UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 6-K

REPORT OF FOREIGN PRIVATE ISSUER

PURSUANT TO RULE 13a-16 OR 15d-16 OF THE

SECURITIES EXCHANGE ACT OF 1934

February 4, 2016

Commission File Number 1-15200

Statoil ASA

(Translation of registrant’s name into English)

FORUSBEEN 50, N-4035, STAVANGER, NORWAY

(Address of principal executive offices)

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

Form 20-F X Form 40-F

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

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

This Report on Form 6-K shall be deemed to be filed and incorporated by reference in the Registration Statements on Form F-3 (File No. 333-188327) and Form S-8 (File No. 333-168426) and to be a part thereof from the date on which this report is furnished, to the extent not superseded by documents or reports subsequently filed or furnished.

This document includes portions from the previously published results announcement of Statoil ASA as of, and for the full year ended, 31 December , 2015, as revised to comply with the requirements of Item 10(e) of Regulation S-K regarding non-GAAP financial information promulgated by the U.S. Securities and Exchange Commission. For more information on our use of non-GAAP financial measures in this report, see the section entitled "Use and Reconciliation of Non-GAAP Financial Measures". This document does not update or otherwise supplement the information contained in the previously published results announcement.

2015 FOURTH QUARTER RESULTS

In the fourth quarter of 2015, Statoil’s net operating income was NOK 1.7 billion, and for the full year 2015 it ended at NOK 14.9 billion. Statoil's net income for the fourth quarter 2015 was negative NOK 9.2 billion, and for the full year 2015 it ended at negative NOK 37.3 billion, mainly as a result of lower short term price assumptions leading to impairment charges and provision.

Today, Statoil presents its update to the capital markets, announcing a step-up in its improvement programme by 50% to USD 2.5 billion per year in 2016. One year ahead of plan, Statoil delivers annual cost improvements of USD 1.9 billion, compared to its 2016 target of USD 1.7 billion. Statoil is reducing organic capital expenditure from USD 14.7 billion in 2015 to around USD 13 billion in 2016, and has substantially improved its portfolio of non-sanctioned projects, with planned start-up by 2022, reducing the average break-even oil price from USD 70 per boe in 2013 to USD 41 per boe in 2016.

“The result in the fourth quarter is highly impacted by the weak commodity price. However, we continue to make strong progress on costs and efficiency. We are now further stepping up our improvement programme, and tightening our capital and exploration expenditures. These are key elements in navigating the business during a period of low oil prices”, says president and CEO of Statoil ASA, Eldar Sætre.

“Statoil is well positioned to capture value from an expected upturn in the market. We have substantially improved our non-sanctioned project portfolio. More than 80% of the operated projects, with start-up by 2022, have a break-even oil price below USD 50 per boe, says Sætre.

The Board of Directors will propose to the Annual general meeting (AGM) to maintain a dividend of USD 0.2201 per share fourth quarter 2015 and the introduction of a two-year scrip dividend programme starting from the fourth quarter 2015. The scrip programme will give shareholders the option to receive quarterly dividends in cash or in newly issued shares in Statoil, at a 5% discount for the fourth quarter 2015. The Norwegian Government, as majority shareholder, supports the proposal and will seek the Norwegian Parliament’s approval to vote in favour of the proposal at the Annual general meeting. The Norwegian government will match subscription of shares by minority shareholders, and thereby maintain its ownership share at 67% throughout the programme.

“We are firmly committed to maintain a competitive capital distribution, in line with our dividend policy. The proposal is to maintain the dividend, while offering shareholders an option to reinvest their dividend in newly issued shares. We are pleased to introduce the scrip programme as an additional tool, strengthening the company’s financial flexibility to invest in high-quality projects in a timely manner”, says Sætre.

Net operating income for the quarter was NOK 1.7 billion, compared to NOK 9.0 billion in the same period in 2014. The reduction was primarily due to the significant drop in liquids prices and gas prices. Realised average liquids prices in the quarter were down 29% measured in NOK compared to the fourth quarter last year. Net impairment charges of NOK 10.1 billion related to impairment of various assets, provisions of NOK 4.8 billion and gain on sale of assets of NOK 3.2 billion impacted the results. Earnings per share in the period were negative NOK 2.89 compared to negative NOK 2.81 in the same period last year.

Statoil delivered equity production of 2,046 mboe per day in the fourth quarter, a reduction of 3% compared to the same period in 2014. Adjusting for divestments, the underlying production was at the same level as in the fourth quarter last year.

Statoil reported cash flow from operations in 2015 of NOK 165.8 billion before taxes paid and working capital items. At year-end, Statoil’s net debt to capital employed was 26.8%. Organic capital expenditure was USD 14.7 billion in 2015.

Statoil completed 39 exploration wells during 2015, with three wells on-going at year-end. Adjusted exploration expenses in the quarter were NOK 4.2 billion, down from NOK 7.5 billion in the fourth quarter of 2014, mainly as a result of lower drilling activity and less expensive wells being drilled.

Statoil experienced three contractor fatalities related to our activities in the fourth quarter; one on the NCS and two in our US onshore operations.

“These fatalities are clear reminders that the safety and security of our people, and the integrity of our operations, must remain our top priority”, says CEO Eldar Sætre.

The Serious Incident Frequency (SIF) was 0.6 in 2015.

Capital Markets Update

Today, Statoil presents its strategy to the capital market, focusing on three priorities:

· Delivering faster and deeper cost reductions: Stepping up the improvement programme by 50% to USD 2.5 billion annually in 2016

· Preparing to invest in the next generation portfolio: Investing in a radically improved project portfolio, with an average break-even of USD 41 per boe

· Capturing the upturn in oil and gas prices: Sustaining the efficiency gains and investing in attractive projects to benefit from the expected price recovery

“Resetting costs – capturing opportunities, that’s the core of our strategy. As an early mover on cost efficiency, we are now shaping our next generation portfolio. Statoil is positioned for value creation in a low price environment, and well placed to capture the gains when the oil price recovers”, says Eldar Sætre

Furthermore, Statoil announces its updated outlook for 2016-2019:

· Statoil will invest around USD 13 billion in 2016

· From 2014 to 2017, Statoil estimates an annual organic production growth of around 1% from a rebased equity production level. From 2017 to 2019 Statoil expects 2–4% organic annual production growth

· The exploration spend in 2016 will be around USD 2 billion

Quarters			Change		Full year
Q4 2015	Q3 2015	Q4 2014	Q4 on Q4		2015	2014	Change

1.7	7.3	9.0	(81%)	IFRS Net operating income (NOK billion)	14.9	109.5	(86%)
(9.2)	(2.8)	(8.9)	N/A	IFRS Net income (NOK billion)	(37.3)	22.0	N/A
2,046	1,909	2,103	(3%)	Total equity liquids and gas production (mboe per day) [4]	1,971	1,927	2%
327.7	357.5	458.9	(29%)	Group average liquids price (NOK/bbl) [1]	370.7	558.4	(34%)

Key events since third quarter 2015:

· The plan for development and operation (PDO) of the North Sea Oseberg Vestflanken 2 was submitted to the authorities

· Gas production started from the Corrib field off the northwest coast of Ireland

· To optimise its exploration portfolio Statoil decided to exit Alaska following recent exploration results in neighbouring leases

· Statoil was awarded interest in 24 licences on the NCS in the 2015 APA round

· Statoil entered into a transaction on the UK shelf, where Statoil acquired First Oil’s 24% share in the UK licence for the Alfa Sentral field

· The 20% interest in Trans Adriatic Pipeline AG was divested to the Italian gas infrastructure company Snam SpA for a total consideration of EUR 208 million

· Statoil and Repsol entered into transactions that saw Statoil farming down a 15% interest in the Gudrun field on the NCS to Repsol, in return for a 13% interest and operatorship in Eagle Ford and operatorship of the BM-C-33 licence in Brazil

· In November, Statoil made the final investment decision to build Hywind pilot park in Scotland, the world’s first floating wind farm

· In January Statoil acquired 11.93% of Lundin Petroleum, increasing the company’s exposure to core field development projects and growth assets on NCS, including Johan Sverdrup and Edvard Grieg

Fourth QUARTER 2015 GROUP REVIEW

The fourth quarter results continue to be severely influenced by low prices and impairment charges. Encouraging operational performance, solid results from marketing and trading and a positive underlying cost development impacted the results.

Total equity liquids and gas production [4] was 2,046 mboe per day, down 3% from 2,103 mboe per day in the fourth quarter of 2014, mainly due to expected natural decline on mature fields and lower ownership shares from redetermination and divestments. The decrease was partially offset by ramp-up on various fields, production from new fields on stream and stronger operational performance.

Total entitlement liquids and gas production [3] was slightly down by 1% to 1,921 mboe per day compared to the fourth quarter of 2014, impacted by the decrease in equity production, partially offset by a beneficial effect from production sharing agreements (PSA effect) mainly as a result of the decline in oil prices.

Net operating income (IFRS) was NOK 1.7 billion in the fourth quarter of 2015, compared to NOK 9.0 billion in the fourth quarter of 2014, primarily due to the significant drop in liquids prices, lower gas prices and the reduction in production as described above. Impairment charges related to various assets of NOK 15.2 billion and provisions of NOK 4.8 billion negatively impacted net operating income, whilst reversal of impairment charges of NOK 5.1 billion mainly related to certain unconventional onshore assets in North America and gain on sale of assets of NOK 3.2 billion positively impacted net operating income.

In the fourth quarter of 2014, net operating income was negatively affected by net impairment charges related to certain assets of NOK 20.6 billion and the effect from cancellation of a rig contract of NOK 2.1 billion. Gains from sale of assets of NOK 6.2 billion and changes in pension plans of NOK 3.5 billion positively affected net operating income.

Total revenues and other income decreased primarily due to the significant drop in liquids prices, lower gas prices and the reduction in production.

Operating and administrative expenses increased by NOK 4.1 billion compared to the fourth quarter of 2014, mainly because a gain related to the change of pension plan in Norway of NOK 3.5 billion was included in the fourth quarter of 2014. The USD/NOK exchange rate development and higher transportation costs added to the increase. Reduced operational costs, lower maintenance, effects from on-going cost initiatives in addition to lower diluent expenses and royalties caused by reduced prices, partially offset the increase.

Depreciation, amortisation and net impairment losses decreased by NOK 2.5 billion mainly due to lower net impairment losses in the fourth quarter of 2015, and reduced depreciation because of net impairments of assets in both 2014 and 2015. The USD/NOK exchange rate development and start-up and ramp-up of production on several fields partially offset the decrease.

Exploration expenses decreased by NOK 11.4 billion to 4.1 billion in the fourth quarter of 2015, mainly due to lower impairment charges, reduced drilling activity and less expensive wells being drilled. The portion of previously capitalised expenditures being expensed this quarter was also lower and added to the decrease.

Net financial items amounted to a loss of NOK 5.3 billion in the fourth quarter of 2015, compared to a loss of NOK 1.0 billion in the fourth quarter of 2014. The change of NOK 4.3 billion is due to a loss on derivatives of NOK 2.3 billion related to the long term debt portfolio, mainly due to an increase in the interest yield curves, compared to a gain on derivatives of NOK 2.2 billion in the fourth quarter 2014 due to a decrease in the interest yield curves.

Income taxes were NOK 5.5 billion in the fourth quarter, equivalent to an effective tax rate of 152.5%, compared to 210.3% in the fourth quarter of 2014.

Please refer to note 5 Income tax to the condensed interim financial statements for information related to income taxes.

Quarters			Change	Condensed income statement under IFRS	Full year
Q4 2015	Q3 2015	Q4 2014	Q4 on Q4	(unaudited, in NOK billion)	2015	2014	Change

112.1	111.9	152.6	(27%)	Total revenues and other income	482.8	622.7	(22%)

(50.9)	(52.5)	(74.3)	(31%)	Purchases [net of inventory variation]	(211.2)	(301.3)	(30%)
(21.5)	(23.2)	(17.4)	23%	Operating and administrative expenses	(91.9)	(80.2)	15%
(33.9)	(19.1)	(36.4)	(7%)	Depreciation, amortisation and net impairment losses	(133.8)	(101.4)	32%
(4.1)	(9.9)	(15.5)	(74%)	Exploration expenses	(31.0)	(30.3)	2%

1.7	7.3	9.0	(81%)	Net operating income	14.9	109.5	(86%)

(5.3)	0.7	(1.0)	>100%	Net financial items	(10.6)	(0.0)	>100%

(3.6)	7.9	8.0	>(100%)	Income before tax	4.3	109.4	(96%)

(5.5)	(10.7)	(16.9)	(67%)	Income tax	(41.6)	(87.4)	(52%)

(9.2)	(2.8)	(8.9)	3%	Net income	(37.3)	22.0	>(100%)

Net income in the fourth quarter of 2015 was negative NOK 9.2 billion compared to negative NOK 8.9 billion in the fourth quarter of 2014, mainly due to lower oil and gas prices, reduced production and increased losses on financial items. Lower income taxes and reduced net impairment charges partially offset the decrease.

Proved reserves at the end of 2015 were 5,060 mmboe, a decrease compared to 5,359 mmboe at the end of 2014. In 2015, a total of 598 mmboe were added through revisions, extensions, discoveries and acquisitions. The reductions in proved reserves were related to sale of reserves in place of 235 mmboe and entitlement production of 662 mmboe.

The reserve replacement ratio (RRR), which measures the proved reserves added to the reserve base (including the effects of sales and purchases) relative to the amount of oil and gas produced, was 55% in 2015, compared to 62% in 2014. The organic reserves replacement ratio was 88% compared to 96% in 2014 and the average three-year replacement ratio (including the effects of sales and purchases), was 81% at the end of 2015 compared to 97% in 2014. The decrease in reserves in 2015 was primarily due to high production on existing fields, reduced commodity prices and completion of the farm out on Shah Deniz. The 2015 SEC forward price for Brent Blend was 54 USD per boe compared to 101 USD per boe in 2014. The decrease was partially compensated for by sanctioning of Johan Sverdrup phase 1 and positive revisions on several of our producing fields due to good production performance and increased efficiency.

Based on average capital employed, return on average capital employed (ROACE) was negative 8.0% for the 12 month period ended 31 December 2015 and 2.7% for the 12 month period ended 31 December 2014.

Organic capital expenditures (excluding acquisitions and capital leases) amounted to NOK 118.8 billion or USD 14.7 billion for the year ended 2015. Organic capital expenditures have been reduced by 18% measured in NOK compared to our original guidance for 2015. Gross investments amounted to NOK 125.5 billion.

Cash flows provided by operating activities were NOK 18.8 billion in the fourth quarter of 2015 compared to NOK 27.3 billion in the fourth quarter of 2014. Excluding working capital movements and taxes paid, cash flows provided by operating activities were NOK 35.0 billion in the fourth quarter of 2015 compared to NOK 40.9 billion in the fourth quarter of 2014. The decrease of NOK 5.9 billion was mainly due to reduced liquid prices and gas prices.

Cash flows used in investing activities were NOK 2.1 billion in the fourth quarter of 2015 compared to NOK 36.2 billion in the fourth quarter of 2014. The decrease of NOK 34.1 billion was mainly due to higher investments in deposits with more than three months to maturity of NOK 38.5 billion and lower proceeds from sale of assets and businesses of NOK 5.4 billion.

Cash flows used in financing activities were NOK 7.6 billion in the fourth quarter of 2015 compared to negative NOK 6.5 billion in the fourth quarter of 2014, an increase of NOK 14.1 billion mainly due issuance of new debt in the fourth quarter of 2014 of NOK 20.5 billion.

Full year 2015

Net operating income (IFRS) was NOK 14.9 billion for the full year of 2015 compared to NOK 109.5 billion for the full year of 2014. The decrease was mainly due to the reduction in prices and the increase in depreciation costs. Significantly stronger refinery margins in 2015 and higher volumes sold, partially offset the decrease.

Net operating income for 2015 was negatively impacted by net impairment charges of NOK 63.3 billion and provisions of NOK 5.4 billion. Gain from sale of assets of NOK 17.6 billion, mainly related to the divestment of the Shah Deniz project impacted net operating income positively.

In 2014, net operating income was negatively affected by net impairment charges of total NOK 38.7 billion and the termination of a rig contract of NOK 2.1 billion. Gain on sale of assets of NOK 12.7 billion, an award payment related to a commercial dispute of NOK 2.8 billion and a gain of NOK 3.5 billion related to the implementation of new pension plans positively impacted net operating income in 2014.

Total revenues and other income decreased, mainly due to the reduction in both liquids and gas prices measured in NOK. The stronger refinery margins in 2015, higher volumes of both liquids and gas sold and increased gain from sale of assets partially offset the decrease.

Operating and administrative expenses increased mainly due to the USD/NOK exchange rate development in 2015 and because a gain related to the change of pension plan was included in 2014. Lower operation and maintenance costs, lower royalties due to reduced liquids prices, lower transportation costs and portfolio changes in addition to positive effects from on-going cost initiatives, partially offset the increase.

Depreciation, amortisation and net impairment losses increased mainly due to increased impairment charges in 2015 and the USD/NOK exchange rate development. In addition, depreciation increased due to start-up and ramp-up of production of several fields. Reduced depreciation because of net impairments of assets in both 2014 and 2015 partially offset the increase.

Exploration expenses were up 2% mainly due to the USD/NOK exchange rate development and increased impairment of exploration assets in 2015. Lower drilling activity, a higher capitalisation rate and a lower portion of previously capitalised expenditures being expensed in 2015, partially offset the increase.

Net financial items amounted to a loss of NOK 10.6 billion for the full year 2015 compared to NOK 0.0 billion for 2014. The change from 2014 is mainly related to loss on derivatives related to the long term debt portfolio in 2015 of NOK 3.8 billion, compared to a gain on derivatives of NOK 5.8 billion for 2014. Fair value changes of derivatives are mainly due to changes in the interest yield curves.

Income tax in the full year of 2015 is NOK 41.6 billion equivalent to a tax rate of 969.3% compared to 79.9% in the full year of 2014.

Please refer to note 5 Income tax to the condensed interim financial statements for information related to income taxes.

Net income in the full year of 2015 was negative NOK 37.3 billion compared to positive NOK 22.0 billion in the full year of 2014, mainly due to the reduction in net operating income explained above and the increased losses on financial items. Lower income taxes partially offset the decrease in net income.

Cash flows provided by operating activities were NOK 109.0 billion for the full year of 2015 compared to NOK 126.5 billion for the full year of 2014. Excluding working capital movements and taxes paid, cash flows provided by operating activities were NOK 165.8 billion for the full year of 2015 compared to NOK 208.8 billion for the full year of 2014. The decrease of NOK 43.0 billion was mainly due to reduced liquids and gas prices.

Cash flows used in investing activities were NOK 115.1 billion for the full year of 2015 compared to NOK 112.0 billion for the full year of 2014.

Cash flows provided by financing activities were negative NOK 7.5 billion for the full year of 2015 compared to negative NOK 23.1 billion for the full year of 2014, an increase of NOK 15.6 billion mainly due to the issuance of new debt of NOK 32.1 billion in the first quarter of 2015 partially offset by lower dividend paid NOK 10.8 billion.

OUTLOOK

· Organic capital expenditures for 2016 (i.e. excluding acquisitions, capital leases and other investments with significant different cash flow pattern) are estimated at around USD 13 billion

· Statoil intends to continue to mature the large portfolio of exploration assets and estimates a total exploration activity level of around USD 2 billion for 2016, excluding signature bonuses

· Statoil expects to deliver efficiency improvements with pre-tax cash flow effects of around USD 2.5 billion from 2016

· Statoil’s ambition is to keep the unit of production cost in the top quartile of Statoil`s peer group

· For the period 2014 – 2017, organic production growth [7] is expected to come from new projects resulting in around 1% CAGR (Compound Annual Growth Rate) from a 2014 level rebased for divestments

· The equity production for 2016 is estimated to be somewhat lower than the 2015 level due to value over volume approach [7]

· Scheduled maintenance activity is estimated to reduce quarterly production by approximately 25 mboe per day in the first quarter of 2016 of which the majority is liquids internationally. In total, the maintenance is estimated to reduce equity production by around 60 mboe per day for the full fiscal year 2016, which is higher than 2015 impact

· Indicative effects from Production Sharing Agreement (PSA-effect) and US royalties are estimated to be around 135 mboe per day in 2016 based on an oil price of USD 40 per barrel and 165 mboe per day based on an oil price of USD 70 per barrel [4]

· Deferral of production to create future value, gas off-take, timing of new capacity coming on stream and operational regularity represent the most significant risks related to the production guidance

· The Board of Directors will propose to the Annual general meeting (AGM) to maintain a dividend of USD 0.2201 per share fourth quarter 2015 and the introduction of a two-year scrip dividend programme starting from the fourth quarter 2015.

· With effect from first quarter of 2016, Statoil will change to USD as presentation currency

DEVELOPMENT AND PRODUCTION NORWAY

Fourth quarter 2015 review

Average daily production of liquids and gas decreased by 2% to 1,309 mboe per day in the fourth quarter of 2015 compared to the fourth quarter of 2014. The decrease was mainly due to expected natural decline on mature fields, lower gas sales and redetermination, partially offset by increased production from several fields and ramp-up of new fields.

Net operating income for Development and Production Norway (DPN) was NOK 14.5 billion compared to NOK 29.5 billion in the fourth quarter of 2014. The decrease by 51% in net operating income in the fourth quarter of 2015 compared to the fourth quarter of 2014 was mainly due to the drop in liquids prices, partially offset by the USD/NOK exchange rate development. Net impairment charges of NOK 3.0 billion negatively impacted net operating income, partially offset by gain on sale of assets of NOK 1.2 billion.

Net operating income in the fourth quarter of 2014 was positively impacted by gain on sale of assets of NOK 5.9 billion and gain related to new pension plans of NOK 2.3 billion, partially offset by impairment charges of NOK 2.3 billion.

Operating and administrative expenses increased mainly because a gain related to the change of pension plan in Norway of NOK 2.3 billion was included in the fourth quarter of 2014, partly offset by effects from on-going improvement initiatives.

Depreciation, amortisation and net impairment losses increased mainly due to impairment charges and start-up and ramp-up of new fields, partially offset by decreased asset retirement obligation.

Exploration expenses decreased compared to 2014 mainly due to lower drilling activity and less expensive wells.

Quarters			Change	Income statement under IFRS	Full year
Q4 2015	Q3 2015	Q4 2014	Q4 on Q4	(in NOK billion)	2015	2014	Change

34.8	33.3	50.3	(31%)	Total revenues and other income	139.5	182.2	(23%)

(5.1)	(6.7)	(5.0)	1%	Operating and administrative expenses	(25.8)	(25.2)	3%
(14.2)	(11.7)	(13.6)	4%	Depreciation, amortisation and net impairment losses	(51.4)	(40.0)	29%
(1.0)	(1.1)	(2.1)	(53%)	Exploration expenses	(4.6)	(5.4)	(14%)

14.5	13.9	29.5	(51%)	Net operating income	57.6	111.7	(48%)

Full year 2015

Net operating income for DPN was NOK 57.6 billion in the full year of 2015 compared to NOK 111.7 billion in the full year of 2014. The decrease was primarily driven by the drop in liquids prices. Net impairment charges of NOK 8.6 billion and lower fair value of derivatives of NOK 2.7 billion negatively impacted net operating income, partially offset by gain on sale of assets of NOK 1.2 billion.

Net operating income in the full year of 2014 was positively impacted by gain on sale of assets of NOK 6.0 billion and gain related to new pension scheme of NOK 2.2 billion, partially offset by impairment charges of NOK 2.3 billion.

Total revenues and other income decreased primarily driven by the drop in liquids prices. Positive USD/NOK exchange rate development and increased volumes partially offset the decrease.

Operating and administrative expenses increased primarily driven by new fields coming on stream, partially offset by cost improvements and reduced turnaround activity levels.

Depreciation, amortisation and net impairment losses increased primarily driven by impairments and start-up and ramp-up of new fields.

Exploration expenses decreased mainly due to lower drilling activity and a lower portion of previously capitalised exploration expenditures being expensed in 2015.

DEVELOPMENT AND PRODUCTION INTERNATIONAL

Fourth quarter 2015 review

Average equity production of liquids and gas in the fourth quarter of 2015 decreased by 5% to 737 mboe per day compared to the fourth quarter of 2014. Ramp-up on Jack/St. Malo (US) and lower effect of planned turnarounds were offset by the divestment of the Shah Deniz project and expected natural decline on various fields.

Average daily entitlement production of liquids and gas increased by 2% to 613 mboe per day compared to the fourth quarter of 2014. The increase was due to a beneficial effect from production sharing agreements (PSA effect), mainly driven by the decline in prices. The PSA effect was 83 mboe per day in the fourth quarter of 2015 compared to 130 mboe per day in the fourth quarter of 2014.

Net operating income for Development and Production International (DPI) was negative NOK 17.3 billion compared to negative NOK 24.7 billion the fourth quarter of 2014. Lower realised oil and gas prices, net impairment losses of NOK 7.1 billion, a provision for a dispute of NOK 2.8 billion and onerous contracts provision of NOK 1.3 billion negatively impacted net operating income. This was partially offset by lower exploration expenses and higher entitlement production.

In the fourth quarter of 2014, net operating income was negatively impacted by net impairment charges of NOK 18.8 billion and the cancellation of a rig contract of NOK 2.1 billion.

Operating and administrative expenses increased due to the USD/NOK exchange rate development. The increase was partially offset by lower operation and maintenance costs, in addition to lower diluent expenses and royalties caused by reduced prices.

Depreciation, amortisation and net impairment losses decreased primarily due to lower net impairment losses in the fourth quarter of 2015 compared to fourth quarter of 2014, and higher reserves estimates and effects from net impairments of assets in both 2014 and 2015. The decrease was partially offset by the USD/NOK exchange rate development in addition to higher production from various fields and start-up and ramp-up of new fields.

Exploration expenses decreased primarily due to lower net impairments in the fourth quarter of 2015 compared to fourth quarter of 2014, reduced drilling activity, and a lower portion of previously capitalised exploration expenditures being expensed this quarter. The USD/NOK development partially offset the decrease

Quarters			Change	Income statement under IFRS	Full year
Q4 2015	Q3 2015	Q4 2014	Q4 on Q4	(in NOK billion)	2015	2014	Change

10.3	11.5	16.3	(37%)	Total revenues and other income	68.4	85.2	(20%)

(6.0)	(7.5)	(5.3)	13%	Operating and administrative expenses	(27.3)	(22.9)	19%
(18.5)	(10.3)	(22.3)	(17%)	Depreciation, amortisation and net impairment losses	(81.6)	(56.8)	44%
(3.1)	(8.8)	(13.4)	(77%)	Exploration expenses	(26.3)	(25.0)	6%

(17.3)	(15.0)	(24.7)	(30%)	Net operating income	(66.9)	(19.5)	>100%

Full year 2015

Net operating income for DPI was negative NOK 66.9 billion in full year of 2015 compared to negative NOK 19.5 billion in the full year of 2014. Net impairment losses of NOK 59.3 billion, net provisions for disputes of NOK 5.4 billion and onerous contracts provision of NOK 1.3 billion negatively impacted net operating income, partially offset by a gain from sale of assets of NOK 12.2 billion.

Net operating income in the full year of 2014 was negatively impacted by impairment charges of NOK 35.6 billion and the cancellation of a rig contract of NOK 2.1 billion, partially offset by gain on sale of assets of NOK 5.8 billion.

Total revenues and other income decreased due to lower realised oil and gas prices and provision for disputes, partially offset by higher gain related to sale of assets and higher entitlement production.

Operating and administrative expenses increased primarily due to the USD/NOK exchange rate development. The start-up of CLOV and Jack/ St. Malo added to the increase. Reduced operations and maintenance costs, lower royalties caused by lower prices and portfolio changes partially offset the increase.

Depreciation, amortisation and net impairment losses increased primarily driven by significant impairments in 2015 in addition to the USD/NOK development, and higher production from start-up and ramp-up of fields. The increase was partially offset by effect from net impairments in 2014 and 2015 and higher reserves estimates.

Exploration expenses increased primarily due to the USD/NOK exchange rate development, partly offset by a higher capitalisation rate in 2015 and a lower portion of previously capitalised exploration expenditures being expensed in 2015

MARKETING, MIDSTREAM AND PROCESSING

Fourth quarter 2015 review

Natural gas sales volumes amounted to 13.6 billion standard cubic meters (bcm), down 8% compared to the fourth quarter of 2014. The decrease was mainly due to divestments and lower third-party volumes. Of the total gas sales in the fourth quarter of 2015, entitlement gas was 11.9 bcm compared to 12.6 bcm in the fourth quarter of 2014.

Average invoiced European natural gas sales price decreased by 15% due to a general decrease in the gas market. Average invoiced North American piped gas sales price decreased by 31% due to a general decrease in the North American gas market.

Net operating income for Marketing, Midstream and Processing (MMP) was NOK 4.2 billion compared to NOK 2.8 billion in the fourth quarter of 2014. Net operating income was positively impacted by gain on sale of assets of NOK 1.5 billion, improved trading results for liquids, and the USD/NOK foreign exchange rate development. Lower margins for European gas sales and trading activity and a loss on operational storage, partly offset the increase

Net operating income in the fourth quarter of 2014 was negatively impacted by loss on operational storage, partially offset by net impairment charges of NOK 0.4 billion.

Operating and administrative expenses increased as a result of higher transportation costs and exchange rates development in NOK towards other currencies. The increase was partially offset by effects from on-going cost initiatives.

Quarters			Change	Income statement under IFRS	Full year
Q4 2015	Q3 2015	Q4 2014	Q4 on Q4	(in NOK billion)	2015	2014	Change

111.8	113.9	144.9	(23%)	Total revenues and other income	467.4	597.3	(22%)

(96.9)	(100.4)	(133.5)	(27%)	Purchases [net of inventory variation]	(406.5)	(544.2)	(25%)
(9.9)	(8.6)	(8.4)	18%	Operating and administrative expenses	(37.6)	(33.2)	13%
(0.8)	3.1	(0.2)	>100%	Depreciation, amortisation and net impairment losses	0.4	(3.6)	>(100%)

4.2	8.0	2.8	50%	Net operating income	23.7	16.2	47%

Full year 2015

Net operating income for MMP was NOK 23.7 billion in the full year of 2015 compared to NOK 16.2 billion in the full year of 2014, positively impacted by net reversal of impairment charges of NOK 3.5 billion and gain on sale of assets of NOK 1.7 billion. Higher refinery margins due to an oversupplied crude market with low spot prices, solid liquids trading results, and the USD/NOK foreign exchange rate development added to the increase. Onerous contract provisions of NOK 1.6 billion, loss on operational storage, and lower margins for the European gas sales partially offset the increase.

Net operating income in the full year of 2014 was positively impacted by gain due to an award payment related to a commercial dispute of NOK 2.8 billion and gain on sale of assets of NOK 0.9 billion. Net operating income was negatively impacted by net impairment charges of NOK 0.8 billion and loss on operational storage.

Total revenues and other income decreased driven by lower US crude oil prices, partly offset by the USD/NOK exchange rate development.

Purchases [net of inventory variation] decreased driven by the same factors as described above.

Operating and administrative expenses increased primarily driven by the exchange rates development in NOK towards other currencies, partially offset by decrease in transportation costs and positive effect of on-going cost initiatives.

Depreciation, amortisation and net impairment losses were positively impacted by net reversal of impairment charges of NOK 3.5 billion.

CONDENSED INTERIM FINANCIAL STATEMENTS

Fourth quarter 2015

CONSOLIDATED STATEMENT OF INCOME

Quarters				Full year
Q4 2015	Q3 2015	Q4 2014	(unaudited, in NOK billion)	2015	2014

109.2	112.2	147.0	Revenues	465.3	606.8
(0.3)	(0.5)	(0.5)	Net income from equity accounted investments	(0.3)	(0.3)
3.1	0.2	6.1	Other income	17.8	16.1

112.1	111.9	152.6	Total revenues and other income	482.8	622.7

(50.9)	(52.5)	(74.3)	Purchases [net of inventory variation]	(211.2)	(301.3)
(19.2)	(21.4)	(15.2)	Operating expenses	(84.5)	(72.9)
(2.3)	(1.8)	(2.2)	Selling, general and administrative expenses	(7.5)	(7.3)
(33.9)	(19.1)	(36.4)	Depreciation, amortisation and net impairment losses	(133.8)	(101.4)
(4.1)	(9.9)	(15.5)	Exploration expenses	(31.0)	(30.3)

1.7	7.3	9.0	Net operating income	14.9	109.5

(5.3)	0.7	(1.0)	Net financial items	(10.6)	(0.0)

(3.6)	7.9	8.0	Income before tax	4.3	109.4

(5.5)	(10.7)	(16.9)	Income tax	(41.6)	(87.4)

(9.2)	(2.8)	(8.9)	Net income	(37.3)	22.0

(9.2)	(2.8)	(8.9)	Attributable to equity holders of the company	(37.5)	21.9
0.0	0.0	0.1	Attributable to non-controlling interests	0.2	0.1

(2.89)	(0.89)	(2.81)	Basic earnings per share (in NOK)	(11.80)	6.89
(2.89)	(0.89)	(2.81)	Diluted earnings per share (in NOK)	(11.80)	6.87
3,178.1	3,179.1	3,178.9	Weighted average number of ordinary shares outstanding (in millions)	3,179.4	3,180.0

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

Quarters				Full year
Q4 2015	Q3 2015	Q4 2014	(unaudited, in NOK billion)	2015	2014

(9.2)	(2.8)	(8.9)	Net income	(37.3)	22.0

8.2	(1.6)	(1.8)	Actuarial gains (losses) on defined benefit pension plans	10.1	(0.0)
(2.3)	0.4	0.8	Income tax effect on income and expenses recognised in OCI	(2.8)	0.9
5.9	(1.1)	(0.9)	Items that will not be reclassified to the Consolidated statement of income	7.3	0.9

6.7	13.6	30.9	Currency translation adjustments¹⁾	27.4	41.6
6.7	13.6	30.9	Items that may be subsequently reclassified to the Consolidated statement of income	27.4	41.6

12.6	12.5	30.0	Other comprehensive income	34.7	42.5

3.4	9.7	21.1	Total comprehensive income	(2.6)	64.5

3.4	9.7	21.0	Attributable to the equity holders of the company	(2.8)	64.4
0.0	0.0	0.1	Attributable to non-controlling interests	0.2	0.1

¹⁾ Currency translation adjustments of NOK 27.4 billion in 2015 is net of accumulated currency translation gains of NOK 3.3 billion reclassified to the Consolidated statement of income related to the sale of interests in the Shah Deniz project, the South Caucasus Pipeline and the Trans Adriatic Pipeline AG. See note 3 Acquisitions and disposals.

CONSOLIDATED BALANCE SHEET

	At 31 December	At 30 September	At 31 December
(unaudited, in NOK billion)	2015	2015	2014

ASSETS
Property, plant and equipment	546.2	559.8	562.1
Intangible assets	83.3	76.3	85.2
Equity accounted investments	7.3	9.2	8.4
Deferred tax assets	17.8	14.5	12.9
Pension assets	11.3	6.1	8.0
Derivative financial instruments	23.8	24.9	29.9
Financial investments	20.6	19.6	19.6
Prepayments and financial receivables	8.5	7.7	5.7

Total non-current assets	718.7	718.2	731.7

Inventories	22.0	24.3	23.7
Trade and other receivables	58.8	62.7	83.3
Derivative financial instruments	4.8	3.3	5.3
Financial investments	86.5	110.1	59.2
Cash and cash equivalents	76.0	65.7	83.1

Total current assets	248.0	266.0	254.8

Total assets	966.7	984.2	986.4

EQUITY AND LIABILITIES
Shareholders' equity	354.7	357.3	380.8
Non-controlling interests	0.3	0.3	0.4

Total equity	355.1	357.7	381.2

Finance debt	264.0	264.2	205.1
Deferred tax liabilities	65.4	66.2	71.5
Pension liabilities	26.2	27.6	27.9
Provisions	109.4	120.8	117.2
Derivative financial instruments	11.3	8.8	4.5

Total non-current liabilities	476.3	487.7	426.2

Trade and other payables	82.2	84.3	100.7
Current tax payable	24.1	31.8	39.6
Finance debt	20.5	14.2	26.5
Dividends payable	6.2	5.7	5.7
Derivative financial instruments	2.3	2.8	6.6

Total current liabilities	135.3	138.8	179.0

Total liabilities	611.7	626.5	605.2

Total equity and liabilities	966.7	984.2	986.4

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(unaudited, in NOK billion)	Share capital	Additional paid-in capital	Retained earnings	Currency translation adjustments	Shareholders' equity	Non-controlling interests	Total equity

At 31 December 2013	8.0	40.3	284.5	22.7	355.5	0.5	356.0
Net income for the period			21.9		21.9	0.1	22.0
Other comprehensive income			0.9	41.6	42.5		42.5
Dividends			(39.4)		(39.4)		(39.4)
Other equity transactions		(0.1)	0.4		0.3	(0.2)	0.1

At 31 December 2014	8.0	40.2	268.4	64.3	380.8	0.4	381.2

At 31 December 2014	8.0	40.2	268.4	64.3	380.8	0.4	381.2
Net income for the period			(37.5)		(37.5)	0.2	(37.3)
Other comprehensive income¹⁾			7.3	27.4	34.7		34.7
Dividends			(23.1)		(23.1)		(23.1)
Other equity transactions		(0.1)	(0.0)		(0.1)	(0.3)	(0.4)

At 31 December 2015	8.0	40.1	215.1	91.6	354.7	0.3	355.1

CONSOLIDATED STATEMENT OF CASH FLOWS

Quarters				Full year
Q4 2015	Q3 2015	Q4 2014	(unaudited, in NOK billion)	2015	2014

(3.6)	7.9	8.0	Income before tax	4.3	109.4

33.9	19.1	36.4	Depreciation, amortisation and net impairment losses	133.8	101.4
(0.9)	7.4	7.4	Exploration expenditures written off	17.1	13.7
0.9	3.5	(5.3)	(Gains) losses on foreign currency transactions and balances	(0.4)	(3.1)
(3.0)	(0.1)	(5.8)	(Gains) losses on sales of assets and businesses	(17.3)	(12.4)
6.6	7.7	1.4	(Increase) decrease in other items related to operating activities¹⁾	19.8	3.9
1.7	(2.6)	(0.9)	(Increase) decrease in net derivative financial instruments¹⁾	9.2	(2.8)
0.7	0.7	0.4	Interest received	2.9	2.1
(1.2)	(0.7)	(0.7)	Interest paid	(3.6)	(3.4)

35.0	42.9	40.9	Cash flows provided by operating activities before taxes paid and working capital items	165.8	208.8

(19.1)	(9.4)	(30.8)	Taxes paid	(65.7)	(96.6)

2.9	8.7	17.3	(Increase) decrease in working capital¹⁾	8.9	14.2

18.8	42.2	27.3	Cash flows provided by operating activities	109.0	126.5

(3.5)	0.0	0.0	Additions through business combinations	(3.5)	0.0
(27.4)	(32.7)	(33.1)	Capital expenditures and investments	(124.7)	(122.6)
24.0	(2.5)	(14.5)	(Increase) decrease in financial investments	(19.8)	(12.7)
(1.2)	0.0	(0.0)	(Increase) decrease in other non-current items	(0.3)	0.8
6.0	3.6	11.4	Proceeds from sale of assets and businesses	33.2	22.6

(2.1)	(31.6)	(36.2)	Cash flows used in investing activities	(115.1)	(112.0)

0.1	0.0	20.5	New finance debt	32.2	20.6
(0.1)	(0.1)	(5.9)	Repayment of finance debt	(11.4)	(9.7)
(5.7)	(5.7)	(5.7)	Dividend paid	(22.9)	(33.7)
(1.9)	2.6	(2.5)	Net current finance debt and other	(5.5)	(0.3)

(7.6)	(3.2)	6.5	Cash flows provided by (used in) financing activities	(7.5)	(23.1)

9.1	7.4	(2.4)	Net increase (decrease) in cash and cash equivalents	(13.6)	(8.6)

1.2	3.3	7.0	Effect of exchange rate changes on cash and cash equivalents	7.1	5.7
65.6	54.9	77.8	Cash and cash equivalents at the beginning of the period (net of overdraft)	82.4	85.3

75.9	65.6	82.4	Cash and cash equivalents at the end of the period (net of overdraft)²⁾	75.9	82.4

¹⁾(Increase)/decrease in items under operating activities include currency effects.

²⁾At 31 December 2015 Cash and cash equivalents included a net bank overdraft of NOK 0.1 billion and at 31 December 2014 Cash and cash equivalents included a net bank overdraft of NOK 0.7 billion.

Notes to the Condensed interim financial statements

1 Organisation and basis of preparation

General information and organisation

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

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

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

Statoil's Condensed interim financial statements for the fourth quarter of 2015 were authorised for issue by the board of directors on 3 February 2016.

Basis of preparation

These Condensed interim financial statements are prepared in accordance with International Accounting Standard 34 Interim Financial Reporting as issued by the International Accounting Standards Board (IASB) and as adopted by the European Union (EU). The Condensed interim financial statements do not include all of the information and disclosures required by International Financial Reporting Standards (IFRS) for a complete set of financial statements, and these Condensed interim financial statements should be read in conjunction with the Consolidated annual financial statements. IFRS as adopted by the EU differ in certain respects from IFRS as issued by the IASB, but the differences do not impact Statoil's financial statements for the periods presented. A description of the significant accounting policies applied in preparing these Consolidated interim financial statements is included in Statoil`s Consolidated annual financial statements for 2014. There have been no changes to significant accounting policies in the four quarters of 2015 compared to the annual financial statements for 2014.

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

The Condensed interim financial statements are unaudited.

New standards and amendments to standards, issued since the third quarter of 2015 but not adopted

An amendment to IFRS 15 Revenue from Contracts with Customers was issued in September 2015, deferring the standard’s effective date by one year to 1 January 2018. Statoil has not yet determined its adoption date for the standard.

In December 2015 the IASB deferred the effective date of the previously issued amendments to IFRS 10 Consolidated Financial Statements and IAS 28 Investments in Associates and Joint Ventures to a future time to be determined by the IASB. Statoil has not yet determined its adoption date for the amendments.

IFRS 16 Leases, issued in January 2016 and effective from 1 January 2019 covers the recognition of leases and related disclosure in the financial statements, and will replace IAS 17 Leases. In the financial statement of lessees, the new standard requires recognition of all contracts that qualify under its definition of a lease as right-of-use assets and lease liabilities in the balance sheet, while lease payments are to be reflected as interest expense and reduction of lease liabilities. The right-of-use assets are to be depreciated in accordance with IAS 16 Property, Plant and Equipment over the shorter of each contract’s term and the assets’ useful life. The standard consequently implies a significant change in lessees’ accounting for leases currently defined as operating leases under IAS 17, both as regards impact on the balance sheet and the statement of income. IFRS 16 defines a lease as a contract that conveys the right to control the use of an identified asset for a period of time in exchange for consideration. While this definition is not dissimilar to that of IAS 17, it would have required further evaluation of each contract to determine whether all leases included in Statoil’s most recent financial statements, or contracts currently not defined as leases, would qualify as leases under the new standard. The standard introduces new requirements both as regards establishing the term of a lease and the related discounted cash flows that determine the amount of a lease liability to be recognised. IFRS 16 requires adoption either on a full retrospective basis, or retrospectively with the cumulative effect of initially recognising the standard as an adjustment to retained earnings at the date of initial application, and if so with a number of practical expedients in transitioning existing leases at the time of initial application. Statoil is in the early phase of evaluating the impact of IFRS 16, and has not yet determined its adoption date, its implementation method, or the expected impact of the standard on the Consolidated financial statements.

Use of estimates

The preparation of financial statements in conformity with IFRS requires management to make judgments, estimates and assumptions that affect the application of policies and reported amounts of assets and liabilities, income and expenses. The estimates and associated assumptions are based on historical experience and various other factors that are believed to be reasonable under the circumstances, the results of which form the basis for making the judgments about carrying values of assets and liabilities that are not readily apparent from other

sources. Actual results may differ from these estimates. The estimates and underlying assumptions are reviewed on an on-going basis, considering current and expected future market conditions. A change in an accounting estimate is recognised in the period in which the estimate is revised if the revision affects only that period, or in the period of the revision and future periods if the revision affects both current and future periods.

2 Segments

Statoil’s operations are managed through the following operating segments: Development and Production Norway (DPN), Development and Production USA (DPUSA), Development and Production International (DPI), Marketing, Midstream and Processing (MMP), New Energy Solutions (NES) and Other.

Statoil reports its business through reporting segments which correspond to the operating segments, except for the operating segments DPUSA and DPI which have been aggregated into one reporting segment, Development and Production International. This aggregation has its basis in similar economic characteristics, the nature of products, services and production processes, the type and class of customers and the methods of distribution. The operating segment NES is reported in the reporting segment Other.

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

Segment data for the fourth quarter and the full year of 2015 and 2014 is presented below. The reported measure of segment profit is Net operating income. Deferred tax assets, pension assets and non-current financial assets are not allocated to the segments. The line item Additions to PP&E, intangibles and equity accounted investments excludes movements related to changes in asset retirement obligations.

Fourth quarter 2015	Development and Production Norway	Development and Production International	Marketing, Midstream and Processing	Other	Eliminations	Total
(in NOK billion)	Development and Production Norway	Development and Production International	Marketing, Midstream and Processing	Other	Eliminations	Total

Revenues third party and other income	1.3	(1.0)	111.4	0.6	-	112.4
Revenues inter-segment	33.6	11.7	0.3	0.0	(45.6)	(0.0)
Net income from equity accounted investments	0.0	(0.4)	0.0	0.1	-	(0.3)

Total revenues and other income	34.8	10.3	111.8	0.7	(45.6)	112.1

Net operating income	14.5	(17.3)	4.2	(0.5)	0.8	1.7

Significant non-cash items recognised
- Depreciation and amortisation	11.2	10.9	0.8	0.3	-	23.4
- Net impairment losses (reversals)	3.0	7.5	(0.0)	0.0	-	10.5
- Provisions	-	2.8	-	-	-	2.8
- Exploration expenditures written off (reversals)	0.1	(1.0)	0.0	0.0	-	(0.9)

Additions to PP&E, intangibles and equity accounted investments	11.8	16.6	2.5	0.4	-	31.3

Fourth quarter 2014	Development and Production Norway	Development and Production International	Marketing, Midstream and Processing	Other	Eliminations	Total
(in NOK billion)	Development and Production Norway	Development and Production International	Marketing, Midstream and Processing	Other	Eliminations	Total

Revenues third party and other income	6.4	2.6	144.3	(0.2)	-	153.1
Revenues inter-segment	43.9	14.4	0.4	0.0	(58.8)	0.0
Net income from equity accounted investments	0.0	(0.7)	0.1	0.0	-	(0.5)

Total revenues and other income	50.3	16.3	144.9	(0.1)	(58.8)	152.6

Net operating income	29.5	(24.7)	2.8	0.5	0.9	9.0

Significant non-cash items recognised
- Depreciation and amortisation	11.3	10.0	0.6	0.2	-	22.2
- Change in pension plan (gain)	(2.3)	(0.1)	(0.7)	(0.4)	-	(3.5)
- Net impairment losses (reversals)	2.3	12.3	(0.4)	0.0	-	14.2
- Unrealised (gain) loss on commodity derivatives	0.4	0.0	(2.8)	0.0	-	(2.4)
- Exploration expenditures written off	0.4	7.0	0.0	0.0	-	7.4

Additions to PP&E, intangibles and equity accounted investments	12.0	17.2	2.4	0.1	-	31.7

Full year 2015	Development and Production Norway	Development and Production International	Marketing, Midstream and Processing	Other	Eliminations	Total
(in NOK billion)	Development and Production Norway	Development and Production International	Marketing, Midstream and Processing	Other	Eliminations	Total

Revenues third party and other income	(0.9)	15.3	465.5	3.1	-	483.1
Revenues inter-segment	140.4	53.9	1.5	0.0	(195.7)	(0.0)
Net income from equity accounted investments	0.0	(0.8)	0.4	0.0	-	(0.3)

Total revenues and other income	139.5	68.4	467.4	3.2	(195.7)	482.8

Net operating income	57.6	(66.9)	23.7	(0.8)	1.2	14.9

Significant non-cash items recognised
- Depreciation and amortisation	42.7	38.9	3.1	1.1	-	85.9
- Net impairment losses (reversals)	8.7	42.7	(3.5)	0.0	-	47.9
- Provisions	0.0	6.1	0.0	0.0	-	6.1
- Unrealised (gain) loss on earn-out agreements	2.6	0.0	0.0	0.0	-	2.6
- Exploration expenditures written off	0.5	16.6	0.0	0.0	-	17.1

Equity accounted investments	0.0	2.9	1.9	2.4	-	7.3
Non-current segment assets	244.1	330.1	49.2	6.1	-	629.5
Non-current assets, not allocated to segments						82.0

Total non-current assets						718.7

Additions to PP&E, intangibles and equity accounted investments	50.6	65.4	7.3	2.2	-	125.5

Full year 2014	Development and Production Norway	Development and Production International	Marketing, Midstream and Processing	Other	Eliminations	Total
(in NOK billion)	Development and Production Norway	Development and Production International	Marketing, Midstream and Processing	Other	Eliminations	Total

Revenues third party and other income	9.0	18.6	595.0	0.4	-	622.9
Revenues inter-segment	173.2	67.3	1.8	0.0	(242.3)	(0.0)
Net income from equity accounted investments	0.1	(0.8)	0.5	(0.0)	-	(0.3)

Total revenues and other income	182.2	85.2	597.3	0.3	(242.3)	622.7

Net operating income	111.7	(19.5)	16.2	(1.5)	2.6	109.5

Significant non-cash items recognised
- Depreciation and amortisation	37.7	33.0	2.8	1.0	-	74.5
- Change in pension plan (gain)	(2.3)	(0.1)	(0.7)	(0.4)	-	(3.5)
- Net impairment losses (reversals)	2.3	23.8	0.8	0.0	-	26.9
- Unrealised (gain) loss on commodity derivatives	0.6	0.0	(3.1)	0.0	-	(2.5)
- Exploration expenditures written off	0.8	12.9	0.0	0.0	-	13.7

Equity accounted investments	0.2	4.8	3.2	0.2	-	8.4
Non-current segment assets	262.0	333.8	46.3	5.1	-	647.3
Non-current assets, not allocated to segments						76.0

Total non-current assets						731.7

Additions to PP&E, intangibles and equity accounted investments	55.1	61.4	7.8	0.8	-	125.1

In the fourth quarter of 2015, the DPI segment recognised a reduction of Revenues of NOK 2.8 billion following an arbitration ruling in a redetermination process for the Agbami asset in Nigeria. In addition NOK 3.3 billion was recognised in the third quarter of 2015. See also note 7 Provisions, commitments, contingent liabilities and contingent assets.

In the fourth quarter of 2015, Statoil recognised net impairment charges of NOK 10.1 billion, which includes an impairment of NOK 0.7 billion related to an equity accounted entity. The net impairment charges consist of impairments of NOK 15.2 billion and reversal of impairments of NOK 5.1 billion. Impairments of NOK 11.7 billion relates to the DPI segment and NOK 3.5 billion to the DPN segment and were mainly driven by reduction in oil and gas forward prices. The reversal of impairments of NOK 5.1billion relates mainly to the DPI segment and was driven by operational improvements, in particular for unconventional onshore assets in North America.

In the third quarter of 2015, Statoil recognised net impairment charges of NOK 4.8 billion. The DPI segment recognised net impairment charges of NOK 6.8 billion mainly related to unconventional onshore assets in North America. The DPN segment recognised impairment charges of NOK 1.8 billion related to assets under development. The MMP segment recognised a net impairment reversal of NOK 3.9 billion mainly related to a refinery.

In the second quarter of 2015 Statoil recognised net impairment charges of NOK 3.1 billion. NOK 2.8 billion of these were recognised on an offshore asset in the DPN segment and NOK 3.1 billion in the DPI segment, mostly related to an asset in the Gulf of Mexico. In addition, DPI recognised a reversal of impairment of NOK 3.2 billion for an unconventional onshore asset in North America.

In the first quarter of 2015 Statoil recognised net impairment charges of NOK 46.1 billion, of which NOK 1.1 billion was recognised in the DPN segment and NOK 45.0 billion in the DPI segment. Of the impairment charges in the DPI segment, NOK 30.4 billion, including goodwill of NOK 4.2 billion, were related to unconventional onshore assets in North America. Of the remaining NOK 14.6 billion, relating to conventional upstream assets, NOK 11.2 billion related to assets in the Gulf of Mexico.

See also note 6 Property, plant and equipment and intangible assets for further details on impairments.

The segment data for the fourth quarter and the full year of 2015 for all segments was influenced by transactions described in note 3 Acquistions and disposals.

Revenues by geographic areas

When attributing the line item Revenues third party and other income to the country of the legal entity executing the sale for the full year of 2015, Norway constitutes 76% and the US constitutes 13%.

Non-current assets by country

	At 31 December	At 30 September	At 31 December
(in NOK billion)	2015	2015	2014

Norway	277.4	292.3	289.6
US	180.9	170.1	182.9
Angola	47.1	48.9	51.3
Brazil	30.6	31.6	29.5
UK	25.4	23.3	19.7
Canada	20.0	20.1	17.6
Algeria	12.6	13.3	11.8
Azerbaijan	12.5	13.6	23.6
Other countries	30.3	31.9	29.5

Total non-current assets¹⁾	636.7	645.3	655.6

¹⁾ Excluding deferred tax assets, pension assets and non-current financial assets.

3 Acquisitions and disposals

Transactions in the fourth quarter of 2015

Sale of interests in Gudrun field and acquisition of interests in Eagle Ford

In the fourth quarter of 2015 Statoil closed the agreement with Repsol to sell a 15% interest in the Gudrun field on the Norwegian continental shelf. Statoil remains the operator and largest equity holder with a 36% interest. Statoil recognised a total gain of NOK 1.2 billion in the Development and Production Norway (DPN) segment. The gain was presented in the line item Other income in the Consolidated statement of income. The transaction was tax exempt under the Norwegian petroleum tax legislation. Proceeds from the sale were NOK 1.9 billion.

Simultaneously Statoil closed the agreement to acquire an additional 13% interest in the Eagle Ford formation with the same party. The total interest in the Eagle Ford shale play after the acquisition is 63% and Statoil also became the sole operator. The acquisition was accounted for as a business combination using the acquisition method. The acquisition and valuation date for the purchase price allocation was 30 December 2015. The fair value of net identifiable assets was NOK 3.5 billion. The acquisition was recognised in the Development and Production International (DPI) and Marketing, Midstream and Processing (MMP) reporting segments with the fair value of net identifiable assets NOK 2.4 billion and NOK 1.1 billion, respectively. The total purchase price of the business combination was NOK 3.5 billion. No goodwill was recognised.

Sale of interests in Trans Adriatic Pipeline AG

In the fourth quarter of 2015 Statoil closed the agreement with Italian gas structure company Snam SpA, entered into in December 2015, to sell its 20.0% interest in Trans Adriatic Pipeline AG. A gain of NOK 1.4 billion was recognised in the MMP segment. The gain was tax exempt and presented in the line item Other income in the Consolidated statement of income. Total proceeds from the sale were NOK 2.0 billion.

Sale of office buildings

In the fourth quarter of 2015 Statoil closed a sales transaction with TRD Campus AS, for sale of the company’s office buildings in Trondheim and Stjørdal through the sale of shares in the Strandveien 4 AS and Arkitekt Ebbelsvei 10 AS. At the same time Statoil entered into 15 year operating lease agreements for the buildings. A gain of NOK 0.6 billion was recognised in the Other segment. The gain was presented in the line item Other income in the Consolidated statement of income. Proceeds from the sale were NOK 1.7 billion.

Transactions in previous quarters 2015

Sale of interests in the Shah Deniz project and the South Caucasus Pipeline

In the second quarter of 2015 Statoil closed an agreement with Petronas, entered into in October 2014, to sell its remaining 15.5% interest in the Shah Deniz project and the South Caucasus Pipeline. Statoil recognised a total gain of NOK 12.4 billion. The gain was presented in the line item Other income in the Consolidated statement of income. In the segment reporting, the gain was recognised in the DPI and the MMP segments, with NOK 12.3 billion and NOK 0.1 billion, respectively. Total proceeds from the sale were NOK 20.3 billion.

Sale of head office building

In the second quarter of 2015 Statoil closed a sales transaction for the sale of the company’s head office building in Stavanger through the sale of shares in the company Forusbeen 50 AS. At the same time, Statoil entered into a 15 year operating lease agreement for the building. A gain of NOK 1.5 billion was recognised in the Other segment. The gain was presented in the line item Other income in the Consolidated statement of income. Proceeds from the sale were NOK 2.3 billion.

Sale of interests in the Marcellus onshore play

In the first quarter of 2015 the transaction between Statoil and Southwestern Energy, reducing Statoil’s average working interest in the non-operated southern Marcellus onshore play from 29% to 23%, for which the agreement had been entered into in the fourth quarter of 2014, was closed. The transaction was recognised in the DPI segment with no impact on the Consolidated statement of income. Proceeds from the sale were NOK 2.8 billion.

4 Financial items

Quarters				Full year
Q4 2015	Q3 2015	Q4 2014	(in NOK billion)	2015	2014

(2.1)	(0.7)	(2.8)	Net foreign exchange gains (losses)	(2.1)	(2.2)
1.2	0.2	1.3	Interest income and other financial items	3.2	4.0
(2.3)	3.1	2.2	Gains (losses) derivative financial instruments	(3.8)	5.8
(2.1)	(1.9)	(1.7)	Interest and other finance expenses	(7.8)	(7.6)

(5.3)	0.7	(1.0)	Net financial items	(10.6)	(0.0)

During the year 2015 Statoil issued bonds with maturities from 4 to 20 years for a total amount of NOK 32.1 billion. The bonds were issued in EUR and swapped into USD. All of the bonds are unconditionally guaranteed by Statoil Petroleum AS.

Statoil has available a US Commercial paper programme with limit of USD 4.0 billion. At 31 December 2015 there are no outstanding amounts on the US Commercial paper programme.

5 Income tax

Quarters				Full year
Q4 2015	Q3 2015	Q4 2014	(in NOK billion)	2015	2014

(3.6)	7.9	8.0	Income before tax	4.3	109.4
(5.5)	(10.7)	(16.9)	Income tax	(41.6)	(87.4)
(152.5 %)	135.3 %	210.3 %	Equivalent to a tax rate of	969.3 %	79.9 %

The tax rate for the fourth quarter of 2015 and the full year 2015, was primarily influenced by impairments and provisions recognised in countries with lower than average tax rates or unrecognised deferred tax assets. This was partially offset by tax effect of foreign exchange losses in entities that are taxable in other currencies than the functional currency. The tax rate for the full year of 2015 was also influenced by write off of deferred tax assets within Development and Production International segment, due to uncertainty related to future taxable income and the tax exempt sale of interests in the Shah Deniz project as described in note 3 Acquisitions and disposals.

The tax rate for the fourth quarter of 2014, and for the full year 2014, was primarily influenced by impairments with lower than average tax rates, partially offset by a tax exempt gain on the Norwegian Continental Shelf as described in note 3 Acquisitions and disposals. The tax rate was also influenced by tax effect of foreign exchange losses in entities that are taxable in other currencies than the functional currency. For the full year 2014 the tax rate was also influenced by the tax exempted sale of interests in the Shah Deniz Project and the recognition of a non-cash tax income following a verdict in the Norwegian Supreme Court in February 2014. The Supreme Court voted in favour of Statoil in a tax dispute regarding the tax treatment of foreign exploration expenditures.

6 Property, plant and equipment and intangible assets

(in NOK billion)	Property, plant and equipment	Intangible assets

Balance at 31 December 2014	562.1	85.2
Additions	92.8	13.8
Transfers	2.7	(2.7)
Disposals and reclassifications ¹⁾	(23.4)	(3.0)
Expensed exploration expenditures and impairment losses	-	(17.1)
Depreciation, amortisation and net impairment losses	(129.6)	(4.2)
Effect of foreign currency translation adjustments	41.7	11.3

Balance at 31 December 2015	546.2	83.3

¹⁾ Includes NOK 5.8 billion related to a change in the classification of Statoil’s investment in the Sheringham Shoal Windfarm (Scira Offshore Energy Ltd) from joint operation (pro-rata line by line consolidation) to joint venture (equity method) following changes in the joint operating agreements.

Impairments

In the fourth quarter of 2015, Statoil recognised net impairments of NOK 10.1 billion mainly related to producing and development assets as a result of reduced oil and gas forward prices. Included in the net impairment amount are NOK 0.7 billion related to an equity accounted entity and NOK 0.4 billion of acquisition costs related to oil and gas prospects. The net impairment on producing and development assets includes undeveloped properties related to unconventional onshore assets in North America which are classified as Intangible assets. Recognised impairment charges related to undeveloped properties are classified as Exploration expenses in the Consolidated statement of income. The full year of 2015 is negatively impacted by net impairment charges of NOK 63.3 billion of which NOK 46.1 billion was recognised in the first quarter of 2015 triggered by reduced price forecast. Due to the uncertainty in the commodity markets which is assumed to impact oil and gas prices in the long term, Statoil’s management decided in the first quarter of 2015 to change Statoil’s long-term economic planning assumptions. In the impairment calculations, Statoil generally use observed forward oil and gas price curves for the first two to three years and the long-term economic planning assumptions for the periods thereafter.

In the third quarter of 2015 Statoil recognised impairment charges of net NOK 4.8 billion, mainly related to oil and gas prospects.

In the second quarter of 2015 Statoil recognised impairment charges of net NOK 3.1 billion triggered by various operational issues.

7 Provisions, commitments, contingent liabilities and contingent assets

Statoil’s estimated asset retirement obligations (ARO) have reduced by NOK 13.8 billion during 2015, mainly due to a reduction in cost estimates for plugging and abandonment updated in the fourth quarter of 2015. Changes in ARO are reflected within Property, plant and equipment and Provisions in the Consolidated balance sheet.

Through its ownership in OML 128 in Nigeria, Statoil is party to an ownership interest redetermination process for the Agbami field. In October 2015, Statoil received the Expert’s final ruling which implies a reduction of 5.17% in Statoil’s equity interest in the field. Statoil had previously initiated arbitration proceedings to set aside interim decisions made by the Expert, but this was declined by the arbitration tribunal in its November 2015 judgment. Statoil will initiate proceedings before the Federal High Court in Lagos to set aside the arbitration award and also intends to initiate a new arbitration to set aside the Expert’s final ruling. As of 31 December 2015, Statoil has a provision of NOK 9.5 billion, net of tax, which reflects a reduction of 5.17% in Statoil’s equity interest in the Agbami field. This provision is increased by NOK 4.6 billion
(NOK 6.1 billion before tax) in the second half of 2015, which is reflected within Provisions in the Consolidated balance sheet. See also note 2 Segments.

At the end of the fourth quarter of 2015 Statoil`s exposure related to on-going long-term gas sales price review arbitration cases was approximately NOK 3.6 billion for gas delivered prior to quarter end. Statoil has provided for its best estimate related to price review arbitration cases in these Condensed interim financial statements, with the impact to the Consolidated statement of income reflected as revenue adjustments.

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

8 Subsequent events

In the first quarter of 2016 Statoil acquired 11.93% of the shares and votes in Lundin Petroleum AS for a total purchase price of SEK 4.6 billion. The shares will be accounted for as a non-current financial investment (available-for-sale) at fair value.

The Board of Directors will propose to the Annual general meeting to maintain a dividend of USD 0.2201 per share fourth quarter 2015 and the introduction of a two-year scrip dividend programme starting from the fourth quarter 2015. The scrip programme will give shareholders the option to receive quarterly dividends in cash or in newly issued shares in Statoil, at a 5% discount for the fourth quarter 2015.

Supplementary disclosures

OPERATIONAL DATA

Quarters			Change		Full year
Q4 2015	Q3 2015	Q4 2014	Q4 on Q4	Operational data	2015	2014	Change

				Prices
43.8	50.5	76.6	(43%)	Average Brent oil price (USD/bbl)	55.3	98.9	(44%)
40.7	45.5	68.5	(41%)	DPN average liquids price (USD/bbl)	48.2	90.6	(47%)
35.5	40.8	64.3	(45%)	DPI average liquids price (USD/bbl)	42.9	85.5	(50%)
38.4	43.5	66.9	(43%)	Group average liquids price (USD/bbl)	45.9	88.6	(48%)
327.7	357.5	458.9	(29%)	Group average liquids price (NOK/bbl) [1]	370.7	558.4	(34%)
1.54	1.56	1.70	(9%)	Transfer price natural gas (NOK/scm) [9]	1.58	1.57	1%
2.00	2.17	2.36	(15%)	Average invoiced gas prices - Europe (NOK/scm) [8]	2.16	2.28	(5%)
0.64	0.61	0.93	(31%)	Average invoiced gas prices - North America (NOK/scm) [8]	0.79	1.04	(24%)
5.7	9.5	5.7	1%	Refining reference margin (USD/bbl) [2]	8.0	4.7	71%

				Entitlement production (mboe per day)
610	580	619	(1%)	DPN entitlement liquids production	595	588	1%
463	419	426	9%	DPI entitlement liquids production	436	383	14%
1,073	998	1,045	3%	Group entitlement liquids production	1,032	971	6%
699	594	712	(2%)	DPN entitlement gas production	637	595	7%
149	148	175	(15%)	DPI entitlement gas production	144	163	(11%)
848	743	886	(4%)	Group entitlement gas production	781	758	3%
1,921	1,741	1,932	(1%)	Total entitlement liquids and gas production [3]	1,812	1,729	5%

				Equity production (mboe per day)
610	580	619	(1%)	DPN equity liquids production	595	588	1%
569	572	560	2%	DPI equity liquids production	569	538	6%
1,179	1,152	1,179	0%	Group equity liquids production	1,165	1,127	3%
699	594	712	(2%)	DPN equity gas production	637	595	7%
168	163	213	(21%)	DPI equity gas production	170	205	(17%)
867	757	925	(6%)	Group equity gas production	806	801	1%
2,046	1,909	2,103	(3%)	Total equity liquids and gas production [4]	1,971	1,927	2%

				MMP sales volumes
209.0	208.0	213.0	(2%)	Crude oil sales volumes (mmbl)	829.0	811.0	2%
11.9	10.5	12.6	(6%)	Natural gas sales Statoil entitlement (bcm)	44.0	43.1	2%
1.7	1.7	2.1	(18%)	Natural gas sales third-party volumes (bcm)	8.6	8.1	6%

				Production cost per boe (last 12 months)
52		55	(5%)	Production cost entitlement volumes (NOK/boe)	52	55	(5%)
48		49	(3%)	Production cost equity volumes (NOK/boe)	48	49	(3%)
6.4		8.7	(26%)	Production cost entitlement volumes (USD/boe)	6.4	8.7	(26%)
5.9		7.8	(24%)	Production cost equity volumes (USD/boe)	5.9	7.8	(24%)

EXCHANGE RATES

Quarters			Change		Full year
Q4 2015	Q3 2015	Q4 2014	Q4 on Q4	Exchange rates	2015	2014	Change

8.53	8.22	6.86	24%	USDNOK average daily exchange rate	8.07	6.30	28%
8.81	8.50	7.43	19%	USDNOK period-end exchange rate	8.81	7.43	19%
9.34	9.14	8.58	9%	EURNOK average daily exchange rate	8.95	8.35	7%
9.62	9.52	9.04	6%	EURNOK period-end exchange rate	9.62	9.04	6%

EXPLORATION EXPENSES

Quarters			Change	Exploration expenses	Full year
Q4 2015	Q3 2015	Q4 2014	Q4 on Q4	(in NOK billion)	2015	2014	Change

1.2	1.4	2.2	(48%)	DPN exploration expenditures (activity)	6.4	7.0	(10%)
5.5	3.6	7.8	(30%)	DPI exploration expenditures (activity)	16.7	16.8	(1%)

6.6	5.0	10.1	(35%)	Group exploration expenditures (activity)	23.1	23.9	(3%)
0.2	0.9	1.4	(86%)	Expensed, previously capitalised exploration expenditure	1.7	2.4	(28%)
(1.6)	(2.6)	(2.0)	(19%)	Capitalised share of current period's exploration activity	(9.2)	(7.3)	27%
(1.1)	6.5	6.0	>(100%)	Impairment (reversal of impairment)	15.4	11.3	36%

4.1	9.9	15.5	(74%)	Exploration expenses IFRS	31.0	30.3	2%

HEALTH, SAFETY AND THE ENVIRONMENT (HSE)

Quarters				Full year
Q4 2015	Q3 2015	Q4 2014	HSE	2015	2014

2.5	2.7	2.7	Total recordable injury frequency	2.7	3.0
0.9	0.6	0.6	Serious incident frequency (SIF)	0.6	0.6
27	33	36	Accidental oil spills	170	213
11	8	71	Accidental oil spills (cubic metres)	23	125

USE AND RECONCILIATION OF NON-GAAP FINANCIAL MEASURES

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

For more information on our use of non-GAAP financial measures, see report section - Financial analysis and review - Non-GAAP measures in Statoil's 2014 Annual Report on Form 20-F.

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

· Return on average capital employed after tax (ROACE)

· Production cost per boe

· Net interest-bearing liabilities adjusted

· Net debt to capital employed ratio

· Net debt to capital employed ratio adjusted

· Organic capital expenditures

Calculation of numerator and denominator used in ROACE calculation	31 December
(in NOK billion, except percentages)	2015	2014

Net Income (last 12 months)	(37.3)	22.0
- Net Financial Items (last 12 months)	(10.6)	0.0
- Tax on Financial Items (last 12 months)	10.2	9.2
+ Accretion Expense after Tax	(1.0)	(1.1)

Net Income adjusted for Financial Items after Tax (A1)	(38.0)	11.8

Calculated Average Capital Employed:
Average Capital Employed (B1)	473.7	442.2

Calculated RoACE:
Calculated RoACE based on Average Capital Employed (A1/B1)	-8.0%	2.7%

Production cost per barrel is based on operating expenses related to production of oil and gas. Statoil uses production cost per barrel because it allows Statoil to evaluate the underlying development in product costs. The following is a reconciliation of overall operating expenses to operating expenses exclusively related to production of oil and gas volumes:

	For the three months ended
Reconciliation of overall operating expenses to production cost	2015		2014				2013
(in NOK billion)	31 December	30 September	30 June	31 March	31 December	30 September	30 June	31 March

Operating expenses in Statoil group	19.2	21.4	21.2	22.7	15.2	19.3	19.3	19.0

Operating expenses in business areas non-upstream	9.4	8.1	8.8	8.9	5.7	7.5	7.1	7.7

Total operating expenses upstream	9.7	13.4	12.4	13.9	9.5	11.8	12.2	11.3

Operation over-/underlift¹⁾	(1.3)	1.4	0.6	1.1	(1.2)	0.0	0.3	(0.0)
Transportation pipeline/vessel upstream²⁾	2.1	2.1	1.7	1.9	2.0	1.7	1.9	1.9
Miscellaneous items³⁾	1.3	1.4	1.4	1.7	(0.6)	1.8	1.4	1.0

Total operating expenses upstream for cost per barrel calculation	7.6	8.4	8.7	9.2	9.2	8.3	8.6	8.4

Injection gas purchase	0.1	0.2	0.1	0.2	0.2	0.0	0.0	0.0

Total operating expenses upstream excl. Injection gas purchase	7.6	8.2	8.5	9.0	9.1	8.2	8.5	8.2

Entitlement production used in the cost per barrel calculation (mboe/d)	1,921	1,741	1,709	1,878	1,932	1,626	1,588	1,770
Equity production used in the cost per barrel calculation (mboe/d)	2,046	1,909	1,873	2,056	2,103	1,829	1,799	1,978

1) Exclusion of the effect from the over-/underlift position in the period. Reference is made to End note 5.

2) Transportation costs are excluded from the unit of production cost calculation.

3) Consists of royalty payments, removal/abandonment estimates and reversal of provision related to the discontinued part of the early retirement pension.

	Entitlement production		Equity production
Production cost (average last 4 quarters) [10]	31 December		31 December
	2015	2014	2015	2014

Production cost per boe in NOK	52	55	48	49
Production cost excluding injection gas per boe in NOK	-	-	47	48

Production cost per boe in USD	6.4	8.7	5.9	7.8
Production cost excluding injection gas per boe in USD	-	-	5.8	7.7

Calculation of capital employed and net debt to capital employed ratio		At 31 December	At 30 September	At 31 December
(in NOK billion)		2015	2015	2014

Shareholders' equity		354.7	357.3	380.8
Non-controlling interests		0.3	0.3	0.4

Total equity	A	355.1	357.7	381.2

Current finance debt		20.5	14.2	26.5
Non-current finance debt		264.0	264.2	205.1

Gross interest-bearing debt	B	284.5	278.4	231.6

Cash and cash equivalents		76.0	65.7	83.1
Current financial investments		86.5	110.1	59.2

Cash and cash equivalents and financial investment	C	162.4	175.7	142.3

Net interest-bearing debt before adjustments [11]	B1 = B-C	122.0	102.7	89.2

Other interest-bearing elements¹⁾		9.8	9.6	8.0
Marketing instruction adjustment²⁾		(1.9)	(1.9)	(1.6)
Adjustment for project loan³⁾		0.0	(0.1)	(0.1)

Net interest-bearing debt adjusted	B2	129.9	110.4	95.6

Normalisation for cash-build up before tax payment (50% of Tax Payment)⁴⁾		0.0	4.7	0.0

Net interest-bearing debt adjusted	B3	129.9	115.1	95.6

Calculation of capital employed:
Capital employed before adjustments to net interest-bearing debt	A+B1	477.1	460.3	470.4
Capital employed before normalisation for cash build up for tax payment	A+B2	485.0	468.1	476.7
Capital employed adjusted	A+B3	485.0	472.7	476.7

Calculated net debt to capital employed:
Net debt to capital employed before adjustments	(B1) / (A+B1)	25.6%	22.3%	19.0%
Net debt to capital employed before normalisation for tax payment	(B2) / (A+B2)	26.8%	23.6%	20.0%
Net debt to capital employed adjusted	(B3) / (A+B3)	26.8%	24.3%	20.0%

¹⁾Cash and cash equivalents adjustments regarding collateral deposits classified as cash and cash equivalents in the Consolidated balance sheet but considered as non-cash in the non-GAAP calculations as well as financial investments in Statoil Forsikring AS classified as current financial investments.

²⁾Adjustment to gross interest-bearing debt due to the Norwegian state`s financial interest (SDFI) part of the financial lease in the Snøhvit vessels which are included in Statoil’s Consolidated balance sheet.

³⁾Adjustment to gross interest-bearing debt due to the Baku-Tbilisi-Ceyhan project loan structure.

⁴⁾Normalisation for cash-build-up before tax payment adjusts to exclude 50% of the cash-build-up related to tax payments due in the beginning of February, April, August, October and December, which were NOK 9.3 billion and NOK 13.8 billion as of September 2015 and 2014, respectively.

CONDENSED FINANCIAL INFORMATION FOR STATOIL GROUP IN USD

Statoil will from Q1 2016 present the Statement in USD. Figures for Q4 2015 in USD is enclosed below.

CONSOLIDATED STATEMENT OF INCOME
	Quarter	Full year
(unaudited, in USD million)	Q4 2015	2015

Total revenues and other income	13,093	59,642

Purchases [net of inventory variation]	(5,974)	(26,254)
Operating expenses	(2,246)	(10,512)
Selling, general and administrative expenses	(270)	(921)
Depreciation, amortisation and net impairment losses	(3,972)	(16,715)
Exploration expenses	(480)	(3,872)

Net operating income	152	1,366

Net income	(1,122)	(5,169)

Basic earnings per share (in USD)	(0.35)	(1.63)
Diluted earnings per share (in USD)	(0.35)	(1.63)
Weighted average number of ordinary shares outstanding (in millions)	3,178.1	3,179.4

CONSOLIDATED BALANCE SHEET
	At 31 December
(unaudited, in USD million)	2015

ASSETS
Total non-current assets	81,588
Total current assets	28,154

Total assets	109,742

EQUITY AND LIABILITIES
Total equity	(40,307)
Total non-current liabilities	(54,073)
Total current liabilities	(15,363)

Total equity and liabilities	(109,743)

CONSOLIDATED STATEMENT OF CASH FLOWS
	Quarter	Full year
(unaudited, in USD million)	Q4 2015	2015

Income before tax	(473)	55

Cash flows provided by operating activities	2,218	13,628
Cash flows used in investing activities	(248)	(14,501)
Cash flows provided by (used in) financing activities	(885)	(729)

Net increase (decrease) in cash and cash equivalents	1,086	(1,602)

NET OPERATING INCOME - GROUP AND SEGMENTS
	GROUP		DPN		DPI		MMP
	Quarter	Full year	Quarter	Full year	Quarter	Full year	Quarter	Full year
(unaudited, in USD million)	Q4 2015	2015	Q4 2015	2015	Q4 2015	2015	Q4 2015	2015

Total revenues and other income	13,093	59,642	4,087	17,339	1,209	8,200	13,091	58,107

Purchases [net of inventory variation]	(5,974)	(26,254)	(0)	(0)	(8)	(10)	(11,362)	(50,547)
Operating and administrative expenses	(2,516)	(11,433)	(600)	(3,223)	(702)	(3,391)	(1,157)	(4,664)
Depreciation, amortisation and net impairment losses	(3,972)	(16,715)	(1,666)	(6,379)	(2,168)	(10,231)	(98)	37
Exploration expenses	(480)	(3,872)	(117)	(576)	(363)	(3,296)	(0)	(0)

Net operating income	152	1,366	1,704	7,161	(2,031)	(8,729)	474	2,932

FORWARD-LOOKING STATEMENTS

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

These forward-looking statements reflect current views about future events and are, by their nature, subject to significant risks and uncertainties because they relate to events and depend on circumstances that will occur in the future. There are a number of factors that could cause actual results and developments to differ materially from those expressed or implied by these forward-looking statements, including levels of industry product supply, demand and pricing; price and availability of alternative fuels; currency exchange rate and interest rate fluctuations; the political and economic policies of Norway and other oil-producing countries; EU directives; general economic conditions; political and social stability and economic growth in relevant areas of the world; the sovereign debt situation in Europe; global political events and actions, including war, terrorism and sanctions; security breaches; situation in Ukraine; changes or uncertainty in or non-compliance with laws and governmental regulations; the timing of bringing new fields on stream; an inability to exploit growth or investment opportunities; material differences from reserves estimates; unsuccessful drilling; an inability to find and develop reserves; ineffectiveness of crisis management systems; adverse changes in tax regimes; the development and use of new technology; geological or technical difficulties; operational problems; operator error; inadequate insurance coverage; the lack of necessary transportation infrastructure when a field is in a remote location and other transportation problems; the actions of competitors; the actions of field partners; the actions of governments (including the Norwegian state as majority shareholder); counterparty defaults; natural disasters and adverse weather conditions, climate change, and other changes to business conditions; an inability to attract and retain personnel; relevant governmental approvals; industrial actions by workers and other factors discussed elsewhere in this report. Additional information, including information on factors that may affect Statoil's business, is contained in Statoil's Annual Report on Form 20-F for the year ended December 31, 2014, filed with the U.S. Securities and Exchange Commission, which can be found on Statoil's website at www.statoil.com.

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

END NOTES

1. The Group's average liquids price is a volume-weighted average of the segment prices of crude oil, condensate and natural gas liquids (NGL).

2. The refining reference margin is a typical average gross margin of our two refineries, Mongstad and Kalundborg. The reference margin will differ from the actual margin, due to variations in type of crude and other feedstock, throughput, product yields, freight cost, inventory, etc.

3. Liquids volumes include oil, condensate and NGL, exclusive of royalty oil.

4. Equity volumes represent produced volumes under a Production Sharing Agreement (PSA) that correspond to Statoil's ownership percentage in a particular field. Entitlement volumes, on the other hand, represent Statoil's share of the volumes distributed to the partners in the field, which are subject to deductions for, among other things, royalty and the host government's share of profit oil. Under the terms of a PSA, the amount of profit oil deducted from equity volumes will normally increase with the cumulative return on investment to the partners and/or production from the license. As a consequence, the gap between entitlement and equity volumes will likely increase in times of high liquids prices. The distinction between equity and entitlement is relevant to most PSA regimes, whereas it is not applicable in most concessionary regimes such as those in Norway, the UK, the US, Canada and Brazil.

5. These are non-GAAP figures. See report section "Use and reconciliation of non-GAAP financial measures" for details.

6. Transactions with the Norwegian State. The Norwegian State, represented by the Ministry of Petroleum and Energy (MPE), is the majority shareholder of Statoil and also holds major investments in other entities. This ownership structure means that Statoil participates in transactions with many parties that are under a common ownership structure and therefore meet the definition of a related party. Statoil purchases liquids and natural gas from the Norwegian State, represented by SDFI (the State's Direct Financial Interest). In addition, Statoil is selling the State's natural gas production in its own name, but for the Norwegian State's account and risk as well as related expenditures refunded by the State. All transactions are considered to be at an arms-length basis. The Group's average invoiced gas price includes volumes sold by the Marketing, Midstream and Processing.

7. The production guidance reflects our estimates of proved reserves calculated in accordance with US Securities and Exchange Commission (SEC) guidelines and additional production from other reserves not included in proved reserves estimates.

8. The Group's average invoiced gas prices include volumes sold by the Marketing, Midstream and Processing (MMP) segment.

9. The internal transfer price paid from MMP to DPN.

10. The production cost per boe is calculated as total operating expenses upstream for the last four quarters divided by the production volumes for the corresponding period. Production cost per BOE in USD is calculated using the average USD/NOK exchange rate for the last 4 quarters. The development in unit production cost is impacted by the USD/NOK exchange rate development. Production costs for Statoil’s international upstream activities are mainly exposed to USD, while the production costs for Statoil’s activities in Norway are exposed to NOK.

11. Since different legal entities in the group lend to projects and others borrow from banks, project financing through external bank or similar institutions will not be netted in the balance sheet and will over-report the debt stated in the balance sheet compared to the underlying exposure in the Group. Similarly, certain net interest-bearing debt incurred from activities pursuant to the Marketing Instruction of the Norwegian government are off-set against receivables on the Norwegian state`s financial interest (SDFI).Some interest-bearing elements are classified together with non-interest bearing elements, and are therefore included when calculating the net interest-bearing debt.

Signatures

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

STATOIL ASA

(Registrant)

Dated: February 4, 2016

By: ___/s/ Hans Jakob Hegge

Name: Hans Jakob Hegge

Title: Chief Financial Officer