our board of directors.
The business address of the directors, executive officers and corporate assembly members is c/o Statoil at the corporate headquarters in Stavanger, Norway.
Board of Directors
Our articles of association require that our board of directors consists of a minimum of five and a maximum of 11 members. Currently, we have nine directors. The members of the board have extensive and relevant experience from Norwegian and international business activities. Members of the board of directors serve two-year terms. The members of the board are primarily recruited from the Norwegian business community.
Our executive management is not represented on the board. As required by Norwegian companies’ law, our employees are entitled to be represented by three board members. The corporate assembly has elected the current board of directors. The current term of office for all directors expires in May 2006. There are no directors’ service contracts that provide for benefits upon termination of employment.
Our directors, their place of residence, age and their position are identified below.
Name | Place of Residence | Age | Position |
Jannik Lindbæk | Oslo, Norway | 67 | Chairman |
Kaci Kullmann Five | Bærum, Norway | 55 | Director |
Finn A Hvistendahl | Oslo, Norway | 64 | Director |
Grace Reksten Skaugen | Oslo, Norway | 52 | Director |
Knut Åm | Stavanger, Norway | 62 | Director |
Ingrid Wiik | New York, USA | 61 | Director |
Lill-Heidi Bakkerud(1) | Bamble, Norway | 42 | Director |
Stein Bredal(1) | Stavanger, Norway | 55 | Director |
Morten Svaan(1) | Trondheim, Norway | 49 | Director |
(1) Elected by the employees.
Jannik Lindbæk was appointed Chairman of the board with effect from November 1, 2003. Mr. Lindbæk has extensive experience both as a business leader and from international activities, as well as knowledge of the oil and gas business. From 1976 to 1985 he was President and Chief Executive Officer in the Storebrand Group, a leading player in the Norwegian markets for general insurance, pensions, life and health insurance, banking and asset management. From 1986 to 1994 Mr. Lindbæk was Chief Executive Officer in Nordiska Investeringsbanken (Nordic Investment Bank), Helsinki, Finland and from 1994 to 1999 he was Executive Vice President of International Finance Corporation (World Bank Group), Washington D.C. He has been Chairman of the board of Gaz de France Norge, Saga Petroleum and Den norske Bank. Mr. Lindbæk is Chairman of the Boards of Bergen International Festival, Transparency International Norge, Plan International Norge and Gearbulk, and a director of the board of Kristian Gerhard Jebsen Skipsrederi.
Kaci Kullmann Five was elected to the board of directors in August 2002. In the period September 29, 2003 to November 1, 2003 she was acting chairman of the board of directors and effective November 1, 2003, she was appointed Deputy Chairman of the board of directors. Ms. Five is a public affairs consultant. In the period 1981 to 1997 she was a member of the Norwegian Parliament and in the period 1989 to 1990 she was minister for Trade and Shipping in the Norwegian Government. Ms. Five was leader of the Norwegian Conservative Party from 1991 to 1994. Currently, Ms. Five is a director of the boards of NMD Grossisthandel, Vitus Apotek AS, Asker og Bærum Budstikke ASA and Bluewater Insurance ASA. She is also a member of the Norwegian Nobel Committee appointed by the Norwegian Parliament.
Finn A Hvistendahl was elected to the board of directors in April 1999, and is the chairman of the audit committee. Mr. Hvistendahl is a business development consultant in Oslo. Previously, he held senior positions in Norsk Hydro and was Chief Executive Officer of Den norske Bank ASA. Currently, he is Chairman of the board of directors of Kredittilsynet (The Financial Supervisory Authority of Norway), and was until recently a member of the board of Dyno Novel AS. Mr. Hvistendahl has an engineering degree in industrial chemistry from The Norwegian University of Science and Technology.
Grace Reksten Skaugen was elected to the board of directors in June 2002. Ms. Skaugen is an independent consultant. She was a Director within Corporate Finance at Enskilda Securities, Oslo, from 1994 until she joined the board of Statoil in 2002. Previously she has worked in venture capital and shipping at Aircontactgruppen in Oslo and Fearnley Finance Ltd. in London. She did postdoctoral research in the field of microelectronics at Columbia University in New York. Ms. Skaugen has been a board member of Storebrand ASA, Hilmar Rekstens Almennyttige Fond (Art Foundation), Geelmuyden-Kiese and a member of the Norwegian WWF Council and Fundraising Committee. Currently, Ms. Skaugen is chairman of the board of Entra Eiendom, a company directly owned by the Norwegian state, the deputy chairman of Opera Software ASA and a board member of Tandberg ASA, both listed on the Oslo Stock Exchange. She is also a board member of Investor AB and Atlas Copco AB, both listed Swedish companies. Ms. S kaugen has a PhD in laser physics from Imperial College of Science and Technology, London University, and an MBA from BI Norwegian School of Management.
Knut Åm was elected to the board of directors in April 1999. Mr. Åm is an independent technology and business development consultant located in Stavanger. He is a former Senior Vice President and head of Exploration and Production of Phillips Petroleum. Previously he has held positions with the Geological Survey of Norway, the Norwegian Petroleum Directorate and Statoil, and he has been adjunct professor of geophysics at the University of Bergen. He has also been Chairman of the board of the Norwegian Oil Industry Association, Christian Michelsen Research and Hitec ASA and President of the Norwegian Petroleum Society and the Norwegian Geological Council. He is presently Chairman of the Industrial Council of the Norwegian Academy of Technological Sciences, Chairman of the board of IOR-Chemco AS, EnVision AS and EnVision StreamLine AS, and board member of Badger Explorer ASA, Petrostreamz AS and the Physics of Geological Processes-Center of Excellence at the University of Oslo. Mr. Åm has a degree in geological and geophysical engineering from The Norwegian University of Science and Technology in Trondheim.
Ingrid Wiik was elected to the board of directors in June 2005. Ms. Wiik is currently vice chair, president and CEO of Alpharma in New York, USA. Since 1983 she has held various managerial posts in Apothekernes Laboratorium/Alpharma, and has been CEO of Alpharma since 2000. Ms. Wiik is a director of Coloplast in Denmark and Norske Skog in Norway.
Lill-Heidi Bakkerud was elected to the board of directors in April 2004 and serves as an employee-elected representative to the board. She has also served in this position previously. Ms. Bakkerud is the full-time union official for Statoil for the Norwegian Oil and Petrochemical Workers Union. She trained as a process/chemistry technician and worked at the petrochemical complex in Bamble and on the Gullfaks field. At present, Ms. Bakkerud is on leave from Gullfaks to carry out her union tasks.
Stein Bredal was elected to the board of directors in April 2000 and serves as an employee-elected representative to the board. He is Materials Coordinator on the Gullfaks field and has worked with Statoil since 1985. Mr. Bredal represents the Confederation of Vocational Unions where he is a full-time union official.
Morten Svaan was elected to the board of directors in June 2004 as an employee-elected representative to the board. He was a union official for NIF/Tekna from 2000 to 2004. Mr. Svaan has a PhD in chemistry from The Norwegian University of Science and Technology and has completed a one year Foundation Program in Business Administration at The Norwegian School of Management. He has worked with Statoil since 1985 in the Manufacturing and Marketing, Petrochemical and Research and Development units. Mr. Svaan is currently working as a project leader within HSE, with a focus on security in the Technology and Projects unit.
Audit Committee
The board of directors established an audit committee in August 2003. A new instruction for the audit committee was adopted by the board of directors on February 11, 2005. The board elects up to four of its members to serve on the audit committee. The current members of the audit committee are Finn A Hvistendahl (chairman), Knut Åm, Ingrid Wiik and Morten Svaan. The audit committee is a sub-committee under the board of directors and its objective is to perform more thorough assessments of specific matters within the Statoil Group and report to the board of directors. The audit committee is instructed to assist the board’s oversight of issues such as(1) the quality and integrity of the company’s financial statements and related disclosure,(2) the external auditor’s qualifications and independence,(3) the performance of the external auditor subject to the requirements of Norwegian law,(4) the performance of the company’s internal a udit function, internal controls and risk management and risk audit function,(5) the company’s compliance with legal and regulatory requirements, including the requirements related to the listing on stock exchanges, and(6) compliance with the group’s ethical rules, including the group’s compliance activities relating to corruption.
The internal audit function reports directly to the board of directors and to the Chief Executive Officer. The audit committee assists the board in overseeing this function. The audit committee also receives regular briefings and reports on internal control and ethical issues.
Under Norwegian law, our external auditor is elected by our shareholders at the Annual General Meeting. The audit committee makes a recommendation to the board of directors in respect of the appointment of the external auditor based upon its evaluation of the qualifications and independence of the auditor to be proposed for election or re-election. The audit committee meets at least six times a year, and meets separately with the internal auditor and the external auditor on a regular basis.
The audit committee is also charged with reviewing the scope of the audit and the nature of any non-audit services provided by external auditors. The external auditors report directly to the audit committee on a regular basis. The audit committee also maintains procedures for the receipt, retention and treatment of complaints received by the company regarding accounting, internal controls or auditing matters and for the confidential, anonymous submission by employees of the company of concerns regarding accounting or auditing matters. The audit committee has the authority to engage independent advisors to assist it in carrying out its duties.
Compensation Committee
The board of directors established a compensation committee effective January 1, 2005. The compensation committee is a sub-committee under the board of directors and was established to assist the board in(1) the further development of Statoil’s reward philosophy and strategy generally, and more specifically with regard to compensation of the CEO,(2) devising internally consistent and externally competitive total compensation programs in order to attract, retain and reward the CEO and key executives for performance related to achievements of financial goals, values and leadership approach, and(3) providing guidance, direction and monitoring of Statoil’s compensation programs with respect to the long-term interest of the shareholders.
The Committee is comprised of three members from the Board. The Chairman of the Board is the Chairman of the Committee, and the two other members are Grace Reksten Skaugen and Knut Åm.
Executive Committee
An executive committee is not required under Norwegian corporate law, but we established the committee as part of the overall organization of our company. Each member of the executive committee supervises separate business areas or staff units. Although the CEO is responsible for making decisions on important matters not requiring the decision of the board of directors, as well as all matters referred to him by the board, the executive committee has an advisory role. The board of directors has granted Helge Lund, Eldar Sætre and Erling Øverland the power of procuration, which under Norwegian law essentially empowers each of them to act on behalf of our company in all matters relating to our normal operations.
The members of our executive committee, their place of residence, age and position are identified below.
Name | Place of Residence | Age | Position |
Helge Lund | Bærum, Norway | 43 | President and Chief Executive Officer |
Eldar Sætre | Sandnes, Norway | 50 | Chief Financial Officer and Executive Vice President |
Peter Mellbye | Stavanger, Norway | 56 | Executive Vice President, International Exploration & Production |
Terje Overvik | Sola, Norway | 54 | Executive Vice President, Exploration and Production Norway |
Rune Bjørnson | Sandnes, Norway | 47 | Executive Vice President, Natural Gas |
Jon Arnt Jacobsen | Stavanger, Norway | 48 | Executive Vice President, Manufacturing & Marketing |
Margareth Øvrum | Bergen, Norway | 47 | Executive Vice President, Technology & Projects |
Nina Udnes Tronstad | Inderøy, Norway | 47 | Executive Vice President, Health, Safety and the Environment |
Jens R Jenssen | Oslo, Norway | 52 | Executive Vice President, Human resources |
Reidar Gjærum | Oslo, Norway | 45 | Executive Vice President, Communication |
Helge Lund was appointed President and Chief Executive Officer on March 7, 2004, and assumed his position on August 15, 2004. Mr. Lund came from the position of Chief Executive of Aker Kvaerner, and from 1999 until he joined Statoil, he held a number of positions in the Aker RGI system, among them the position as Deputy Chief Executive and Chief Operating Officer, before becoming Chief Executive Officer of Aker Kværner in 2002. For a period he was also appointed to the board of directors of Kvaerner. Mr. Lund joined the Hafslund Nycomed industrial company in 1993, and from 1997, he was deputy managing director of Nycomed Pharma for a period of two years. Before then, Mr. Lund was a political advisor in the Conservative Party's parliamentary group and a consultant at McKinsey & Co. Mr. Lund graduated as a business economist from the Norwegian School of Economics and Business Administration (NHH) in Bergen. He also has a master of business administration (MBA) from the In sead business school in France.
Eldar Sætre became Chief Financial Officer and Executive Vice President on September 1, 2004 after he had been acting in this position since September 30, 2003. Mr. Sætre was senior vice president for corporate control, planning and accounting since 1998 and senior vice president for corporate planning and control in the period from 1995 to 1998. Before then, his positions included controller for Gullfaks (1985-1989), commercial manager for Bergen Operations (1989-1992) and controller in E&P Norway (1992-1995). Mr. Sætre joined the group in 1980. He graduated with a Masters of Science degree in Business from the Norwegian School of Economics and Business Administration (NHH) in 1980.
Peter Mellbye took over as Executive Vice President, International Exploration & Production on September 1, 2004, after he had served as Executive Vice President of Natural Gas since 1992. Employed at Statoil since 1982, Mr. Mellbye has held numerous positions. Most recently, Mr. Mellbye served as President of the Natural Gas business segment from 1990 to 1992 and as Vice President of Natural Gas Marketing from 1982 to 1990. Currently, Mr. Mellbye is a member of the board of the Energy Policy Foundation of Norway, and was previously a member of the boards of Siemens AS and Institut Francais du Pétrole in France. Mr. Mellbye graduated from the Universities of Oslo and Bergen with a degree in political science in 1977.
Terje Overvik has been Executive Vice President, Exploration & Production Norway since September 1, 2004. He previously served as Executive Vice President for Technology from August 19, 2002. Mr. Overvik has held a number of different posts in Statoil, including platform manager for the Statfjord A platform in the North Sea from 1992 to 2000, and Vice President for Statfjord operations from 2000 to 2002. He holds a PhD from The Norwegian University of Science and Technology (NTNU) in Trondheim, where he also worked as an associate professor and researcher before joining Statoil in 1983.
Rune Bjørnson was appointed Executive Vice President, Natural Gas on September 1, 2004. Mr. Bjørnson came from the position of Senior Vice President for Supply and Transport in Statoil’s Natural Gas business area. Mr. Bjørnson was managing director of Statoil’s operations in the UK from 2001 to 2003. Since 1990, he has held a number of executive positions in the natural gas area, and he also performed market analysis work for the group when he joined Statoil in 1985. From 1999 to 2001 Mr. Bjørnson was chair of the Gas Negotiating Committee (GFU). He has an MSc in Economics from the University of Bergen.
Jon Arnt Jacobsen has been Executive Vice President, Manufacturing & Marketing since September 1, 2004. He came from the position of Senior Vice President for group finance in Statoil, which he had held since 1998. He previously held the position of General Manager and head of the Singapore branch at Den norske Bank ASA (DnBNor). From 1992 to 1995, Mr. Jacobsen headed the industrial section of DnBNor’s corporate customer division, having previously held a number of different positions in DnBNor’s banking organization for the oil and gas industry over a seven-year period. He worked from 1983 to 1985 as a downstream market analyst for Esso Norge. Mr. Jacobsen was a member of the board of Mesta AS from 2002 to 2004. He has a business degree from the Norwegian School of Management and an MBA from the University of Wisconsin.
Margareth Øvrum was appointed Executive Vice President, Technology & Projects on March 30, 2005. She previously held the position of Executive Vice President for Health, Safety and the Environment since September 1, 2004. Before then, she was Senior Vice President for operations support in Exploration & Production Norway and head of Statoil’s Bergen office. Before taking up her appointment in Bergen in 2000, Ms. Øvrum held a number of supervisory posts offshore on Gulllfaks and Veslefrikk over a 10-year period, and was the group’s first female platform manager. From 1987 to 1991, Ms. Øvrum held various managerial posts onshore linked to the start-up, operation and maintenance of Statoil’s operations in the Tampen area. She joined Statoil in 1982, working on strategic analysis. Ms. Øvrum is a member of the board of Elkem, and a member of the committee of shareholders’ representatives at Storebrand ASA. She was previously the chair of the board of directors of Helse Bergen and a member of the boards of University of Bergen and Siemens. She has a degree in engineering from The Norwegian University of Science and Technology (NTNU), specializing in technical physics.
Nina Udnes Tronstad was appointed Executive Vice President for Health, Safety and Environment on March 30, 2005. She came from the position as Vice President Production for the Kristin Field Development Project, a position she had held since November 2001. From 2000 until 2001, she was Vice President Business Development in Exploration & Production Norway. In the four-year period 1996-2000 she was Senior Vice President Information Technology in Statoil. From 1994 until 1996 she was Vice President Supply and Logistics in Statoil’s Swedish retail company. During her first years in Statoil, she held different professional and managerial positions within research and development and within Statoil’s refinery operations. She is currently a member of the board of Eitzen Maritime Services ASA. She joined Statoil in 1983 after finishing a degree in Chemical engineering from The Norwegian University of Science and Technology (NTNU).
Jens R Jensen was appointed Executive Vice President, Human Resources on October 18, 2004. He came from the post of Senior Vice President for Human Resources at Aker Kvaerner ASA, a global provider of engineering and construction services, technology products and integrated solutions. He has held a number of senior positions in this area since 1991 in Aker AS, Aker Oil & Gas Technology and Aker Maritime ASA. From 1982 to 1986, Mr. Jenssen worked with human resources at Norwegian classification society Det Norske Veritas. He then spent several years – most recently in 2001 and 2002 – as an independent consultant to major companies in banking, finance and insurance, research, media, technology and manufacturing. Mr. Jensen holds a degree in psychology from the University of Oslo.
Reidar Gjærum took over as Executive Vice President for Corporate Communication on May 1, 2005. He came from the position of Executive Vice President for communications and marketing in the IT company EDB Business Partner. From 1993 to 1996 Mr Gjærum was communications director in the Confederation of Norwegian Business and Industry (NHO). From 1996 to 2001 he held a number of executive positions in Telenor, including that of director of external communications. He then became managing director of the JKL Woldsdal consultancy (now JKL Oslo), a post he held until 2003 when he joined EDB Business Partner as Executive Vice President for communications and marketing. Mr Gjærum attended the Program for Management Development at Harvard Business School in Boston, USA.
Corporate Assembly
Our corporate assembly consists of 12 members. The general meeting elects eight members, and our employees elect an additional four members.Our corporate assembly has a duty to control the board of directors and our Chief Executive Officer in their management of our company. Norwegian companies law imposes a fiduciary duty on the corporate assembly to our shareholders. The corporate assembly communicates its recommendations concerning the board of directors’ proposals about the annual accounts, balance sheets, allocation of profits and coverage of losses of our company to the general meeting. The corporate assembly renders decisions, based on the board’s proposals, in matters related to substantial investments, measured in terms of the total resources of our company, and matters regarding rationalizations or restructurings of the operations of the company which will result in a major change or reorganization of the workforce. The corporate assembly is also responsible for electing and removing our board of directors. The term of office of the corporate assembly members is two years and the current term of office expires in May 20 06.
Set forth below is a list of the current members of our corporate assembly, their place of residence, age and occupation.
Name | Place of Residence | Age | Position |
Anne Kathrine Slungård | Trondheim, Norway | 41 | Marketing Director, Entra Eiendom, Trondheim, Norway |
Kjell Bjørndalen | Skotselv, Norway | 58 | Chairman of the Norwegian Trade Union; Fellesforbundet, Oslo, Norway |
Kirsti Høegh Bjørneset | Ålesund, Norway | 42 | Attorney, Tømmerdal & Co, Ålesund, Norway |
Erlend Grimstad | Oslo, Norway | 47 | Executive Vice President, Umoe AS, Oslo, Norway |
Anne Britt Norø | Bodø, Norway | 49 | Cand. Jur., Team Bodø KF, Bodø, Norway |
Wenche Meldahl | Stavanger, Norway | 59 | MBA, Stavanger, Norway |
Per Inge Søreng | Tromsø, Norway | 58 | Office manager, IF, Tromsø, Norway |
Asbjørn Rolstadås | Trondheim, Norway | 61 | Professor at The Norwegian University of Science and Technology, Trondheim, Norway |
Arvid Færaas | Vormedal, Norway | 42 | Union official, NOPEF (Statoil) |
Per Helge Ødegård | Porsgrunn, Norway | 42 | Union official, Lederne (Statoil) |
Hans M Saltveit | Haugesund, Norway | 33 | Union official, YS (Statoil) |
Åse Karin Staupe | Stavanger, Norway | 38 | Sector Manager, Tekna (Statoil) |
Compensation
Compensation to the Board of Directors, Executive Committee and Corporate AssemblyIn 2005, total remuneration of NOK 510,000 was paid to the members of the corporate assembly, NOK 2,300,000 to the board of directors and NOK 23,400,353 to the members of the executive committee, excluding compensation paid to the Chief Executive.
Chief Executive Officer Helge Lund received in 2005 NOK 5,128,647 in salary and other remuneration (including pension premium paid). According to his contract, Helge Lund is entitled to severance pay equivalent to two annual salaries, excluding term of notice of six months, when the resignation is a request from the board. In addition, Helge Lund is entitled, under specific terms, to a pension amounting to 66 per cent of pensionable salary after reaching the age of 62. The full service period is 15 years and the benefits are independent of any future changes in Norwegian National Insurance (Folketrygden). Based on performance, the board will assess an annual performance payment for Helge Lund. This payment may amount to a maximum of 30 per cent of base salary.
A dispute regarding pension arrangements for Olav Fjell, the former Chief Executive Officer, was settled in 2005.
A performance pay system has also been established for the other members of the corporate executive committee, senior vice presidents and vice presidents. This entails a variable remuneration based on pre-determined goals. The scheme allows for a bonus of 10 per cent of base salary on achieving set goals, with a ceiling of 20 per cent for results that clearly exceed these goals.
If resigning at the request of the company, members of the corporate executive committee, other than the CEO, are on a general basis entitled to severance pay equivalent to 12 months salary, including a six month term of notice. The pension rights follow the general system in Statoil ASA. Executive Vice President Peter Mellbye is entitled to severance pay including term of notice equivalent to 24 months salary, if resigning at the request of the company. Peter Mellbye is entitled, under specific terms, to a pension after reaching the age of 60. The pension will amount to 66 per cent of pensionable salary.
Pension Benefits
We provide pension benefits to the majority of the group’s employees entitling them to defined future pension benefits. The amounts of benefits provided are generally based on years of service and final salary levels.
Employees in the parent company, and the majority of the Norwegian subsidiaries, are covered by Statoil’s pension funds. These funds are organized as independent trusts. The major part of their assets are invested in Norwegian and foreign bonds and shares, as well as in real estate in Norway. Employees in subsidiaries are partly insured through their own pension funds or through collective pension schemes in various insurance companies.
The projected benefit obligation at year end 2005 was NOK 22,568 million, whereas the estimated fair value of plan assets at the end of the same period amounts to NOK 20,347 million.
Share Saving Plan
Statoil ASA has a common bonus scheme for its employees. Employees may save Statoil shares up to a maximum of 5 per cent of each employee’s base salary. If the shares are kept for two full calendar years, the employee will be granted one share for each two purchased. The scheme was introduced in 2004. In 2005, approximately 8,000 employees took part in the scheme, most of them in Norway. In addition to Norway, the scheme is available for employees in 13 different countries.
Board Practices
In keeping with business practice in Norway, the board of directors of Statoil does not adopt its decisions through committees, but in the full board, even though Statoil has an audit committee and a compensation committee to prepare certain issues for the board of directors and support the board of directors in their responsibilities for management and control of the company.
Employees
As of December 31, 2005, we had 25,644 employees, of whom we employed 12,214 in Norway. The remaining employees were employed outside of Norway, with more than 100 employees in each of Poland, Ireland, Denmark, Sweden, Lithuania, Latvia, Estonia, the UK, Russia and the Faroe Islands.The table below sets forth the number of employees in each business area and the corporate technical service unit as at the end of 2005, 2004 and 2003, and the numbers of employees inside and outside of Norway. The table does not include employees of affiliated companies.
| Number of employees as of December 31, | ||||||||
| 2005 | 2004 | 2003 | ||||||
| Norway | Outside Norway | Total | Norway | Outside Norway | Total | Norway | Outside Norway | Total |
E&P-Norway | 6 099 | 0 | 6 099 | 5 835 | 0 | 5 835 | 6 405 | 0 | 6 405 |
International E&P | 308 | 405 | 713 | 325 | 258 | 583 | 338 | 268 | 606 |
Natural Gas | 649 | 202 | 851 | 664 | 145 | 809 | 847 | 147 | 994 |
Manufacturing and Marketing | 1 558 | 12 591 | 14 149 | 2 149 | 10 827 | 12 976 | 1 506 | 6 941 | 8 447 |
Technology and projects | 1 827 | 89 | 1 916 | 1 783 | 29 | 1 812 | n/a | n/a | n/a |
Other Operations | 1 773 | 143 | 1 916 | 1 794 | 90 | 1 884 | 2 739 | 135 | 1 794 |
Total | 12 214 | 13 430 | 25 644 | 12 710 | 11 189 | 23 899 | 11 835 | 7 491 | 19326 |
Much of the increase in the number of employees in Manufacturing and Marketing stems from the purchase of the 50 per cent of the SDS retail business in 2004. See Item 4–Information on the Company–Business Overview for details about the purchase.
We intend to limit our recruitment to growth areas and focus on young professionals and specific key competencies.
In Norway, we have a set of union/employer agreements at national, industry and local levels, which is the typical way of organizing union agreements in Norwegian industry. We take part in agreements at the national level as a member of the Norwegian Employers Association and at the industry level as a member of the Norwegian Oil Industry Association and the Federation of Norwegian Process Industry, both of which are branches of the Norwegian Employers Association.
At the local level, we have agreements with the trade unions. Our employees are represented by five trade unions: the Norwegian Oil and Petrochemical Workers Union, Confederation of Vocational Unions, Norwegian Association for Supervisors, Norwegian Society of Chartered Engineers and Norwegian Society of Engineers. Approximately 70 per cent of our employees are union members. The unions are entitled to appoint three members to our board of directors. Labor contracts with the unions were renewed in 2004 for a period of two years. Overall, we consider our relations with our employees and the unions to be good, and there are currently no major labor disputes.
We continuously seek to improve the skills and development of our employees in each of our business units. Employees participate in various training programs. Our training organization provides different development programs, and we cooperate with selected colleges and universities as well as other educational and research institutions in Norway and abroad.
Share Ownership
The number of Statoil shares owned by the members of the board of directors, the executive committee, and the corporate assembly is shown below. Board members and members of the executive committee, including closely related parties, who own Statoil shares are set forth below. Each owns less than one per cent of the Statoil shares outstanding.Board of directors | No. of shares owned as of March 24, 2006 |
Knut Åm | 14,594 |
Finn A Hvistendahl | 2,947 |
Kaci Kullmann Five | 1,000 |
Ingrid Wiik | 500 |
Morten Svaan | 469 |
Stein Bredal | 352 |
Lill-Heidi Bakkerud | 165 |
Executive committee | No. of shares owned as of March 24, 2006 |
Helge Lund (Chief Executive Officer) | 3,256 |
Peter Mellbye | 3,250 |
Margareth Øvrum | 2,875 |
Jon Arnt Jacobsen | 1,707 |
Eldar Sætre | 1,478 |
Reidar Gjærum | 1,397 |
Terje Overvik | 1,217 |
Nina Udnes Tronstad | 807 |
Jens R Jenssen | 500 |
Rune Bjørnson | 297 |
Members of the corporate assembly owned as of March 24, 2006 a total of 976 shares.
Item 7 Major Shareholders and Related Party Transactions
Major Shareholders
The Norwegian State as a Shareholder
| Number of shares | Per cent of shares |
Kingdom of Norway | 1,535,712,598 | 70.1(1) |
(1) Based upon 2,165,258,466 ordinary shares outstanding and 24,327,134 ordinary shares held in treasury as of March 24, 2006.
In June 2001, in connection with the initial public offering of our ordinary shares, we established a sponsored American Depositary Receipt facility with The Bank of New York as depositary pursuant to which American Depositary Receipts (ADRs) representing American Depositary Shares (ADSs) are issued. We have been informed by The Bank of New York that in the United States, as of March 24, 2006, there were 57,734,575 ADRs outstanding (representing approximately 2.67 per cent of the ordinary shares outstanding). As of March 24, 2006 there were 98 registered holders of ADR’s resident in the United States. Furthermore, 133,823,915 regular shares were held as of March 24 by 229 registered holders resident in the United States.
On April 26, 2001 the Storting (the Norwegian parliament) authorized the Ministry of Petroleum and Energy to reduce its shareholding in us by up to one-third of our value through the sale of its existing shares or the issuance by us of new shares to new investors. Following the initial public offering, the Norwegian State owned 80.84 per cent of the shares of Statoil. This percentage was calculated based on shares authorized and issued.
In July 2004, the Norwegian Ministry of Petroleum reduced its ownership in Statoil to 75.47 per cent through a sale to institutional and other investors.
On February 16, 2005 the Norwegian Ministry of Petroleum and Energy sold 100 million Statoil shares through an off-exchange underwritten block sale. This represented 4.6 per cent of our shares. The shares were sold to a global investment bank and were passed on to institutional investors in Norway and abroad. In addition, 17.65 million shares were made available for sale to private investors, at the rate set in the institutional sale.
Following these transactions, the Norwegian state now owns 70.1 per cent of the shares of Statoil.
On March 24, 2006, we entered into an agreement with the Norwegian State in connection with the authorization to repurchase Statoil shares for subsequent annulment, proposed by Statoil’s board of directors. The State has agreed to redeem an amount of its shares proportional to the amount of Statoil shares we may purchase under this authorization. As a result, the Norwegian State’s ownership interest will remain unchanged. The State has also agreed to vote in favor of the share repurchase authorization proposed by the board of directors at the annual general meeting on May 10, 2006.
The Norwegian State does not have any different voting rights from the rights of other ordinary shareholders as described in Item 10–Additional Information–Memorandum and Articles of Association. However, as the Norwegian State, acting through the Minister of Petroleum and Energy, continues to own in excess of two-thirds of the shares in us following completion of the initial public offering, it has the sole power to amend our articles of association. As long as the Norwegian State owns more than one-third of our shares, it will be able to prevent any amendments to our articles of association. In addition, as a majority shareholder, the Norwegian State has the power to control any decision at general meetings of our shareholders that requires a majority vote, including the election of the majority of the corporate assembly, which has the power to elect our board of directors and approve the dividend proposal by the board of directors.
The Norwegian State has stated that as one of our several shareholders, it will concentrate on issues relating to return on capital and dividend policy, emphasizing long-term profitable business development and the creation of value for all shareholders. The Norwegian State will exercise its ownership position based on a coordinated ownership strategy to maximize the value of the Norwegian State’s aggregate holdings in Statoil and the SDFI.
The Norwegian State as a Regulatory Authority
As a corporation based in Norway, we are subject to the laws and regulations of the Kingdom of Norway. Changes to relevant laws and regulations could have a significant impact on our operations. Various agencies and departments of the Kingdom of Norway exercise regulatory functions over our activities. The Ministry of Petroleum and Energy also exercises important regulatory powers over all petroleum operations of the companies of the NCS, including those of Statoil. For additional information about the Ministry of Petroleum and Energy’s role, see the section entitled Item 4–Information on the Company–Regulation. A number of other agencies and departments, such as the Norwegian Petroleum Directorate, the Ministry of Finance, the Ministry of Labor and Government Administration, the Ministry of the Environment and the Norwegian Pollution Control Authority, exercise regulatory powers which affect important parts of our operations.
A significant part of the taxes we pay are paid to the Norwegian State, see Item 4–Information on the Company–Business Overview–Regulation–Taxation of Statoil.
The Norwegian State’s Direct Participation in Petroleum Operations on the NCS
The Norwegian State’s policy as an owner has been, and continues to be, to ensure that petroleum activities create the highest possible value for the Norwegian State. Initially, the Norwegian State’s participation in petroleum operations was organized mainly through us. In 1985, the Norwegian State established the State’s direct financial interest, or SDFI, through which the Norwegian State has taken direct participating interests in licenses and petroleum facilities on the NCS. As a result, the Norwegian State holds interests in a number of licenses and petroleum facilities in which we also hold interests. Until June 17, 2001, we acted as manager of the SDFI’s interests in licenses and petroleum facilities.
As a result of changes in global markets and competitive conditions in the petroleum industry, the Norwegian State implemented a strategic review of its oil and gas policy in 2000. Based on the results of this strategic review, the Norwegian State prepared a plan to restructure its petroleum holdings on the NCS that was approved by the Storting on April 26, 2001. The key elements of the restructuring plan include:
• the partial privatization of Statoil;
• a restructuring of the Norwegian State’s SDFI assets, including the sale of SDFI assets to us and to other oil and gas companies and an exchange of interests in certain oil and gas infrastructure between the SDFI and us;
• the establishment of procedures to ensure that, as long as the Norwegian State instructs us to do so, we will continue to market and sell the State’s oil and gas, together with our oil and gas, following the partial privatization;
• the transfer of responsibility over and management of the SDFI’s assets from us to a new company which will be wholly-owned by the Norwegian State; and
• the transfer of operational responsibility over certain pipelines on the NCS from us to a new company which, for the time being, is wholly owned by the Norwegian State.
Marketing and Sale of the SDFI’s Oil and Gas
Introduction. We have historically marketed and sold the Norwegian State’s oil and gas as a part of our own production. The Norwegian State has elected to continue this arrangement. Accordingly, at an extraordinary general meeting held on February 27, 2001, the Norwegian State, as sole shareholder, revised our articles of association by adding a new article which requires us to continue to market and sell the Norwegian State’s oil and gas together with our own oil and gas in accordance with an instruction established in shareholder resolutions in effect from time to time. At an extraordinary general meeting held on May 25, 2001, the Norwegian State, as sole shareholder, approved a resolution containing the instructions referred to in the new article. This resolution is referred to as the owner’s instruction.
The Norwegian State has a coordinated ownership strategy to maximize the aggregate value of its ownership interests in Statoil and the Norwegian State’s oil and gas. This is reflected in the owner’s instruction, which contains a general requirement that, in our activities on the NCS we are required to take account of these ownership interests in decisions that may affect the execution of this marketing arrangement.
The owner’s instruction sets forth specific terms for the marketing and sale of the Norwegian State’s oil and gas. The principal provisions of the owner’s instruction are as set forth below.
Objectives. The overall objective of the marketing arrangement is to obtain the highest possible total value for our oil and gas and the Norwegian State’s oil and gas and ensure an equitable distribution of the total value creation between the Norwegian State and us. In addition, the following considerations are important:
• create the basis for making long-term and predictable decisions concerning the marketing and sale of the Norwegian State’s oil and gas;
• ensure that results, including costs and revenues related to our oil and gas and the Norwegian State’s oil and gas, are transparent and possible to measure; and
• ensure an efficient and simple administration and execution.
Our tasks. Our tasks under the owner’s instruction are to market and sell the Norwegian State’s oil and gas and to carry out all necessary tasks, other than those carried out jointly with other licensees under the production license, in relation to the marketing and sale of the Norwegian State’s oil and gas, including, but not limited to, the responsibility for processing, transport and marketing. In the event that the owner’s instruction is terminated, in whole or in part, by the Norwegian State, the owner’s instruction provides a mechanism under which contracts for the marketing and sale of the Norwegian State’s oil and gas to which we are a party may be assigned to the Norwegian State or its nominee. Alternatively, the Norwegian State may require that the contracts be continued in our name, but to the effect that in the underlying relationship between the Norwegian State and us, the Norwegian State receives all rights and obligations related to the Norwegian State’s oil and gas.
Costs. The Norwegian State does not pay us specific consideration for executing these tasks, but the Norwegian State reimburses us for its proportionate share of certain costs, which under the owner’s instruction may be our actual costs or an amount specifically agreed.
Price mechanisms. For sales of the Norwegian State’s natural gas, both to us and to third parties, the payment to the Norwegian State is based on either achieved prices, a net back formula or market value. We now purchase all of the Norwegian State’s oil and NGL. Pricing of the crude oil is based on market reflective prices. NGL prices are based on either achieved prices, market value or market reflective prices.
Lifting mechanism. As part of the coordinated ownership strategy, a lifting mechanism for the Norwegian State’s and our oil and gas is established in accordance with rules set out in the owner’s instruction.
To ensure a neutral weighting between the Norwegian State’s and our natural gas volumes, a list has been established for deciding the priority between each individual field. To decide the ranking, a mathematical optimization model is used which describes existing and planned production facilities, infrastructure and processing terminals where the Norwegian State and we have ownership interests. The list yields a result giving the highest total net present value for the Norwegian State’s and our oil and gas. In the evaluation, the following objective criteria shall, among other things, apply:
• the effect of the draw on the depletion rate;
• identification of time critical fields;
• influence on oil/liquid fields with associated gas needing gas disposal; and
• free capacity and flexibility in transportation systems and onshore facilities.
The different fields are ranked in accordance with the assumed total value creation for the Norwegian State and us, assuming all of the fields meet our profitability requirements if we participate as a licensee, and the Norwegian State’s profitability requirements if the State is a licensee. The list is updated annually or more frequently if incidents occur that may significantly influence the ranking. Within each individual field where both the Norwegian State and we are licensees, the Norwegian State and we will deliver volumes and share income in accordance with our respective participating interests.
The Norwegian State’s oil and NGL are lifted together with our oil and NGL in accordance with applicable lifting procedures for each individual field and terminal.
Withdrawal or Amendment. The Norwegian State may utilize its position as majority shareholder of Statoil, at any time, to withdraw or amend the instruction requiring us to market and sell the SDFI oil and natural gas together with our own.
Petoro - The SDFI Management Company
From the establishment of Statoil in 1972 until January 1, 1985, the participation of the Norwegian State in production licenses and facilities for transport and utilization of petroleum took place entirely through us. As of January 1, 1985, the Norwegian State’s participation was reorganized through the establishment of the SDFI. Through this reorganization the Norwegian State began taking a direct financial interest in production licenses. The establishment of the SDFI entailed a transfer of a substantial part of our participation in most of our then-existing licenses to the SDFI, although formally such licenses continued to be held wholly in our name. Since its establishment in 1985, the SDFI has taken shares in most licenses awarded. The SDFI also holds shares in a number of oil and gas pipelines and land-based terminal facilities.
We were, until June 17, 2001, registered as licensee for all SDFI shares in licenses. In accordance with a decision made in an extraordinary general meeting on May 10, 2001, we were until this time also the manager of the SDFI shares in these licenses on behalf of the Norwegian State. Where both the SDFI and we had an interest in the same license, the department managing our interest also managed the SDFI interest. In fields with SDFI interests only, the interests were managed by a separate unit that we established for this purpose. Our tasks as the manager of the SDFI’s interests have included attending management committee meetings for both the SDFI’s and our own share in licenses, and votes cast by us in management committee meetings have represented both the SDFI’s and our own interests in the licenses. We have also been responsible for marketing the petroleum of which the Norwegian State becomes the owner through the SDFI shares in production licenses.
In connection with the restructuring, the Norwegian State on May 9, 2001 established a new State-owned company, Petoro AS, which took over responsibility for and the management of the SDFI assets as licensee, in accordance with a new chapter of the Petroleum Act. The Norwegian State continues to be the beneficial owner of these assets. We continue to market and sell the Norwegian State’s oil and gas together with our own oil and gas, pursuant to the owner’s instruction described under –Marketing and Sale of the SDFI’s Oil and Gas above. One of the tasks of Petoro AS is to supervise our compliance with the owner’s instruction.
Petoro AS does not own any of the oil and gas produced under the license interests it holds, does not receive any revenues from sales of the State’s oil and gas, and is not permitted to obtain an operator role. However, Petoro AS may become a participant in new licenses awarded by the Norwegian State.
Gassco – The Gas Transportation Operating Company
In connection with the restructuring of the Norwegian State’s oil and gas interests, on May 14, 2001 the Norwegian State established a separate company, Gassco AS, which on January 1, 2002 took over as operator of the natural gas transportation system previously operated by us. Gassco AS is wholly owned by the Norwegian State. The owners of the infrastructure systems appointed Gassco AS as the new operator.
The transfer of the operatorship to Gassco AS was made without consideration and does not affect existing arrangements with respect to ownership or access to the natural gas transportation system or tariffs for transport. However, in accordance with the joint venture agreements relating to each of the gas transportation assets, the operator is entitled to be reimbursed for its costs as operator. Accordingly, since Gassco AS was appointed as operator, we no longer receive such reimbursement, and we will, as will other users of the infrastructure, be required to pay our portion of Gassco AS’s expenses associated with the operation of the natural gas pipelines in which we hold interests.
Gassco AS has entered into contracts with us for each infrastructure joint venture, pursuant to which we will carry out technical operating activities on behalf of Gassco AS, such as system maintenance, for which we will receive reimbursement of costs. Either Gassco or we may terminate without cause each of these contracts, except the contract for the Statpipe joint venture, after five years. Either Gassco or we may also terminate the part of the Statpipe contract, which refers to the offshore pipelines, after five years. Currently, Gassco may terminate the part of the Statpipe contract that refers to the Kårstø plant, at any time, provided that 2/3 of the owners, representing more than 2/3 of the ownership interests, have supported such termination.
As from January 1, 2003 the ownership of the Zeepipe, Franpipe, Europipe II, Åsgard Transport, Statpipe, Oseberg Gas Transport and Vesterled joint ventures and Norpipe AS were transferred to a new joint venture called Gassled. This also includes the terminals in Statpipe and Vesterled, the Europipe Receiving Facilities and the Europipe Metering Station. The ownership interest in Zeepipe Terminal JV and Dunkerque Terminal DA will also be adjusted. Gassco AS is the operator of the Gassled joint venture.
Our initial direct ownership interest in Gassled is 20.379 per cent (21.133 per cent including our indirect interest through our 25 per cent holding in Norsea Gas AS), 10.35542 per cent in Zeepipe Terminal JV and 13.73678 per cent in Dunkerque Terminal DA. From January 1, 2011, our direct ownership interest in Gassled will be reduced to 17.662 per cent due to an increased ownership interest for SDFI. In addition, our ownership interest in Gassled may also change as a result of inclusion of existing or new infrastructure or if Gassled undertakes further investments without participation from its owners in the same ratio as their ownership interests in Gassled. For more information on the Gassled joint venture, see Item 4–Information on the Company–Business Overview–Natural Gas.
Related Party Transactions
Transactions with the Norwegian State
For a description of transactions with the Norwegian State, see –Major Shareholders–The Norwegian State as a Shareholder above.
Transactions with other entities in which the Norwegian State is a major shareholder
Norsk Hydro. We hold interests in a number of the licenses and petroleum facilities in which Norsk Hydro also holds interests, and for many of these licenses and petroleum facilities Norsk Hydro or we serve as operator. Norsk Hydro has an indirect participating interest in the Gassled joint venture. Further, we from time to time engage in common drilling campaigns, exploration and development projects with Norsk Hydro. In addition, Norsk Hydro is a party to the 15-year agreement for the sale of ethane described below in —Transactions with associated companies. The Norwegian State owns 45.2 per cent of the total number of Norsk Hydro ASA shares outstanding.
Others. As a result of the substantial percentage of industry in Norway controlled by the Norwegian State, there are many state-controlled entities with which we do business. The financial value of most such transactions is relatively small, and the ownership interest of the Norwegian State of such counter parties has not had any effect on the arm’s-length nature of the transactions. In particular, in respect of the goods and services that we purchase, we purchase telephone services from Telenor ASA, a telecommunications company in which the Norwegian State holds a 53.1 per cent interest. Such purchases are made pursuant to standard tariff rates applicable to public and private companies in Norway.
Transactions with associated companies
Borealis. On November 28, 2000, we entered into a long-term sales and purchase agreement with Borealis for the sale of LPG derived from Statoil and SDFI’s share of crude oil from the Oseberg field in which the combined participating interest is now 48.90 per cent. The LPG is made available after the crude oil from Oseberg has gone through the transportation, separation and storage processes in the Vestprosess facility at Mongstad, our refinery in Norway. The agreement provides for regular deliveries of LPG to Borealis’s Rafnes plant. The price is based on the content of isobutane in the delivered LPG and is set in relation to the market price for naphtha. Certain quality specifications regulate the methanol, butane and isobutane content in the delivered product. The initial period for the contract is 15 years. During the first nine months of 2005, we sold 293,000 tonnes of LPG under this contract for an approximate consideration of NOK 790 million.
On March 3, 2005 Statoil entered into a 10-year agreement with Borealis for the sale of LPG from the Snøhvit field. Deliveries under the agreement are expected to commence following the start-up of production on the Snøhvit field, currently scheduled for the last quarter of 2007. Expected volume will be approximately 150,000 tonnes per year. The LPG will be used by Borealis as feedstock in their 50 per cent owned olefin plant (Noretyl) at Rafnes, Norway, which in 2005 completed an expansion project.
On June 2, 1997, we entered into a 15-year agreement for the sale of ethane between the participants in the Troll field, including us, as sellers and Borealis, Noretyl ANS and Norsk Hydro Produksjon AS as buyers. This contract provides for the purchase and sale of ethane feedstock for the Borealis plant in Stenungsund, Sweden, the Noretyl plant in Rafnes, Norway, and the Hydro Agri Ammonia plant at Herøya in Porsgrunn, Norway from the Gassled owned Kårstø plant. Currently, 50 per cent of production is delivered to Stenungsund and 50 per cent to Rafnes. At Rafnes, 50 per cent is delivered to Hydro Agri Ammonia plant, 25 per cent to Hydro Polymers and 25 per cent to Borealis. It is a take-or-pay contract whereby the buyers are obligated to pay for all ethane made available by the sellers under the contract. The price for the ethane is based on the market price of naphtha and is adjusted to reflect changes in the Norwegian consumer price index and the market price of marine fuel. Deliveri es under the contract began in October 2000, and the initial term of the agreement lasts until October 1, 2015. During the first nine months of 2005, the seller group sold 348,000 tonnes of ethane under this contract for an approximate consideration of NOK 810 million.
In October 2005, Statoil sold its 50 per cent holding in Borealis. See Item 4—Information on the Company—Manufacturing and Marketing.
Other Transactions with the Norwegian State
Total purchases of oil and NGL from the Norwegian State by Statoil amounted to NOK 97,078 million (282 mmboe), NOK 81,487 million (319 mmboe) and NOK 68,479 million (336 mmboe), in 2005, 2004 and 2003, respectively. Purchases of natural gas from the Norwegian State amounted to NOK 262, NOK 237 million and NOK 255 million in 2005, 2004 and 2003, respectively. The prices paid by Statoil for the oil purchased from the Norwegian State are estimated market prices. In addition, Statoil sells the Norwegian State’s natural gas, in its own name, but for the account and risk of the Norwegian State.
The Norwegian State compensates Statoil for its relative share of the costs related to certain Statoil natural gas storage and terminal investments and related activities.
Employee Loans
We have a general arrangement with DnB NOR whereby DnB NOR makes available to each of our employees personal consumer loans of up to NOK 150,000. The employees pay the “norm interest rate”, which is set by the Norwegian State, and we pay the difference between the norm interest rate and the then-current market interest rate. We also guarantee these loans up to an aggregate maximum amount of NOK 10 million. The repayment period is up to eight years. Our obligations for paying the interest rate difference will be dependent on the loan volume, but based on current interest rates would not exceed NOK 5 million per year.
The three employee-elected members of the board of directors and two members of the executive Committee each entered into loan agreements under this facility prior to July 30, 2002, and had as of December 31, 2005, an aggregate total balance outstanding payable to DnB NOR under this loan facility of NOK 332,167. Members of the executive committee and the board of directors may not enter into loans under the foregoing program.
Transactions with chairman of the board
We have made an office in Oslo available to our Chairman, Mr. Jannik Lindbæk. The office is used both in relation to his work as Chairman and to his other business activities unrelated to Statoil. We have estimated that 40 per cent of the use of the office is related to his capacity as Chairman. For the remaining 60 per cent, Mr. Lindbæk pays rent at normal market rate.
Item 8 Financial Information
Consolidated Statements and Other Financial Information
See Item 18-Financial Statements.
Legal Proceedings
We are involved in a number of judicial, regulatory and arbitration proceedings concerning matters arising in connection with the conduct of our business. Except as set forth below, we are currently not aware of any legal proceedings or claims that we believe could have, individually or in the aggregate, significant effects on our financial position or profitability or our results of operations or liquidity.
The Horton Case
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, a Turks & Caicos Island company, for consultancy services in Iran. The consultancy agreement provided for the payment of USD 15.2 million for consultancy services to be rendered over the 11-year contract term. Two payments totaling USD 5.2 million were made under the contract before the payments were stopped. The contract was terminated in September 2003. On June 29, 2004, Økokrim informed Statoil that it had concluded that Statoil violated section 276c, first paragraph (b) of the Norwegian Penal Code (which became effective from July 4, 2003 and prohibits conferring on or offering to a middleman an improper advantage in return for exercising his influence with a decision-maker without the decision-maker receiving any advantage) and imposed a penalty on Statoil of NOK 20 million. Statoil’s board decided on October 14, 2004 to accept the penalty without admitting or denying the charges by Økokrim. Before agreeing to pay the fine imposed by Økokrim, Statoil had already accepted that the Horton contract violated its own ethical policies and standards. Statoil has taken a number of steps to prevent a similar situation from arising in the future. Økokrim also informed Statoil that it issued a penalty notice to former Statoil executive vice president Richard Hubbard on the same legal basis, seeking to impose a penalty of NOK 200,000. Richard Hubbard announced on October 18, 2004 that he had accepted the Økokrim fine of NOK 200,000.
The original charge that Statoil paid bribes to Iranian decision makers with the intention of securing commercial advantages in Iran, was not pursued further by Økokrim in the penalty notice of June 2004.
The U.S. Securities and Exchange Commission (SEC) is conducting a formal investigation into the Horton consultancy arrangement to determine if there have been any violations of U.S. federal securities laws, including the Foreign Corrupt Practices Act. The U.S. Department of Justice is conducting a criminal investigation of the Horton matter jointly with the Office of the United States Attorney for the Southern District of New York. The SEC Staff informed Statoil on September 24, 2004 that it is considering recommending that the SEC authorize a civil enforcement action in federal court against Statoil for violations of various U.S. federal securities laws, including the anti-bribery and books and records provisions of the Foreign Corrupt Practices Act. Statoil is continuing to provide information to the U.S. authorities to assist them in their ongoing investigations.
Iranian authorities have also carried out inquiries into the Horton 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.
In May 2005, the Venezuelan Government issued statements indicating that Sincor operates outside the scope of the Congress authorization of 1993. See Item 4—Information on the Company–International Exploration and production-Venezuela-Sincor.
In May 2005, the Venezuelan National Assembly created a special commission to investigate the operating service agreements and strategic associations signed between the national oil company and private parties between 1992 and 1997. The investigation is not finalized. In May 2005, in a hearing before the National Assembly’s special commission, the Ministry of Energy and Petroleum or MEP stated that the strategic associations in the Venezuela heavy oil belt had “legal problems”, and requested that the National Assembly review Sincor. MEP’s position is that Sincor is outside of the scope of a 1993 congressional authorization based on its interpretation of an internal congressional report. Statoil believes that Sincor has all the necessary authorizations to continue operating the project as it has done until now.
On June 23, 2005 MEP informed Sincor in an official communication (oficio) that certain activities carried out by Sincor, including production above 114 mbls, were outside of the Congressional authorization and therefore Sincor should pay a 30 per cent royalty on production in excess of 114 mbls as provided in the 2002 Hydrocarbon Law, instead of 16 2/3 per cent.
Royalty on Sincor extra heavy oil production is paid monthly after issuance by MEP of a monthly invoice. In the invoice for June 2005 production, issued in August 2005, MEP applied a 30 per cent rate on extra heavy oil volumes above 114 mbls extracted after June 24, 2005. Monthly royalty invoices through December sought payment of a 30 per cent royalty rate on such extra heavy oil production above 114 mbls from June 24, 2005. Statoil’s share of such additional royalty invoiced by MEP in fiscal 2005 is approximately USD11.9 million, which Statoil has paid under protest with express reservation of its rights.
After paying each royalty invoice, Statoil has filed separate administrative motions (recurso de reconsideración) against each monthly invoice issued by MEP from June through December 2005. As of the date of this annual report, MEP has not ruled on any of the motions filed. Statoil has reserved the right to pursue other remedies available to it.
Dividend Policy
We have paid dividends to our shareholders in each year since our IPO in 2001. Since 2001, our dividend policy has been to pay an annual, aggregate dividend to shareholders of an amount in the range of 45 per cent to 50 per cent of our consolidated net income as determined in accordance with U.S. GAAP. In any one year, however, the aggregate dividend paid to shareholders may be lower or higher than 45 per cent to 50 per cent of U.S.GAAP net income, reflecting our view of the cyclical outlook for energy prices as well as our operating cash flows, financing requirements and capital expenditure plans to ensure we maintain appropriate financial flexibility.
On March 9, 2006, Statoil’s board of directors proposed an authorization to repurchase Statoil shares for subsequent annulment. The authorization must be approved by at least a two-thirds majority of the aggregate number of votes cast, as well as a two-thirds majority of the share capital represented at the annual general meeting to be held on May 10, 2006.
In connection with the proposed share repurchase authorization, we have entered into an agreement with the Norwegian State, which currently holds 70.1 per cent of our shares. Pursuant to the terms of the agreement, the State has agreed to vote in favor of the board’s proposal. See Item 7-Major Shareholders and Related Party Transactions for further information regarding the agreement with the Norwegian State.
If the share repurchase authorization proposed by the board of directors is granted by the annual general meeting of our shareholders, the board intends to modify our dividend policy so that the target annual return to shareholders of 45 per cent to 50 per cent of consolidated net income as determined in accordance with U.S. GAAP may be achieved through a combination of cash dividends and share repurchases. It is the Board’s ambition to grow the ordinary cash dividend measured in NOK per share. Future dividends and share repurchases will depend on our evaluation of expected cash flow development, capital expenditure plans, financing requirements and appropriate financial flexibility.
Significant Changes
None.
Item 9 The Offer and Listing
Markets and Market Prices
The principal trading market for Statoil’s ordinary shares is the Oslo Stock Exchange on which they have been listed since the initial public offering of Statoil on June 18, 2001. The ordinary shares are also listed on the New York Stock Exchange trading in the form of American Depositary Shares, or ADSs, evidenced by American Depositary Receipts, or ADRs. Each ADS represents one ordinary share. Statoil has a sponsored ADR facility with the Bank of New York as Depositary.
The following tables provide, for the periods indicated, the reported high and low quotations at market close for the ordinary shares on the Oslo Stock Exchange, as derived from its Daily Official List, and the highest and lowest sales prices of the ADSs as reported on the New York Stock Exchange composite tape.
Year ended December 31, | NOK per ordinary share | USD per ADS | ||
High | Low | High | Low | |
2001 | 71.00 | 58.00 | 7.64 | 6,15 |
2002 | 73.50 | 50.00 | 9.35 | 6.31 |
2003 | 74.75 | 51.50 | 11.30 | 7.29 |
2004 | 103.50 | 74.00 | 15.93 | 10.85 |
2005 | 166.50 | 91.25 | 25.80 | 14.69 |
Quarter ended | NOK per ordinary share | USD per ADS | ||
High | Low | High | Low | |
89.00 | 74.00 | 12.78 | 10.85 | |
June 30, 2004 | 93.00 | 79.50 | 13.58 | 11.52 |
September 30, 2004 | 98.75 | 83.50 | 14.62 | 11.99 |
December 31, 2004 | 103.50 | 88.75 | 15.93 | 14.28 |
March 31, 2005 | 114.25 | 91.25 | 18.55 | 14.69 |
June 30, 2005 | 133.50 | 106.50 | 20.30 | 16.32 |
September 30, 2005 | 166.50 | 135.25 | 25.80 | 20.68 |
December 31, 2005 | 163.00 | 134.25 | 24.69 | 20.60 |
March up until March 24, 2006 | 184.50 | 154.00 | 27.69 | 24.13 |
Month of | NOK per ordinary share | USD per ADS | ||
High | Low | High | Low | |
September 2005 | 166.50 | 156.00 | 25.80 | 24.69 |
October 2005 | 163.00 | 134.25 | 24.69 | 20.60 |
November 2005 | 155.50 | 142.50 | 23.92 | 21.63 |
December 2005 | 160.00 | 150.50 | 24.13 | 22.28 |
January 2006 | 184.00 | 154.00 | 27.69 | 24.13 |
February 2006 | 184.50 | 164.50 | 27.47 | 24.19 |
March up until March 24, 2006 | 180.00 | 171.50 | 27.09 | 25.62 |
Item 10 Additional Information
Memorandum and Articles of Association
Summary of our Articles of Association
Name of the Company
Our registered name is Statoil ASA. We are a Norwegian public limited company.
Registered office
Our registered office is in Stavanger, Norway, registered with the Norwegian Register of Business Enterprises under number 913 609 016.
Object of the company
The object of our company is, either by us or through participation in or together with other companies, to carry out exploration, production, transportation, refining and marketing of petroleum and petroleum derived products, as well as other businesses.
Share capital
Our share capital is NOK 5,473,964,000 divided into 2,189,585,600 ordinary shares.
In connection with our initial public offering, the extraordinary general meeting held on May 25, 2001 resolved to increase our share capital through the issuance of 25,000,000 additional shares for the purpose of granting bonus shares to qualifying investors. Following the distribution of bonus shares in 2002, Statoil retained 23,441,885 of these shares. The shares cannot be used for any other purpose without the consent of a general meeting. The board of directors has proposed to reduce the share capital through the annulment of the remaining 23,411,885 shares. The proposal is subject to approval by a vote of shareholders at the annual general meeting on May 10, 2006.
Nominal value of shares
The nominal value of each ordinary share is NOK 2.50.
Board of directors
Our articles of association provide that our board of directors shall be composed of a minimum of five and a maximum of 11 directors.
Corporate Assembly
We have a corporate assembly of 12 members who are elected for two-year terms. The general meeting elects eight members with three alternates and four members with four alternates are elected by and among the employees.
Annual general meeting
Our annual general meeting is held no later than June 30 each year upon at least two weeks’ written notice.
The meeting will deal with the Annual Report and accounts, including distribution of dividends, and any other matters as required by law or our articles of association.
Marketing of petroleum on behalf of the Norwegian State
Our articles of association provide that we are responsible for marketing and selling petroleum produced under the SDFI’s shares in production licenses on the NCS as well as petroleum received by the Norwegian State as royalty together with our own production. Our general meeting adopted an instruction in respect of such marketing on May 25, 2001.
Election Committee
The general meeting decided to amend our articles of association on May 7, 2002 in order to establish an election committee. The tasks of the election committee are to make recommendations to the general meeting regarding the election of shareholder-elected members and deputy members of the corporate assembly, and to make recommendations to the corporate assembly regarding the election of shareholder-elected members and deputy members of the board of directors.
The election committee shall consist of four members who shall be shareholders or representatives of shareholders. The chairman of the corporate assembly shall be a permanent member and chairman of the election committee. The general meeting shall elect two members, and one member shall be elected by and among the corporate assembly's shareholder-elected members.
General Meetings
In accordance with Norwegian law, our annual general meeting of shareholders is required to be held each year on or prior to June 30. Norwegian law requires that written notice of general meetings be sent to all shareholders whose addresses are known at least two weeks prior to the date of the meeting. A shareholder may vote at the general meeting either in person or by proxy.
Although Norwegian law does not require us to send proxy forms to our shareholders for general meetings, we plan to include a proxy form with future notices of general meetings.
In addition to the annual general meeting, extraordinary general meetings of shareholders may be held if deemed necessary by the board of directors, the corporate assembly or the chairman of the corporate assembly. An extraordinary general meeting must also be convened for the consideration of specific matters at the written request of our auditors or of shareholders representing a total of at least 5 per cent of the outstanding share capital.
Voting Rights
All of our ordinary shares carry equal right to vote at general meetings. Except as otherwise provided, decisions which shareholders are entitled to make pursuant to Norwegian law or our articles of association may be made by a simple majority of the votes cast. In the case of elections, the persons who obtain the most votes cast are deemed elected. However, certain decisions, including resolutions to waive preferential rights in connection with any share issue, to approve a merger or demerger, to amend our articles of association or to authorize an increase or reduction in our share capital, must receive the approval of at least two-thirds of the aggregate number of votes cast as well as two-thirds of the share capital represented at a shareholders’ meeting. The Norwegian State continues to hold more than two-thirds of our share capital. See Item 7–Major Shareholders and Related Party Transactions–Major Shareholders–The Norwegian State as a Shareholder.
In general, in order to be entitled to vote, a shareholder must be registered as the owner of shares in the share register kept by the Norwegian Central Securities Depository, referred to as the VPS System (described below), or, alternatively, report and show evidence of its share acquisition to us prior to the general meeting.
Beneficial owners of shares that are registered in the name of a nominee are generally not entitled to vote under Norwegian law, nor are any persons who are designated in the register as holding such shares as nominees. The beneficial owners of ADSs are therefore only able to vote at meetings by surrendering their ADSs, withdrawing their ordinary shares from the ADS depositary and registering their ownership of such ordinary shares directly in our share register in the VPS System. Alternatively, the ADS holder may instruct the ADR depositary to vote the ordinary shares underlying the ADSs on behalf of the holder, provided that the ADS holder instructs the ADR depositary to execute a temporary transfer of the underlying ordinary shares in the VPS System to the beneficial owner. Similarly, beneficial owners of ordinary shares registered through other VPS-registered nominees may not be able to vote their shares unless their ownership is re-registered in the name of the beneficial owner prior to the relevant shareholders’ meeting.
The VPS System and Transfer of Shares
The VPS System is Norway’s paperless centralized securities registry. It is a computerized bookkeeping system that is operated by an independent body in which the ownership of, and all transactions relating to, Norwegian listed shares must be recorded. Our share register is operated through the VPS System.
All transactions relating to securities registered with the VPS are made through computerized book entries. No physical share certificates are or can be issued. The VPS System confirms each entry by sending a transcript to the registered shareholder regardless of beneficial ownership. To effect these entries, the individual shareholder must establish a securities account with a Norwegian account agent. Norwegian banks, the Central Bank of Norway, authorized investment firms in Norway, bond issuing mortgage companies, management companies for securities funds (insofar as units in securities funds they manage are concerned), and Norwegian branches of credit institutions established within the EEA are allowed to act as account agents.
The entry of a transaction in the VPS System is prima facie evidence in determining the legal rights of parties as against the issuing company or a third party claiming an interest in the subject security. The VPS System is strictly liable for any loss resulting from an error in connection with registering, altering or canceling a right, except in the event of contributory negligence, in which event compensation owed by the VPS System may be reduced or withdrawn. A transferee or assignee of shares may not exercise the rights of a shareholder with respect to his or her shares unless that transferee or assignee has registered his or her shareholding or has reported and shown evidence of such share acquisition and the acquisition of such shares is not prevented by law, our articles of association or otherwise.
Amendments to our Articles of Association, including Variation of Rights
The affirmative vote of two-thirds of the votes cast as well as two-thirds of the aggregate share capital represented at the general meeting is required to amend our articles of association. Any amendment which would reduce any shareholder’s right in respect of dividends payments or other rights to our assets or restrict the transferability of shares requires a majority vote of at least 90 per cent of the aggregate share capital represented in a general meeting. Certain types of changes in the rights of our shareholders require the consent of all affected shareholders as well as the percentage threshold otherwise required to amend our articles of association.
Additional Issuances and Preferential Rights
If we issue any new shares, including bonus share issues, our articles of association must be amended, which requires the same vote as other amendments to our articles of association. In addition, under Norwegian law, our shareholders have a preferential right to subscribe to issues of new shares by us. The preferential rights to subscribe to an issue may be waived by a resolution in a general meeting passed by the same percentage threshold required to approve amendments to our articles of association.
The general meeting may, with a vote as described above, authorize the board of directors to issue new shares, and to waive the preferential rights of shareholders in connection with such issuances. Such authorization may be effective for a maximum of two years, and the par value of the shares to be issued may not exceed 50 per cent of the nominal share capital when the authorization was granted.
The issuance of shares to holders who are citizens or residents of the United States upon the exercise of preferential rights may require us to file a registration statement in the United States under United States securities laws. If we decide not to file a registration statement, these holders may not be able to exercise their preferential rights.
Under Norwegian law, bonus share issues may be distributed, subject to shareholder approval, by transfer from Statoil’s distributable equity or from our share premium reserve. Any bonus issues may be affected either by issuing shares or by increasing the par value of the shares outstanding.
Minority Rights
Norwegian law contains a number of protections for minority shareholders against oppression by the majority including but not limited to those described in this paragraph. Any shareholder may petition the courts to have a decision of the board of directors or general meeting declared invalid on the grounds that it unreasonably favors certain shareholders or third parties to the detriment of other shareholders or the company itself. In certain grave circumstances shareholders may require the courts to dissolve the company as a result of such decisions. Minority shareholders holding 5 per cent or more of our share capital have a right to demand that we hold an extraordinary general meeting to discuss or resolve specific matters. In addition, any shareholder may demand that we place an item on the agenda for any shareholders’ meeting if we are notified in time for such item to be included in the notice of the meeting.
Mandatory Bid Requirement
Norwegian law requires any person, entity or group acting in concert that acquires more than 40 per cent of the voting rights of a Norwegian company listed on the Oslo Stock Exchange, or OSE, to make an unconditional general offer to acquire the whole of the outstanding share capital of that company. The offer is subject to approval by the OSE before submission of the offer to the shareholders. The offer must be in cash or contain a cash alternative at least equivalent to any other consideration offered. The offering price per share must be at least as high as the highest price paid by the offeror in the six-month period prior to the date the 40 per cent threshold was exceeded, but equal to the market price if it is clear that the market price was higher when the 40 per cent threshold was exceeded. A shareholder who fails to make the required offer must within four weeks dispose of sufficient shares so that the obligation ceases to apply. Otherwise, the OSE may cause the shares exceeds the 40 per cent limi t to be sold by public auction. A shareholder who fails to make such bid cannot, as long as the mandatory bid requirement remains in force, vote the portion of his shares which exceeds the 40 per cent limit or exercise any rights of share ownership in respect of such shares, unless a majority of the remaining shareholders approve, other than the right to receive dividends and preferential rights in the event of a share capital increase. In addition, the OSE may impose a daily fine upon a shareholder who fails to make the required offer.
Compulsory Acquisition
A shareholder who, directly or via subsidiaries, acquires shares representing more than 90 per cent of the total number of issued shares as well as more than 90 per cent of the total voting rights has the right (and each remaining minority shareholder of that company would have the right to require the majority shareholder) to effect a compulsory acquisition for cash of any shares not already owned by the majority shareholder. A compulsory acquisition has the effect that the majority shareholder becomes the owner of the shares of the minority shareholders with immediate effect.
A majority shareholder who effects a compulsory acquisition is required to offer the minority shareholders a specific price per share. The determination of the offer price is at the discretion of the majority shareholder. Should any minority shareholder not accept the offered price, such minority shareholder may, within a specified period of not less than two months, request that the price be set by the Norwegian courts. The cost of such court procedure would normally be charged to the account of the majority shareholder, and the courts would have full discretion in determining the consideration due to the minority shareholder as a result of the compulsory acquisition.
Election and Removal of Directors and Corporate Assembly
At the general meeting of shareholders, two-thirds of the members of the corporate assembly are elected, together with alternate members, while the remaining one-third, together with alternate members, are elected by and from among our employees. There is no quorum requirement, and nominees who receive the most votes are elected. Any shareholder at the meeting may place nominations before the meeting.
We have an election committee that makes recommendations to the general meeting regarding the election of shareholder-elected members of the corporate assembly and their alternates. The committee consists of four members who are shareholders or representatives of shareholders. The chairman of the corporate assembly is a permanent member of the committee and acts as its chairman. The general meeting elects two members and one member is elected by and from among the corporate assembly's shareholder-elected members. Each member is elected for a two-year term. A member of the corporate assembly (other than a member elected by employees) may be removed by the shareholders at any time without cause.
Our directors are elected to the Board and may be removed from office by our corporate assembly. If requested by at least one third of the members of the corporate assembly, up to one-third of the directors must be employee representatives. Our election committee makes recommendations to the corporate assembly regarding the election of shareholder-elected directors of the board and their alternates. Half of the corporate assembly members elected by the employees may demand that the members of the board of directors be elected by the shareholder-elected members of the corporate assembly and the employee-elected members of the corporate assembly, each voting as a separate group. A director (other than a director elected directly by the employees) may be removed at any time by the corporate assembly without cause.
The corporate assembly makes decisions by majority vote, and more than half of its members must be present for a quorum. If votes are tied, the chairman of the meeting casts the deciding vote. The members of the corporate assembly and the board of directors have fiduciary duties to the shareholders, see –Liability of Directors and–Corporate Assembly.
Payment of Dividends
For a discussion of the declaration and payment of dividends on our ordinary shares, see Item 3–Key Information–Dividends and Item 8–Financial Information–Dividend Policy.
Rights of Redemption and Repurchase of Shares
Our articles of association do not authorize the redemption of shares. In the absence of authorization, the redemption of shares may still be decided by a general meeting of shareholders by a two-thirds majority under certain conditions. However, the share redemption would, for all practical purposes, depend on the consent of all shareholders whose shares are redeemed.
A Norwegian company may purchase its own shares if an authorization to do so has been given by a general meeting with the approval of at least two-thirds of the aggregate number of votes cast as well as two thirds of the share capital represented at the general meeting. The aggregate par value of treasury shares held by the company must not exceed 10 per cent of the company’s share capital and treasury shares may only be acquired if the company’s distributable equity, according to the latest adopted balance sheet, exceeds the consideration to be paid for the shares. The authorization by the general meeting cannot be given for a period exceeding 18 months.
On May 5, 2004, the annual general meeting of shareholders has authorized our board of directors to acquire Statoil shares in the market for sale and transfer to employees as part of the group’s share investment plan. The authorization is subject to renewal at the annual general meeting in 2006.
On March 9, 2006, the board of directors proposed an authorization to repurchase Statoil shares for subsequent annulment in connection with the adoption of a revised dividend policy for the company. The proposal will be subject to authorization by a vote of shareholders at the annual general meeting on May 10, 2006.
Shareholders’ Votes on Certain Reorganizations
A decision to merge with another company or to demerge requires a resolution of our shareholders at a general meeting passed by a two-thirds majority of the aggregate votes cast as well as two-thirds of the aggregate share capital represented at the general meeting. A merger plan or demerger plan signed by the board of directors along with certain other required documentation would have to be sent to all shareholders at least one month prior to the shareholders’ meeting.
The general meeting must approve any agreement by which we acquire assets or services from a shareholder or a shareholder’s related party against a consideration exceeding the equivalent of 5 per cent of our share capital. This does not apply to acquisition of listed securities at market price or to agreements in the ordinary course of business entered into on normal commercial terms.
Liability of Directors
Our directors, the Chief Executive Officer and the corporate assembly owe a fiduciary duty to the company and its shareholders. Their fiduciary duty requires that they act in our best interests when exercising their functions and to exercise a general duty of loyalty and care toward us. Their principal task is to safeguard the interests of the company.
Our directors, the Chief Executive Officer and the members of the corporate assembly can each be held liable for any damage they negligently or willfully cause us. Norwegian law permits the general meeting to exempt any such person from liability, but the exemption is not binding if substantially correct and complete information was not provided at the general meeting when the decision was taken. If a resolution to grant such exemption from liability or to not pursue claims against such a person has been passed by a general meeting with a smaller majority than that required to amend our articles of association, shareholders representing more than 10 per cent of the share capital or (if there are more than 100 shareholders) more than 10 per cent of the number of shareholders may pursue the claim on our behalf and in our name. The cost of any such action is not our responsibility, but can be recovered by any proceeds we receive as a result of the action. If the decision to grant exemption from liability or not to pursue claims is made by the majority necessary to amend the articles of association, the minority shareholders cannot pursue the claim in our name.
Indemnification of Directors and Officers
Neither Norwegian law nor our articles of association contain any provision concerning indemnification by us of our board of directors.
Distribution of Assets on Liquidation
Under Norwegian law, a company may be wound-up by a resolution of the company’s shareholders in a general meeting passed by both a two-thirds majority of the aggregate votes cast and two-thirds of the aggregate share capital represented at the general meeting. The shares rank equal in the event of a return on capital by the company upon a winding-up or otherwise.
Material Contracts
See Item 7-Major Shareholders and Related Party Transactions.
Exchange Controls and Other Limitations Affecting Shareholders
Under Norwegian foreign exchange controls currently in effect, transfers of capital to and from Norway are not subject to prior government approval except for the physical transfer of payments in currency, which is restricted to licensed banks. This means that non-Norwegian resident shareholders may receive dividend payments without a Norwegian exchange control consent as long as the payment is made through a licensed bank.
There are presently no restrictions affecting the rights of non-residents or foreign owners to hold or vote our shares.
Taxation
Norwegian Tax Matters
This section describes the material Norwegian tax consequences that apply to shareholders resident in Norway as well as non-resident shareholders in connection with the acquisition, ownership, and disposition of the shares and ADSs. This section does not provide a complete description of all tax regulations which might be relevant (i.e., for investors for whom special regulations may be applicable). This section is based on current law and practice. Shareholders should consult their professional tax advisor for advice concerning individual tax consequences.
On December 10, 2004 the Norwegian tax reform was approved by the Storting. The reform is fully in force with effect for 2006.
Taxation of Dividends
Corporate shareholders resident in Norway for tax purposes are exempt from tax on dividends decided by the shareholders meeting of Norwegian companies after January 1, 2004.
Individual shareholders who are residents of Norway for tax purposes are subject to tax on dividends received as ordinary income at a flat rate, currently 28 per cent. The individual shareholders are entitled to a tax credit against the Norwegian tax levied on dividends distributed from Norwegian companies equal to the tax to be levied on the dividends received, and will effectively not be subject to tax on dividends from Norwegian companies.
For individual shareholders, the current imputation system for dividends will be abolished and replaced with a classical system with partial double taxation as of January 1, 2006. Dividend income exceeding a “shield interest deduction”, which is an amount equal to the risk-free interest after tax on the base cost of the shareholding, will be taxable at a flat rate, currently 28 per cent. The average interest on Government bonds of 5 years’ maturity will be applied.
Non-resident shareholders are as a general rule subject to a withholding tax at a rate of 25 per cent on dividends distributed by Norwegian companies. This withholding tax does not apply to corporate shareholders resident for tax purposes in European Economic Area (EEA) countries. The withholding rate of 25 per cent is often reduced in tax treaties between Norway and the country in which the shareholder is resident. Generally, the treaty rate does not exceed 15 per cent and in cases where a corporate shareholder holds a qualifying percentage of the shares of the distributing company, the withholding tax rate on dividends may be further reduced. The withholding tax rate in the tax treaty between United States and Norway is 15 per cent in all cases. The withholding tax does not apply to shareholders that carry on business activities in Norway and whose shares are effectively connected with such activities. In that case, the rules described in the paragraph above regarding corporate shareholders res ident in Norway apply. We are obligated by law to deduct any applicable withholding tax when paying dividends to non-resident shareholders except individual and corporate shareholders within the EEA. The exception for individual shareholders within the EEA only applies to dividends paid in 2005.
The 15 per cent withholding rate under the tax treaty between Norway and the United States will apply to dividends paid on shares held directly by holders properly demonstrating to the company that they are entitled to the benefits of the tax treaty.
Dividends paid to the depositary for redistribution to shareholders holding ADSs will at the outset be subject to a withholding tax of 25 per cent. The beneficial owners will in this case have to apply to the Central Office for Foreign Tax Affairs (COFTA) for refund of the excess amount of tax withheld. As yet there is no standardized application form to obtain a refund of Norwegian withholding tax. An application must contain the following information:
1. the company from which dividends were received and the date and amount of payment, the exact number of shares, the amount of tax withheld by Norway and the amount claimed for refund from Norway. All amounts are to be stated in Norwegian kroner;
2. confirmation from a central tax authority stating that, in the year the dividends were declared or received, the refund claimant was resident for tax purposes in the country with respect to which such claimant claims the benefits of a tax treaty with Norway, and original documentation that the claimant was the beneficial owner of the shares when the dividends were declared; and
3. evidence that the dividends were actually received by the applicant and the rate at which Norwegian withholding tax was withheld on the dividends.
The application must be signed by the applicant. If the application is signed by proxy, a copy of the letter of authorization must be enclosed.
However, pursuant to agreements with The Financial Supervisory Authority of Norway and the Norwegian Directorate of Taxes, The Bank of New York, acting as depositary, is entitled to receive dividends from us for redistribution to a beneficial owner of shares or ADSs at the applicable treaty withholding rate, provided the beneficial holder has furnished The Bank of New York appropriate certification to establish such holder’s eligibility for the benefits under an applicable tax treaty with Norway.
Wealth Tax. The shares are included when computing the wealth tax imposed on individuals who for tax purposes are considered resident in Norway. Norwegian joint stock companies and certain similar entities are not subject to wealth tax. Currently, the marginal wealth tax rate is 1.1 per cent of the value assessed. The value for assessment purposes for shares listed on the Oslo Stock Exchange is 65 per cent of the listed value of such shares as of January 1 in the year of assessment.
Non-resident shareholders are not subject to wealth tax in Norway for shares in Norwegian joint stock companies unless the shareholder is an individual and the shareholding is effectively connected with his business activities in Norway.
Inheritance Tax and Gift Tax. When shares or ADSs are transferred, either through inheritance or as a gift, such transfer may give rise to inheritance tax in Norway if the deceased, at the time of death, or the donor, at the time of the gift, is a resident or citizen of Norway. If a Norwegian citizen at the time of death, however, is not a resident of Norway, Norwegian inheritance tax will not be levied if an inheritance tax or a similar tax is levied by the country of residence. Irrespective of citizenship, Norwegian inheritance tax may be levied if the shares or ADSs are effectively connected with the conduct of a trade or business through a permanent establishment in Norway.
Taxation upon Disposition of Shares
Corporate shareholders resident in Norway for tax purposes are exempt from tax on gains realized from March 26, 2004. Costs directly related to the acquisition and sale of such shares will not be deductible for tax purposes. Corporate shareholders will not be allowed a deduction for losses upon sale, swap and redemption of shares if a gain would be exempt.
Corporate shareholders resident in Norway for tax purposes will realize a taxable gain or loss upon a sale, redemption or other disposition of shares prior to March 26, 2004. Net loss realized in the period from March 26 to December 31, 2004 may be offset against net gains realized before March 26, 2004.
Individual shareholders resident in Norway for tax purposes will realize a taxable gain or loss upon a sale, redemption or other disposition of shares at any time.
Both for corporate and individual shareholders resident for tax purposes in Norway who are subject to tax on gains realized according to the rules described above, such capital gain or loss is included in or deducted upon computation of general income in the year of disposal. General income is taxed at a flat rate of 28 per cent. The gain is subject to tax and the loss is deductible irrespective of the length of the ownership and the number of shares disposed of.
The taxable gain or loss is computed as the sales price adjusted for transactional expenses less the taxable basis. A shareholder’s tax basis is normally equal to the acquisition cost of the shares. The tax basis is adjusted according to the so-called RISK-rules which allow an opening value adjustment. RISK is the Norwegian abbreviation for the variation in the company’s retained earnings after tax less dividend distributed during the ownership of the shareholder. The RISK amount is computed at the end of the fiscal year. If the shareholder owns shares acquired at different times, the shares that were acquired first will be regarded as the first to be sold for the purpose of calculating capital gains or losses.
As of January 1, 2006 the opening value adjustment according to the RISK-rules was abolished for individual shareholders. Any unused “shield interest deduction” from earlier years attributable to the individual shares realized may be deducted.
Shareholders not resident in Norway are generally not subject to tax in Norway on capital gains, and losses are not deductible upon sale, redemption or other disposition of shares or ADSs in Norwegian companies, unless the shareholder has been resident for tax purposes in Norway and the disposal takes place within five years after the end of the calendar year in which the shareholder ceased to be a resident of Norway for tax purposes or, alternatively, the shareholder is carrying on business activities in Norway and such shares or ADSs are or have been effectively connected with such activities.
Transfer Tax. There is no transfer tax imposed in Norway in connection with the sale or purchase of shares.
United States Tax Matters
This section describes the material United States federal income tax consequences to U.S. holders (as defined below) of owning shares or ADSs. It applies to you only if you hold your shares or ADSs as capital assets for tax purposes. This section does not apply to you if you are a member of a special class of holders subject to special rules, including:
• dealers in securities;
• traders in securities that elect to use a mark-to-market method of accounting for their securities holdings;
• tax-exempt organizations;
• life insurance companies;
• persons liable for alternative minimum tax;
• persons that actually or constructively own 10 per cent or more of the voting stock of Statoil;
• persons that hold shares or ADSs as part of a straddle or a hedging or conversion transaction; or
• persons whose functional currency is not the U.S. dollar.
This section is based on the Internal Revenue Code of 1986, as amended, its legislative history, existing and proposed regulations, published rulings and court decisions, and the Convention between the United States of America and the Kingdom of Norway for the Avoidance of Double Taxation and the Prevention of Fiscal Evasion with Respect to Taxes on Income and Property (the ‘‘Treaty’’). These laws are subject to change, possibly on a retroactive basis. In addition, this section is based in part upon the representations of the depositary and the assumption that each obligation in the deposit agreement and any related agreement will be performed in accordance with its terms. For United States federal income tax purposes, if you hold ADRs evidencing ADSs, you generally will be treated as the owner of the ordinary shares represented by those ADRs. Exchanges of shares for ADRs, and ADRs for shares generally will not be subject to United States federal income tax.
You are a ‘‘U.S. holder’’ if you are a beneficial owner of shares or ADSs and you are for United States federal income tax purposes:
• an individual who is a citizen or resident of the United States;
• a United States domestic corporation;
• an estate whose income is subject to United States federal income tax regardless of its source; or
• a trust if a United States court can exercise primary supervision over the trust’s administration and one or more United States persons are authorized to control all substantial decisions of the trust.
You should consult your own tax advisor regarding the United States federal, state and local and other tax consequences of owning and disposing of shares and ADSs in your particular circumstances.
Taxation of Dividends. If you are a U.S. holder, the gross amount of any dividend paid by Statoil out of its current or accumulated earnings and profits (as determined for United States federal income tax purposes) is subject to United States federal income taxation. If you are a non-corporate U.S. holder, dividends paid to you in taxable years beginning before January 1, 2009 that constitute qualified dividend income will be taxable to you at a maximum tax rate of 15 per cent if you hold the shares or ADSs for more than 60 days during the 121-day period beginning 60 days before the ex-dividend date and meet other holding-period requirements. Dividends we pay with respect to shares or ADSs generally will be qualified dividend income.
You must include any Norwegian tax withheld from the dividend payment in this gross amount even though you do not in fact receive the amount withheld as tax. The dividend is taxable to you when you, in the case of shares, or the depositary, in the case of ADSs, receive the dividend, actually or constructively. The dividend will not be eligible for the dividends-received deduction generally allowed to United States corporations in respect of dividends received from other United States corporations.
The amount of the dividend distribution that you must include in your income as a U.S. holder will be the U.S. dollar value of the Norwegian kroner payments made, determined at the spot Norwegian kroner/U.S. dollar rate on the date the dividend distribution is included in your income, regardless of whether the payment is in fact converted into U.S. dollars. Distributions in excess of current and accumulated earnings and profits, as determined for United States federal income tax purposes, will be treated as a non-taxable return of capital to the extent of your tax basis in the shares or ADSs and, to the extent in excess of your tax basis, will be treated as capital gain.
Subject to certain limitations, the 15 per cent Norwegian tax withheld in accordance with the Treaty and paid over to Norway will be creditable against your United States federal income tax liability. Special rules apply in determining the foreign tax credit with respect to dividends that are subject to the maximum 15 per cent rate. Dividends will be income from sources outside the United States. Dividends paid in taxable years beginning before January 1, 2007 generally will be ‘‘passive income’’ or ‘‘financial services income’’, and dividends paid in taxable years beginning after December 31, 2006 will, depending on your circumstances, be ‘‘passive’’ or ‘‘general’’ income, which, in either case, is treated separately from other types of income for purposes of computing the foreign tax credit allowable to you.
Any gain or loss resulting from currency exchange fluctuations during the period from the date you include the dividend payment in income to the date you convert the payment into U.S. dollars generally will be treated as ordinary income or loss and will not be eligible for the special tax rate applicable to qualified dividend income. Such gain or loss generally will be income or loss from sources within the United States for foreign tax credit limitation purposes.
Taxation of Capital Gains. If you are a U.S. holder and you sell or otherwise dispose of your shares or ADSs, you generally will recognize capital gain or loss for United States federal income tax purposes equal to the difference between the U.S. dollar value of the amount that you realize and your tax basis, determined in U.S. dollars, in your shares or ADSs. Capital gain of a non-corporate U.S. holder that is recognized before January 1, 2009 is generally taxed at a maximum rate of 15 per cent where the holder has a holding period greater than one year. The gain or loss will generally be income or loss from sources within the United States for foreign tax credit limitation purposes.
If you receive any foreign currency on the sale of shares or ADSs, you may recognize ordinary income or loss from sources within the United States as a result of currency fluctuations between the date of the sale of the shares or ADSs and the date the sales proceeds are converted into U.S. dollars.
Report of DeGolyer and MacNaughton
DeGolyer and MacNaughton, independent petroleum engineering consultants, performs an independent evaluation of proved reserves, which was performed as of December 31, 2005 for our properties. DeGolyer and MacNaughton has delivered to us its summary letter report describing its procedures and conclusions, a copy of which appears as Appendix A hereto.
Documents on Display
It is possible to read and copy documents referred to in this Annual Report on Form 20-F that have been filed with the SEC at the SEC’s public reference room located at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference rooms and their copy charges.
Item 11 Quantitative and Qualitative Disclosures about Market Risk
Statoil operates in the worldwide crude oil, refined products and natural gas markets and is exposed to fluctuations in hydrocarbon prices, foreign currency rates and interest rates that can affect the revenues and cost of operating, investing and financing. Our management has used and intends to use financial and commodity-based derivative contracts to reduce the risks in overall earnings and cash flows. Statoil also uses derivatives to establish certain limited speculative positions based on market movements.
Statoil has established an Enterprise-Wide Risk Management Program, which establishes guidelines for entering into contractual arrangements (derivatives) to manage its commodity price, foreign currency rate, and interest rate risk. Our Corporate Risk Committee meets on a regular basis to review the existing policies and implementation of the guidelines. These procedures establish control over the use of derivatives, routine monitoring and reporting requirements, as well as counter-party credit approval processes.
See Item 5-Operating and Financial Review and Prospects-Critical Accounting Policies and Estimates-Risk Management for details on our assessment of fair market value of derivatives.
Commodity Risk. The following table contains the fair market value and related price risk sensitivity of our commodity-based derivatives, as accounted for under FAS 133, all amounts in NOK million
| Fair market value asset | Fair market value liability | 10% sensitivity |
At December 31, 2005 |
|
|
|
Crude Oil and Refined Products | 728 | (867) | 1,102 |
Natural Gas and Electricity | 464 | (324) | 44 |
At December 31, 2004 |
|
|
|
Crude Oil and Refined Products | 1,230 | (594) | 389 |
Natural Gas and Electricity | 167 | (182) | 7 |
Substantially all these fair market value assets and liabilities are related to over-the-counter (OTC) derivatives. The term of crude oil and refined products derivatives is usually less than one year. The term of natural gas forwards is usually three years or less. Included in the fair market values and basis for sensitivity figures are immaterial derivative positions held for speculative purposes.
Price risk sensitivities for 2005 and 2004 were calculated by assuming a hypothetical across-the-board 10 per cent adverse change in all commodity prices regardless of the term or historical relationships between the contractual price of the instrument and the underlying commodity prices. In the event of an actual 10 per cent change in all underlying prices, the change in the fair value of the derivative portfolio at the two respective year ends would typically be different from that shown above due to expected correlations between risk categories. In addition, there would be expected offsetting effects from changes in the fair value of our corresponding physical positions, contracts and anticipated transactions, which are not required to be recorded at market, and which are not reflected in the above table.
A 10 per cent relative change of certain underlying commodity prices in relation to other prices would typically yield other sensitivities than those provided in the table above. Natural Gas sensitivities may for instance be adversely impacted by certain relative commodity price changes, due to pricing elements in long-term physical delivery contracts and assumptions used in arriving at the fair market value of FAS 133 derivatives related to long-term contracts.
Interest and Currency Risk. Interest and currency risks constitute significant financial risks for the Statoil group. Total exposure is managed at a portfolio level in accordance with approved strategies and mandates. Interest rate risk and currency risk are assessed against mandates on a regular basis. The fair market value of financial instruments related to our interest rate swaps currency swaps and fixed interest long-term debt are specified in the table below:
| Net fair market value at December 31, | |
| 2005 | 2004 |
Debt-related instruments | 3,425 | 5,011 |
Non-debt related instruments | (2,025) | 1,967 |
Long-term fixed interest debt | (28,498) | (27,702) |
The estimated loss associated with a 10 per cent adverse change in NOK currency rates would result in a loss of fair value of approximately NOK 6.8 billion and NOK 5.3 billion as of December 31, 2005 and 2004 respectively. A hypothetical one percentage point adverse change in interest rates would result in a loss of NOK 0.3 billion and NOK 0.3 billion related to interest-bearing liabilities, investments in debt securities and related financial instruments as of December 31, 2005, and 2004, respectively. These estimated currency and interest rate sensitivities are based on an uncorrelated loss scenario and actual results could vary due to assumptions used and offsetting account correlations not reflected within this analysis.
Statoil’s cash flows are largely in U.S. dollars and euros but significant amounts are also in Norwegian kroner, Swedish kroner, Danish kroner and UK pounds sterling. The currencies in the debt portfolio are managed in connection with our expected future net cash flows per currency. Our debt, after considering currency swaps, is mainly in U.S. dollars.
Equity Securities. Equity securities, consisting mainly of the portfolio held by Statoil Forsikring a.s., are recorded at fair value and have exposure to price risk. The fair value of equity securities is based on quoted market prices. Risk is estimated as the potential loss in fair value resulting from a hypothetical 10 per cent adverse change in quoted market prices. Actual results may vary due to assumptions utilized and risk correlations.
Fair market value at December 31, in NOK million | 2005 | 2004 |
Equity securities | 3,994 | 2,257 |
Market risk on equity securities, amounts in NOK million | 2005 | 2004 |
10 per cent change in share prices | 399 | 226 |
Item 12 Description of Securities Other Than Equity Securities
Not applicable.
PART II
Item 13 Defaults, Dividend Arrearages and Delinquencies
None.
Item 14 Material Modifications to the Rights of Security Holders and Use of Proceeds
None.
Item 15 Controls and Procedures
Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rules 13a-15(b) as of the end of the period covered by this Form 20-F. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that these disclosure controls and procedures are effective at the reasonable assurance level.
In designing and evaluating our disclosure controls and procedures, our management, with the participation of the Chief Executive Officer and Chief Financial Officer, recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected.
There were no changes to our internal control over financial reporting that occurred during the period covered by this Form 20-F that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Item 16A Audit Committee Financial Expert
Our board of directors has determined that a member of our Audit Committee, Mr. Finn A Hvistendahl, qualifies as an “audit committee financial expert”, as defined in Item 16A of Form 20-F. The board of directors has also determined that Mr. Hvistendahl is independent within the meaning of Rule 10A-3 under the Securities Exchange Act.
Item 16B Code of Ethics
Statoil has adopted a code of ethics that applies to the Chief Executive Officer, Chief Financial Officer and the principal accounting officer. We have published our code of ethics on our website. It is accessible at www.statoil.com/ethics.
Statoil also has ethical guidelines that apply to all employees. The guidelines are principle-based and describe corporate values and required standards of business conduct and ethics. The ethical guidelines are designed to deter wrongdoing and to promote honest and ethical conduct, compliance with applicable laws and regulations, internal reporting of violations of the guidelines and accountability for adherence of the guidelines.
Item 16C Principal Accountant Fees and Services
Ernst & Young has served as our independent public auditor for each of the fiscal years in the three-year period ended December 31, 2005, for which audited consolidated financial statements appear in this annual report on Form 20-F.
The following table shows information about fees paid by Statoil to Ernst & Young.
(in NOK million) | For the year ended December 31, | |
2005 | 2004 | |
Audit fees | 25.0 | 23.8 |
Audit-related fees | 11.4 | 4.5 |
Tax fees | 0.1 | 5.1 |
Total | 36.5 | 33.4 |
Audit Services are defined as the standard audit work that needs to be performed each year in order to issue an opinion on the consolidated financial statements of Statoil, and to issue reports on the Norwegian GAAP statutory financial statements. It also includes other audit services which are those services that only the external auditor reasonably can provide, such as auditing of non-recurring transactions and application of new accounting policies, audits of significant and newly implemented system controls and pre-issuance reviews of quarterly financial results
Audit Related Services include those other assurance and related services provided by auditors, but not restricted to those that can only reasonably be provided by the external auditor signing the audit report, that are reasonably related to the performance of the audit or review of the company's financial statements such as acquisition due diligence, audits of pension and benefit plans, consultations concerning financial accounting and reporting standards.
Tax Services include the assistance with compliance and reporting of excise and value added taxes, assistance with our assessment of new or changing tax regimes, assessment of our transfer pricing policies and practices, and assistance with assessing relevant rules, regulations and facts going into our correspondence with tax authorities.
Audit Committee Pre-approval Policies and Procedures
Effective from the appointment of the audit committee by the board of directors, all services provided by the external auditor must be pre-approved by the audit committee. Provided that the suggested types of services are permissible under SEC guidelines, pre-approval is usually granted in a regular audit committee meeting. The Chairman of the audit committee has been given the authority to pre-approve when deemed necessary, provided that the full audit committee is presented to the case at its next meeting. Some pre-approvals may therefore be granted on an ad hoc basis by the Chairman of the audit committee if an urgent reply is deemed necessary.
Item 16D Exemptions from the Listing Standards for Audit Committees
Statoil is relying on the exemption provided in Rule 10A-3(b)(1)(iv)(C) from the independence requirements of the Securities Exchange Act with respect to Morten Svaan, a member of the audit committee and who is also one of three members of the board of directors of Statoil elected by the employees in accordance with Norwegian companies law. Mr. Svaan is a non-executive employee of the company and currently works as a project leader within HSE. Statoil does not believe that its reliance on this exemption would materially adversely affect the ability of the audit committee to act independently or to satisfy the other requirements of Rule 10A-3 relating to audit committees.
Item 16E Purchases of Equity Securities by the Issuer and Affiliated Purchasers
The annual general meeting of shareholders authorized on May 11, 2005 that the board of directors on behalf of the company acquire Statoil shares in the market. The authorization may be used to acquire Statoil shares with an overall nominal value of up to NOK 10 million.
The board decides the manner in which the acquisition of Statoil shares in the market take place. Shares acquired in accordance with the authorization may only be used for sale and transfer to employees of the Statoil group as part of the group’s share investment plan approved by the board. The lowest amount which may be paid per share is the nominal value and the highest amount which may be paid per share is a maximum of 100 times the nominal value. The current authorization is valid until November 2006.
The nominal value of each share is NOK 2.50 (USD 0.37). At a maximum overall nominal value of NOK 10 million, the current authorization covers a repurchase of no more than four million shares.
Period in which shares where repurchased | Number of shares repurchased | Average price per | Total number of shares purchased as part of program(1) | Maximum number of shares that may yet be purchased under the program |
74,266 | 95.14 | 74,266 | 3,914,743 | |
February 2005 | 69,803 | 106.35 | 69,803 | 3,844,940 |
March 2005 | 68,366 | 110.35 | 68,366 | 3,776,574 |
April 2005 | 69,540 | 109.72 | 69,540 | 3,707,034 |
May 2005 | 69,132 | 106.81 | 69,132 | 3,637,902 |
June 2005 | 59,093 | 127.00 | 59,093 | 3,578,809 |
July 2005 | 59,889 | 145.88 | 59,889 | 3,518,920 |
August 2005 | 59,152 | 153.00 | 59,152 | 3,459,768 |
September 2005 | 54,990 | 161.00 | 54,990 | 3,404,778 |
October 2005 | 58,302 | 143.88 | 58,302 | 3,346,476 |
November 2005 | 61,471 | 144.82 | 61,471 | 3,285,005 |
December 2005 | 51,332 | 157.94 | 51,332 | 3,233,673 |
January 2006 | 41,183 | 168.23 | 41,183 | 3,192,490 |
February 2006 | 39,299 | 169.20 | 39,299 | 3,153,191 |
March 2006 | 38,440 | 175,07 | 38,440 | 3,114,751 |
Total | 874,258(2) | 133.71(3) | 874,258 | 3,114,751 |
(1) The authorization to repurchase a maximum of four million shares with a maximum overall nominal value of NOK 10 million was given by the annual general meeting on May 5, 2004 and renewed on May 11, 2005. The current authorization is valid until November 2006.
(2) All shares repurchased have been purchased in the open market and pursuant to authorizations mentioned above.
(3) Weighted average price per share. Converted for the convenience of the reader at the year-end 2005 rate of exchange of NOK/USD 6.7444, this is equivalent to USD 19.81.
PART III
Item 17 Financial Statements
Not applicable.
Item 18 Financial Statements
The consolidated financial statements beginning on page F-1 and the related notes, together with the report thereon of Ernst & Young, are filed as part of this Annual Report on Form 20-F.
Item 19 Exhibits
The following exhibits are filed as part of this Annual Report:
Exhibit 1 | Articles of Association of Statoil ASA, as amended (English translation) (Incorporated by reference to exhibit 1 to Statoil’s Annual Report on Form 20-F for the fiscal year ended December 31, 2002) (File no. 1-15200). |
Exhibit 2(b)(i) | Instruments Defining the Rights of Holders of Long-Term Debt: The total amount of long-term securities of Statoil authorized under any instrument does not exceed 10 per cent of the total assets of Statoil on a consolidated basis. Statoil agrees to furnish copies of any or all such instruments to the Securities and Exchange Commission upon request. |
Exhibit 4(a) (i) | Technical Service Agreement between Gassco AS and Statoil ASA, dated February 27, 2002 (Incorporated by reference to exhibit 4 to Statoil’s Annual Report on Form 20-F for the fiscal year ended December 31, 2001) (File no. 1-15200). |
Exhibit 4(a) (ii) | Agreement relating to purchase and sale of SDFI assets (Incorporated by reference to Exhibit 10.1 to Statoil’s Registration Statement on Form F-1, filed on May 14, 2001) (File no. 333-13502). |
Exhibit 4(c) | Employment agreements with Helge Lund (English translation) (Incorporated by reference to exhibit 4 (c) to Statoil’s Annual Report on Form 20-F for the fiscal year ended December 31, 2003) (File no. 1-15200). |
Exhibit 8 | Subsidiaries. |
Exhibit 12 | Rule 13a-14(a) Certifications. |
Exhibit 13 | Rule 13a-14(b) Certifications. |
SIGNATURE
The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this Annual Report on its behalf.
STATOIL ASA
(Registrant)
By: /s/ ELDAR SÆTRE
Eldar Sætre
Chief Financial Officer
Dated: March 31, 2006
Appendix A - Report of DeGolyer and MacNaughton
DEGOLYER AND MACNAUGHTON
5001 Spring Valley Road
Suite 800 East
Dallas, Texas 75244
February 27, 2006
Statoil ASA
Forusbeen 50
N-4035 Stavanger
Norway
Gentlemen:
Pursuant to your request, we have prepared estimates of the proved oil, condensate, liquefied petroleum gas (LPG), and sales gas reserves, as of December 31, 2005, of certain properties in Algeria, Angola, Azerbaijan, China, Iran, Ireland, Nigeria, Norway, the United Kingdom, the United States and Venezuela owned by Statoil ASA (STATOIL). The estimates are discussed in our “Report as of December 31, 2005 on Proved Reserves of Certain Properties owned by Statoil ASA” (the Report). We also have reviewed STATOIL’s estimates of reserves, as of December 31, 2005, of the same properties included in the Report.
In our opinion, the information relating to proved reserves estimated by us and referred to herein has been prepared in accordance with Paragraphs 10–13, 15, and 30(a)–(b) of Statement of Financial Accounting Standards No. 69 (November 1982) of the Financial Accounting Standards Board and Rules 4–10(a)(1)–(13) of Regulation S–X of the United States Securities and Exchange Commission (SEC).
STATOIL represents that its estimates of the proved reserves, as of December 31, 2005, attributable to STATOIL’s interests in the properties included in the Report are as follows, expressed in millions of barrels (MMbbl) or billions of cubic feet (Bcf):
Oil, Condensate, and LPG | Sales Gas | Net Equivalent |
1,761 | 14,225 | 4,295 |
Note: Net equivalent million barrels is based on 5,612 cubic feet of gas being equivalent to 1 barrel of oil, condensate, or LPG. |
STATOIL has advised us that its estimates of proved oil, condensate, LPG, and natural gas reserves are in accordance with the rules and regulations of the SEC. It is our opinion that the guidelines and procedures that STATOIL has adopted to prepare its estimates are in accordance with generally accepted petroleum reserves evaluation practices and are in accordance with the requirements of the SEC.
Our estimates of the proved reserves, as of December 31, 2005, attributable to STATOIL’s interests in the properties included in the Report are as follows, expressed in millions of barrels (MMbbl) or billions of cubic feet (Bcf):
Oil, Condensate, and LPG | Sales Gas | Net Equivalent |
1,777 | 14,242 | 4,315 |
Note: Net equivalent million barrels is based on 5,612 cubic feet of gas being equivalent to 1 barrel of oil, condensate, or LPG. |
In comparing the detailed reserves estimates prepared by us and those prepared by STATOIL for the properties involved, we have found differences, both positive and negative, in reserves estimates for individual properties. These differences appear to be compensating to a great extent when considering the reserves of STATOIL in the properties included in the Report, resulting in overall differences not being substantial. It is our opinion that the reserves estimates prepared by STATOIL on the properties reviewed by us and referred to above, when compared on the basis of net equivalent million barrels of oil, in aggregate, do not differ materially from those prepared by us.
Submitted,
DeGOLYER and MacNAUGHTON
Financial Statements
Table of Contents
Audited Consolidated Financial Statements for the year ended December 31, 2005 |
Supplementary Information on Oil and Gas Producing Activities (unaudited) |
TO THE BOARD OF DIRECTORS AND SHAREHOLDERS OF STATOIL ASA
Report of Independent Registered Public Accounting Firm – USGAAP accountsWe have audited the accompanying consolidated balance sheets of Statoil ASA and subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of income, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2005. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Statoil ASA and subsidiaries at December 31, 2005 and 2004, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with U.S. generally accepted accounting principles.
Ernst & Young AS
Jostein Johannessen
State Authorized Public Accountant
(Norway)
CONSOLIDATED STATEMENTS OF INCOME - USGAAP
For the year ended December 31, | |||
(in NOK million) | 2005 | 2004 | 2003 |
REVENUES | |||
Sales | 390,540 | 303,756 | 248,527 |
Equity in net income of affiliates | 1,090 | 1,209 | 616 |
Other income | 1,668 | 1,253 | 232 |
Total revenues | 393,298 | 306,218 | 249,375 |
EXPENSES | |||
Cost of goods sold | (235,722) | (188,179) | (149,645) |
Operating expenses | (30,327) | (27,350) | (26,651) |
Selling, general and administrative expenses | (7,803) | (6,298) | (5,517) |
Depreciation, depletion and amortization | (21,097) | (17,456) | (16,276) |
Exploration expenses | (3,253) | (1,828) | (2,370) |
Total expenses before financial items | (298,202) | (241,111) | (200,459) |
Income before financial items, other items, | |||
income taxes and minority interest | 95,096 | 65,107 | 48,916 |
Net financial items | (3,562) | 5,739 | 1,399 |
Other items | 0 | 0 | (6,025) |
Income before income taxes and minority interest | 91,534 | 70,846 | 44,290 |
Income taxes | (60,039) | (45,425) | (27,447) |
Minority interest | (765) | (505) | (289) |
Net income | 30,730 | 24,916 | 16,554 |
Ordinary and diluted earnings per share | 14.19 | 11.50 | 7.64 |
Weighted average number of ordinary shares outstanding | 2,165,740,054 | 2,166,142,636 | 2,166,143,693 |
Revenues are net of excise tax of NOK 23,336, NOK 22,910 and NOK 20,753 million in 2005, 2004 and 2003, respectively.
See notes to the consolidated financial statements.
CONSOLIDATED BALANCE SHEETS - USGAAP
At December 31, | ||
(in NOK million) | 2005 | 2004 |
ASSETS | ||
Cash and cash equivalents | 7,025 | 5,028 |
Short-term investments | 6,841 | 11,621 |
Cash, cash equivalents and short-term investments | 13,866 | 16,649 |
Accounts receivable | 43,361 | 31,736 |
Inventories | 8,635 | 6,971 |
Prepaid expenses and other current assets | 10,989 | 9,713 |
Total current assets | 76,851 | 65,069 |
Investments in affiliates | 4,451 | 10,339 |
Long-term receivables | 9,691 | 8,176 |
Net property, plant and equipment | 181,481 | 152,916 |
Other assets | 16,505 | 11,743 |
TOTAL ASSETS | 288,979 | 248,243 |
LIABILITIES AND SHAREHOLDERS’ EQUITY | ||
Short-term debt | 1,529 | 4,730 |
Accounts payable | 23,262 | 19,282 |
Accounts payable - related parties | 9,766 | 5,621 |
Accrued liabilities | 13,145 | 12,385 |
Income taxes payable | 29,750 | 19,117 |
Total current liabilities | 77,452 | 61,135 |
Long-term debt | 32,669 | 31,459 |
Deferred income taxes | 43,347 | 44,270 |
Other liabilities | 27,375 | 24,733 |
Total liabilities | 180,843 | 161,597 |
Minority interest | 1,492 | 1,616 |
Common stock (NOK 2.50 nominal value), 2,189,585,600 shares authorized and issued | 5,474 | 5,474 |
Treasury shares, 24,208,212 and 23,452,876 shares | (156) | (60) |
Additional paid-in capital | 37,304 | 37,273 |
Retained earnings | 65,402 | 46,153 |
Accumulated other comprehensive income (loss) | (1,380) | (3,810) |
Total shareholders’ equity | 106,644 | 85,030 |
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | 288,979 | 248,243 |
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY - USGAAP
(in NOK million, except share data) | Number of shares issued | Share capital | Treasury shares | Additional paid-in capital | Retained earnings | Accumulated other comprehensive income | Total |
At January 1, 2003 | 2,189,585,600 | 5,474 | (59) | 37,728 | 17,355 | (3,481) | 57,017 |
Net income | 16,554 | 16,554 | |||||
Translation adjustment and other | |||||||
comprehensive income | 2,885 | 2,885 | |||||
Total comprehensive income | 19,439 | ||||||
Ordinary dividend | (6,282) | (6,282) | |||||
At December 31, 2003 | 2,189,585,600 | 5,474 | (59) | 37,728 | 27,627 | (596) | 70,174 |
Net income | 24,916 | 24,916 | |||||
Translation adjustment and other | |||||||
comprehensive income | (3,214) | (3,214) | |||||
Total comprehensive income | 21,702 | ||||||
Settlement with the Norwegian | |||||||
State (see note 1) | (458) | (458) | |||||
Value of stock compensation plan | 3 | 3 | |||||
Treasury shares purchased | (1) | (1) | |||||
Ordinary dividend | (6,390) | (6,390) | |||||
At December 31, 2004 | 2,189,585,600 | 5,474 | (60) | 37,273 | 46,153 | (3,810) | 85,030 |
Net income | 30,730 | 30,730 | |||||
Translation adjustment and other | |||||||
comprehensive income | 2,430 | 2,430 | |||||
Total comprehensive income | 33,160 | ||||||
Value of stock compensation plan | 31 | 31 | |||||
Treasury shares purchased | (96) | (96) | |||||
Ordinary dividend | (11,481) | (11,481) | |||||
At December 31, 2005 | 2,189,585,600 | 5,474 | (156) | 37,304 | 65,402 | (1,380) | 106,644 |
Other comprehensive income amounts are net of income tax benefit of NOK 161, NOK 38 and NOK 81 million at December 31, 2005, 2004 and 2003, respectively.
Dividends paid per share were NOK 5.30, NOK 2.95 and NOK 2.90 in 2005, 2004 and 2003, respectively.
See notes to the consolidated financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS - USGAAP
For the year ended December 31, | |||
(in NOK million) | 2005 | 2004 | 2003 |
OPERATING ACTIVITIES | |||
Consolidated net income | 30,730 | 24,916 | 16,554 |
Adjustments to reconcile net income to net cash flows provided by operating activities: | |||
Minority interest in income | 765 | 505 | 289 |
Depreciation, depletion and amortization | 21,097 | 17,456 | 16,276 |
Exploration expenditures written off | 158 | 110 | 256 |
(Gains) losses on foreign currency transactions | 1,330 | (1,919) | 781 |
Deferred taxes | (5,078) | 5,006 | (6,177) |
(Gains) losses on sales of assets and other items | (1,605) | (1,531) | 5,719 |
Changes in working capital (other than cash and cash equivalents): | |||
• (Increase) decrease in inventories | (1,664) | (1,645) | 349 |
• (Increase) decrease in accounts receivable | (11,625) | (1,149) | 2,054 |
• (Increase) decrease in prepaid expenses and other current assets | (1,842) | (4,590) | (1,511) |
• (Increase) decrease in short-term investments | 4,780 | (2,307) | (4,047) |
• Increase (decrease) in accounts payable | 7,923 | (147) | (949) |
• Increase (decrease) in other payables | 282 | 1,449 | 2,436 |
• Increase (decrease) in taxes payable | 10,522 | 1,387 | (682) |
(Increase) decrease in non-current items related to operating activities | 477 | 1,266 | (551) |
Cash flows provided by operating activities | 56,250 | 38,807 | 30,797 |
INVESTING ACTIVITIES | |||
Acquisitions, net of cash acquired | (13,154) | 0 | 0 |
Additions to property, plant and equipment | (31,389) | (31,800) | (22,075) |
Exploration expenditures capitalized | (1,242) | (748) | (331) |
Change in long-term loans granted and other long-term items | (734) | (2,650) | (7,682) |
Proceeds from sale of business | 7,802 | 0 | 0 |
Proceeds from sale of assets | 1,053 | 3,239 | 6,890 |
Cash flows used in investing activities | (37,664) | (31,959) | (23,198) |
FINANCING ACTIVITIES | |||
New long-term borrowings | 422 | 4,599 | 3,206 |
Repayment of long-term borrowings | (3,187) | (6,574) | (2,774) |
Distribution to minority shareholders | (910) | (559) | (356) |
Dividends paid | (11,481) | (6,390) | (6,282) |
Net short-term borrowings, bank overdrafts and other | (1,358) | (131) | (1,656) |
Cash flows used in financing activities | (16,514) | (9,055) | (7,862) |
Net increase (decrease) in cash and cash equivalents | 2,072 | (2,207) | (263) |
Effect of exchange rate changes on cash and cash equivalents | (75) | (81) | 877 |
Cash and cash equivalents at the beginning of the year | 5,028 | 7,316 | 6,702 |
Cash and cash equivalents at the end of the year | 7,025 | 5,028 | 7,316 |
Interest paid | 2,004 | 1,179 | 1,336 |
Taxes paid | 54,625 | 38,844 | 34,230 |
Changes in working capital items resulting from the disposal of the subsidiary Navion in 2003 are excluded from Cash flows provided by operating activities and classified as Proceeds from sale of assets. Changes in balance sheet items resulting from the acquisition of the Statoil Detaljhandel Skandinavia in 2004 are excluded from Cash flows provided by operating activities and Cash flows used in financing activities, and classified as Additions to property, plant and equipment.
See notes to the consolidated financial statements.
1. ORGANIZATION AND BASIS OF PRESENTATION
Statoil ASA was founded in 1972, as a 100 per cent Norwegian State-owned company. Statoil’s business consists principally of the exploration, production, transportation, refining and marketing of petroleum and petroleum-derived products. In 1985, the Norwegian State transferred certain properties from Statoil to the State’s direct financial interest (SDFI), which were also 100 per cent owned by the Norwegian State.
In conjunction with a partial privatization of Statoil in June 2001, the Norwegian State restructured its holdings in oil and gas properties on the Norwegian Continental Shelf. In this restructuring, the Norwegian State transferred to Statoil certain SDFI properties with a book value of approximately NOK 30 billion, in consideration for which NOK 38.6 billion in cash plus interest and currency fluctuation from the valuation date of NOK 2.2 billion (NOK 0.7 billion after tax), and certain pipelines and other assets with a net book value of NOK 1.5 billion were transferred to the Norwegian State. The transaction was completed June 1, 2001 with a valuation date of January 1, 2001 with the exception of the sale of an interest in the Mongstad terminal which had a valuation date of June 1, 2001.
The total amount paid to the Norwegian State was financed through a public offering of shares of NOK 12.9 billion, issuance of new debt of NOK 9 billion and the remainder from existing cash and short-term borrowings.
The transfer of properties from SDFI has been accounted for as transactions among entities under common control and the results of operations and financial position have been accounted for at historical cost. The final cash settlement is under review by the Norwegian State, and Statoil recorded in 2004 the estimated outcome against shareholders’ equity. No further material impact is expected.
2. SUMMARY OF SIGNIFICANT ACCOUTING POLICIES
The consolidated financial statements of Statoil ASA and its subsidiaries (the Company or the group) are prepared in accordance with United States generally accepted accounting principles (USGAAP).
Consolidation
The consolidated financial statements include the accounts of Statoil ASA and subsidiary companies owned directly or indirectly more than 50 per cent. Inter-company transactions and balances have been eliminated. Investments in companies in which Statoil does not have control, but has the ability to exercise significant influence over operating and financial policies (generally 20 to 50 per cent ownership), are accounted for by the equity method. Undivided interests in unincorporated joint ventures in the oil and gas business, including pipeline transportation, are consolidated on a pro rata basis.
Foreign currency translation
Each foreign entity’s financial statements are prepared in the currency in which that entity primarily conducts its business (the functional currency). For Statoil’s foreign subsidiaries the local currency is normally identical with the functional currency, with the exception of some upstream and trading subsidiaries, which have US dollar as functional currency, mainly because most of the revenues and costs are in US dollar.
When translating foreign functional currency financial statements to Norwegian kroner, year-end exchange rates are applied to asset and liability accounts, and average rates are applied to income statement accounts. Adjustments resulting from this process are included in the Accumulated other comprehensive income account in shareholders’ equity, and do not affect net income.
Transactions denominated in currencies other than the entity’s functional currency are re-measured into the functional currency using current exchange rates. Gains or losses from this re-measurement are included in income.
Revenue recognition
Revenues associated with sale and transportation of crude oil, natural gas, petroleum and chemical products and other merchandises are recorded when title passes to the customer at the point of delivery of the goods based on the contractual terms of the agreements. Revenue is recorded net of customs, excise taxes and royalties paid in kind on petroleum products.
Sales and purchases of physical commodities which are not settled net are presented on a gross basis as Sales and Cost of goods sold in the Income statement. Activities related to the trading of commodity based derivative instruments are reported on a net basis, with the margin included in Sales. Arrangements involving a series of buys and sells entered into in order to obtain a given quantity and quality of a commodity at a given location are recognized net and included in Sales.
Revenues from the production of oil and gas properties in which we have an interest with other companies are recorded on the basis of volumes lifted and sold to customers during the period in accordance with the sales method.
Transactions with the Norwegian State
Statoil markets and sells the Norwegian State’s share of oil and gas production from the Norwegian continental shelf (NCS). All purchases and sales of SDFI oil production are recorded as Cost of goods sold and Sales. All oil received by the Norwegian State as royalty in kind from fields on the NCS is purchased by Statoil. Statoil includes the costs of purchase and proceeds from the sale of this royalty oil in its Cost of goods sold and Sales respectively.
Statoil is selling, in its own name, but for the Norwegian State’s account and risk, the state’s production of natural gas. This sale and related expenses refunded by the State, are recorded net in Statoil’s financial statements. Refunds include expenses related to activities incurred to secure market access, and investments made to maximize profitability from the sale of natural gas.
Inter-company balances and transactions in connection with activities in licenses are not included in related parties’ transactions.
Cash and cash equivalents
Cash and cash equivalents include cash, bank deposits and all other monetary instruments with three months or less to maturity at the date of purchase.
Short-term investments
Short-term investments include bank deposits and all other monetary instruments and marketable equity and debt securities with a maturity of between three and twelve months at the date of purchase. The portfolios of securities are considered trading securities and are valued at fair value (market). The resulting unrealized holding gains and losses are included in Net financial items.
Inventories
Inventories are valued at the lower of cost or market. Costs of crude oil held at refineries and the majority of refined products are determined under the last-in, first-out (LIFO) method. Certain inventories of crude oil, refined products and non-petroleum products are determined under the first-in, first-out (FIFO) method. Cost includes raw material, freight, and direct production costs together with a share of indirect costs.
Use of estimates
Preparation of the financial statements requires the Company to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as disclosures of contingencies. Actual results may ultimately differ from the estimates and assumptions used.
The nature of Statoil’s operations, and the many countries in which Statoil operates, are subject to changing economic, regulatory and political conditions. Statoil does not believe it is vulnerable to the risk of a near-term severe impact as a result of any concentration of its activities.
Property, plant and equipment
Property, plant and equipment are carried at historical cost less accumulated depreciation, depletion and amortization. Expenditures for significant renewals and improvements are capitalized. Ordinary maintenance and repairs are charged to income when performed. Provisions are made for costs related to significant periodic maintenance programs.
Depreciation of production installations and field-dedicated transport systems for oil and gas is calculated using the unit of production method based on proved reserves expected to be recovered during the concession or contract period. Ordinary depreciation of other assets and of transport systems used by several fields is calculated on the basis of their economic life expectancy, using the straight-line method. The economic life of nonfield-dedicated transport systems is normally the production period of the related fields, limited by the concession or contract period. Straight-line depreciation of other assets is based on the following estimated useful lives:
Machinery and equipment | 3 — 10 years | |
Production plants onshore | 15 — 20 years | |
Buildings | 20 — 33 years | |
Vessels | 20 — 25 years | |
Intangibles | 10 — 20 years |
Oil and gas accounting
Statoil uses the “Successful efforts”- method of accounting for oil and gas producing activities. Expenditures to acquire mineral interests in oil and gas properties and to drill and equip exploratory wells are capitalized until it is clarified if there are proved reserves. Expenditures to drill exploratory wells that do not find proved reserves, and geological and geophysical and other exploration expenditures are expensed.
Unproved oil and gas properties are assessed quarterly; unsuccessful wells are expensed. Exploratory wells that have found reserves, but classification of those reserves as proved depends on whether a major capital expenditure can be justified, may remain capitalized for more than one year. The main conditions are that either firm plans exist for future drilling in the license or a development decision is planned in the near future.
Expenditures to drill and equip exploratory wells that find proved reserves are capitalized. Capitalized expenditures of producing oil and gas properties are depreciated and depleted by the unit of production method. Pre-production expenditures are expensed as incurred.
Impairment of long-lived assets
Tangible assets, identifiable intangible assets and goodwill, are tested for impairment when events or a change in circumstances during the year indicate that their carrying amount may not be recoverable. Goodwill is tested for impairment every year.
Impairment of long lived assets is determined for each autonomous group of assets (oil and gas fields or licenses, or independent operating units) by comparing their carrying value with the undiscounted cash flows they are expected to generate based upon management’s expectations of future economic and operating conditions . Should this comparison indicate that an asset is impaired, the asset is written down to fair value, generally determined based on expected discounted cash flows.
Goodwill is tested for impairment at the reporting unit level by comparing the reporting unit’s carrying value (including goodwill) with its estimated fair value, generally determined based on expected discounted cash flows.
Assets held for sale
Assets held for sale are classified as short-term if the appropriate accounting criteria are met. The main criteria are that management with the authority to do so commits to a plan to sell the assets and expects to record the transfer of the assets as a completed sale within one year. Assets held for sale are measured at the lower of its carrying amount or fair value less costs to sell.
Asset retirement obligation
Financial Accounting Standard (FAS) 143, Accounting for Asset Retirement Obligations was effective from January 1, 2003. The Statement requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. Fair value is estimated based on existing technology and regulation. Upon initial recognition of a liability, the costs are capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. Changes in asset retirement obligation estimates are capitalized as part of the long-lived asset and charged to income prospectively over the remaining useful life of the asset. The discount rate used when estimating the fair value of the asset retirement obligation is a credit-adjusted risk-free interest rate with the same expected maturity as the removal obligation.
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.
Leased assets
Capital leases, which provide Statoil with substantially all the rights and obligations of ownership, are classified as assets under Property, plant and equipment and as liabilities under Long-term debt valued at the present value of minimum lease payments. The assets are subsequently depreciated over their expected economic life, and the liability is reduced for lease payments less the effective interest expense.
Employee retirement plans
Defined benefit plans where the employees have the right of a defined amount of pension, are allocated to net income over the service period. Accumulated gains and losses in excess of 10 per cent of the greater of the benefit obligation or the fair value of assets are amortized over the remaining service period of active plan participants. Prior service costs, due to plan amendments on defined benefit plans, are amortized on a straight-line basis over the average remaining service period of active participants.
Contribution plans, plans where the company’s obligation is to contribute a defined amount to the employee, are allocated to net income in the period the contribution covers. Multi-employer plans are recognized similar to contribution plans.
Stock based compensation
Statoil adopted in 2004 FAS 123 (R) and related interpretations in accounting for the compensation plan as it relates to bonus shares. In accordance with this standard compensation expense is measured at fair value. Compensation expense is measured at the grant date based on the estimated value of the awarded shares and recognized over the service period. The awarded shares are accounted for as compensation expense in the Income Statement and recorded as an equity transaction (included in Additional paid-in capital).
Research and development
Research and development expenditures are expensed as incurred.
Income taxes
Deferred income tax expense is calculated using the liability method. Under this method, deferred tax assets and liabilities are determined by applying the enacted statutory tax rates applicable to future years to the temporary differences between the carrying values of assets and liabilities for financial reporting and their tax basis. Effects of changes in tax laws and tax rates are recognized at the date the tax law changes.
Deferred tax benefit is reduced by a valuation allowance if it is unlikely that the benefit can be used. Uplift benefit is reflected in the accounts when the deduction impacts taxes payable.
Derivative financial instruments and hedging activities
Statoil operates in the worldwide crude oil, refined products, and natural gas markets and is exposed to fluctuations in hydrocarbon prices, foreign currency rates and interest rates that can affect the revenues and cost of operating, investing and financing. Statoil’s management has used and intends to use financial and commodity-based derivative contracts to reduce the risks in overall earnings and cash flows. Statoil applies hedge accounting in certain circumstances as allowed by FAS 133, and enters into derivatives which economically hedge certain of its risks even though hedge accounting is not allowed by the Statement or is not applied by Statoil.
For derivatives where hedge accounting is used, Statoil formally designates the derivative as either a fair value hedge of a recognized asset or liability or unrecognized firm commitment, or a cash flow hedge of an anticipated transaction. Statoil documents the designated hedging relationship upon entering into the derivative, including identification of the hedging instrument and the hedged item or transaction, strategy and risk management objective for undertaking the hedge, and the nature of the risk being hedged. Furthermore, each derivative is assessed for hedge effectiveness both at the inception of the hedging relationship and on a quarterly basis, for as long as the derivative is outstanding. Hedge accounting is only applied when the derivative is deemed to be highly effective at offsetting changes in fair values or anticipated cash flows of the hedged item or transaction. For hedged forecasted transactions, hedge accounting is discontinued if the forecasted transaction is no longer probable of occu rring. Any previously deferred hedging gains or losses would be recorded to earnings when the transaction is considered to be probable of not occurring. Earnings impacts for all designated hedges are recorded in the Consolidated Statement of Income generally on the same line item as the gain or loss on the item being hedged.
Statoil records all derivatives that do not qualify for the normal purchase and normal sales exemption at fair value as assets or liabilities in the Consolidated Balance Sheets. For fair value hedges, the effective and ineffective portions of the change in fair value of the derivative, along with the gain or loss on the hedged item attributable to the risk being hedged, are recorded in earnings as incurred. For cash flow hedges, the effective portion of the change in fair value of the derivative is deferred in accumulated Other comprehensive income in the Consolidated Balance Sheets until the transaction is reflected in the Consolidated Statements of Income, at which time any deferred hedging gains or losses are recorded in earnings. The ineffective portion of the change in the fair value of a derivative used as a cash flow hedge is recorded in earnings in Sales or Cost of goods sold as incurred.
Reclassifications
Certain reclassifications have been made to prior years’ figures to be consistent with current year’s presentation.
New Accounting Standards and changes in regulations
The Norwegian Parliament decided in June 2003 to replace governmental refunds for removal costs on the Norwegian continental shelf with ordinary tax deductions for such costs. Previously, removal costs were refunded by the Norwegian State based on the company’s percentage of income taxes payable over the productive life of the removed installation. As a consequence of the changes in legislation, Statoil has charged the receivable of NOK 6.0 billion against the Norwegian State related to refund of removal costs to income under Other items in the second quarter of 2003. Furthermore, the resulting deferred tax benefit of NOK 6.7 billion has been taken to income under Income taxes.
Statoil adopted Financial Accounting Standard (FAS) 123 (R) Share-Based Payment in 2004, as an employee share saving plan was introduced. Employees have the opportunity to buy shares in Statoil every year up to a ceiling of five per cent of their gross salary. For shares held for at least two calendar years, employees will receive one bonus share for every two purchased. The bonus element is valued at the grant day and charged to income over the vesting period. The effect on the Consolidated Statements of Income and financial position is immaterial.
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 Nonmonetary 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. If the standard had been applied as of January 1, 2003 the impact to the results and equity for the years 2003, 2004 and 2005 would have been immaterial.
Beginning January 1, 2006 Statoil will adopt 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 requires 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, nonfinancial assets be accounted for as a change in accounting estimate effected by a change in accounting principle.
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.
As of January 1, 2004 Natural Gas has taken over certain activities from International Exploration and Production. The activities consist of gas sales activities in some foreign countries, construction of a pipeline for transportation of natural gas from Azerbaijan to Turkey and sale of Statoil’s natural gas processed at the Cove Point terminal in the USA. Figures for 2003 have been adjusted to reflect the new structure.
At January 1, 2004 the Kollsnes activity was transferred from Exploration and Production Norway to Natural Gas. At February 1, 2004 the Kollsnes gas processing plant was transferred to Gassled. The transfer did not lead to significant changes in Statoil’s existing rights, obligations or book values of the Kollsnes assets. The operatorship was taken over by Gassco. Assets related to Kollsnes were transferred from Exploration and Production Norway to Natural Gas at net book value of NOK 4.2 billion. Prior periods’ figures have been adjusted to reflect the new structure.
The segment Other includes increased insurance costs of NOK 0.8 billion in 2005, due to extra insurance premiums and liabilities in the two mutual insurance companies in which Statoil Forsikring participates. The corresponding increase for 2004 is NOK 0.4 billion.
Segment data for the years ended December 31, 2005, 2004 and 2003 is presented below:
(in NOK million) | Exploration and Production Norway | International Exploration and Production | Natural Gas | Manufacturing and Marketing | Other and eliminations | Total |
Year ended December 31, 2005 | ||||||
Revenues third party | 2,114 | 6,366 | 44,973 | 338,318 | 437 | 392,208 |
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 | 339,380 | (109,091) | 393,298 |
Depreciation, depletion and amortization | 11,450 | 6,273 | 775 | 2,207 | 392 | 21,097 |
Income before financial items, other items, | ||||||
income taxes and minority interest | 74,132 | 8,364 | 5,901 | 7,646 | (947) | 95,096 |
Imputed segment income taxes | (56,030) | (3,027) | (4,013) | (1,288) | 0 | (64,358) |
Segment net income | 18,102 | 5,337 | 1,888 | 6,358 | (947) | 30,738 |
Year ended December 31, 2004 | ||||||
Revenues third party | 1,570 | 3,261 | 32,657 | 266,182 | 1,339 | 305,009 |
Revenues inter-segment | 72,403 | 6,504 | 447 | 58 | (79,412) | 0 |
Income (loss) from equity investments | 77 | 0 | 222 | 937 | (27) | 1,209 |
Total revenues | 74,050 | 9,765 | 33,326 | 267,177 | (78,100) | 306,218 |
Depreciation, depletion and amortization | 12,381 | 2,215 | 652 | 1,719 | 489 | 17,456 |
Income before financial items, other items, | ||||||
income taxes and minority interest | 51,029 | 4,188 | 6,784 | 3,921 | (815) | 65,107 |
Imputed segment income taxes | (37,904) | (1,429) | (4,381) | (850) | 0 | (44,564) |
Segment net income | 13,125 | 2,759 | 2,403 | 3,071 | (815) | 20,543 |
Year ended December 31, 2003 | ||||||
Revenues third party | 2,250 | 2,157 | 24,785 | 218,169 | 1,398 | 248,759 |
Revenues inter-segment | 60,170 | 4,458 | 445 | 120 | (65,193) | 0 |
Income (loss) from equity investments | 74 | 0 | 222 | 353 | (33) | 616 |
Total revenues | 62,494 | 6,615 | 25,452 | 218,642 | (63,828) | 249,375 |
Depreciation, depletion and amortization | 11,969 | 1,784 | 619 | 1,419 | 485 | 16,276 |
Income before financial items, other items, | ||||||
income taxes and minority interest | 37,855 | 1,781 | 6,005 | 3,555 | (280) | 48,916 |
Imputed segment income taxes | (28,066) | (676) | (4,196) | (755) | (15) | (33,708) |
Segment net income | 9,789 | 1,105 | 1,809 | 2,800 | (295) | 15,208 |
Borrowings are managed at a corporate level and interest expenses are not allocated to segments. Income tax is calculated on Income before financial items, other items, income taxes and minority interest. Additionally, income tax benefit on segments with net losses is not recorded. As such, Imputed segment income taxes and Segment net income can be reconciled to Income taxes and Net income per the Consolidated Statements of Income as follows:
For the year ended December 31, | |||
(in NOK million) | 2005 | 2004 | 2003 |
Segment net income | 30,738 | 20,543 | 15,208 |
Net financial items | (3,562) | 5,739 | 1,399 |
Other items (see note 2) | 0 | 0 | (6,025) |
Change in deferred tax due to new legislation (see note 2) | 0 | 0 | 6,712 |
Tax on financial items and other tax adjustments | 4,319 | (2,261) | (451) |
Change in deferred tax on undistributed earnings in foreign companies* | 0 | 1,400 | 0 |
Minority interest | (765) | (505) | (289) |
Net income | 30,730 | 24,916 | 16,554 |
Imputed segment income taxes | 64,358 | 44,564 | 33,708 |
Change in deferred tax due to new legislation (see note 2) | 0 | 0 | (6,712) |
Tax on financial items and other tax adjustments | (4,319) | 2,261 | 451 |
Change in deferred tax on undistributed earnings in foreign companies* | 0 | (1,400) | 0 |
Income taxes | 60,039 | 45,425 | 27,447 |
* | Due to changes in Norwegian tax legislation in 2004 dividends received from corporations are, with a few exceptions, exempted from Norwegian income tax. Consequently, deferred tax liabilities of NOK 1.4 billion related to undistributed retained earnings in subsidiaries and affiliates have been reversed. |
The Exploration and Production Norway and International Exploration and Production segments explore for, develop and produce crude oil and natural gas, and extract natural gas liquids, sulfur and carbon dioxide. The Natural Gas segment transports and markets natural gas and natural gas products. Manufacturing and Marketing is responsible for petroleum refining operations and the marketing of crude oil and refined petroleum products except gas.
Inter-segment revenues are sales to other business segments within Statoil and are at estimated market prices. These inter-company transactions are eliminated for consolidation purposes. Imputed segment income taxes are calculated on the basis of Income before financial items, other items, income taxes and minority interest.
Long-term deferred tax assets, included in Other long-term assets, are not allocated to business segments, but are included in the segment Other.
(in NOK million) | Addition to long-lived assets | Investments in affiliates | Other long- term assets |
Year ended December 31, 2005 | |||
Exploration and Production Norway | 16,257 | 252 | 86,134 |
International Exploration and Production | 25,295 | 0 | 62,163 |
Natural Gas | 2,542 | 3,261 | 15,976 |
Manufacturing and Marketing | 1,630 | 818 | 22,345 |
Other | 470 | 120 | 20,892 |
Total | 46,194 | 4,451 | 207,510 |
Year ended December 31, 2004 | |||
Exploration and Production Norway | 16,776 | 258 | 81,371 |
International Exploration and Production | 18,987 | 0 | 37,956 |
Natural Gas | 2,368 | 2,984 | 14,551 |
Manufacturing and Marketing | 4,162 | 7,022 | 23,033 |
Other | 551 | 75 | 15,924 |
Total | 42,844 | 10,339 | 172,835 |
Year ended December 31, 2003 | |||
Exploration and Production Norway | 13,136 | 1,324 | 75,144 |
International Exploration and Production | 8,019 | 0 | 31,875 |
Natural Gas | 860 | 2,006 | 13,766 |
Manufacturing and Marketing | 1,546 | 7,655 | 15,571 |
Other | 530 | 37 | 15,053 |
Total | 24,091 | 11,022 | 151,409 |
Revenues by geographic areas | |||
For the year ended December 31, | |||
(in NOK million) | 2005 | 2004 | 2003 |
Norway | 290,708 | 224,361 | 186,823 |
Europe (excluding Norway) | 48,189 | 44,465 | 27,436 |
United States | 35,106 | 26,974 | 26,486 |
Other areas | 18,205 | 9,209 | 8,014 |
Total revenues (excluding equity in net income of affiliates) | 392,208 | 305,009 | 248,759 |
Long-lived assets by geographic areas | |||
Norway | 132,828 | 121,511 | 112,993 |
Europe (excluding Norway) | 34,041 | 35,890 | 26,620 |
United States | 15,490 | 678 | 638 |
Other areas | 29,397 | 24,890 | 21,554 |
Total long-lived assets (excluding long-term deferred tax assets) | 211,756 | 182,969 | 161,805 |
4. SIGNIFICANT ACQUISITIONS AND DISPOSITIONS
Effective January 1, 2003 Statoil sold 100 per cent of the shares in Navion ASA to Norsk Teekay AS, a wholly-owned subsidiary of Teekay Shipping Corporation. The operations of Navion were shuttle tanking and conventional shipping. The sales price for the fixed assets of Navion, excluding Navion Odin and Navion’s 50 per cent share in the West Navigator drillship which were not included in the sale, was approximately USD 800 million. The sale was accounted for in the Manufacturing and Marketing segment and the effect on consolidated net income was immaterial.
Statoil and BP signed an agreement in June 2003 whereby Statoil acquired 49 per cent of BP’s interest in the In Salah gas project and 50 per cent of BP’s interest in the In Amenas gas condensate project, both in Algeria. The purchase price was USD 740 million, and Statoil has in addition covered the expenditures incurred after January 1, 2003 related to the acquired interests. After the receipt of necessary governmental approvals in 2004, the two projects were transferred from Long-term receivables to Property, plant and equipment in the Consolidated Balance Sheets. The projects are included in the segment International Exploration and Production.
In January 2004 Statoil acquired 11.24 per cent of the Snøhvit field, of which 10 per cent from Norsk Hydro and 1.24 per cent from Svenska Petroleum. Following these transactions, Statoil has an ownership share of 33.53 per cent in the Snøhvit field. The field is included in Property, plant and equipment and recorded in the segment Exploration and Production Norway.
In January 2004 Statoil sold its 5.26 per cent shareholding in the German company Verbundnetz Gas, generating a gain of NOK 619 million before tax (NOK 446 million after tax). The gain was classified as Other income in the Consolidated Statements of Income, and included in the segment Natural Gas.
In 2004 Statoil acquired the retailer group ICA’s 50 per cent holding in Statoil Detaljhandel Skandinavia AS (SDS), and now owns 100 per cent of SDS. Following approval under the EU merger control regulations on July 1, the transaction was completed on July 8, 2004. Based on Statoil’s ownership share, SDS was accounted for in accordance with the equity method up to and including the second quarter of 2004. SDS is consolidated as a subsidiary from the third quarter of 2004. NOK 0.5 billion of the cost price for SDS was allocated to goodwill and NOK 0.7 billion to intangible assets, mainly consisting of franchise agreements. SDS is included in the Manufacturing and Marketing segment.
In October 2004 Statoil sold its 50 per cent interest in the joint venture “Partrederiet West Navigator DA”, which owns the deepwater drill ship West Navigator, to Smedvig ASA. The interest in the joint venture was included in the segment Exploration and Production Norway. The agreed purchase price was USD 175 million for the vessel adjusted for Statoil’s share of the cash flow from the operation of the vessel from May 1, 2004. The effect on Income before financial items, other items, income taxes and minority interest was immaterial, while there was a positive tax effect of NOK 0.3 billion.
On April 27, 2005 Statoil entered into an agreement to acquire assets from EnCana Corporation’s Gulf of Mexico subsidiary at a cost of USD 2.0 billion plus the balance of costs incurred between effective date January 1, 2005 and the closing date. The acquisition includes working interests in six discoveries, including a 25 per cent interest in the Tahiti discovery currently under development, and an average 40 per cent working interest in 239 gross blocks covering approximately 1.4 million acres (5,665 square km). The closing of the transaction took place May 26, 2005 and the acquired assets and liabilities were included in Statoil’s accounts from the same date. The investment is recognized in the segment International Exploration and Production. Statoil is currently allocating the purchase price based on the fair value of the assets acquired.
In June 2005 Statoil agreed to sell its 50 per cent holding in Borealis A/S to IOB Holding A/S, a company jointly owned by International Petroleum Investment Company and OMV Aktiengesellschaft. Borealis’ activity consists primarily of production of olefins and polyolefins as feedstock for plastic products. Including a dividend of EUR 80 million, the sales price amounted to EUR 1 billion. The closing of the transaction took place on October 13, 2005 and the gain of approximately NOK 1.5 billion (before and after tax) has been classified as Other income in the Consolidated Statements of Income and is included in the Manufacturing and Marketing segment.
5. ASSET IMPAIRMENTS
In 2005 an impairment charge of NOK 2.2 billion before tax (NOK 1.6 billion after tax) was recorded in Depreciation, depletion and amortization in the International Exploration and Production segment to write down book value of Statoil’s share in the Iranian South Pars gas field project. The write-down is due to considerable cost increases and delays in development of phases 6-7-8 in the project. Fair value was calculated based on an assessment of expected discounted cash-flows for the project..
6. AUDITORS’ REMUNERATION
(in NOK million) | Audit fees | Audit related fees | Tax fees | Total |
2005 | ||||
Ernst & Young - Norway | 11.8 | 10.2 | 0.1 | 22.1 |
Ernst & Young - abroad | 13.2 | 1.2 | 0 | 14.4 |
Total | 25.0 | 11.4 | 0.1 | 36.5 |
2004 | ||||
Ernst & Young - Norway | 11.4 | 4.1 | 2.3 | 17.8 |
Ernst & Young - abroad | 12.4 | 0.4 | 2.8 | 15.6 |
Total | 23.8 | 4.5 | 5.1 | 33.4 |
In addition audit fee related to Statoil-operated licenses amounts to NOK 3.8 and NOK 3.5 million for 2005 and 2004, respectively.
7. INVENTORIES
At December 31, | ||
(in NOK million) | 2005 | 2004 |
Crude oil | 4,383 | 3,664 |
Petroleum products | 5,915 | 3,344 |
Other | 1,157 | 1,253 |
Total - inventories valued on a FIFO basis | 11,455 | 8,261 |
Excess of current cost over LIFO value | (2,820) | (1,290) |
Total | 8,635 | 6,971 |
8. SUMMARY FINANCIAL INFORMATION OF UNCONSOLIDATED EQUITY AFFILIATES
Statoil’s investments in affiliates included up to October 13, 2005 a 50 per cent interest in Borealis A/S, a petrochemical production company, and included up to July 8, 2004 a 50 per cent interest in Statoil Detaljhandel Skandinavia AS (SDS), a group of retail petroleum service stations. As from July 8, 2004 SDS became a subsidiary of Statoil ASA.
Summary of financial information for affiliated companies accounted for by the equity method is shown below. Statoil’s investment in these companies is included in Investments in affiliates.
Equity method affiliates - gross amounts
(in NOK million) | Boreal A/S | SDS | |||||
2005 | 2004 | 2003 | 2005 | 2004 | 2003 | ||
At December 31, | |||||||
Current assets | - | 8,321 | 7,286 | - | - | 2,799 | |
Non-current assets | - | 17,548 | 19,085 | - | - | 6,787 | |
Current liabilities | - | 8,502 | 7,058 | - | - | 3,717 | |
Long-term debt | - | 2,323 | 6,140 | - | - | 1,951 | |
Other liabilities | - | 2,785 | 2,375 | - | - | 444 | |
Net assets | - | 12,259 | 10,798 | - | - | 3,474 | |
Year ended December 31, | |||||||
Gross revenues | 28,755 | 38,504 | 30,936 | - | 13,244 | 24,615 | |
Income before taxes | 1,806 | 2,205 | 126 | - | 60 | 210 | |
Net income | 1,409 | 1,689 | 135 | - | 46 | 148 | |
Capital expenditures | 1,255 | 1,805 | 1,002 | - | 237 | ||
Statoil received a total of NOK 861 million in dividends from Borealis for 2005, of which NOK 627 million were declared and received as a part of the Borealis sales transaction. Further reference is made to note 4. No dividends were received from Borealis for the years 2004 and 2003.
Statoil received dividends amounting to NOK 100 and NOK 65 million from SDS in 2004 and 2003, respectively.
Equity method affiliates - detailed information
Currency | (in million) | Ownership | (in NOK million) | ||||
Par value | Share capital | Book value | Profit share | ||||
Borealis A/S | EUR | - | - | - | - | 705 | |
South Caucasus Pipeline Holding Company Limited | USD | 253 | 1,012 | 25.5% | 1,743 | - | |
Other companies | - | - | - | 2,708 | 385 | ||
Total | 4,451 | 1,090 | |||||
Ownership corresponds to voting rights.
South Caucasus Pipeline Holding Company Limited is in the process of constructing a gas pipeline from Baku in Azerbaijan to Turkey. The pipeline is expected to be operational in 2007.
9. INVESTMENTS
Short-term investments(in NOK million) | At December 31, | |
2005 | 2004 | |
Short-term deposits | 12 | 53 |
Commercial papers | 6,621 | 9,735 |
Liquidity funds | 47 | 1,662 |
Other | 161 | 171 |
Total short-term investments | 6,841 | 11,621 |
The cost price of short-term investments for the years ended December 31, 2005 and 2004 was NOK 6,795 and NOK 11,876 million, respectively. All short-term investments are considered to be trading securities and are recorded at fair value with unrealized gains and losses included in income.
Long-term investments included in Other assets
(in NOK million) | At December 31, | |
2005 | 2004 | |
Shares in other companies (cost method) | 2,921 | 2,206 |
Commercial papers | 1,408 | 1,810 |
Bonds | 5,422 | 2,891 |
Marketable equity securities | 3,994 | 2,257 |
Total long-term investments | 13,745 | 9,164 |
Included in Shares in other companies is Statoil BTC Caspian AS’ investment in 8.71 per cent of the shares in BTC Pipeline Company. The investment had a book value of NOK 2,272 and NOK 1,543 million as at year-end 2005 and 2004, respectively. BTC Pipeline Company is in the process of constructing an oil pipeline from Baku in Azerbaijan to Ceyhan in Turkey. The pipeline is expected to be operational in 2006.
10. PROPERTY, PLANT AND EQUIPMENT
(in NOK million) | Machinery, equipment and trans- portation equipment | Produc- tion plants oil and gas, incl. pipelines | Produc- tion plants onshore | Buildings and land | Vessels | Construc- tion in progress | Capitalized exploration expen- ditures** | Total |
Cost as at January 1, 2005 | 10,729 | 249,412 | 39,292 | 11,441 | 754 | 36,101 | 2,886 | 350,615 |
Accumulated depreciation, depletion and amortization at January 1 | (6,947) | (167,217) | (20,905) | (2,467) | (160) | (3) | 0 | (197,699) |
Additions and transfers | 968 | 28,460 | 1,060 | 728 | 121 | 4,101 | 10,319 | 45,757 |
Disposal at booked value | (41) | (24) | (52) | (147) | (502) | (5) | (3) | (774) |
Expensed exploration expenditures capitalized earlier years | 0 | 0 | 0 | 0 | 0 | 0 | (158) | (158) |
Depreciation, depletion and amortization for the year | (854) | (15,085) | (2,250) | (479) | (31) | (2,211) | 0 | (20,910) |
Foreign currency translation | (97) | 1,146 | 851 | 99 | (3) | 1,597 | 1,057 | 4,650 |
Balance specified at December 31, 2005 | 3,758 | 96,692 | 17,996 | 9,175 | 179 | 39,580 | 14,101 | 181,481 |
Estimated useful life (years) | 3 -10 | * | 15-20 | 20-33 | 20-25 | |||
Goodwill and intangible assets are included in Other assets in the Consolidated Balance Sheets. Intangible assets are depreciated over 10-20 years.
* | Depreciation according to Unit of production, see note 2. |
In 2005, 2004 and 2003, capitalized interests amounted to NOK 1,672, NOK 829 and NOK 442 million, respectively. In addition to depreciation, depletion and amortization specified above intangible assets have been amortized by NOK 187 million in 2005.
** | Capitalized exploration expenditures include signature bonuses and other acquired exploration rights of NOK 11,071, NOK 609 and NOK 1,045 million as at the end of 2005, 2004 and 2003, respectively. |
Capitalized exploratory expenditures that are pending the determination of proved reserves
(in NOK million) | 2005 | 2004 | 2003 |
Capitalized expenditures at January 1 | 2,277 | 2,747 | 2,550 |
Additions | 1,236 | 935 | 365 |
Reclassified to Production plants oil and gas, including pipelines based on the booking of proved reserves | (480) | (1,235) | (63) |
Expensed, previously capitalized exploration expenditures | (149) | (61) | (59) |
Foreign currency translation | 146 | (109) | (46) |
Capitalized expenditures at December 31 | 3,030 | 2,277 | 2,747 |
In addition to capitalized signature bonuses and other acquired exploration rights of NOK 11,071 million, capitalized exploratory drilling expenditures at year-end 2005 consisted of the following capitalized exploratory drilling expenditures that are pending the determination of proved reserves at December 31:
NOK million | Number of wells | |
Exploratory well expenditures that have been capitalized for a period of one year or less (A) | 1,461 | 20 |
Exploratory well expenditures that have been capitalized for a period greater than one year, aged (B) | ||
- Completed in 2004 | 413 | 6 |
- Completed in 2003 | 306 | 12 |
- Completed in 2002 | 233 | 8 |
- Completed in 2001 | 340 | 3 |
- Completed in 2000 | 97 | 4 |
- Completed in 1999 | 66 | 2 |
- Completed in 1998 | 114 | 2 |
Total | 1,569 | 37 |
Exploratory well expenditures that have been capitalized for a period greater than one year, by category (B) | ||
- Wells where additional drilling efforts are underway or firmly planned in the near future | 519 | 13 |
- Wells with economic reserves, development decision planned in the near future | 973 | 23 |
- Wells with economic reserves, development decision pending available capacity in infrastructure | 77 | 1 |
Total | 1,569 | 37 |
Total of capitalized exploratory drilling expenditures (A+B) | 3,030 | 57 |
11. PROVISIONS
Provisions against assets (other than property, plant and equipment and intangible assets) recorded during the past three years are as follows:
(in NOK million) | Balance at January 1, | Foreign currency translation | Expense | Recovery | Write-off | Other 1) | Balance at December 31, |
Year 2005 | |||||||
Provisions against other long-term assets | 0 | 0 | 4 | 0 | 0 | 0 | 4 |
Provisions against accounts receivable | 255 | (4) | 54 | (9) | (75) | 38 | 259 |
Year 2004 | |||||||
Provisions against other long-term assets | 0 | 0 | 0 | 0 | 0 | 0 | 0 |
Provisions against accounts receivable | 275 | 0 | 29 | (39) | (22) | 12 | 255 |
Year 2003 | |||||||
Provisions against other long-term assets | 0 | 0 | 0 | 0 | 0 | 0 | 0 |
Provisions against accounts receivable | 153 | 0 | 59 | (5) | (5) | 73 | 275 |
(1) | Other is primarly related to provisions for accounts receivable in acquired companies. |
12. FINANCIAL ITEMS
For the year ended December 31, | |||
(in NOK million) | 2005 | 2004 | 2003 |
Interest and other financial income | 738 | 775 | 1,057 |
Currency exchange adjustments, net | (5,835) | 5,031 | 98 |
Interest and other financial expenses | (589) | (317) | (877) |
Dividends received | 700 | 271 | 179 |
Gain (loss) on sale of securities | 755 | 286 | 205 |
Unrealized gain (loss) on securities | 669 | (307) | 737 |
Net financial items | (3,562) | 5,739 | 1,399 |
13. INCOME TAXES
Income before income taxes and minority interest consists of
For the year ended December 31, | |||
(in NOK million) | 2005 | 2004 | 2003 |
Norway | |||
Offshore | 75,414 | 55,709 | 43,516 |
Onshore | (208) | 7,532 | 3,121 |
Other countries 1) | 16,328 | 7,605 | 3,678 |
Other items (see note 2) | 0 | 0 | (6,025) |
Total | 91,534 | 70,846 | 44,290 |
Significant components of income tax expense were as follows
For the year ended December 31, | |||
(in NOK million) | 2005 | 2004 | 2003 |
Norway | |||
Offshore | 63,120 | 40,548 | 34,754 |
Onshore | 4 | 133 | 2 |
Other countries 1) | 4,122 | 1,635 | 737 |
Uplift benefit | (2,129) | (1,897) | (1,869) |
Current income tax expense | 65,117 | 40,419 | 33,624 |
Norway | |||
Offshore | (4,287) | 3,512 | (376) |
Onshore 2) | (188) | 722 | 859 |
Other countries 1) | (603) | 772 | 52 |
Change in deferred tax due to new legislation (see note 2) | 0 | 0 | (6,712) |
Deferred tax expense | (5,078) | 5,006 | (6,177) |
Total income tax expense | 60,039 | 45,425 | 27,447 |
(1) | Includes taxes liable to Norway on income in other countries. |
(2) | Due to changes in Norwegian tax legislation in 2004, dividends from companies, with some exceptions, are not be taxable in Norway. Consequently, NOK 1.4 billion in deferred taxes related to retained earnings in subsidiaries and affiliates have been reversed in 2004. |
Significant components of deferred tax assets and liabilities were as follows
For the year ended December 31, | ||
(in NOK million) | 2005 | 2004 |
Deferred tax assets | ||
Inventory | 2,930 | 1,825 |
Other short-term items | 1,665 | 331 |
Net operating loss carry-forwards | 1,278 | 1,160 |
Property, plant and equipment | 3,930 | 1,837 |
Decommissioning and asset retirement obligation | 13,107 | 10,289 |
Other long-term items | 1,462 | 1,596 |
Valuation allowance | (2,592) | (1,923) |
Total deferred tax assets | 21,780 | 15,115 |
Deferred tax liabilities | ||
Other short-term items | 864 | 1,179 |
Property, plant and equipment | 46,714 | 43,045 |
Capitalized exploration expenditures and interest | 8,002 | 8,367 |
Other long-term items | 5,442 | 6,589 |
Total deferred tax liabilities | 61,022 | 59,180 |
Net deferred tax liabilities | 39,242 | 44,065 |
Deferred taxes are classified as follows | ||
Short-term deferred tax asset | (3,733) | 0 |
Long-term deferred tax asset | (372) | (205) |
Long-term deferred tax liability | 43,347 | 44,270 |
Net deferred tax liability | 39,242 | 44,065 |
A valuation allowance has been provided as Statoil believes that available evidence creates uncertainty as to the realizability of certain deferred tax assets. Statoil will continue to assess the valuation allowance and to the extent it is determined that such allowance is no longer required, the tax benefit of the remaining net deferred tax assets will be recognized in the future.
Reconciliation of Norwegian nominal statutory tax rate of 28 per cent to effective tax rate
For the year ended December 31, | |||
(in NOK million) | 2005 | 2004 | 2003 |
Calculated income taxes at statutory rate | 25,630 | 19,837 | 14,088 |
Petroleum surtax at statutory rate | 37,707 | 27,855 | 21,758 |
Uplift benefit | (2,129) | (1,897) | (1,869) |
Other, net | (1,169) | (370) | 182 |
Change in deferred tax due to new legislation (see note 2) | 0 | 0 | (6,712) |
Income tax expense | 60,039 | 45,425 | 27,447 |
Revenue from oil and gas activities on the NCS is taxed according to the Petroleum tax law. In addition to normal corporation tax, a special tax of 50 per cent is levied after deducting uplift, a special investment tax credit. Uplift is deducted by 7.5 per cent per year for four years, as from the year of investment. Uplift credits of NOK 10.8 billion will be recognized over a period of four years.
At the end of 2005, Statoil had tax losses carry forwards of NOK 3.9 billion, primarily in the US and Ireland. Only a minor part of the carry-forward amounts expire before 2019.
14. SHORT-TERM INTEREST-BEARING DEBT
At December 31, | ||
(in NOK million) | 2005 | 2004 |
Bank loans and overdraft facilities | 288 | 1,541 |
Current portion of long-term debt | 1,131 | 2,971 |
Other | 110 | 218 |
Total | 1,529 | 4,730 |
Weighted average interest rate | 4.81% | 3.64% |
15. LONG-TERM INTEREST-BEARING DEBT
Weighted average interest rate | Balance in NOK million at December 31 | ||||
2005 | 2004 | 2005 | 2004 | ||
Unsecured debentures bonds | |||||
US dollar (USD) | 6.25% | 6.25% | 14,609 | 13,219 | |
Norwegian kroner (NOK) | 2.69% | 2.19% | 500 | 499 | |
Euro (EUR) | 5.06% | 4.27% | 5,891 | 8,127 | |
Swiss franc (CHF) | 4.01% | 4.01% | 1,128 | 1,197 | |
Japanese yen (JPY) | 0.91% | 0.95% | 2,469 | 2,632 | |
Great British pounds (GBP) | 6.13% | 6.13% | 3,069 | 2,948 | |
Total | 27,666 | 28,622 | |||
Unsecured bank loans | |||||
US dollar (USD) | 4.40% | 2.39% | 1,391 | 2,108 | |
Secured bank loans | |||||
US dollar (USD) | 5.21% | 3.46% | 3,899 | 3,332 | |
Other currencies | 3.51% | 6.10% | 306 | 13 | |
Other debt | 538 | 355 | |||
Grand total debt outstanding | 33,800 | 34,430 | |||
Less current portion | 1,131 | 2,971 | |||
Total long-term debt | 32,669 | 31,459 | |||
The table above contains market values of loans per currency and loan type, and does therefore not illustrate the economic effects of agreements entered into to swap the various currencies to USD.
Statoil has an unsecured debenture bond agreement for USD 500 million with a fixed interest rate of 6.5 per cent, maturing in 2028. At December 31, 2005 and 2004, NOK 3,343 and NOK 2,981 million were outstanding, respectively. The interest rate of the bond has been swapped to a LIBOR-based floating interest rate.
Statoil has an unsecured debenture bond agreement for USD 500 million, with a fixed interest rate of 5.125 per cent, maturing in 2014. At December 31, 2005 and 2004, NOK 3,382 and NOK 3,017 million were outstanding, respectively. The interest rate of the bond has been swapped to a LIBOR-based floating interest rate.
Statoil has an unsecured debenture bond agreement for EUR 500 million, with a fixed interest rate of 5.125 per cent, maturing in 2011. At December 31, 2005 and 2004, NOK 3,961 and NOK 4,081 million were outstanding, respectively. EUR 200 million of the bond has been swapped through an interest rate swap agreement to an EURIBOR-based floating interest rate.
Statoil has an unsecured debenture bond agreement for GBP 225 million, with a fixed interest rate of 6.125 per cent, maturing in 2028. At December 31, 2005 and 2004, NOK 2,622 and NOK 2,619 million were outstanding, respectively. The bond has been swapped through cross currency interest rate swap agreements to an USD LIBOR-based floating interest rate.
Statoil has an unsecured debenture bond agreement for USD 375 million, with a fixed interest rate of 5.75 per cent, maturing in 2009. At December 31, 2005 and 2004, NOK 2,528 and NOK 2,252 million were outstanding, respectively. Net after buyback this amounts to NOK 2,197 and NOK 1,955 million at year-end exchanges rates.
In addition to the unsecured debentures bond debt of NOK 14,609 million, denominated in US dollars, Statoil utilizes foreign currency swaps to manage foreign exchange risk on its long-term debt. As a result, an additional NOK 13,057 million of Statoil’s unsecured debentures bond debt has been swapped to US dollars. The foreign currency swaps are not reflected in the table above as the swaps are separate legal agreements. The foreign currency swaps do not qualify as hedges according to FAS 133 as the swaps are not to functional currency, although they represent economic hedges. The stated interest rate on the majority of the long-term debt is fixed. Interest rate swaps are utilized to manage interest rate exposure.
Substantially all unsecured debenture bond and unsecured bank loan agreements contain provisions restricting the pledging of assets to secure future borrowings without granting a similar secured status to the existing bondholders and lenders.
Statoil’s secured bankloans in USD have been secured by guarantee commitments amounting to USD 83 million, mortgage in shares in a subsidiary and investments in other companies with a combined book value of NOK 4,490 million, a bank deposit with a book value of NOK 1,494 million, and Statoil’s pro-rata share of income from certain applicable projects.
Statoil has 20 debenture bond agreements outstanding, which contain provisions allowing Statoil to call the debt prior to its final redemption at par if there are changes to the Norwegian tax laws or at certain specified premiums. The agreements are, net after buyback, valued at NOK 23,743 million at the December 31, 2005 closing rate.
Long-term debt falls due as follows
(in NOK million) | ||
2006 | 1,131 | |
2007 | 2,255 | |
2008 | 2,257 | |
2009 | 3,612 | |
2010 | 530 | |
Thereafter | 24,015 | |
Total | 33,800 | |
Statoil has an agreement with an international bank syndicate for committed long-term revolving credit facility totaling USD 2.0 billion, all undrawn. Commitment fee is 0.0575 per cent per annum.
As of December 31, 2005 and 2004 respectively, Statoil had no committed short-term credit facilities available or drawn.
16. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
Statoil uses derivative financial instruments to manage risks resulting from fluctuations in underlying interest rates, foreign currency exchange rates and commodity (such as oil, natural gas and refined petroleum products) prices. Because Statoil operates in the international oil and gas markets and has significant financing requirements, it has exposure to these risks, which can affect the cost of operating, investing and financing. Statoil has used and intends to use financial and commodity-based derivative contracts to reduce the risks in overall earnings and cash flows. Derivative instruments creating essentially equal and offsetting market exposures are used to help manage certain of these risks. Management also uses derivatives to establish certain positions based on market movements although this activity is immaterial to the consolidated financial statements.
Interest and currency risks constitute significant financial risks for the Statoil group. Total exposure is managed at portfolio level in accordance with the strategies and mandates issued by the Enterprise-Wide Risk Management Program and monitored by the Corporate Risk Committee. Statoil’s interest rate exposure is mainly associated with the group’s debt obligations and management of the assets in Statoil Forsikring AS. Statoil mainly employs interest rate swap and currency swap agreements to manage interest rate and currency exposure.
Statoil uses swaps, options, futures, and forwards to manage its exposure to changes in the value of future cash flows from future purchases and sales of crude oil and refined oil products. The term of the oil and refined oil products derivatives is usually less than one year. Natural gas and electricity swaps, options, forwards, and futures are likewise utilized to manage Statoil’s exposure to changes in the value of future sales of natural gas and electricity. These derivatives usually have terms of approximately three years or less. Most of the derivative transactions are made in the over-the-counter (OTC) market.
Cash Flow Hedges
Statoil has in the past designated certain derivative instruments as cash flow hedges to hedge against changes in the amount of future cash flows related to the sale of crude oil and petroleum products and cash flows related to interest payments over periods ending no later than December 31, 2005. Hedge ineffectiveness related to Statoil’s then outstanding cash flow hedges was immaterial and recorded to earnings during the year ended December 31, 2005. The net change in Accumulated other comprehensive income associated with hedging transactions during the year was NOK 393 million after tax. The net amount reclassified into earnings during the year was NOK 470 million after tax. At December 31, 2005, the net deferred hedging loss in Accumulated other comprehensive income related to cash flow hedges was zero, and there will be no effects on earnings over the next 12 months from the expired cash flow hedges. The unrealized loss component of derivative instruments excluded from the assessment o f hedge effectiveness related to cash flow hedges during the year ended December 31, 2005 was immaterial.
Fair Value Hedges
Statoil has designated certain derivative instruments as fair value hedges to hedge against changes in the value of financial liabilities. There was no gain or loss component of a derivative instrument excluded from the assessment of hedge effectiveness related to fair value hedges during the year ended December 31, 2005. The net loss recognized in earnings in Income before income taxes and minority interest during the year for ineffectiveness of fair value hedges was NOK 22 million.
Fair Value of Financial Instruments
Except for the recorded amount of fixed interest long-term debt, the recorded amounts of cash and cash equivalents, receivables, bank loans, other interest-bearing short-term debt, and other liabilities approximate their fair values. Marketable equity and debt securities are also recorded at their fair values.
The following table contains the carrying amounts and estimated fair values of financial derivative instruments, and the carrying amounts and estimated fair value of long-term debts. Commodity contracts settled by delivery of commodities (oil and oil products, natural gas and electricity) are excluded from the summary:
(in NOK million) | Fair market value of assets | Fair market value of liabilities | Net carrying amount |
At December 31, 2005 | |||
Debt-related instruments | 3,443 | (18) | 3,425 |
Non-debt-related instruments | 8 | (2,033) | (2,025) |
Long-term fixed interest debt | 0 | (28,498) | (26,570) |
Crude oil and Refined products | 681 | (755) | (74) |
Gas and Electricity | 230 | (83) | 147 |
At December 31, 2004 | |||
Debt-related instruments | 5,022 | (12) | 5,011 |
Non-debt-related instruments | 1,972 | (5) | 1,967 |
Long-term fixed interest debt | 0 | (27,702) | (25,793) |
Crude oil and Refined products | 1,089 | (395) | 694 |
Gas and Electricity | 86 | (131) | (45) |
Fair values are estimated using quoted market prices, estimates obtained from brokers, prices of comparable instruments, and other appropriate valuation techniques. The fair value estimates approximate the gain or loss that would have been realized if the contracts had been closed out at year-end, although actual results could vary due to assumptions utilized.
Credit risk management
Statoil manages credit risk concentration with respect to financial instruments by holding only investment grade securities distributed among a variety of selected issuers. A list of authorized investment limits by commercial issuer is maintained and reviewed regularly along with guidelines which include an assessment of the financial position of counter-parties as well as requirements for collateral.
Credit risk related to commodity-based instruments is managed by maintaining, reviewing and updating lists of authorized counter-parties by assessing their financial position, by frequently monitoring credit exposure for counter-parties, by establishing internal credit lines for counterparties, and by requiring collateral or guarantees when appropriate under contracts and required in internal policies. Collateral will typically be in the form of cash or bank guarantees from first class international banks.
Credit risk from interest rate swaps and currency swaps, which are over-the-counter (OTC) transactions, derive from the counter-parties to these transactions. Counter-parties are highly rated financial institutions. The credit ratings are reviewed minimum annually and counter-party exposure is monitored on a continuous basis to ensure exposure does not exceed credit lines and complies with internal policies. Non-debt-related foreign currency swaps usually have terms of less than one year, and the terms of debt-related-interest swaps and currency swaps are up to 24 years, in line with that of corresponding hedged or risk managed long-term loans.
The credit risk concentration with respect to receivables is limited due to the large number of counter-parties spread worldwide in numerous industries.
17. EMPLOYEE RETIREMENT PLANS
Pension benefits
Statoil and many of its subsidiaries have defined benefit retirement plans, which cover substantially all of their employees. Plan benefits are generally based on years of service and final salary levels. Some subsidiaries have defined contribution plans and multi-employer plans.
Net periodic pension cost
For the year ended December 31, | |||
(in NOK million) | 2005 | 2004 | 2003 |
Benefits earned during the year | 1,079 | 1,062 | 849 |
Interest cost on prior years’ benefit obligation | 1,025 | 938 | 791 |
Expected return on plan assets | (1,125) | (902) | (843) |
Amortization of loss | 53 | 175 | 54 |
Amortization of prior service cost | 37 | 34 | 34 |
Amortization of net transition assets | 0 | 0 | (15) |
Defined benefit plans | 1,069 | 1,307 | 870 |
Defined contribution plans | 47 | 34 | 27 |
Multi-employer plans | 26 | 21 | 0 |
Total net pension cost | 1,142 | 1,362 | 897 |
Pension costs are partly charged to partners of Statoil-operated activities.
Change in projected benefit obligation (PBO)
(in NOK million) | 2005 | 2004 |
Projected benefit obligation at January 1 | 19,021 | 17,642 |
Benefits earned during the year | 1,079 | 1,062 |
Interest cost on prior years’ benefit obligation | 1,025 | 938 |
Actuarial loss (gain) | 1,840 | (388) |
Benefits paid | (372) | (350) |
Acquisitions | 14 | 117 |
Foreign currency translation | (39) | 0 |
Projected benefit obligation at December 31 | 22,568 | 19,021 |
Change in pension plan assets
(in NOK million) | 2005 | 2004 |
Fair value of plan assets at January 1 | 17,319 | 15,143 |
Actual return on plan assets | 1,807 | 1,157 |
Company contributions* | 1,488 | 1,154 |
Benefits paid | (234) | (188) |
Acquisitions | 10 | 53 |
Foreign currency translation | (43) | 0 |
Fair value of plan assets at December 31 | 20,347 | 17,319 |
* | In 2004 the amount included paid-up policies transferred from external companies. |
Status of pension plans reconciled to Consolidated Balance Sheets
(in NOK million) | 2005 | 2004 |
Funded status of the plans at December 31 | (2,221) | (1,702) |
Unrecognized net loss | 3,811 | 2,685 |
Unrecognized prior service cost | 256 | 295 |
Total net prepaid pension recognized at December 31 | 1,846 | 1,278 |
Amounts recognized in the Consolidated Balance Sheets
(in NOK million) | 2005 | 2004 |
Prepaid pension at December 31 | 5,538 | 4,633 |
Accrued pension liabilities | (4,564) | (3,960) |
Intangible assets | 258 | 295 |
Other comprehensive income | 614 | 310 |
Net amount recognized at December 31 | 1,846 | 1,278 |
Weighted-average assumptions for the year ended (Profit and Loss items)
(in per cent) | 2005 | 2004 |
Discount rate | 5.50 | 5.50 |
Expected return on plan assets | 6.50 | 6.00 |
Expected rate of compensation increase | 3.50 | 3.50 |
Weighted-average assumptions at the end of the year (Balance sheet items)
(in per cent) | 2005 | 2004 |
Discount rate | 4.75 | 5.50 |
Expected return on plan assets | 5.75 | 6.50 |
Expected rate of compensation increase | 3.00 | 3.50 |
The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for pension plans with accumulated benefit
obligations in excess of plan assets
At December 31, | ||
(in NOK million) | 2005 | 2004 |
Projected benefit obligation | 5,754 | 4,894 |
Accumulated benefit obligation | 4,557 | 3,648 |
Fair value on plan assets | 470 | 365 |
The accumulated benefit obligation (ABO) was NOK 18,550 million at December 31, 2005.
Benefits expected to be paid (from the funded plans)
(in NOK million) | ||
2006 | 232 | |
2007 | 260 | |
2008 | 295 | |
2009 | 336 | |
2010 | 381 | |
2011-2015 | 2,823 | |
Total payments expected during the next 10 years | 4,327 | |
Pension assets allocated on respective investments classes
At December 31, | ||
(in per cent) | 2005 | 2004 |
Equity securities | 30 | 26 |
Debt securities | 46 | 32 |
Commercial papers | 10 | 31 |
Real estate | 5 | 6 |
Other assets | 9 | 5 |
Total | 100 | 100 |
In its asset management, the pension fund aims at achieving long-term returns which contribute towards meeting future pension liabilities. Assets are managed to achieve a return as high as possible within a framework of public regulation and prudent risk management policies. The pension fund’s target returns require a need to invest in assets with a higher risk than risk-free investments. Risk is reduced through maintaining a well diversified asset portfolio. Assets are diversified both in terms of location and different asset classes. Derivatives are used within set limits to facilitate effective asset management.
Statoil’s pension funds invest in both financal assets and real estate. The expected rate of return on real estate is expected to be between the rate of return on equity securities and debt securities. The table below presents the portfolio weight and expected rate of return of the finance portfolio, as approved by the board of the Statoil pension funds for 2006.
Finance portfolio Statoils pension funds | Portfolio weight 1) | Expected rate of return | |
Equity securities | 35.0% | (+/- 5.0%) | X + 4.0% |
Debt securities | 64.5% | (+5.5%/-10.0%) | X |
Commercial papers | 0.5% | (+15.0%/-0.5%) | X - 0.4% |
Total finance portfolio | 100.0% | ||
1) | The brackets express the scope of tactical deviation by Statoil Kapitalforvaltning ASA (the asset manager). |
X= | Long-term rate of return on debt securities. |
The long-term expected return on pension assets is based on long-term risk-free rate adjusted for the expected long-term risk premium for the respective investment classes.
Company contributions are mainly related to employees in Norway. This payment may either be paid in cash or be deducted from the pension premium fund. Statoil has a relatively large amount classified as pension premium fund in Statoil’s pension funds. The decision whether to pay in cash or deduct from the pension premium fund is made on an annual basis. The expected company contribution for the next five years will be approximately NOK 1.0 billion annually. The company contribution in 2005 was NOK 2.5 billion, of which NOK 1.2 billion was deducted from the pension premium fund.
18. DECOMMISSIONING AND REMOVAL LIABILITIES
The asset retirement obligation (ARO) is related to future well closure, decommissioning and removal expenditures. The accretion expense is classified as Operating expenses.
(in NOK million) | 2005 | 2004 |
Asset retirement obligation at January 1 | 18,602 | 16,494 |
Liabilities incurred/revision in estimates | 796 | 1,515 |
Accretion expense | 840 | 771 |
Disposals | (69) | (22) |
Incurred removal cost | (212) | (89) |
Currency exchange adjustments | 77 | (67) |
Asset retirement obligation at December 31 | 20,034 | 18,602 |
Long-lived assets related to ARO at January 1 | 3,388 | 2,757 |
Net assets incurred/revision in estimates | 615 | 1,470 |
Depreciation | (437) | (821) |
Currency exchange adjustments | 40 | (18) |
Long-lived assets related to ARO at December 31 | 3,606 | 3,388 |
The 2005 figures in the tables above include the implementation effect of FIN 47. See note 2 for further information regarding the implementation.
19. RESEARCH AND DEVELOPMENT EXPENDITURES
Research and Development (R&D) expenditures were NOK 1,066, NOK 1,027 and NOK 1,004 million in 2005, 2004 and 2003, respectively. R&D expenditures are partly financed by partners of Statoil-operated activities.20. LEASES
Statoil leases certain assets, notably shipping vessels and drilling rigs.
In 2005, rental expense was NOK 4,502 million. In 2004 and 2003 rental expenses were NOK 4,367 and NOK 4,893 million, respectively.
The information in the table below shows future minimum lease payments under non-cancelable leases at December 31, 2005. In addition, Statoil has entered into subleases of certain assets amounting to a total future rental income of NOK 1,970 million, of which NOK 1,390 million for 2006.
Statoil has entered into a number of general or field specific long-term frame agreements mainly related to loading and transport of crude oil. The main contracts expire in 2007 or later, up until the end of the respective field lives. Such contracts are not included in the below table of future lease payments unless they entail specific minimum payment obligations.
Amounts related to capital leases include future lease payments for assets in the books at year-end 2005.
(in NOK million) | Operating leases | Capital leases |
2006 | 3,121 | 54 |
2007 | 2,680 | 47 |
2008 | 2,921 | 25 |
2009 | 1,887 | 24 |
2010 | 1,130 | 23 |
Thereafter | 3,445 | 507 |
Total future lease payments | 15,184 | 680 |
Interest component | (486) | |
Net present value | 194 | |
Property, plant and equipment include the following amounts for leases that have been capitalized at December 31, 2005 and 2004.
At December 31, | ||
(in NOK million) | 2005 | 2004 |
Vessels and equipment | 307 | 190 |
Accumulated depreciation | (128) | (97) |
Capitalized amounts | 179 | 93 |
21. OTHER COMMITMENTS AND CONTINGENCIES
Contractual commitments
(in NOK million) | 2006 | Thereafter | Total |
Contractual commitments related to investments and property, plant and equipment | 13,458 | 9,552 | 23,010 |
These contractual commitments mainly comprise construction and acquisition of property, plant and equipment.
Statoil has entered into agreements for pipeline transportation for most of its prospective gas sales contracts. These agreements ensure the right to transport the production of gas through the pipelines, but also impose an obligation to pay for booked capacity. In addition, the group has entered into certain obligations for entry capacity fees and terminal, processing, storage and vessel transport capacity commitments. The following table outlines nominal minimum obligations for future years. Corresponding expenses for 2005 and 2004 were NOK 4,460 and NOK 3,701 million. Obligations payable by the group to unconsolidated equity affiliates are included gross in the table below. Where the group reflects both ownership interests and transport capacity cost for a pipeline in the consolidated accounts, the amounts in the table include the transport commitments that exceed Statoil’s ownership share.
Transport capacity and other obligations at December 31, 2005:
(in NOK million) | ||
2006 | 4,853 | |
2007 | 5,002 | |
2008 | 4,331 | |
2009 | 3,839 | |
2010 | 3,724 | |
Thereafter | 27,125 | |
Total | 48,874 | |
In 2004 Statoil signed an agreement with the U.S. based energy company Dominion regarding additional capacity at the Cove Point liquefied natural gas (LNG) terminal in the USA. The agreement involves annual terminal capacity of approximately 7.7 billion cubic meters of gas for a 20-year period with planned start-up in 2008, and is subject to approval from US authorities. Pending such approval, no obligations related to the additional Cove Point capacity have been included in the table above at year-end 2005.
Guarantees
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, 2005 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 Sheet and the cost has been recorded as other financial expenses.
Statoil Detaljhandel has issued guarantees amounting to a total of SEK 1.1 billion (NOK 0.9 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 year-end.
Contingent liabilities and insurance
Like any other licensee, Statoil has unlimited liability for possible compensation claims arising from its offshore operations, including transport systems. The Company has taken out insurance to cover this liability up to about USD 0.8 billion (NOK 5.4 billion) for each incident, including liability for claims arising from pollution damage. Most of the group’s production installations are covered through Statoil Forsikring a.s, which reinsures a major part of the risk in the international insurance market. About 23 per cent is retained.
Statoil Forsikring a.s is a member of two mutual insurance companies, Oil Insurance Ltd and sEnergy Insurance Ltd. Membership of these companies means that Statoil Forsikring is liable for its proportionate share of any losses which might arise in connection with the business operations of the companies. Members of the companies have joint and several liability for any losses that arise to the pool.
Other commitments and contingencies
As a condition for being awarded oil and gas exploration and production licenses, participants may be committed to drill a certain number of wells. At the end of 2005, Statoil was committed to participate in 16 wells off Norway and 16 wells outside Norway, with an average ownership interest of approximately 50 per cent. Statoil’s share of estimated expenditures to drill these wells amounts to approximately NOK 4 billion. Additional wells that Statoil may become commited to participate in depending on future discoveries in certain licences are not included in these numbers.
The price reviews for two long-term natural gas sales contracts are currently in arbitration. Contractual prices for a total volume of 3.2 billion cubic meters of gas delivered as of December 31, 2005 and for future deliveries under these contracts may be positively or negatively affected by the arbitration verdicts, the final outcome of which cannot be determined at this time.
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 an administrative appeal to annul the demand for such payments, and are communicating with the Ministry to find an overall solution for Sincor.
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 judgment. Statoil does not expect that neither the financial position, results of operations nor 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) has conducted an investigation concerning an agreement which Statoil entered into in 2002 with Horton Investments Ltd for consultancy services in Iran. On June 28, 2004 Økokrim informed Statoil that it had concluded that Statoil violated section 276c, first paragraph (b) of the Norwegian Penal Code, which became effective from July 4, 2003 and prohibits conferring on or offering to a middleman an improper advantage in return for exercising his influence with a decision-maker, without the decision-maker receiving any advantage, and imposed a penalty on Statoil of NOK 20 million. The Board of Statoil ASA decided on October 14, 2004 to accept the penalty without admitting or denying the charges by Økokrim.
The U.S. Securities and Exchange Commission (SEC) is also conducting a formal investigation into the Horton consultancy arrangement to determine if there have been any violations of U.S. federal securities laws, including the Foreign Corrupt Practices Act. The U.S. Department of Justice is conducting a criminal investigation of the Horton matter jointly with the Office of the United States Attorney for the Southern District of New York. The SEC Staff informed Statoil on September 24, 2004 that it is considering recommending that the SEC authorize a civil enforcement action in federal court against Statoil for violations of
various U.S. federal securities laws, including the anti-bribery and books and records provisions of the Foreign Corrupt Practices Act. Statoil is continuing to provide information to the U.S. authorities to assist them in their ongoing investigations.
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.
22. RELATED PARTIES
Total purchases of oil and natural gas liquid from the Norwegian State amounted to NOK 97,078 million (282 million barrels oil equivalents), NOK 81,487 million (319 million barrels oil equivalents), and NOK 68,479 million (336 million barrels oil equivalents), in 2005, 2004 and 2003, respectively. Purchases of natural gas from the Norwegian State amounted to NOK 262, NOK 237 and NOK 255 million in 2005, 2004 and 2003, respectively. Amounts payable to the Norwegian State for these purchases are included as Accounts payable - related parties in the Consolidated Balance Sheets. The prices paid by Statoil for the purchases from the Norwegian State are estimated market prices.
Statoil is, in its own name, but for the Norwegian State’s account and risk, selling the State’s natural gas production. This sale, as well as related expenditures refunded by the State, are shown net in Statoil’s Financial Statements. Refunds include expenses incurred related to activities and investments necessary to obtain market access and to optimize the profit from sale of natural gas.
23. SHAREHOLDERS' EQUITY
The common stock consists of 2,189,585,600 shares at nominal value NOK 2.50.
In 2001, 25,000,000 treasury shares were issued. During 2002 and 2003 a total of 1,558,115 of the treasury shares were distributed as bonus shares in favor of retail investors in the initial public offering in 2001. Distribution of treasury shares requires approval by the general meeting.
There exists only one class of shares and all shares have voting rights.
The board of directors is authorized on behalf of the company to acquire Statoil shares in the market. The authorization may be used to acquire Statoil shares with an overall nominal value of up to NOK 10 million. The board will decide the manner in which the acquisition of Statoil shares in the market will take place. Such shares acquired in accordance with the authorization may only be used for sale and transfer to employees of the Statoil group as part of the group’s share investment plan approved by the board. The lowest amount which may be paid per share is the nominal value; the highest amount which may be paid per share is a maximum of 100 times the nominal value. The authorization will apply untill November 2006. As per December 31, 2005 Statoil has 766,327 shares according to this authorization.
Retained earnings available for distribution of dividends at December 31, 2005 is limited to the retained earnings of the parent company based on Norwegian accounting principles and legal regulations and amounts to NOK 80,952 million (before provisions for proposed dividend for the year ended December 31, 2005 of NOK 17,756 million). This differs from retained earnings in the financial statements of NOK 65,402 million mainly due to the impact of the transfer of the SDFI properties to Statoil, which is not reflected in the Norwegian GAAP accounts until the second quarter of 2001. Distribution of dividends is not allowed to reduce the shareholders’ equity of the parent company below 10 per cent of total assets.
24. SHARE-BASED COMPENSATION
In 2004 Statoil introduced a Share Saving Plan for all permanent Statoil employees both in full and part time positions. Because of differences in legal and tax regulations between participating jurisdictions, and with the need for specific technical solutions for the Share Saving Plan, the program will be launched at different times in the different countries/companies within the Statoil Group.
Statoil’s Share Saving Plan gives the employees the opportunity to purchase Statoil shares through monthly salary deduction. The employees may save up to five per cent of their annual gross salary. Statoil will, for employees in some of the companies in the group, give a contribution to the employees of 20 per cent of the saved amount, at a maximum of NOK 1,500 per employee per year. Terms may vary between participating entities in the group.
If the shares are kept for two full calendar years of continued employment the employees will be allocated one bonus share for each two they have bought. The same kind of allocation is planned to be carried out for future yearly programs.
Due to uncertainty with respect to future share prices, the number of shares to be purchased by employees under the programs is unknown. Consequently, the number of bonus shares to be purchased by Statoil must be estimated to measure the annual expense of the program. The fair value of the bonus shares is estimated at the date of grant using a one-factor capital asset pricing model with adjustments for dividend payments assumed according to the corporate dividend policy in the vesting period.
Significant assumptions for 2005 used in connection with estimating the fair value are shown in the table below.
Risk free interest rate | 3.0% | |
Risk premium | 5.5% | |
Beta | 1.0 | |
Expected return/discount rate | 8.5% | |
The model requires the input of highly subjective assumptions. Because changes in the subjective input assumptions can affect the fair value estimate, in management’s opinion, the existing models do not necessarily provide a reliable single measure of fair value of Statoil’s Share Saving plan.
The basis for purchases of bonus shares is the combined amount of salary deductions and Statoil contributions. For the 2004, 2005 and 2006 programs (granted in 2005), this amounts to NOK 54, NOK 121 and NOK 162 million, respectively.
Estimated compensation expense including contribution and social security related to the 2004, 2005 and 2006 programs for Statoil amounts to NOK 35,
NOK 72 and NOK 96 million respectively. At December 31, 2005 the amount of compensation expense yet to be expensed throughout the vesting period is NOK 150 million.
25. SUBSEQUENT EVENTS
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 has resulted from a review of the Retail Business Portfolio and the intention to accelerate strategic commitment to Scandinavian and Eastern European markets. The nature and timing of any resulting transactions are uncertain, but are expected to occur during 2006. Current and long-term assets in Statoil Ireland amount to EUR 132 and EUR 127 million respectively as at December 31, 2005. Current liabilities amount to EUR 96 million as at December 31, 2005.
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. The agreement results in that Statoil after the transaction will have a 75 per cent interest in the license. Several discoveries have been made in this area, including the Luva discovery. The investment will be recorded in the segment Exploration and Production Norway.
SUPPLEMENTARY INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
In accordance with Statement of Financial Accounting Standards No. 69, Disclosures about Oil and Gas Producing Activities and regulations of the US Securities and Exchange Commission (SEC), Statoil is making certain supplemental disclosures about oil and gas exploration and production operations. While this information was developed with reasonable care and disclosed in good faith, it is emphasized that some of the data is necessarily imprecise and represents only approximate amounts because of the subjective judgment involved in developing such information. Accordingly, this information may not necessarily represent the present financial condition of Statoil or its expected future results.
All the tables presented include the impact from the SDFI transaction. See note 1.
Oil and gas reserve quantities
Statoil’s oil and gas reserves have been estimated by its experts in accordance with industry standards under the requirements of the SEC. Reserves are net of royalty oil paid in kind, and quantities consumed during production. Statements of reserves are forward-looking statements.
The determination of these reserves is part of an ongoing process subject to continual revision as additional information becomes available.
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
(i) | Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. | |
(ii) | Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based. | |
(iii) | Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”; (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources. |
Proved developed oil and gas reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
On the Norwegian Continental Shelf, Statoil sells its oil and gas together with the oil and gas of the Norwegian state (SDFI). Under this arrangement, Statoil and SDFI will deliver gas from Norway and elsewhere to its customers in accordance with certain supply type sales contracts. The commitments will be met using a schedule that provides the highest possible total value for our oil and gas and the Norwegian State’s oil and gas. Likewise, we hold commitments to deliver gas from Azerbaijan and Algeria where our entitlement to gas deliveries under the production sharing agreements in effect is less than our commitment to deliver. Our proved gas reserves (entitlements) will be drawn on to supply this gas to the extent that we hold entitlement to the gas delivered against these commitments.
The total expected commitments to be met by the Statoil/SDFI arrangement and Statoil’s separate commitments were on December 31, 2005 to deliver an aggregate of 35 tcf.
This does not include commitments where we do not hold title to any of the gas that we deliver.
Statoil’s and SDFI’s delivery commitments for the contract years 2005, 2006, 2007 and 2008 are 2.0, 2.0, 2.2 and 2.2 tcf. These commitments may be met by production of proved reserves from fields were Statoil and/or the Norwegian State participates and by drawing on existing gas markets to manage temporary shortfalls or surpluses in production. We are currently expecting a shortfall in supply of LNG from our own production in contract year 2006 due to an expected delay in the start-up of an LNG liquefaction plant in Norway. Efforts to mitigate the effects of this are being made. This may concern approximately four per cent of our commitments to deliver gas in that year.
The principles for booking of proved gas reserves are limited to contracted gas sales and gas with access to a market.
In 2002, Statoil entered into a buy-back contract in Iran. Statoil also participates in a number of production sharing agreements (PSA). Reserves from such agreements are based on the volumes to which Statoil has access (cost oil and profit oil), limited to available market access. Proved reserves at end of year associated with PSA and buy-back agreements are disclosed separately.
Statoil is booking as proved reserves volumes equivalent to our tax liabilities payable in-kind under negotiated fiscal arrangements (production sharing agreements or income sharing agreements).
The subtotals and totals in the following tables may not equal the sum of the amounts shown due to rounding.
Net proved oil and NGL reserves in million barrels | Net proved gas reserves in billion standard cubic feet | Net proved oil, NGL and gas reserves in million barrels oil equivalents | |||||||
Norway | Outside Norway | Total | Norway | Outside Norway | Total | Norway | Outside Norway | Total | |
At December 31, 2002 | 1,286 | 580 | 1,867 | 13,215 | 255 | 13,470 | 3,641 | 626 | 4,267 |
Of which: | |||||||||
Proved developed reserves | 919 | 137 | 1,056 | 9,321 | 30 | 9,351 | 2,580 | 143 | 2,722 |
Proved reserves under PSA and buy-back agreements | 0 | 349 | 349 | 0 | 0 | 0 | 0 | 349 | 349 |
Production from PSA and buy-back agreements | 0 | 12 | 12 | 0 | 0 | 0 | 0 | 12 | 12 |
Revisions and improved recovery | 110 | 41 | 151 | 311 | 1 | 312 | 165 | 41 | 206 |
Extensions and discoveries | 27 | 15 | 43 | 503 | 303 | 806 | 117 | 69 | 186 |
Purchase of reserves-in-place | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 |
Sales of reserves-in-place | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 |
Production | (239) | (31) | (271) | (695) | (6) | (700) | (363) | (33) | (395) |
At December 31, 2003 | 1,184 | 605 | 1,789 | 13,334 | 552 | 13,886 | 3,560 | 703 | 4,264 |
Of which: | |||||||||
Proved developed reserves | 876 | 163 | 1,039 | 9,582 | 25 | 9,606 | 2,584 | 167 | 2,751 |
Proved reserves under PSA and buy-back agreements | 0 | 364 | 364 | 0 | 303 | 303 | 0 | 418 | 418 |
Production from PSA and buy-back agreements | 0 | 13 | 13 | 0 | 0 | 0 | 0 | 13 | 13 |
Revisions and improved recovery | 111 | (4) | 107 | (9) | 334 | 324 | 109 | 56 | 165 |
Extensions and discoveries | 23 | 20 | 44 | 14 | 0 | 14 | 26 | 20 | 46 |
Purchase of reserves-in-place | 10 | 47 | 57 | 478 | 582 | 1,060 | 95 | 150 | 246 |
Sales of reserves-in-place | (13) | 0 | (13) | (87) | 0 | (87) | (29) | 0 | (29) |
Production | (226) | (37) | (263) | (751) | (31) | (782) | (360) | (42) | (402) |
At December 31, 2004 | 1,089 | 632 | 1,720 | 12,978 | 1,437 | 14,416 | 3,401 | 888 | 4,289 |
Of which: | |||||||||
Proved developed reserves | 782 | 170 | 952 | 9,316 | 234 | 9,550 | 2,442 | 212 | 2,654 |
Proved reserves under PSA and buy-back agreements | 0 | 398 | 398 | 0 | 1,192 | 1,192 | 0 | 610 | 610 |
Production from PSA and buy-back agreements | 0 | 20 | 20 | 0 | 26 | 26 | 0 | 25 | 25 |
Revisions and improved recovery | 127 | (45) | 82 | 501 | (172) | 329 | 217 | (76) | 141 |
Extensions and discoveries | 119 | 84 | 204 | 474 | 24 | 498 | 204 | 88 | 292 |
Purchase of reserves-in-place | 17 | 0 | 17 | 18 | 0 | 18 | 20 | 0 | 20 |
Sales of reserves-in-place | (5) | 0 | (5) | (79) | 0 | (79) | (19) | 0 | (19) |
Production | (205) | (52) | (257) | (869) | (87) | (957) | (360) | (67) | (427) |
At December 31, 2005 | 1,142 | 619 | 1,761 | 13,024 | 1,202 | 14,225 | 3,462 | 833 | 4,295 |
Of which: | |||||||||
Proved developed reserves | 787 | 202 | 990 | 9,348 | 150 | 9,498 | 2,453 | 229 | 2,682 |
Proved reserves under PSA and buy-back agreements | 0 | 351 | 351 | 0 | 973 | 973 | 0 | 524 | 524 |
Production from PSA and buy-back agreements | 0 | 34 | 34 | 0 | 83 | 83 | 0 | 49 | 49 |
The conversion rates used are 1 standard cubic meter = 35.3 standard cubic feet, 1 standard cubic meter oil equivalent = 6.29 barrels of oil equivalent and 1,000 standard cubic meter gas = 1 standard cubic meter oil equivalent.
Statoil is required through its articles of association to market and sell the Norwegian State’s oil and gas together with Statoil’s own oil and gas in accordance with the owner’s instruction established in shareholder resolutions in effect at any given time. For natural gas acquired by Statoil for its own use, its payment to the Norwegian State will be based on market value. For all other sales of natural gas to Statoil or to third parties the payment to the Norwegian State will be based on either achieved prices, a net back formula or market value. All of the Norwegian State’s oil and NGL will be acquired by Statoil. Pricing of the crude oil will be based on market reflective prices; NGL prices will be either based on achieved prices, market value or market reflective prices.
The Norwegian State may at any time cancel the owner’s instruction. Due to this uncertainty and the Norwegian State’s estimate of proved reserves not being available to Statoil, it is not possible to determine the total quantities to be purchased by Statoil under the owner’s instruction from properties in which it participates in the operations.
Capitalized costs related to Oil and Gas producing activities
At December 31, | ||
(in NOK million) | 2005 | 2004 |
Unproved Properties | 14,101 | 2,886 |
Proved Properties, wells, plants and other equipment, including removal obligation assets | 309,441 | 273,289 |
Total Capitalized Expenditures | 323,542 | 276,175 |
Accumulated depreciation, depletion, amortization and valuation allowances | (179,197) | (160,315) |
Net Capitalized Expenditures | 144,345 | 115,860 |
Costs incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
These costs include both amounts capitalized and expensed.
(in NOK million) | Norway | Outside Norway | Total |
Year ended December 31, 2005 | |||
Exploration costs | 2,188 | 2,213 | 4,401 |
Development costs 1), 2) | 15,697 | 10,664 | 26,361 |
Acquired unproved properties | 103 | 13,157 | 13,260 |
Total | 17,988 | 26,034 | 44,022 |
Year ended December 31, 2004 | |||
Exploration costs | 1,102 | 1,390 | 2,492 |
Development costs 1), 2) | 15,400 | 9,819 | 25,219 |
Acquired proved properties | 2,999 | 8,441 | 11,440 |
Total | 19,501 | 19,650 | 39,151 |
Year ended December 31, 2003 | |||
Exploration costs | 1,220 | 1,538 | 2,758 |
Development costs 1) | 13,284 | 6,071 | 19,355 |
Acquired unproved properties | 0 | 54 | 54 |
Total | 14,504 | 7,663 | 22,167 |
(1) | Development costs include investments in Norway in facilities for liquefaction of natural gas and storage of LNG amounting to NOK 665 million in 2005, NOK 1,262 million in 2004, and NOK 614 million in 2003. |
(2) | Includes minor development costs in unproved properties. |
Results of Operation for Oil and Gas Producing Activities
As required by Statement of Financial Accounting Standards No. 69 (FAS 69), the revenues and expenses included in the following table reflect only those relating to the oil and gas producing operations of Statoil.
Effective January 2005, production costs incurred in Norway no longer include cost of transporting certain volumes of NGL that in 2004 and 2003 incurred costs totaling approximately NOK 0.7 and NOK 0.5 billion, respectively.
Activities included in Statoil’s segment disclosures in note 3 to the financial statements but excluded from the table below relate to transportation and business development as well as effects of disposals of oil and gas interests. Certain minor reclassifications have been made to prior periods’ figures to be consistent with the current period’s classifications.
Income tax expense is calculated on the basis of statutory tax rates in addition to uplift and tax credits only. No deductions are made for interest or overhead.
Transfers are recorded approximating market prices.
(in NOK million) | Norway | Outside Norway | Total |
Year ended December 31, 2005 | |||
Sales | 13 | 5,682 | 5,696 |
Transfers | 95,403 | 13,163 | 108,566 |
Total revenues | 95,416 | 18,845 | 114,262 |
Exploration expenses | (1,818) | (1,435) | (3,253) |
Production costs | (7,754) | (1,675) | (9,429) |
Accretion expense | (750) | (66) | (816) |
Special items 1) | 0 | (2,211) | (2,211) |
DD&A | (11,450) | (4,062) | (15,512) |
Total costs | (21,772) | (9,449) | (31,221) |
Results of operations before taxes | 73,644 | 9,397 | 83,041 |
Tax expense | (56,868) | (3,476) | (60,344) |
Results of producing operations | 16,776 | 5,921 | 22,697 |
Year ended December 31, 2004 | |||
Sales | 21 | 3,026 | 3,047 |
Transfers | 72,400 | 6,499 | 78,899 |
Total revenues | 72,421 | 9,525 | 81,946 |
Exploration expenses | (777) | (1,051) | (1,828) |
Production costs | (8,038) | (1,298) | (9,336) |
Accretion expense | (701) | (56) | (757) |
Special items 1) | (259) | 0 | (259) |
DD&A | (12,123) | (2,215) | (14,338) |
Total costs | (21,898) | (4,620) | (26,518) |
Results of operations before taxes | 50,523 | 4,905 | 55,427 |
Tax expense | (38,287) | (1,830) | (40,118) |
Results of producing operations | 12,235 | 3,075 | 15,310 |
Year ended December 31, 2003 | |||
Sales | 352 | 1,930 | 2,282 |
Transfers | 60,143 | 4,455 | 64,598 |
Total revenues | 60,495 | 6,385 | 66,880 |
Exploration expenses | (1,365) | (1,005) | (2,370) |
Production costs | (7,865) | (839) | (8,704) |
Accretion expense | (479) | (48) | (527) |
Special items 1) | 0 | (151) | (151) |
DD&A | (11,971) | (1,625) | (13,596) |
Total costs | (21,680) | (3,668) | (25,348) |
Results of operations before taxes | 38,815 | 2,718 | 41,532 |
Tax expense | (29,290) | (1,035) | (30,325) |
Results of producing operations | 9,525 | 1,682 | 11,207 |
(1) | Impairment of the South Pars 6-7-8 field in 2005, the Murchison and Thune field in 2004, and the Dunlin field in 2003. |
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves
The table below shows the standardized measure of future net cash flows relating to proved reserves presented. The analysis is computed in accordance with FAS 69, by applying year-end market prices, costs, and statutory tax rates, and a discount factor of 10 per cent to year end quantities of net proved reserves. The standardized measure is a forward-looking statement.
Future price changes are limited to those provided by contractual arrangements in existence at the end of each reporting year. Future development and production costs are those estimated future expenditures necessary to develop and produce year-end estimated proved reserves based on year-end cost indices, assuming continuation of year-end economic conditions. Future net cash flow pre-tax is net of decommissioning and removal costs.
Estimated future income taxes are calculated by applying appropriate year-end statutory tax rates. These rates reflect allowable deductions and tax credits and are applied to estimated future pretax net cash flows, less the tax basis of related assets. Discounted future net cash flows are calculated using 10 per cent mid-period discount factors. Discounting requires a year-by-year estimate of when future expenditures will be incurred and when reserves will be produced. The information provided does not represent management’s estimate of Statoil’s expected future cash flows or value of proved oil and gas reserves.
Estimates of proved reserve quantities are imprecise and change over time as new information becomes available. Moreover, identified reserves and contingent resources, that may become proved in the future, are excluded from the calculations. The standardized measure of valuation prescribed under FAS 69 requires assumptions as to the timing and amount of future development and production costs and income from the production of proved reserves. This does not reflect management’s judgment and should not be relied upon as an indication of Statoil’s future cash flow or value of its proved reserves.
(in NOK million) | Norway | Outside Norway | Total |
At December 31, 2005 | |||
Future net cash inflows | 1,067,475 | 276,682 | 1,344,157 |
Future development costs | (51,098) | (30,328) | (81,426) |
Future production costs | (198,399) | (45,980) | (244,379) |
Future income tax expenses | (629,910) | (53,232) | (683,142) |
Future net cash flows | 188,068 | 147,142 | 335,210 |
10 per cent annual discount for estimated timing of cash flows | (77,281) | (67,218) | (144,499) |
Standardized measure of discounted future net cash flows | 110,787 | 79,924 | 190,711 |
At December 31, 2004 | |||
Future net cash inflows | 739,788 | 179,336 | 919,124 |
Future development costs | (42,906) | (22,169) | (65,075) |
Future production costs | (172,892) | (35,516) | (208,408) |
Future income tax expenses | (395,155) | (29,108) | (424,263) |
Future net cash flows | 128,835 | 92,543 | 221,378 |
10 per cent annual discount for estimated timing of cash flows | (56,336) | (44,862) | (101,198) |
Standardized measure of discounted future net cash flows | 72,499 | 47,681 | 120,180 |
At December 31, 2003 | |||
Future net cash inflows | 644,003 | 132,884 | 776,887 |
Future development costs | (39,207) | (17,029) | (56,236) |
Future production costs | (179,686) | (26,509) | (206,195) |
Future income tax expenses | (320,763) | (19,998) | (340,761) |
Future net cash flows | 104,347 | 69,348 | 173,695 |
10 per cent annual discount for estimated timing of cash flows | (47,303) | (37,810) | (85,113) |
Standardized measure of discounted future net cash flows | 57,044 | 31,538 | 88,582 |
Of a total of NOK 81,426 million of estimated future development costs as of December 31, 2005, an amount of NOK 54,570 million is expected to be spent within the next three years, as allocated in the table below.
Future development costs
(in NOK million) | 2006 | 2007 | 2008 | Total |
Norway | 14,300 | 10,402 | 7,350 | 32,052 |
Outside Norway | 12,732 | 6,674 | 3,112 | 22,518 |
Total | 27,032 | 17,076 | 10,462 | 54,570 |
Future development cost expected to be spent on proved undeveloped reserves | 24,652 | 14,863 | 8,629 | 48,144 |
In 2005, Statoil incurred NOK 26,354 million in development costs, of which NOK 22,876 million related to proved undeveloped reserves. The comparable amounts for 2004 were NOK 33,135 and NOK 28,353 million, and for 2003 NOK 19,355 and NOK 14,355 million, respectively.
Changes in the standardized measure of discounted future net cash flows from proved reserves
(in NOK million) | 2005 | 2004 |
Standardized measure at January 1 | 120,180 | 88,582 |
Net change in sales and transfer prices and in production (lifting) costs related to future production | 380,489 | 146,938 |
Changes in estimated future development costs | (27,189) | (34,976) |
Sales and transfers of oil and gas produced during the period, net of production costs | (110,018) | (77,023) |
Net change due to extensions, discoveries, and improved recovery | 38,080 | 10,668 |
Net change due to purchases and sales of minerals in place | 896 | 26,129 |
Net change due to revisions in quantity estimates | 11,970 | 10,733 |
Previously estimated development costs incurred during the period | 26,354 | 33,135 |
Accretion of discount | (121,003) | (41,506) |
Net change in income taxes | (129,048) | (42,500) |
Total change in the standardized measure during the year | 70,531 | 31,598 |
Standardized measure at December 31 | 190,711 | 120,180 |
Operational statistics
Productive oil and gas wells and developed and undeveloped acreage
The following tables show the number of gross and net productive oil and gas wells and total gross and net developed and undeveloped oil and gas acreage in which Statoil had interests at December 31, 2005.
A “gross” value reflects to wells or acreage in which Statoil has interests (calculated as 100 per cent). The net value corresponds to the sum of whole or fractional working interest in gross wells or acreage.
At December 31, 2005 | Norway | Outside Norway | Total | ||
Number of productive oil and gas wells | |||||
Oil wells | 741 | 632 | 1,373 | ||
— net | 190 | 113 | 304 | ||
Gas wells | — gross | 147 | 80 | 227 | |
— net | 45 | 29 | 74 | ||
At December 31, 2005 (in thousands of acres)* | Norway | Outside Norway | Total | ||
Developed and undeveloped oil and gas acreage | |||||
Acreage developed | — gross | 681 | 922 | 1,603 | |
— net | 162 | 306 | 468 | ||
Acreage undeveloped | — gross | 14,131 | 22,416 | 36,547 | |
— net | 5,656 | 13,155 | 18,811 | ||
*1,000 acres = 4.05 square km
Remaining terms of leases and concessions are between one and 35 years.
Exploratory and development drilling activities
The following table shows the number of exploratory and development oil and gas wells in the process of being drilled by Statoil at December 31, 2005.
(number of wells) | Norway | Outside Norway | Total |
Number of wells in progress | |||
— gross | 36 | 35 | 71 |
— net | 9.9 | 6.1 | 16.0 |
Net productive and dry oil and gas wells
The following tables show the net productive and dry exploratory and development oil and gas wells completed or abandoned by Statoil in the past three years. Productive wells include wells in which hydrocarbons were found, and the drilling or completion of which, in the case of exploratory wells, has been suspended pending further drilling or evaluation. A dry well is one found to be incapable of producing in sufficient quantities to justify completion.
Norway | Outside Norway | Total | |
Year 2005 | |||
Net productive and dry exploratory wells drilled | 3.3 | 2.2 | 5.5 |
- Net dry exploratory wells drilled | 1.1 | 0.9 | 2.0 |
- Net productive exploratory wells drilled | 2.2 | 1.3 | 3.5 |
Net productive and dry development wells drilled | 16.9 | 6.7 | 23.6 |
- Net dry development wells drilled | 0.0 | 0.0 | 0.0 |
- Net productive development wells drilled | 16.9 | 6.7 | 23.6 |
Year 2004 | |||
Net productive and dry exploratory wells drilled | 2.5 | 1.1 | 3.5 |
- Net dry exploratory wells drilled | 0.5 | 0.1 | 0.6 |
- Net productive exploratory wells drilled | 2.0 | 0.9 | 3.0 |
Net productive and dry development wells drilled | 16.9 | 6.7 | 23.6 |
- Net dry development wells drilled | 0.0 | 0.0 | 0.0 |
- Net productive development wells drilled | 16.9 | 6.7 | 23.6 |
Year 2003 | |||
Net productive and dry exploratory wells drilled | 4.3 | 2.5 | 6.8 |
- Net dry exploratory wells drilled | 1.7 | 1.0 | 2.7 |
- Net productive exploratory wells drilled | 2.6 | 1.5 | 4.1 |
Net productive and dry development wells drilled | 25.3 | 18.1 | 43.4 |
- Net dry development wells drilled | 2.4 | 0.0 | 2.4 |
- Net productive development wells drilled | 22.9 | 18.1 | 41.0 |
Average sales price and production cost per unit
Norway | Outside Norway | |
Year ended December 31, 2005 | ||
Average sales price liquids in USD per bbl | 54.1 | 51.0 |
Average sales price natural gas in NOK per Sm3 | 1.45 | 1.12 |
Average production costs, in NOK per boe | 21.6 | 25.2 |
Year ended December 31, 2004 | ||
Average sales price liquids in USD per bbl | 38.4 | 35.7 |
Average sales price natural gas in NOK per Sm3 | 1.10 | 0.89 |
Average production costs, in NOK per boe | 22.5 | 30.9 |
Year ended December 31, 2003 | ||
Average sales price crude in USD per bbl | 29.1 | 27.6 |
Average sales price natural gas in NOK per Sm3 | 1.02 | 0.83 |
Average production costs, in NOK per boe | 21.9 | 26.1 |