Equinor — Annual Report 2014

Mar 19, 2015

2014 Statutory report

in accordance with Norwegian authority requirements

© Statoil 2015 STATOIL ASA BOX 8500 NO-4035 STAVANGER NORWAY TELEPHONE: +47 51 99 00 00

www.statoil.com

Cover photo: Harald Pettersen

Board of directors report3
The Statoil share4
Our business4
Group profit and loss analysis6
Cash flows8
Liquidity and capital resources9
Group outlook10
Risk review11
Safety, security and sustainability 13
Safety and security13
Sustainability14
People and organisation17
Research and development19
Board developments20
Board statement on corporate governance20
Board statement on Reporting of payments to governments21

Consolidated financial statement Statoil23
Notes to the consolidated financial statements28
1 Organisation 28
2 Significant accounting policies 28
3 Segments 37
4 Acquisitions and dispositions 40
5 Financial risk management41
6 Remuneration44
7 Other expenses 45
8 Financial items 45
9 Income taxes46
10 Earnings per share48
11 Property, plant and equipment48
12 Intangible assets 51
13 Financial investments and non-current prepayments53
14 Inventories53
15 Trade and other receivables54
16 Cash and cash equivalents 54
17 Shareholders' equity54
18 Finance debt 55
19 Pensions56
20 Provisions60
21 Trade and other payables 61
22 Leases61
23 Other commitments, contingent liabilities and contingent assets62
24 Related parties63
25 Financial instruments: fair value measurement and sensitivity analysis of market risk 64
26 Supplementary oil and gas information (unaudited)68
27 Subsequent events78

Notes to the Financial statements Statoil ASA83
1 Organisation and basis of presentation83
2 Significant accounting policies 83
3 Financial risk management and derivatives87
4 Revenues 89
5 Remuneration90
6 Share-based compensation97
7 Auditor's remuneration 98
8 Research and development expenditures 98
9 Financial items 98
10 Income taxes98
11 Property, plant and equipment100
12 Investments in subsidiaries and other equity accounted companies 100
13 Financial assets and liabilities101
14 Inventories102

15 Trade and other receivables102
16 Cash and cash equivalents 102
17 Equity and shareholders103
18 Finance debt 104
19 Pensions105
20 Provisions109
21 Trade and other payables 109
22 Leases110
23 Other commitments and contingencies110
24 Related parties112
25 Subsequent events113
Report of KPMG on the financial statements of Statoil ASA114
Recommendation of the corporate assembly116

Board of directors report

The profitability of the oil and gas industry continues to be challenged and Statoil's financial results in 2014 were influenced by the fall in oil prices, related impairment losses and increased exploration expenses. Production efficiency has improved significantly, the cost improvement programmes are on track and the safety results are good. The financial position is robust, and Statoil provides a competitive dividend. Through significant flexibility in the investment programme, the company is well prepared for continuous market weakness and uncertainty.

Net operating income was NOK 109.5 billion in 2014, down from NOK 155.5 billion in 2013. The 30% decrease was mainly attributable to lower prices for liquids and gas, related impairment losses primarily driven by reduced short-term oil price forecasts, and increased exploration expenses mainly due to impairments of oil and gas prospects and signature bonuses.

Operational performance was strong, with safety improvements, production as expected and strong project execution. Total equity liquids and gas production in 2014 was 1,927 mboe per day, slightly lower than in 2013 when total equity production amounted to 1,940 mboe per day. The annual equity production outside of Norway ended at a record high of 743 mboe per day. Gudrun and three fast-track projects came on stream on the Norwegian continental shelf (NCS) and production started from the partner-operated Jack/St.Malo-field in the US Gulf of Mexico during the fourth quarter of 2014. On 3 January 2015, the Valemon-field on the NCS came on stream and on 13 February, the plan for development and operations (PDO) for the Johan Sverdrup-field was submitted to the Norwegian Ministry of Petroleum and Energy.

Statoil's cash flows provided by operating activities were NOK 126.5 billion in 2014, compared to NOK 101.3 billion in 2013. At the end of the year, Statoil's net debt to capital employed was 20%. Statoil`s total cash flows in 2014 reflect lower prices, issuance of new debt, lower taxes paid and the implementation of quarterly dividend payments.

In October, Helge Lund informed Statoil's board of directors that he had decided to resign. The board of directors appointed Eldar Sætre as acting president and CEO of Statoil with immediate effect. Following a search process evaluating Norwegian and international candidates, Eldar Sætre was appointed new president and CEO on 3 February 2015.

After more than three years of relatively stable prices, 2014 saw the price of Brent crude climb to USD 115 per barrel in June before dropping to USD 55 per barrel at the end of December. The global economic situation continues to be fragile, with development partly driven by uncertain political environments in key countries and regions, in addition to normal supply and demand factors. Consequently, energy prices could continue to fluctuate considerably in the short to medium-term.

Last year Statoil launched a comprehensive efficiency programme to address the fundamental challenge of increasing costs in the oil and gas industry - as well as in Statoil. Going forward, Statoil will reinforce the efforts and the commitment to deliver on the priorities of high value growth, increased efficiency and competitive shareholder returns. The progress is on track with solid and sustainable improvements. So far, realised improvements amount to nearly USD 600 million. In 2015, Statoil will step up its efficiency program by 30% with a target to realise USD 1.7 billion in annual savings from 2016.

Maintaining significant flexibility in a broad portfolio of operated assets, Statoil is prepared to use this flexibility to deliver on its priorities. Cash flow growth from producing assets combined with the flexible investment programme enables Statoil to maintain the indicated net debt of 15-30% at different price scenarios towards 2018.

Organic capital expenditures (excluding acquisitions and financial leases) amounted to USD 19.6 billion for the year ended 31 December 2014, in line with the guidance for 2014 of around USD 20 billion.

Stricter project prioritisation and a comprehensive efficiency program will improve cash flow and profitability. The strong financial position provides a firm basis on which to balance capital investment and dividend to shareholders, which is expected to grow in line with long term earnings. Based on the sanctioned portfolio of projects, Statoil will continue to deliver high value production growth towards 2018. The ambition is to grow organic equity production annually by around 2% from 2014-16 and by 3% from 2016-18 from a rebased level.

Safe, secure and efficient execution of operations is the number-one priority for Statoil. Last year saw continued progress in the safety performance compared to previous years. The serious incident frequency (measured as incidents per million hours worked), including the suppliers' employees, decreased from 0.8 in 2013 to 0.6 in 2014. However, this solid result was overshadowed by two fatalities with the contractor workforce in the US onshore operations.

Statoil has reinforced and will continue to step up ambitions with regards to the security improvement programme. The security culture of the company is strengthened and measures have been implemented to increase physical security, strengthen information technology security and protection of personnel.

Statoil was among the leading exploration companies in the industry also in 2014, strengthening the reserve base through exploration, adding 540 million barrels of oil equivalents to the resource base. Statoil reported a reserve replacement ratio (RRR) of 62% in 2014. Organic RRR was 96%, which is a reduction compared to 2013, however, on a satisfactory level. The average three-year replacement ratio was 117% at the end of 2014.

Statoil continues to optimise the portfolio. In 2014, Statoil announced divestments with total net proceeds worth of USD 4.3 billion in a challenging market environment, including sale of assets and reduced ownership on the NCS. Statoil also exit the Shah Deniz gas field, including the Shah Deniz stage 2 development project in Azerbaijan.

To Statoil, sustainability is a business matter where the need to remain a highly competitive company is combined and strengthened by our efforts to accelerate the development of more carbon-efficient solutions to produce energy. Being a trusted company with a long-term social license to operate will enhance future business opportunities. Statoil's commitment to long-term, sustainable growth, in line with the principles of the UN Global Compact, is reflected in the sustainability reporting.

Statoil enters 2015 with a robust financial position, strong operational performance and is well prepared to meet the volatility in the markets and the demanding situation for the industry. The strategy remains firm and Statoil is reinforcing the efforts and commitment to deliver on the priorities of high value growth, increased efficiency and competitive shareholder returns.

The Statoil share

The board of directors proposes an ordinary dividend of total NOK 7.20 per share for 2014 at an aggregate total of NOK 22.9 billion.

It is Statoil's ambition to grow the annual cash dividend, measured in NOK per share, in line with long term underlying earnings.

In 2014 Statoil implemented quarterly dividend payments. The updated dividend policy is conditional upon the AGM authorising the board of directors to decide payment of quarterly dividends. Such authorisation must be renewed at each AGM in order to remain valid.

The board approves 1Q -3Q interim dividends based on an authorisation from the annual general meeting (AGM), while the annual general meeting approves the 4Q (and total annual) dividend based on a proposal from the board. When deciding the interim dividends and recommending the total annual dividend level, the board will take into consideration expected future cash flow, capital expenditure plans, financing requirements and appropriate financial flexibility. The shareholders at the AGM may vote to reduce, but may not increase, the fourth quarter (and hence total year) dividend proposed by the board of directors.

Statoil announces dividend payments in connection with quarterly results. Payment of quarterly dividends normally takes place approximately four months after the announcement of each quarterly dividend. Hence, in 2014 Statoil paid the 2013 annual dividend and two quarterly dividends.

In addition to cash dividend, Statoil might buy back shares as part of total distribution of capital to the shareholders.

In 2013, the ordinary dividend was NOK 7.00 per share, an aggregate total of NOK 22.3 billion.

The Statoil share, listed on the Oslo Stock Exchange under the ticker code STL, decreased during 2014, starting out 2 January 2014 at NOK 146.90, ending up at NOK 131.20 at the end of 2014. Statoil is also listed on the New York Stock Exchange under the ticker code STO.

Our business

Statoil is a technology-driven energy company primarily engaged in oil and gas exploration and production activities.

Statoil ASA is a public limited liability company organised under the laws of Norway and subject to the provisions of the Norwegian Public Limited Liability Companies Act. The Norwegian State is the largest shareholder in Statoil ASA, with a direct ownership interest of 67%.

Statoil has business operations in more than 30 countries and territories, and has more than 22,500 employees worldwide. The company's head office is located in Stavanger, Norway. Statoil is the leading operator on the Norwegian continental shelf (NCS).

Statoil is present in several of the most important oil and gas provinces in the world. In 2014, 39% of Statoil's equity production came from international activities. Statoil also holds operatorships internationally.

Statoil is among the world's largest net sellers of crude oil and condensate, and is the one of the largest suppliers of natural gas to the European market.

Processing and refining are also part of our operations. Statoil is also participating in projects that focus on other forms of energy, such as offshore wind, in anticipation of the need to expand energy production, strengthen energy security and combat adverse climate change.

Statoil aims to grow and enhance value through its technology-focused upstream strategy, supplemented by selective positions in the midstream and in low-carbon technologies. Statoil's top priorities remain to conduct safe, reliable operations with zero harm to people and the environment, and to deliver profitable production growth through disciplined investments and prudent financial management with competitive redistribution of capital to shareholders. To succeed going forward we continue to focus strategically on the following:

• Sustaining leading exploration company performance
• Taking out the full value potential of the Norwegian Continental Shelf (NCS)
• Strengthening our global offshore positions
• Maximising the value of our onshore positions
• Creating enhanced value from midstream solutions
• Continuing portfolio management to enhance value creation
• Utilising oil and gas expertise and technology to open new renewable energy opportunities

Statoil's operations are managed through the following business areas:

Development and Production Norway (DPN)

DPN comprises our upstream activities on the NCS. DPN operates both developed fields and a significant number of exploration licences in the North Sea, the Norwegian Sea and the Barents Sea. In 2014, around 68% of Statoil's total entitlement production was production from DPN. The aim of DPN is to continue its leading role and ensure maximum value creation on the NCS. Through excellent HSE and improved operational performance and cost, DPN strives to maintain and strengthen Statoil's position as a world- leading operator of producing offshore fields. DPN seeks to open new acreage and to mature improved oil recovery and exploration prospects.

Development and Production International (DPI)

DPI comprises our worldwide upstream activities that are not included in the DPN and Development and Production North America business areas. DPI's ambition is to build a large and profitable international production portfolio comprising activities ranging from accessing new opportunities to delivering on existing projects and managing a production portfolio.

Development and Production North America (DPNA)

DPNA comprises our upstream activities in North America. DPNA's ambition is to develop a material and profitable position in North America, including the deepwater regions of the Gulf of Mexico and unconventional oil and gas in the US and oil sands Canada. In this connection, we aim to further strengthen our capabilities in deepwater and unconventional oil and gas operations.

Marketing, Processing and Renewable Energy (MPR)

Marketing, Processing and Renewable Energy (MPR) is responsible for the marketing and trading of crude oil, natural gas, power, emissions, liquids and refined products, for transportation and processing, and for developing business opportunities in renewables. MPR markets Statoil's own volumes and purchases the Norwegian state's direct financial interest (SDFI) total equity production of crude oil in addition to third-party volumes. MPR is also responsible for marketing SDFI's gas.

Exploration (EXP)

EXP is responsible for creating a global center for exploration and deploying resources to priority activities across the portfolio. Main focus areas are accessing high potential new acreage in priority basins, globally prioritising and drilling more significant wells in growth and frontier basins, delivering nearfield exploration on the NCS and other select areas, and achieving step-change improvements in performance.

Technology, Projects and Drilling (TPD)

Technology, Projects and Drilling (TPD) business area is responsible for delivering projects and wells and providing global support on standards and procurement. TPD is also responsible for developing Statoil as a technology company. TPD's main focus areas is to provide safe, efficient and costcompetitive global well, project delivery, technological excellence, and research and development. Cost-competitive procurement is an important contributory factor, although group-wide procurement services are also expected to help to drive down costs in the group.

Global Strategy and Business Development (GSB)

GSB sets the strategic direction for Statoil and identifies, develops and delivers business opportunities. This is achieved through close collaboration across geographic locations and business areas. Statoil's strategy plays an important role in guiding Statoil's business development focus. The ambition of the GSB business area is to closely link corporate strategy and business development to actively drive Statoil's corporate development.

Group profit and loss analysis

Net operating income was NOK 109.5 billion in 2014, down from NOK 155.5 billion to 2013, impacted by lower prices, impairment losses and exploration expenses.

	For the year ended 31 December
Operational	2014	2013	14-13 change
Prices
Average Brent oil price (USD/bbl)	98.9	108.7	(9%)
Development and Production Norway average liquids price (USD/bbl)	90.6	101.0	(10%)
Development and Production International average liquids price (USD/bbl)	85.6	98.4	(13%)
Group average liquids price (USD/bbl)	88.6	100.0	(11%)
Group average liquids price (NOK/bbl)	558.5	587.8	(5%)
Transfer price natural gas (NOK/scm)	1.57	1.92	(18%)
Average invoiced gas prices - Europe (NOK/scm)	2.28	2.45	(7%)
Average invoiced gas prices - North America (NOK/scm)	1.04	0.83	25%
Refining reference margin (USD/bbl)	4.7	4.1	15%
Entitlement production (mboe per day)
Development and Production Norway entitlement liquids production	588	591	(1%)
Development and Production International entitlement liquids production	383	354	8%
Group entitlement liquids production	971	945	3%
Development and Production Norway entitlement gas production	595	626	(5%)
Development and Production International entitlement gas production	163	148	10%
Group entitlement gas production	758	773	(2%)
Total entitlement liquids and gas production	1,729	1,719	1%
Equity production (mboe per day)
Development and Production Norway equity liquids production	588	591	(1%)
Development and Production International equity liquids production	538	524	3%
Group equity liquids production	1,127	1,115	1%
Development and Production Norway equity gas production	595	626	(5%)
Development and Production International equity gas production	205	200	3%
Group equity gas production	801	825	(3%)
Total equity liquids and gas production	1,927	1,940	(1%)
Liftings (mboe per day)
Liquids liftings	967	950	2%
Gas liftings	779	792	(2%)
Total liquids and gas liftings	1,746	1,742	0%
MPR sales volumes
Crude oil sales volumes (mmbl)	811.0	809.0	0%
Natural gas sales Statoil entitlement (bcm)	43.1	44.2	(2%)
Natural gas sales third-party volumes (bcm)	8.1	12.3	(34%)
Production cost (NOK/boe, last 12 months)
Production cost entitlement volumes	55	50	10%
Production cost equity volumes	49	44	11%

Total equity liquids and gas production was 1,927 mboe per day in 2014, slightly lower than in 2013 when total equity production amounted to 1,940 mboe per day. Start-up and ramp-up of production on various fields and higher production regularity compared to last year were offset by expected natural decline and reduced ownership shares from divestments.

Total entitlement liquids and gas production was 1,729 mboe per day in 2014 compared to 1,719 mboe per day in 2013. The total entitlement production in 2014 remained at the same level as the production in 2013, for the same reasons as described above and a relatively lower negative effect from production sharing agreements (PSA effect). The PSA effect was 157 mboe and 182 mboe per day in 2014 and 2013, respectively.

Production cost per boe of entitlement volumes was NOK 55 and NOK 50 for the 12 months ended 31 December 2014 and 2013, respectively. Based on equity volumes, the production cost per boe was NOK 49 and NOK 44 for the 12 months ended 31 December 2014 and 2013, respectively. The increase in 2014 from last year is due to increased production costs impacted by new fields coming on stream.

Income statement under IFRS	For the year ended 31 December
(in NOK billion)	2014	2013 (restated)	14-13 change
Revenues	606.8	616.6	(2%)
Net income from associated companies	(0.3)	0.1	>(100%)
Other income	16.1	17.8	(10%)
Total revenues and other income	622.7	634.5	(2%)
Purchases [net of inventory variation]	(301.3)	(306.9)	(2%)
Operating expenses and selling, general and administrative expenses	(80.2)	(81.9)	(2%)
Depreciation, amortisation and net impairment losses	(101.4)	(72.4)	40%
Exploration expenses	(30.3)	(18.0)	69%
Net operating income	109.5	155.5	(30%)
Net financial items	(0.0)	(17.0)	(100%)
Income before tax	109.4	138.4	(21%)
Income tax	(87.4)	(99.2)	(12%)
Net income	22.0	39.2	(44%)

Total revenues and other income amounted to NOK 622.7 billion in 2014 compared to NOK 634.5 billion in 2013. Revenues are generated from both the sale of lifted crude oil, natural gas and refined products produced and marketed by Statoil, and from the sale of liquids and gas purchased from third parties. In addition, we market and sell the Norwegian State's share of liquids from the NCS. All purchases and sales of the Norwegian State's production of liquids are recorded as purchases [net of inventory variations] and revenues, respectively, while sales of the Norwegian State's share of gas from the NCS are recorded net.

The 2% decrease in revenues from 2013 to 2014 was mainly due to decreased prices for liquids and European gas and reduced volumes of liquids and gas sold, partly offset increased US gas prices and a positive exchange rate development (NOK/USD). Also, revenues in 2014 were positively impacted by gains from derivatives, mainly due to significant drop in the forward curve in the oil market.

Other income was NOK 16.1 billion in 2014 compared to NOK 17.8 billion in 2013. Other income in 2014 consists of the gain from the sale of certain ownership interests on the NCS to Wintershall (NOK 5.9 billion) and the divestment of working interests in the Shah Deniz Project and South Caucasus Pipeline (NOK 5.4 billion). In addition, an arbitration settlement (NOK 2.8 billion), following an arbitration ruling in Statoil's favour, impacted Other income in 2014. Other income in 2013 was mainly impacted by gains from sale of certain ownership interests on the NCS to OMV (NOK 10.1 billion) and Wintershall (NOK 6.4 billion).

Purchases [net of inventory variation] include the cost of liquids purchased from the Norwegian State, which is pursuant to the Owner's instruction, and the cost of liquids and gas purchased from third parties. Purchases [net of inventory variation] amounted to NOK 301.3 billion in 2014 compared to 306.9 billion in 2013. The 2% decrease from 2013 to 2014 was mainly related to lower prices for liquids and gas, including the write-down of inventories from cost to market value, and reduced third party volumes. The decrease was partly offset by currency effects (NOK/USD).

Operating expenses and selling, general and administrative expenses amounted to NOK 80.2 billion in 2014 compared to NOK 81.9 billion in 2013, down by 2%. In 2014, the expenses were positively impacted by a curtailment gain of NOK 3.5 billion recognised upon the decision to change the company's pension plan in Norway. In 2013, expenses were negatively impacted by an onerous contract provision of NOK 4.9 billion related to the Cove Point terminal in the US. These effects were offset by increased expenses in 2014 mainly due to new fields coming on stream, onshore production ramp-up and increased transportation costs in the North America. In addition, the NOK/USD exchange rate development increased expenses in 2014 compared to 2013.

Depreciation, amortisation and net impairment losses amounted to NOK 101.4 billion in 2014 compared to NOK 72.4 billion in 2013. Included in these totals were net impairment losses of NOK 26.9 billion for 2014 and NOK 7.0 billion for 2013.

Depreciation, amortisation and net impairment losses increased by 40% compared to 2013, mainly due to impairment losses related to Statoil's international operations, primarily driven by reduced short-term oil price forecasts. Also, new investments, higher production and increased asset retirement obligation, with a corresponding higher basis for depreciation, partly offset by increased proved reserves estimates, added to increased depreciation costs in 2014 compared to 2013.

In 2014, exploration expenses were NOK 30.3 billion, a NOK 12.3 billion increase compared to 2013 when exploration expenses were NOK 18.0 billion. The increase in exploration expenses from 2013 to 2014 was mainly due to increased impairments of oil and gas prospects and signature bonuses internationally. Also, the cancellation of a rig contract in 2014 impacted exploration expenses negatively in 2014 compared to 2013.

As a result of the above, net operating income was NOK 109.5 billion in 2014, compared to NOK 155.5 billion in 2013.

Net financial items amounted to NOK 0.0 billion in 2014, compared to a loss of NOK 17.0 billion in 2013. The improved result was mainly due to a positive change in currency derivatives used for currency and liquidity risk management as a result of changes in underlying currency positions together with a strengthening of USD towards NOK of 22.2% in 2014 compared to a strengthening of USD towards NOK of 9.3% in 2013. In addition a positive fair value change on interest rate swap positions relating to the interest rate management of non-current bonds mainly due to a decrease in long term USD interest rates by an average of 0.6 percentage points in 2014 compared to an increase in 2013 by an average of 1.0 percentage points. This was offset by increased interest and other finance expenses.

Income taxes were NOK 87.4 billion in 2014 equivalent to an effective tax rate of 79.9%, compared to NOK 99.2 billion, equivalent to an effective tax rate of 71.7%, in 2013.

The effective tax rate in 2014 was influenced by impairment losses with lower than average tax rates, partly offset by tax exempted gains on the Norwegian continental shelf (NCS) and sale of interests in the Shah Deniz project and tax effect of foreign exchange losses in entities that are taxable in other currencies than the functional currency. These losses are tax deductible, but do not impact the Consolidated statement of income. The effective tax rate in 2014 was also impacted by the recognition of a non-cash tax income following a verdict in the Norwegian Supreme Court in February 2014. The Supreme Court voted in favor of Statoil in a tax dispute regarding the tax treatment of foreign exploration expenditures.

The effective tax rate is calculated as income taxes divided by income before taxes. Fluctuations in the effective tax rates from year to year are principally the result of non-taxable items (permanent differences) and changes in the relative composition of income between Norwegian oil and gas production, taxed at a marginal rate of 78%, and income from other tax jurisdictions. Other Norwegian income, including the onshore portion of net financial items, is taxed at 27% (28% prior to 2014), and income in other countries is taxed at the applicable income tax rates in those countries.

In 2014, net income was NOK 22.0 billion compared to NOK 39.2 billion in 2013. The 44% decrease from 2013 to 2014 was mainly due to reduced prices, leading to lower earnings and impairment losses, and increased exploration expenditures.

Return on average capital employed (ROACE) was 2.7% in 2014 compared to 11.3% in 2013. The decrease was due to the 73% decrease in net income adjusted for financial items, in combination with an increase in average capital employed.

The Statoil board of directors proposes a dividend of NOK 1.80 per share for the fourth quarter of 2014, subject to approval at the Annual general meeting (AMG) in line with the authorisation from May 2014. The proposed annual dividend for 2014 amounted to NOK 7.20 per share, an aggregate total of NOK 22.9 billion. Considering the proposed dividend the remaining net income in the parent company will be allocated to reserve for valuation variances with NOK 1.6 billion and NOK 18.4 billion will be transferred from retained earnings. For 2013, Statoil paid an ordinary dividend of NOK 7.00 per share, an aggregate total of NOK 22.3 billion.

In 2014, following a regular review process of Statoil's 2012 Consolidated financial statements, the Financial Supervisory Authority of Norway (the FSA) concluded that it had identified three errors, related to interpretation and application of IFRS accounting principles for determination of cash generating units (CGUs) and impairment evaluations. For two of the matters Statoil accepted the FSA's interpretations and has applied such interpretations in preparing its Consolidated financial statements for 2014 and 2013. Statoil did not restate prior period financial statements as the impact was immaterial. For the third matter Statoil does not accept the FSA's conclusion. In accordance with due process for such matters under Norwegian regulation, Statoil has appealed the order to the Norwegian Ministry of Finance and has been granted a stay in carrying out the FSA's order pending the final outcome of the appeal.

In accordance with §3-3 of the Norwegian Accounting Act, the board of directors confirms that the financial statements have been prepared on the basis of the going concern assumption.

Cash flows

Statoil`s cash flows in 2014 reflect lower prices, issuance of new debt, lower taxes paid and the implementation of quarterly dividend payments.

Cash flows provided by operations

The most significant drivers of cash flows provided by operations are the level of production and prices for liquids and natural gas that impact revenues, purchases [net of inventory], taxes paid and changes in working capital items.

Cash flows provided by operating activities were NOK 126.5 billion in 2014 compared to NOK 101.3 billion in 2013, an increase of NOK 25.2 billion. Cash flows provided by operating activities before taxed paid and working capital items were reduced by NOK 10.0 billion compared to 2013, driven by decreased profitability mainly caused by lower prices for liquids and European gas. The decrease was offset by positive changes in working capital and lower taxes paid in 2014 compared to 2013.

Cash flows used in investing activities

Cash flows used in investing activities were NOK 112.0 billion in 2014 compared to NOK 110.4 billion in 2013, an increase of NOK 1.6 billion mainly due to increased capital expenditures, partly offset by lower investments in deposits with more than three months maturity. The proceeds from sale of assets in 2014 of NOK 22.6 billion mainly relates to the divestment of interests in the Shah Deniz field and the South Caucasus pipeline and the sale of interests in licences on the NCS.

Cash flows provided by (used in) financing activities

Cash flows used in financing activities were NOK 23.1 billion in 2014, a change of NOK 49.7 billion compared to 2013. Cash flows used in financing activities in 2014 are mainly related to payments of dividends and repayments of debt. The increase in dividend paid of NOK 12.2 billion from 2013 to 2014 was impacted by the introduction of quarterly dividends in 2014. This was partly offset by issuance of new debt in November 2014 of NOK 20.6 billion. Cash flows provided by financing activities amounted to NOK 26.6 billion in 2013, influenced by debt issuances of NOK 62.8 billion in total.

Liquidity and capital resources

Statoil has a strong balance sheet and considerable financial flexibility. The net debt ratio was 20% at the end of 2014.

Financial position and liquidity

Statoil's financial position is strong although net debt ratio before adjustments at year end increased from 14.0% in 2013 to 19.0% in 2014. Net interestbearing debt increased from NOK 58.0 billion to NOK 89.2 billion. During 2014 Statoil's total equity increased from NOK 356.0 billion to NOK 381.2 billion. From 2013 to 2014 both cash flows provided by operating activities and cash flows used in investments increased. For 2013, Statoil paid a dividend of NOK 7.00 per share. Statoil introduced quarterly dividends in 2014 and have paid out quarterly dividends for the first three quarters. The quarterly dividends for the first and second quarter were paid out in 2014. The board of directors has proposed a dividend of NOK 1.80 per share for the fourth quarter, implying a total dividend of NOK 7.20 per share for 2014. Total dividend payments were NOK 33.7 billion in 2014.

We believe that, given the current liquidity reserves, including committed credit facilities of USD 3.0 billion and very good access to various capital markets, Statoil will have sufficient capital available.

Funding needs arise as a result of the Group's general business activity. We generally seek to establish financing at the corporate level. Project financing may be used in cases involving joint ventures with other companies. We aim at having access at all times to a variety of funding sources in respect of markets and instruments as well as maintaining relationships with a core group of international banks that provide various kinds of banking services.

We have diversified our cash investments across a range of financial instruments and counterparties to avoid concentrating risk in any one type of investment or any single country. As of 31 December 2014, approximately 35% of our liquid assets were held in USD-denominated assets, 21% in NOK, 20% in EUR, 14% in DKK, 9% in SEK, and 2% in GBP, before the effect of currency swaps and forward contracts. Approximately 57% of our liquid assets were held in treasury bills and commercial papers, 37% in time deposits, 3% in liquidity funds and 3% at bank available. As of 31 December 2014, approximately 2.0% of our liquid assets were classified as restricted cash (including collateral deposits).

Long-term funding is raised when we identify a need for such financing based on our business activities, cash flows and required financial flexibility or when market conditions are considered to be favourable. Recent bond transactions were made at very favourable terms, pre-funding longer-term commitments.

The group's borrowing needs are usually covered through the issuing of short-term and long-term securities, including utilisation of a US Commercial Paper Program (program limit USD 4.0 billion) and a Shelf Registration Statement (unlimited) filed with the Securities and Exchange Commission (SEC) in the United States as well as through issues under a Euro Medium-Term Note (EMTN) Programme (program limit was recently updated to USD 16.0 billion) listed on the London Stock Exchange committed credit facilities and credit lines may also be utilised. After the effect of currency swaps, the major part of our borrowings is exposed to USD.

Statoil ASA issued new debt securities in 2014 equivalent to NOK 20.5 billion as follows for general corporate purposes. In February 2015, Statoil issued notes worth EUR 3.75 billion (NOK 32.1 billion) under the EMTN programme.

Financial indicators		For the year ended 31 December
(in NOK billion)	2014	2013
Gross interest-bearing financial liabilities	231.6	182.5
Net interest-bearing liabilities before adjustments	89.2	58.0
Net debt to capital employed ratio	19.0 %	14.0 %
Net debt to capital employed ratio adjusted	20.0 %	15.2 %
Cash and cash equivalents	83.1	85.3
Current financial investments	59.2	39.2

Gross interest-bearing debt

Gross interest-bearing debt was NOK 231.6 billion and NOK 182.5 billion at 31 December 2014 and 2013, respectively. The NOK 49.0 billion increase from 2013 to 2014 was due to an increase in current finance debt of NOK 9.4 billion and an increase in non-current finance debt of NOK 39.6 billion. Our weighted average annual interest rate was 3.78% and 4.06% at 31 December 2014 and 2013, respectively. Our weighted average maturity on finance debt was 9 years at 31 December 2014, compared to 10 years at 31 December 2013.

Net interest-bearing debt

Net interest-bearing debt before adjustments were NOK 89.2 billion and NOK 58.0 billion at 31 December 2014 and 2013, respectively. The increase of NOK 31.2 billion from 2013 to 2014 was mainly related to an increase in gross interest-bearing debt of NOK 49.0 billion in addition to an increase in cash and cash equivalents and current financial investments of NOK 17.9 billion, reflecting the level of bond issues and active portfolio management (proceeds from sales of assets).

The net debt to capital employed ratio

The net debt to capital employed ratio before adjustments was 19.0% and 14.0% in 2014 and 2013, respectively. The net debt to capital employed ratio adjusted was 20.0% and 15.2% in 2014 and 2013, respectively.

Cash, cash equivalents and current financial investments

Cash and cash equivalents were NOK 83.1 billion and NOK 85.3 billion at 31 December 2014 and 2013, respectively. The decrease from 2013 to 2014 reflects a reduction in bond issuances as well as the liquidity management of cash and cash equivalents and current financial investments and the proceeds from sales of assets.

Current financial investments, which are part of our liquidity management, amounted to NOK 59.2 billion and NOK 39.2 billion at 31 December 2014 and 2013, respectively.

Group outlook

Statoil expects to grow the organic production annually by around 2% from 2014-16, and by 3% from 2016-18. Organic capital expenditures in 2015 are estimated at around USD 18 billion.

Our plans address the current environment while continuing to invest in high-quality projects. We reinforce our efforts and commitment to deliver on our priorities of high value growth, increased efficiency and competitive shareholder return.

• Organic capital expenditures for 2015 (i.e. excluding acquisitions, capital leases and other investments with significant different cash flow pattern), are estimated at around USD 18 billion, compare to USD 19.6 billion in 2014.
• Statoil will continue to mature the large portfolio of exploration assets and estimates a total exploration activity level at around USD 3.2 billion for 2015, excluding signature bonuses.
• Statoil expects to deliver efficiency improvements with pre-tax cash flow effects of around USD 1.7 billion from 2016.
• Our ambition is to maintain ROACE (Return on Average Capital Employed) at 2013 level adjusted for price and currency level, and to keep our unit of production cost in the top quartile of our peer group.
• For the period 2014 2016 organic production growth is expected to come from new projects resulting in around 2% CAGR (Compound Annual Growth Rate) from a 2014 level rebased for divestments.
• The equity production development for 2015 is estimated to be around 2% CAGR from a 2014 level rebased for divestments.
• Scheduled maintenance activity is estimated to reduce equity production by around 45 mboe per day for the full year 2015, of which the majority is liquids.
• Indicative PSA (Production Sharing Agreement) effect and US royalties are estimated to around 160 mboe per day in 2015 based on an oil price of USD 60 per barrel and 190 mboe per day based on an oil price of USD 100 per barrel.
• Deferral of gas 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.

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.

Risk review

The results of our operations depend on a number of factors, most significantly those affecting prices received in Norwegian kroner (NOK) for our products.

Market risk

The factors that influence the results of our operations include:

• the level of crude oil and natural gas prices
• trends in the exchange rate between the US dollar (USD), in which the trading price of crude oil is generally stated and to which natural gas prices are frequently related, and NOK, in which our accounts are reported and a substantial proportion of our costs are incurred
• our oil and natural gas production volumes, which in turn depend on entitlement volumes under Product Sharing Agreements (PSAs) and available petroleum reserves, and our own, as well as our partners' expertise and cooperation in recovering oil and natural gas from those reserves.

Our results will also be affected by

• trends in the international oil industry, including possible actions by governments and other regulatory authorities in the jurisdictions in which we operate
• possible or continued actions by members of the Organization of Petroleum Exporting Countries (OPEC) that affect price levels and volumes
• refining margins, costs of oilfield services, supplies and equipment
• competition for exploration opportunities and operatorships
• deregulation of the natural gas market,
• changes in our portfolio of assets due to acquisitions and disposals.

all of which may cause substantial changes to the existing market structures and to the overall level and volatility of prices.

The illustration shows the indicative full-year effect on the financial result for 2015 given certain changes in the crude oil prices, natural gas contract prices and the USDNOK exchange rates. The estimated price sensitivity of our financial results to each of the factors has been estimated based on the assumption that all other factors remain unchanged.

Significant downward adjustments of Statoil's commodity price assumptions will result in impairment losses on certain producing and development assets in the portfolio. Subsequent to year end 2014, commodity prices have continued to be volatile. See Note 11 Property, plant and equipment and note 12 Intangible assets to the Consolidated financial statements for sensitivity analysis related to impairment losses.

Our oil and gas price hedging policy is designed to support our long-term strategic development and our attainment of targets by protecting financial flexibility and cash flows.

Our products are marketed and traded worldwide and therefore subject to competition and antitrust laws at the supranational and national level in multiple jurisdictions. We are exposed to investigations from competition and antitrust authorities, and violations of the applicable laws and regulations may lead to substantial fines. In May 2013, the EFTA Surveillance Authority conducted an unannounced inspection at our main office in Stavanger, Norway, on behalf of the European Commission. The authorities suspected participation by several companies, including Statoil, in anti-competitive practices and/or market manipulation related to the Platts' Market-On-Close price assessment process. The investigation is not finalised and no conclusions have been made.

The products in scope in the investigation are traded worldwide and there is a risk that authorities in other jurisdictions could also bring similar proceedings.

Fluctuating foreign exchange rates can have a significant impact on our operating results. Our revenues and cash flows are mainly denominated in or driven by USD, while our operating expenses and income taxes payable largely accrue in NOK. We seek to manage this currency mismatch by issuing or swapping non-current financial debt in USD. This long-term funding policy is an integrated part of our total risk management programme. We also engage in foreign currency management in order to cover our non-USD needs, which are primarily in NOK. In general, an increase in the value of USD in relation to NOK will increase our reported earnings from transaction effects when the underlying results are net positive.

Liquidity risk

Liquidity risk is the risk that Statoil will not be able to meet obligations of financial liabilities when they become due. The purpose of liquidity management is to make certain that Statoil has sufficient funds available at all times to cover its financial obligations.

Statoil manages liquidity and funding at the corporate level, ensuring adequate liquidity to cover Statoil's operational requirements. Statoil has a high focus and attention on credit and liquidity risk. In order to secure necessary financial flexibility, which includes meeting Statoil's financial obligations, Statoil maintains a conservative liquidity management policy. To identify future long-term financing needs, Statoil carries out three-year cash forecasts at least monthly. During 2014 Statoil's overall liquidity was solid.

The main cash outflows are the annual dividend payment and tax payments. If the monthly cash flow forecast shows that the liquid assets one month after tax and dividend payments will fall below the defined policy level, new long-term funding will be considered.

Mainly all of Statoil's financial liabilities related to derivative financial instruments, both exchange traded and non-exchange traded commodity-based derivatives together with financial derivatives, with the exception of some interest rate derivatives classified as non-current in the balance sheet, fall due within one year, based on the underlying delivery period of the contracts included in the portfolio. The interest rate derivatives classified as non-current in the balance sheet are due from 2016 till 2043.

Credit risk

Credit risk is the risk that Statoil's customers or counterparties will cause the company financial loss by failing to honour their obligations. Credit risk arises from credit exposures with customer accounts receivables as well as from financial investments, derivative financial instruments and deposits with financial institutions.

Key elements of the credit risk management approach include:

• A global credit risk policy
• Credit mandates
• Internal credit rating process
• Credit risk mitigation tools
• A continuous monitoring and managing of credit exposures

Prior to entering into transactions with new counterparties, the credit policy requires all counterparties to be formally identified and approved. In addition all sales, trading and financial counterparties are assigned internal credit ratings as well as exposure limits. Once established, all counterparties are re-assessed minimum annually and continuously monitored. Counterparty risk assessments are based on a quantitative and qualitative analysis of recent financial and other relevant business information. In addition, Statoil evaluates any past payment performance, the counterparties' size and business diversification, and the inherent industry risk. The internal credit ratings reflect Statoil's assessment of the counterparties' credit risk. Exposure limits are determined based on assigned internal credit ratings combined with other factors, such as expected transaction and industry characteristics. Credit mandates define acceptable credit risk thresholds and are endorsed by management and regularly reviewed with regard to changes in market conditions.

Statoil uses risk mitigation tools to reduce or control credit risk both on a counterparty and portfolio level. The main tools include bank and parental guarantees, prepayments and cash collateral. For bank guarantees only investment grade international banks are accepted as counterparties. Statoil has predefined limits for the minimum average credit rating allowed at any given time on the group portfolio level as well as maximum credit exposures for individual counterparties. Statoil monitors the portfolio on a regular basis and individual exposures versus limits on a daily basis. The total credit exposure portfolio of Statoil is geographically diversified among a number of counterparties within the oil and energy sector, as well as larger oil and gas consumers and financial counterparties. The majority of the company's credit exposure is with investment grade counterparties.

For further information about financial risk management and derivatives, see note 3 Financial risk management and derivatives to the financial statements of Statoil ASA.

Yearly average	2014	2013
Crude oil (USD/bbl Brent blend)	98.9	108.7
Average invoiced gas price (NOK/scm)	2.3	2.4
Refining reference margin (USD/bbl)	4.7	4.1
USDNOK average daily exchange rate	6.3	5.9

Safety, security and sustainability

Safety, security and sustainability must go to the core of our business. Safety and security is our first priority. We aim to be recognised as the most carbon efficient oil and gas producer and to create lasting local value for communities.

Safety and security

Statoil aims to be an industry leader in safety --- to be recognised for our safety performance and to act as a driving force for improving the safety standards in our industry. Everyone working for us, and in the joint arrangements we operate, is required to comply with our safety and security standards. We expect our employees to intervene in unsafe situations and take active part in mitigating security risks. We also actively engage with our suppliers and partners to encourage them to embed a safety and security culture in their workforce.

We are working closely with industry peer companies on incident prevention and emergency preparedness. Our industry is determined to learn from incidents and accidents to prevent similar occurrences in the future. We believe that accidents can be prevented. However, we recognise the risks associated with our business and are prepared to handle situations that require immediate action to save lives and protect the environment, facilities, equipment and any third parties who may be affected. To ensure we are always prepared, we hold regular emergency response drills and provide, for instance, travel security and hostage survival training.

Safety performance

Four focus areas have guided our safety work in 2014: Compliance & Leadership (a structured way of working that focuses on understanding tasks, risks and requirements), simplification of the management system, risk management, and technical integrity. Going forward, further strengthening technical integrity and continuing the Compliance and Leadership programme will be priority areas within safety.

Statoil uses serious incident frequency (SIF) as a key indicator to monitor safety performance. This indicator (number of serious incidents, including near misses, per million hours worked) combines actual consequences of incidents and the potential for incidents to develop into serious or major accidents. Our target is to achieve a SIF below 0.5 by the end of 2015.

SIF dropped from 0.8 per million hours worked in 2013 to 0.6 per million hours worked in 2014. The main cause for serious incidents this year was insufficient understanding of risk. Reaching our 2014 target for this key performance indicator represented a major improvement in safety performance.

Total recordable injuries per million hours worked (TRIF) improved from 3.8 in 2013 to 3.0 in 2014. In the same period, TRIF for our employees decreased from 2.0 to 1.7 and TRIF for our contractors improved from 4.7 to 3.6. The lost-time injury frequency dropped significantly from 1.4 in 2013 to 1.1 in 2014. Regrettably, there were two fatalities among contractors working at Statoil-operated assets.

Oil and gas leakages represent a major accident risk, and as part of our risk management we closely monitor serious oil and gas leakages (leakages above 0.1kg/sec). In 2014, the number of serious oil and gas leakages declined from 1.6 to 1.1 leakages per month, compared to our target of maximum 0.5 serious oil and gas leakages per month by the end of 2015. The most frequent cause of oil and gas leakages was technical failure due to aging, and the leakages occurred most often in valves and flanges.

In our view, safer behaviour prompted by our Compliance & Leadership programme made a significant contribution to improved safety results. This programme is a structured way of working that focuses on understanding tasks, risks and requirements, to ensure a safe and efficient performance of any task. Both employees and suppliers were trained in this programme in 2014.

There was a minor decline in the number of accidental oil spills from 2013 to 2014. Despite this decline, however, the related volume of oil spills increased from 69m³ to 125m³ in the same period. Three large oil spills accounted for the major volume of oil spills: Statfjord C, Norway (40m³); Bakken, USA (34 m³); and Snorre A, Norway (33m³). The main causes for accidental oil spills were technical errors, equipment failure and inadequate inspection or maintenance programmes.

Health and working environment

We are committed to providing a healthy working environment for our people and make systematic efforts to design and improve working conditions in order to prevent occupational accidents, work-related illness and sickness absence. We emphasise the psychosocial aspects (the combination of psychological and social factors) of the working environment, and promote the good health and well-being of all of our employees.

We work proactively to reduce our workers' exposure to physical health risks and to prevent and treat psycho-social challenges in our work environment. We include work related illness cases in our key indicator for measuring safety performance, the serious incident frequency (SIF), so that the top management has a balanced view of safety, including significant health and working environment aspects.

Noise levels, ergonomic strains and psycho-social factors were the most significant causes of work-related illnesses in 2014. The sickness absence rate decreased with 0.1 percent points to 3.8% from 2013 to 2014.

Security Improvement Programme

Following the tragic terrorist attack against the In Amenas facility in Algeria in 2013, there was a step change in our approach to security. The 19 recommendations given in the In Amenas investigation report, together with recommendations from other internal and external sources, formed the basis for our Security Improvement Programme, initiated in 2013. The programme was established to significantly strengthen our security capabilities and develop a stronger security culture throughout the company. The corporate unit for security and emergency preparedness is responsible for running the programme, which is expected to be finalised in 2015.

In 2014, we continued to implement the security improvement programme. Significant activities included revision of security related governance requirements and training material, and publication of a new methodology for performing security risk assessments. Security professionals were employed and appointed throughout the company in accordance with the principle that operational security is exercised at the lowest organisational level that is possible and appropriate. Internal communication activities and leader workshops were organised to enhance security competence and awareness in the company. Additionally, we strengthened our networks with government bodies and oil and gas industry peers to further enhance our own and others' security capabilities.

Sustainability

The global demand for energy is expected to increase by 37% by 2040, according to the International Energy Agency (IEA) World Energy Outlook 2014. More energy production is needed for a growing global population; both to replenish fossil fuel capacity, and to expand renewable energy sources. By 2040, the IEA expects the world's energy supply mix to be divided into four almost-equal parts: oil, gas, coal and low carbon sources.

Our global energy systems must be transformed to become more sustainable. The International Panel on Climate Change (IPCC) reports that the impact of human fossil energy consumption on the global climate is undisputable (Climate Change 2013, The Physical Science Basis).

Sustainability strategy

In Statoil, we believe that we can bring to the fore expertise, solutions and technologies linked to carbon efficiency that can support reduced emissions from energy, and also provide stronger community development. This is why we launched our sustainability strategy in 2014, following a year of analysis, risk assessment and wide-ranging engagement across the value chain and with external partners. Our objective is to be recognised as the most carbon efficient oil and gas producer, and to create lasting value for communities.

We expect and are preparing for higher carbon costs, stricter climate regulations and competition from low-carbon technologies. Reducing carbon emissions from our operations is important: not only because of the effects on climate, but also to ensure that we are competitive and efficient. To achieve this, we have set ambitious carbon and flaring intensity targets for 2020. In 2014, we implemented a new climate key performance indicator: CO² emissions reductions. This indicator measures estimated emissions reductions at an early stage in project decisions. Efforts to reduce CO2 emissions fall into two categories: energy efficiency improvements and flaring reduction initiatives. Through energy efficiency improvement projects, we combine emissions reductions with production efficiencies and cost savings.

We are investing in offshore wind and carbon capture and storage (CCS). We have been a global leader in CCS since 1996 and we continue to pioneer research and implementation within this area. Carbon capture technology programmes are currently being conducted at the Technology Centre Mongstad, and we have installed CCS technology on the Sleipner platform and at the Snøhvit subsea facility in Norway. Our renewable energy strategy focuses on offshore wind. Our growing offshore wind portfolio includes a 40% ownership share in the Sheringham Shoal Offshore Wind Farm (317 megawatt installed capacity) and a 35% ownership share in the Dudgeon Offshore Wind Farm (planned 402 megawatt capacity), both in the UK.

In addition to managing our emissions, we look beyond the company to advocate for cost-effective climate and energy policies. In 2014, our priorities included efforts to make our internal investment assessments more robust, initiatives to reduce global methane emissions and flaring, and the advocacy of consistent and ambitious climate policies, including implementation of carbon pricing tools.

Maintaining the trust of our local stakeholders and remaining accountable to them is part of our corporate values. We need to understand and respond appropriately to each specific operational setting. Creating lasting value for communities, the second strand of our sustainability strategy, implies working within a number of areas simultaneously, while demonstrating inclusive stakeholder engagement. Our broad strategic intent includes five sub-themes: Aim for outstanding resource efficiency; Prevent harm to the local environment; Create local opportunities; Respect human rights and Be open and transparent.

Our aim is to avoid causing significant harm to the local or regional environment. We strive to apply high standards to waste management, emissions to air and impact on ecosystems – wherever we work. This includes integrating environmental and social risk management into our planning and decision-making processes, at all levels in the organisation. We apply the precautionary approach and a combination of corporate requirements and risk-based local solutions to manage our environmental performance. We are committed to using resources efficiently, and reusing or recycling as appropriate. This reduces environmental impact and can also save costs. We promote the responsible use of water, from sourcing to disposal.

Climate and environmental performance

Statoil performed better than the industry average on all environmental indicators covered in the International Oil and Gas Producers' annual environmental survey in 2014. The survey also confirmed that Statoil already is one of the most carbon efficient oil and gas producers in the world.

Environmental performance data represent total figures from Statoil-operated assets, except scope 3 greenhouse gas emissions (defined below).

Our operated production increased from 974 mmboe in 2013 to 997 mmboe in 2014. Emissions of carbon dioxide (CO2) therefore increased from 15.1 million tonnes in 2013 to 15.3 million tonnes in 2014, and our total energy consumption increased by 1.3TWh to 73.7TWh in 2014. Methane (CH4) emissions increased from 37.0 thousand tonnes in 2013 to 39.0 thousand tonnes in 2014.

In 2014, we identified potential savings of 339,000 tonnes of CO2 through the new key performance indicator CO2 emissions reductions. 152,000 tonnes were related to flaring reduction initiatives for our US onshore operations. The majority of the reduction initiatives were implemented in 2014. For 2015, we have set a target of 330,000 tonnes of identified CO2 savings.

Our direct (scope 1) greenhouse gas (GHG) emissions increased from 16.0 million tonnes CO2 equivalents to 16.3 million tonnes CO2 equivalents from 2013 to 2014, mainly due to increased operated production. GHG emissions include emissions of carbon dioxide and methane. Other greenhouse gases are not included, as these are assessed to be insignificant for Statoil. Scope 2 GHG emissions were 0.3 million tonnes CO2 equivalents. Scope 2 emissions include indirect emissions as a result of energy imported from a third party. In 2014, we started reporting scope 3 GHG emissions, which entail emissions form the oil and gas products that we refine or process and sell for third party consumption. Scope 3 GHG emissions were 288 million tonnes CO2 equivalents in 2014.

Our fresh water consumption increased from 12.0 million cubic metres in 2013 to 14.8 million cubic metres in 2014. Our onshore shale operations in the USA (tight oil and shale gas) contributed significantly to the total water consumption. We are working on improving the water efficiency in our onshore activities in North America through means such as water recycling and substituting fresh water with brackish water.

Nitrogen oxide emissions were 46.0 thousand tonnes in 2014. Sulphur oxide emissions increased from 2.0 thousand tonnes in 2013 to 2.2 thousand tonnes in 2014. Total emissions of non-methane volatile organic compounds increased from 57.6 thousand tonnes in 2013 to 68.4 thousand tonnes in 2014.

In 2014, the total volume of waste was 399 thousand tonnes.

Our operations in Europe are subject to emissions allowances according to the EU Emissions Trading System (EU ETS). In 2014, over 85% of our total direct carbon dioxide emissions were related to our European operations. In addition to being part of the EU ETS, emissions from our activities in Norway are subject to CO2 tax (approximately USD 65 per tonne of CO2 for offshore activities). In 2014, we paid NOK 3.4 billion in CO2 tax in Norway.

Human rights

Our commitment to respect human rights is based on the International Bill of Human Rights and the International Labour Organization's (ILO) 1998 Declaration on Fundamental Rights and Principles at Work. We follow the United Nations (UN) Global Compact Principles and the Voluntary Principles on Security and Human Rights (VPSHR). We strive to conduct our business operations consistently with the UN Guiding Principles on Business and Human Rights and the OECD Guidelines for Multinational Enterprises.

Following a risk-based approach, we assess human rights aspects and potential impacts of our ongoing activities and new business opportunities in order to avoid adverse impacts on individuals and nearby communities potentially affected by our operations. Our human rights efforts cover topics such as community impact, labour standards and security. Human rights aspects are incorporated in our annual monitoring plans, as relevant, based on risk.

In 2014, we continued our efforts to implement our commitment to respect human rights consistently with the UN Guiding Principles on Business and Human Rights and our values and policies. Key initiatives included:

• Incorporating 'respect for human rights' as a central element in our new sustainability strategy and enhancing these aspects in the management system, including corporate risk management, project risk assessment and investment decision review.
• Initiating a process to review our human rights commitment statement.
• Developing a corporate framework for site-level community grievance mechanisms and continued implementing such mechanisms for our operations in Brazil, Tanzania, the USA and relevant exploration activities.
• Assessing how we manage human rights risks in the supply chain and identifying improvement measures. The conclusions were endorsed by the Corporate Executive Committee and the Board's Safety, Security, Sustainability and Ethics Committee.
• Developing and applying tools for improved follow-up of human rights impacts in operated and non-operated business partnerships.
• Continuing our active participation in joint industry initiatives, such as the Business and Human Rights Project at IPIECA (the global oil and gas industry association for environmental and social issues).

The use of security forces may represent a particular human rights risk in situations where security services are not well regulated or security guards are not adequately trained. Statoil is an active participant in the Voluntary Principles on Security and Human Rights Initiative and strives to respect and implement these principles in our operations. Prior to procuring security services, we include human rights criteria as part of pre-qualification screening, integrity due diligence and contractual provisions and clauses, as appropriate. Our security providers are given training that is commensurate with their duties. In 2014, Statoil used armed security services provided by the local government in Tanzania and Nigeria. Human rights training was provided in each case.

Working with our suppliers

We are committed to using suppliers who operate consistently in accordance with our values and who maintain high standards of safety, security and sustainability when they work for us. Safety, security and sustainability aspects are incorporated in all phases of our procurement process. All potential suppliers must meet our minimum requirements in order to qualify as a supplier. These requirements include safety, security and environmental criteria. Based on a risk assessment, additional human rights criteria may be included in the qualification process. Additionally, following a risk-based approach, suppliers are screened for material integrity risks, and if relevant, subjected to a more extensive integrity due diligence review, which includes human rights.

All potential suppliers for contracts valued at more than NOK 7 million are required to sign our Supplier Declaration, which establishes minimum standards for ethics, anti-corruption, security, health and safety, and commits our suppliers to respect human rights and to promote these principles among their own sub-suppliers. The Supplier Declaration is available at www.statoil.com. A supplier follow-up strategy, based on risk, is required to be established after a contract has been awarded. We perform monitoring activities such as follow-up, verifications and audits to manage identified risks. In 2014, we conducted an assessment of how we manage human rights risks in the supply chain, and identified improvement areas and actions for 2015.

Transparency and anti-corruption

We believe that transparency is a cornerstone of good governance. It allows businesses to prosper in a predictable environment, contributes to a level playing field and enables citizens to hold governments accountable. We have zero tolerance for corruption in our operations.

Our business generates significant revenues for governments. Transparency is vital to ensuring that the wealth derived from the energy we produce is put to effective and equitable use. We were one of the first major oil and gas companies to voluntarily start disclosing all revenues and payments to governments in the countries where we operate. We welcome initiatives to strengthen and harmonise global revenue transparency legislation, including project-by-project disclosure of payments, as laid out in the EU Directive and a similar Norwegian legislation that is effective from 1 January 2014. For Statoil, it is important that revenue transparency regulation applies globally, is effective, and creates a level playing field for all companies, communities and governments.

Statoil is opposed to all forms of corruption, including facilitation payments. We have in place a company-wide anti-corruption compliance programme that ensures implementation of our zero-tolerance policy. The anti-corruption compliance programme entails mandatory procedures designed to comply with applicable laws and regulations, and training on relevant issues such as gifts, hospitality and conflict of interest. Compliance officers, who are responsible for ensuring that ethics and anti-corruption considerations are integrated into our business activities, constitute an important part of the programme.

Our Ethics Code of Conduct describes our business practice requirements and the behaviour we expect in areas such as anti-corruption, fair competition, conflict of interest and a non-discriminatory working environment with equal opportunities. Everyone who works for Statoil, including employees, officers, board members and others who act on Statoil's behalf, must follow this code. The code is available in local languages in the countries where we operate, and in the Ethics and values section at www.statoil.com.

Statoil seeks and develops relations with suppliers and partners that uphold a commitment to our values and operational integrity. Our company-wide integrity due diligence process helps us to understand potential partners and suppliers, how their business is conducted and their values. Before entering into a new business relationship, or extending an existing one, the relationship has to satisfy our integrity due diligence requirements, which include integrity, human rights and labour standards criteria.

A priority in 2014 was to develop and implement good practice tools and requirements for follow-up of non-operated joint ventures. Another focus area for our anti-corruption work was strengthening our compliance officer network.

Additionally, we opened our Ethics Helpline to external parties, after receiving a license from the Norwegian Data Protection Authorities.

Other relevant reports

Some of the most significant safety, security and sustainability performance indicators at group level are presented above. More information about Statoil's safety and sustainability policies, activities, plans and performance is available in the 2014 Sustainability Report, based on the Global Reporting Initiative

G4 Guidelines. Detailed information about payments to governments is available in the 2014 Payments to Governments report. Both reports are available at www.statoil.com.

People and organisation

Statoil's overall strategic objective is to build a globally competitive company which is an exceptional place to perform and develop.

We are committed to attracting and selecting the right people and providing opportunities for people to grow. Our global people policy is the most important guideline for our people processes, together with our values and Ethics Code of Conduct. The policy is available in The Statoil Book at Statoil.com.

In Statoil we encourage our employees to take responsibility for their own learning and development and continuously build new skills and share knowledge, supported by our Corporate University LEAP (Learn, Engage, Achieve, Perform). We develop and deploy our people through the People@Statoil process, our common annual platform for measuring performance, rewards, development and deployment. The process is described in the Statoil Book. We endeavour to ensure a good match between employees' professional interests and business goals and needs.

We promote diversity among our employees. The importance of diversity is stated explicitly in Statoil's values and Ethics Code of Conduct. We try to create the same opportunities for everyone and do not tolerate discrimination or harassment of any kind in our workplace. In 2014, we continued to focus on strengthening women in leadership and professional positions and on building broad international experience in our workforce. Our commitment to diversity and inclusion was demonstrated in the 2014 Global People Survey, where we maintained our high score of 5.1 (6 being the highest) for the existence of zero tolerance for discrimination and harassment within the workplace.

In 2014, the overall percentage of women in the company was 31% - and 45% of the members of the board of directors were women, as were 11% of the corporate executive committee. We pay close attention to male-dominated positions and discipline areas, and in 2014 the proportion of female engineers remained stable at 27% in Statoil ASA. Among staff engineers with up to 20 years' experience, the proportion of women increased to 31%. We continue to strive to increase the number of female managers through our development programmes, and in 2014 the total proportion of female managers in Statoil increased to 28%.

Statoil works systematically with recruitment and development programmes in order to build a diverse workforce by attracting, recruiting and retaining people of both genders and different nationalities and age groups across all types of positions. The intake of apprentices in Norway is an important part of the company's recruitment of skilled workers and commitment to the education and training of young technicians and operators in the oil and gas industry. In 2014, apprenticeships were given to 135 new students; of these 36 were female. The total number of apprentices in Statoil is 315.

In 2014, 20% of employees and 22% of our managerial staff held nationalities other than Norwegian. Outside Norway, Statoil aims to increase the number of people and managers who are locally recruited and to reduce the long-term use of expats in business operations. In 2014, 60% of new hires in Statoil were non-Norwegians and 33% were women.

At Statoil we reward our people on the basis of their performance, giving equal emphasis to delivery and behaviour. Our reward approach is adapted to local market conditions at the locations in which we operate and is transparent, non-discriminatory and supports equal opportunities. Given the same position, experience and performance, our employees will be at the same remuneration level relative to the local market. This is demonstrated in the salary ratio between women and men at different levels in Statoil ASA. In 2014 this ratio remained very high, with an average of 98%.

In 2014, management and employee representatives collaborated closely, in particular on the two corporate change initiatives Statoil Technical Efficiency Programme (STEP) and Organisational Efficiency Programme (OE). In addition, the European Works Council continued to be an important channel of communication between the company and employees. We promote good employee and industrial relations practices through various networks and forums, including IndustriALL Global Union (IndustriALL) and International Labour Organisation (ILO).

In Statoil, the total turnover rate for 2014 increased to 4.5%. On 31 December 2014, the Statoil group employed 22,516 permanent employees and 2% of the workforce worked part-time. In the annual organizational and working environment survey, which continued to have a high response of 86%, our employees reported an overall satisfaction of 4.5. This is a slight decrease from the score of 4.6 in 2013.

About our People data

Our people performance data relates to permanent employees in our direct employment. Statoil defines consultants as contracted personnel that are mainly based in our offices. Temporary employees and enterprise personnel are not included in the workforce table. Enterprise personnel are defined as third party service providers and work on our on-shore and off-shore operations. These were roughly estimated to be around 42,000 in 2014. The information about people policies applies to Statoil and its subsidiaries.

More information about Statoil's approach to People and Organisation is available in the 2014 Sustainability Report

Total workforce by region, gender, employment type and new hires (headcount)*

	Permanent employees		% Women		New hires		%Part time		Consultants
Geographical region	2014	2013	2014	2013	2014	2013	2014	2013	2014	2013
Norway	19,670	20,336	30%	30%	263	923	3%	3%	1039	1826
Rest of Europe	909	935	31%	30%	101	72	3%	2%	119	145
Africa	117	140	34%	33%	13	34	na	na	21	30
Asia	135	140	52%	53%	5	26	na	na	11	11
North America	1,375	1,559	34%	35%	92	303	na	na	210	7
South America	310	303	40%	38%	27	56	4%	na	11	103
TOTAL	22,516	23,413	31%	31%	501	1414	2%	3%	1411	2122
Non-OECD	677	690	40%	39%	59	119	na	na	46	146

* Enterprise personnel, defined as third-party service providers who work at our onshore and offshore operations, are not included. These were roughly estimated to be around 42,000 in 2014.

Research and development

Statoil is a technology-intensive company and research and development is an integral part of our strategy. We continuously develop and deploy innovative technologies to ensure safe and efficient operations and to deliver on our strategic objectives.

Statoil's corporate technology strategy sets the strategic direction for how technology development and implementation can address the challenges and contribute to achieving the corporate ambitions. Statoil believe that technology is a critical success factor in the business environment where we operate. In addition to requiring capital efficiency, this environment is characterised by a broad and complex opportunity set, stricter demands on our licence to operate and tougher competition. In this context, technology is increasingly important for resource access and value creation. The technology development activities aim to reduce field development, drilling and operating costs.

Statoil utilises a range of tools for the development of new technologies where choice of tool is dependent on strategic importance of technology and the position related to intellectual property. The toolbox includes:

• in-house R&D
• collaborative development projects with our major suppliers
• project related development as part of our field development activities
• direct investment in technology start-up companies through our Statoil technology invest venture activities
• invitation to open innovation challenges as part of Statoil innovate

Statoil has demonstrated ability to overcome significant technical challenges through the development and deployment of innovative technologies. Our technology strategy, "putting technology to work", supports the business strategy and strengthens Statoil's position as a technology-driven upstream company. It is based on three main principles:

• Prioritising business-critical technologies increased the focus on upstream technologies
• Strengthening our licence to operate continuously focusing on technologies for safe, reliable and efficient operations
• Expanding our capabilities build on competitive advantages, stimulate innovation and take a long-term view on selected potentially high-impact technology ventures

Statoil's corporate priorities send clear messages related to high-grading the portfolio for value growth, and the necessity to reduce costs and improve return on capital employed. The corporate technology strategy's focus on both value enhancing and cost effective solutions is well aligned with these messages. Increased focus on development and re-use of standardised technologies will be a key to success.

Statoil's Research, development and innovation business cluster (RDI) is responsible for carrying out research to meet Statoil's business needs and is organised in four programmes: exploration, mature area developments and IOR, frontier developments and un-conventionals. In addition there are two other units - innovation and projects. RDI has four research centres in Norway with world leading laboratories and large-scale test facilities. Internationally RDI is present close to the operations in Rio de Janeiro (Brazil), Houston and Austin (US), Calgary and St. Johns (Canada) and Beijing (China). Cooperation with external environments plays an important role for R&D in Statoil and RDI has an Academia programme that coordinates cooperation with Norwegian and international universities.

Research and development expenditures were NOK 3.0 billion and NOK 3.2 billion in 2014 and 2013, respectively.

Board developments

Statoil's board of directors consists of 11 members.

The composition of the board has been changed during 2014. Øystein Løseth is new member of the board of Statoil ASA since 1 October 2014. Mr. Løseth is also a member of the board's audit committee.

The board held eight ordinary board meetings and three extraordinary board meetings in 2014. The average attendance at these board meetings was 95,6%.

The board's audit committee held seven meetings in 2014 and the attendance was 96,5%.

The board's compensation and executive development committee held seven meetings in 2014 and the attendance was 100%.

The board's safety, sustainability and ethics committee held five meetings in 2014 and the attendance was 90%.

In 2014, the board inter alia visited Statoil's activities in Tanzania. The entire board, or part of it, regularly visits several Statoil locations, and a board trip to an international location is normally made on a semi-annual basis. In visiting Statoil locations globally, the board emphasises the importance of improving its insight into, and knowledge about, Statoil's commercial activities as well as the company's local organisations.

Board statement on corporate governance

To ensure sound corporate practice, Statoil's organisation is structured and managed in accordance with the Norwegian Code of Practice for Corporate Governance.

Statoil's board of directors actively adheres to good corporate governance standards and will at all times ensure that Statoil either complies with the Norwegian Code of Practice for Corporate Governance (the "Code") or explains possible deviations from the Code. The topic of corporate governance is subject to regular assessment and discussion by the board. The Code can be found at www.nues.no.

The Code covers 15 topics, and the board statement covers each of these topics and describes Statoil's adherence to the Code. The statement describes the foundation and principles for Statoil's corporate governance structure, while more detailed factual information can be found on our website, in our annual report on form 20-F, and in our sustainability report. Links to relevant information at our website are included in the statement.

The statement from the board of directors is provided as a separate report available on statoil.com.

Board statement on Reporting of payments to governments

Today, the board of directors and the chief executive officer have reviewed and approved the board of director's report prepared in accordance with the Norwegian Securities Trading Act section 5-5a regarding Reporting on payments to governments as of 31 December 2014.

To the best of our knowledge, we confirm that:

• The information presented in the report has been prepared in accordance with the requirements of the Norwegian Securities Trading Act section 5-5a and associated regulations

The report on payments to governments is provided as a separate report available on www.statoil.com.

Statement on compliance

Today, the board of directors, the chief executive officer and the chief financial officer reviewed and approved the board of directors' report and the Statoil ASA consolidated and separate annual financial statements as of 31 December 2014.

To the best of our knowledge, we confirm that:

• the Statoil ASA consolidated annual financial statements for 2014 have been prepared in accordance with IFRSs and IFRICs as adopted by the European Union (EU), IFRSs as issued by the International Accounting Standards Board (IASB) and additional Norwegian disclosure requirements in the Norwegian Accounting Act, and that
• the separate financial statements for Statoil ASA for 2014 have been prepared in accordance with the Norwegian Accounting Act and Norwegian Accounting Standards, and that
• the board of directors' report for the group and the parent company is in accordance with the requirements in the Norwegian Accounting Act and Norwegian Accounting Standard no 16, and that
• the information presented in the financial statements gives a true and fair view of the company's and the group's assets, liabilities, financial position and results for the period viewed in their entirety, and that
• the board of directors' report gives a true and fair view of the development, performance, financial position, principle risks and uncertainties of the company and the group.

Consolidated financial statement Statoil

CONSOLIDATED STATEMENT OF INCOME

				Full year
(in NOK billion)	Note	2014	2013 (restated*)	2012 (restated*)
Revenues		606.8	616.6	700.5
Net income from associated companies		(0.3)	0.1	1.7
Other income	4	16.1	17.8	16.0
Total revenues and other income	3	622.7	634.5	718.2
Purchases [net of inventory variation]		(301.3)	(306.9)	(362.2)
Operating expenses		(72.9)	(74.1)	(60.8)
Selling, general and administrative expenses		(7.3)	(7.8)	(10.0)
Depreciation, amortisation and net impairment losses	11, 12	(101.4)	(72.4)	(60.5)
Exploration expenses	12	(30.3)	(18.0)	(18.1)
Net operating income	3	109.5	155.5	206.6
Net financial items	8	(0.0)	(17.0)	0.1
Income before tax		109.4	138.4	206.7
Income tax	9	(87.4)	(99.2)	(137.2)
Net income		22.0	39.2	69.5
Attributable to equity holders of the company		21.9	39.9	68.9
Attributable to non-controlling interests		0.1	(0.6)	0.6
Basic earnings per share (in NOK)	10	6.89	12.53	21.66
Diluted earnings per share (in NOK)	10	6.87	12.50	21.60

* Related to a change in significant accounting policies in 2014, see note 2 Significant accounting policies.

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

(in NOK billion)	Note	2014	2013	Full year 2012
Net income		22.0	39.2	69.5
Actuarial gains (losses) on defined benefit pension plans	19	(0.0)	(5.9)	5.5
Income tax effect on income and expense recognised in OCI		0.9	1.5	(1.5)
Items that will not be reclassified to statement of income		0.9	(4.4)	4.0
Foreign currency translation differences		41.6	22.9	(11.9)
Items that may be subsequently reclassified to statement of income		41.6	22.9	(11.9)
Other comprehensive income		42.5	18.5	(7.9)
Total comprehensive income		64.5	57.7	61.6
Attributable to the equity holders of the company		64.4	58.3	61.0
Attributable to non-controlling interests		0.1	(0.6)	0.6

CONSOLIDATED BALANCE SHEET

			At 31 December
(in NOK billion)	Note	2014	2013
ASSETS
Property, plant and equipment	11	562.1	487.4
Intangible assets	12	85.2	91.5
Investments in associated companies		8.4	7.4
Deferred tax assets	9	12.9	8.2
Pension assets	19	8.0	5.3
Derivative financial instruments	25	29.9	22.1
Financial investments	13	19.6	16.4
Prepayments and financial receivables	13	5.7	8.5
Total non-current assets		731.7	646.8
Inventories	14	23.7	29.6
Trade and other receivables	15	83.3	81.8
Derivative financial instruments	25	5.3	2.9
Financial investments	13	59.2	39.2
Cash and cash equivalents	16	83.1	85.3
Total current assets		254.8	238.8
Total assets		986.4	885.6
EQUITY AND LIABILITIES
Shareholders' equity		380.8	355.5
Non-controlling interests		0.4	0.5
Total equity	17	381.2	356.0
Finance debt	18, 22	205.1	165.5
Deferred tax liabilities	9	71.5	71.0
Pension liabilities	19	27.9	22.3
Provisions	20	117.2	101.7
Derivative financial instruments	25	4.5	2.2
Total non-current liabilities		426.2	362.7
Trade and other payables	21	100.7	95.6
Current tax payable		39.6	52.8
Finance debt	18	26.5	17.1
Dividends payable	17	5.7	0.0
Derivative financial instruments	25	6.6	1.5
Total current liabilities		179.0	166.9
Total liabilities		605.2	529.6
Total equity and liabilities		986.4	885.6

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

		Additional paid	Retained	Currency translation	Shareholders'	Non-controlling
(in NOK billion)	Share capital	in capital	earnings	adjustments	equity	interests	Total equity
At 31 December 2011	8.0	40.7	218.5	11.7	278.9	6.3	285.2
Net income for the period			68.9		68.9	0.6	69.5
Other comprehensive income			4.0	(11.9)	(7.9)		(7.9)
Dividends			(20.7)		(20.7)		(20.7)
Other equity transactions		(0.1)	0.1		0.0	(6.2)	(6.2)
At 31 December 2012	8.0	40.6	270.8	(0.2)	319.2	0.7	319.9
Net income for the period			39.9		39.9	(0.6)	39.2
Other comprehensive income			(4.4)	22.9	18.5		18.5
Dividends			(21.5)		(21.5)		(21.5)
Other equity transactions		(0.3)	(0.3)		(0.6)	0.4	(0.2)
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

Refer to note 17 Shareholders' equity.

CONSOLIDATED STATEMENT OF CASH FLOWS

(in NOK billion)	Note	2014	2013	Full year 2012
Income before tax		109.4	138.4	206.7
Depreciation, amortisation and net impairment losses	11, 12	101.4	72.4	60.5
Exploration expenditures written off		13.7	3.1	3.1
(Gains) losses on foreign currency transactions and balances		(3.1)	4.8	3.3
(Gains) losses from dispositions	4	(12.4)	(17.6)	(14.7)
(Increase) decrease in other items related to operating activities		3.9	6.6	(14.6)
(Increase) decrease in net derivative financial instruments	25	(2.8)	11.7	(1.1)
Interest received		2.1	2.1	2.6
Interest paid		(3.4)	(2.5)	(2.5)
Cash flows provided by operating activities before taxes paid and working capital items		208.8	218.8	243.3
Taxes paid		(96.6)	(114.2)	(119.9)
(Increase) decrease in working capital		14.2	(3.3)	4.6
Cash flows provided by operating activities		126.5	101.3	128.0
Capital expenditures and investments		(122.6)	(114.9)	(113.1)
(Increase) decrease in financial investments		(12.7)	(23.2)	(12.1)
(Increase) decrease in other non-current items		0.8	0.6	(1.2)
Proceeds from sale of assets and businesses	4	22.6	27.1	29.8
Cash flows used in investing activities		(112.0)	(110.4)	(96.6)
New finance debt		20.6	62.8	13.1
Repayment of finance debt		(9.7)	(7.3)	(12.2)
Dividend paid	17	(33.7)	(21.5)	(20.7)
Net current finance debt and other		(0.3)	(7.3)	1.6
Cash flows provided by (used in) financing activities		(23.1)	26.6	(18.2)
Net increase (decrease) in cash and cash equivalents		(8.6)	17.5	13.2
Effect of exchange rate changes on cash and cash equivalents		5.7	2.9	(1.9)
Cash and cash equivalents at the beginning of the period (net of overdraft)	16	85.3	64.9	53.6
Cash and cash equivalents at the end of the period (net of overdraft)	16	82.4	85.3	64.9

Cash and cash equivalents included a net bank overdraft of NOK 0.7 billion at 31 December 2014, a net bank overdraft that was rounded to zero at 31 December 2013 and NOK 0.3 billion at 31 December 2012.

Notes to the consolidated financial statements

1 Organisation

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

Statoil ASA is listed on the Oslo Stock Exchange (Norway) and the New York Stock Exchange (USA).

The Statoil group's business consists principally of the exploration, production, transportation, refining and marketing of petroleum and petroleum-derived products and other forms of energy.

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

The Consolidated financial statements of Statoil for the full year 2014 were authorised for issue in accordance with a resolution of the board of directors on 10 March 2015.

2 Significant accounting policies

Statement of compliance

The Consolidated financial statements of Statoil ASA and its subsidiaries (Statoil) have been prepared in accordance with International Financial Reporting Standards (IFRSs) as adopted by the European Union (EU) and also comply with IFRSs as issued by the International Accounting Standards Board (IASB).

Basis of preparation

The financial statements are prepared on the historical cost basis with some exceptions, as detailed in the accounting policies set out below. These policies have been applied consistently to all periods presented in these Consolidated financial statements. Certain amounts in the comparable years have been restated to conform to current year presentation. The subtotals and totals in some of the tables may not equal the sum of the amounts shown due to rounding.

Operating related expenses in the Consolidated statement of income are presented as a combination of function and nature in conformity with industry practice. Purchases [net of inventory variation] and Depreciation, amortisation and net impairment losses are presented in separate lines by their nature, while Operating expenses and Selling, general and administrative expenses as well as Exploration expenses are presented on a functional basis. Significant expenses such as salaries, pensions, etc. are presented by their nature in the notes to the Consolidated financial statements.

Standards and amendments to standards, issued but not yet adopted

At the date of these Consolidated financial statements, the following standards and amendments to standards applicable to Statoil have been issued, but were not yet effective:

• IFRS 15 Revenue from Contracts with Customers, issued in May 2014 and effective from 1 January 2017 covers the recognition of such revenue in the financial statements and related disclosure and will replace IAS 18 Revenue. The standard requires identification of the performance obligations for the transfer of goods and services in each contract with customers. Revenue will be recognised upon satisfaction of the performance obligations in the amounts that reflect the consideration to which the company expects to be entitled in exchange for those goods and services. The standard requires adoption either on a retrospective basis or on the basis of the cumulative effect on retained earnings. Statoil is in the process of evaluating the potential impact of IFRS 15, and has not yet determined its adoption date or its implementation method for the standard.
• The amendment to IFRS 11 Accounting for Acquisitions of Interests in Joint Operations, issued in May 2014 and effective from 1 January 2016, establishes requirements for the accounting for acquisitions of interests in joint operations in which the activity constitutes a business. The amendment is to be applied prospectively. Statoil will adopt the amendment on the effective date.
• IFRS 9 Financial Instruments, issued in its final form in July 2014 and effective from 1 January 2018, will replace IAS 39 Financial Instruments: Recognition and Measurement. IFRS 9 introduces a new model for classification and measurement of financial assets and financial liabilities, a reformed approach to hedge accounting, and a more forward-looking impairment model. The standard's transition provisions partly require retrospective adoption, and partly prospective adoption. Statoil is in the process of evaluating the potential impact of IFRS 9, and has not yet determined its adoption date for the standard.
• The amendments to IFRS 10 Consolidated Financial Statements and IAS 28 Investments in Associates and Joint Venture, issued in September 2014 and effective from 1 January 2016, establish requirements for the accounting for sales or contributions of assets between an investor and its associate or joint venture. Whether or not the assets are housed in a subsidiary, a full gain or loss will be recognised in the Consolidated statement of income when the transaction involves assets that constitute a business, whereas a partial gain or loss will be recognised when the transaction involves assets that do not constitute a business. The amendments are to be applied prospectively. Statoil will adopt the amendments on the effective date.

Other standards and amendments to standards, issued but not yet effective, are either not expected to impact Statoil's Consolidated financial statements materially, or are not expected to be relevant to Statoil's Consolidated financial statements upon adoption.

Changes in accounting policies in the current period

Natural gas sales made by Statoil subsidiaries on behalf of the Norwegian State

With effect from 2014, Statoil changed its policy for the presentation of natural gas sales, and related expenditure, on behalf of the Norwegian State made by Statoil subsidiaries in their own name. Where the subsidiary is considered the principal in the transaction, such gas sales were previously presented gross in the Consolidated statement of income, while the Norwegian State's share of profit or loss was reflected in Statoil's Selling, general and administrative expenses as expenses or reduction of expenses, respectively. With effect from 2014, such natural gas sales by Statoil subsidiaries on behalf of the Norwegian State, are presented net in the Consolidated statement of income. The sales are linked to, and in nature no different from, Statoil ASA's marketing and sale of natural gas in its own name, but for the Norwegian State's account and risk, which are presented net. Following the change in policy, the assessment of the principal in the transactions and the related presentation of sales for the account and risk of the Norwegian State are determined on a consolidated basis. The revised policy more consistently reflects the sales of natural gas for the account and risk of the Statoil group, excluding transactions on behalf of the Norwegian State, and therefore provides more relevant information.

The changes have been applied retrospectively in these Consolidated financial statements including the notes. The change in accounting policy is immaterial to the Consolidated statement of income for the periods covered by these Consolidated financial statements. There is no impact on Net operating income, Net income, the Consolidated balance sheet or the Consolidated statement of cash flows from this policy change.

Recognition of disputed income tax positions

With effect from 2014, Statoil changed its policy for the recognition of income tax positions for which payment has been made despite Statoil disputing the tax claim involved. While previously only amounts virtually certain of being refunded to Statoil were reflected as assets for positions involving such disputed income tax amounts, as of 2014 Statoil reflects as assets any disputed amounts that probably will be refunded. The corresponding impact in the Statement of Income is reflected as a reduction within Income tax. Disputed income tax positions are now reflected in the Consolidated balance sheet as assets if a refund from the relevant tax authority is probable, and as liabilities if an outflow of cash from Statoil is probable. This ensures that the accounts better and more consistently reflect the underlying facts and evaluations in each case, and consequently provide more relevant information, independently of whether an income tax dispute occurs in a tax regime (such as for instance Norway) that requires up-front payment in disputed matters, or in a tax regime where disputed payments are not due until a dispute has been legally settled in Statoil's disfavour.

The change in accounting policy is not material to the Consolidated statement of income, the Consolidated balance sheet and the Consolidated statement of cash flows for the periods covered by these Consolidated financial statements, and comparative figures have not been adjusted.

Other accounting policy changes in 2014

Other accounting policy changes in 2014 compared to the annual financial statements for 2013 have not materially impacted Statoil's Consolidated financial statements upon adoption. Such other accounting policy changes in 2014 include implementation of the amendments to IAS 32 Financial Instruments: Presentation, issued in December 2011, and IFRIC 21 Levies, issued in May 2013.

Basis of consolidation

Subsidiaries

The Consolidated financial statements include the accounts of Statoil ASA and its subsidiaries. Entities are determined to be controlled by Statoil, and consolidated in Statoil's financial statements, when Statoil has power over the entity, ability to use that power to affect the entity's returns, and exposure to, or rights to, variable returns from its involvement with the entity.

All intercompany balances and transactions, including unrealised profits and losses arising from Statoil's internal transactions, have been eliminated in full. Non-controlling interests are presented separately within equity in the balance sheet.

Joint operations and similar arrangements, joint ventures and associates

An arrangement to which Statoil is party is defined as jointly controlled when the sharing of control is contractually agreed, which exists only when decisions about the relevant activities require the unanimous consent of the parties sharing control. Such joint arrangements are classified as either joint operations or joint ventures.

The parties to a joint operation have rights to the assets and obligations for the liabilities, relating to their respective share of the joint arrangement. In determining whether the terms of contractual arrangements and other facts and circumstances lead to a classification as joint operations, Statoil in particular considers the nature of products and markets of the arrangement and whether the substance of their agreements is that the parties involved have rights to substantially all the arrangement's assets. Statoil accounts for the assets, liabilities, revenues and expenses relating to its interests in joint operations in accordance with the principles applicable to those particular assets, liabilities, revenues and expenses. Normally this leads to accounting for the joint operation in a manner similar to the previous proportionate consolidation method.

Those of Statoil's exploration and production licence activities that are within the scope of IFRS 11 Joint Arrangements have been classified as joint operations. A considerable number of Statoil's unincorporated joint exploration and production activities are conducted through arrangements that are not jointly controlled, either because unanimous consent is not required among all parties involved, or no single group of parties has joint control over the activity. Licence activities where control can be achieved through agreement between more than one combination of involved parties are considered to be outside the scope of IFRS 11, and these activities are accounted for on a pro-rata basis using Statoil's ownership share. In determining whether each separate arrangement related to Statoil's unincorporated joint exploration and production licence activities is within or outside the scope of IFRS 11, Statoil considers the terms of relevant licence agreements, governmental concessions and other legal arrangements impacting how and by whom each arrangement is controlled. Subsequent changes in the ownership shares and number of licence participants, transactions involving licence shares, or changes in the terms of relevant agreements may lead to changes in Statoil's evaluation of control and impact a licence arrangement's classification in relation to IFRS 11 in Statoil's Consolidated financial statements. Currently there are no significant differences in Statoil's accounting for unincorporated licence arrangements whether in scope of IFRS 11 or not.

Joint ventures, in which Statoil has rights to the net assets, are accounted for using the equity method.

Investments in companies in which Statoil has neither control nor joint control, but has the ability to exercise significant influence over operating and financial policies, are classified as associates and are accounted for using the equity method.

Statoil as operator of joint operations and similar arrangements

Indirect operating expenses such as personnel expenses are accumulated in cost pools. These costs are allocated on an hours incurred basis to operating segments and Statoil operated joint operations under IFRS 11 and to similar arrangements (licences) outside the scope of IFRS 11. Costs allocated to the other partners' share of operated joint operations and similar arrangements reduce the costs in the Consolidated statement of income. Only Statoil's share of the statement of income and balance sheet items related to Statoil operated joint operations and similar arrangements are reflected in the Consolidated statement of income and the Consolidated balance sheet.

Reportable segments

Statoil identifies its operating segments on the basis of those components of Statoil that are regularly reviewed by the chief operating decision maker, Statoil's corporate executive committee (CEC). Statoil combines operating segments when these satisfy relevant aggregation criteria.

Statoil's accounting policies as described in this note also apply to the specific financial information included in reportable segments related disclosure in these Consolidated financial statements.

Foreign currency translation

In preparing the financial statements of the individual entities, transactions in foreign currencies (those other than functional currency) are translated at the foreign exchange rate at the dates of the transactions. Monetary assets and liabilities denominated in foreign currencies are translated to the functional currency at the foreign exchange rate at the balance sheet date. Foreign exchange differences arising on translation are recognised in the Consolidated statement of income as foreign exchange gains or losses within Net financial items. Foreign exchange differences arising from the translation of estimatebased provisions, however, generally are accounted for as part of the change in the underlying estimate and as such may be included within the relevant operating expense or income tax sections of the Consolidated statement of income depending on the nature of the provision. Non-monetary assets that are measured at historical cost in a foreign currency are translated using the exchange rate at the date of the transactions.

Presentation currency

For the purpose of the Consolidated financial statements, the statement of income and the balance sheet of each entity are translated from the functional currency into the presentation currency, Norwegian kroner (NOK). The assets and liabilities of entities whose functional currencies are other than NOK, including Statoil's parent company Statoil ASA whose functional currency is United States dollar (USD), are translated into NOK at the foreign exchange rate at the balance sheet date. The revenues and expenses of such entities are translated using the foreign exchange rates on the dates of the transactions. Foreign exchange differences arising on translation from functional currency to presentation currency are recognised separately in Other comprehensive income (OCI).

Business combinations

Determining whether an acquisition meets the definition of a business combination requires judgement to be applied on a case by case basis. Acquisitions are assessed under the relevant IFRS criteria to establish whether the transaction represents a business combination or an asset purchase. Depending on the specific facts, acquisitions of exploration and evaluation licences for which a development decision has not yet been made, have largely been concluded to represent asset purchases.

Business combinations, except for transactions between entities under common control, are accounted for using the acquisition method of accounting. The acquired identifiable tangible and intangible assets, liabilities and contingent liabilities are measured at their fair values at the date of the acquisition. Acquisition costs incurred are expensed under Selling, general and administrative expenses.

Revenue recognition

Revenues associated with sale and transportation of crude oil, natural gas, petroleum products and other merchandise are recognised when risk passes to the customer, which is normally when title passes at the point of delivery of the goods, based on the contractual terms of the agreements.

Revenues from the production of oil and gas properties in which Statoil shares an interest with other companies are recognised on the basis of volumes lifted and sold to customers during the period (the sales method). Where Statoil has lifted and sold more than the ownership interest, an accrual is recognised for the cost of the overlift. Where Statoil has lifted and sold less than the ownership interest, costs are deferred for the underlift.

Revenue is presented net of customs, excise taxes and royalties paid in-kind on petroleum products. Revenue is presented gross of in-kind payments of amounts representing income tax.

Sales and purchases of physical commodities, which are not settled net, are presented on a gross basis as Revenues and Purchases [net of inventory variation] in the statement of income. Activities related to trading and commodity-based derivative instruments are reported on a net basis, with the margin included in Revenues.

Transactions with the Norwegian State

Statoil markets and sells the Norwegian State's share of oil and gas production from the Norwegian continental shelf (NCS). The Norwegian State's participation in petroleum activities is organised through the State's direct financial interest (SDFI). All purchases and sales of the SDFI's oil production are classified as Purchases [net of inventory variation] and Revenues, respectively. Statoil sells, in its own name, but for the Norwegian State's account and risk, the State's production of natural gas. This sale, and related expenditures refunded by the Norwegian State, are presented net in the Consolidated financial statements.

Employee benefits

Wages, salaries, bonuses, social security contributions, paid annual leave and sick leave are accrued in the period in which the associated services are rendered by employees of Statoil.

Research and development

Statoil undertakes research and development both on a funded basis for licence holders and on an unfunded basis for projects at its own risk. Statoil's own share of the licence holders' funding and the total costs of the unfunded projects are considered for capitalisation under the applicable IFRS requirements. Subsequent to initial recognition, any capitalised development costs are reported at cost less accumulated amortisation and accumulated impairment losses.

Income tax

Income tax in the Consolidated statement of income comprises current and deferred tax expense. Income tax is recognised in the Consolidated statement of income except when it relates to items recognised in OCI.

Current tax consists of the expected tax payable on the taxable income for the year and any adjustment to tax payable for previous years. Uncertain tax positions and potential tax exposures are analysed individually, and the best estimate of the probable amount for liabilities to be paid (unpaid potential tax exposure amounts, including penalties) and for assets to be received (disputed tax positions for which payment has already been made) in each case is recognised within current tax or deferred tax as appropriate. Interest income and interest expenses relating to tax issues are estimated and recognised in the period in which they are earned or incurred, and are presented within Net financial items in the Consolidated statement of income.

Deferred tax assets and liabilities are recognised for the future tax consequences attributable to differences between the carrying amounts of existing assets and liabilities and their respective tax bases, subject to the initial recognition exemption. The amount of deferred tax is based on the expected manner of realisation or settlement of the carrying amount of assets and liabilities, using tax rates enacted or substantially enacted at the balance sheet date. A deferred tax asset is recognised only to the extent that it is probable that future taxable income will be available against which the asset can be utilised. In order for a deferred tax asset to be recognised based on future taxable income, convincing evidence is required, taking into account the existence of contracts, production of oil or gas in the near future based on volumes of proved reserves, observable prices in active markets, expected volatility of trading profits and similar facts and circumstances.

A petroleum tax, currently levied at a rate of 51%, is levied on profits derived from petroleum production and pipeline transportation on the NCS. The petroleum tax is applied to relevant income in addition to the standard 27% income tax, resulting in a 78% marginal tax rate on income subject to Norwegian petroleum tax. The basis for computing the petroleum tax is the same as for income subject to ordinary corporate income tax, except that onshore losses are not deductible against the petroleum tax, and a tax-free allowance (uplift) is computed on the basis of the original capitalised cost of offshore production installations at a rate of 5.5% per year. The uplift may be deducted from taxable income for a period of four years, starting in the year in which the capital expenditures are incurred. The uplift benefit is recognised when the deduction is included in the current year tax return and impacts taxes payable. Unused uplift may be carried forward indefinitely.

Oil and gas exploration and development expenditures

Statoil uses the successful efforts method of accounting for oil and gas exploration costs. Expenditures to acquire mineral interests in oil and gas properties and to drill and equip exploratory wells are capitalised as exploration and evaluation expenditures within Intangible assets until the well is complete and the results have been evaluated. If, following the evaluation, the exploratory well has not found proved reserves, the previously capitalised costs are evaluated for derecognition or tested for impairment. Geological and geophysical costs and other exploration expenditures are expensed as incurred.

Capitalised exploration and evaluation expenditures, including expenditures to acquire mineral interests in oil and gas properties, related to offshore wells that find proved reserves are transferred from exploration expenditures and acquisition costs - oil and gas prospects (Intangible assets) to Property, plant and equipment at the time of sanctioning of the development project. For onshore wells where no sanction is required, the transfer of acquisition cost – oil and gas prospects (Intangible assets) to Property, plant and equipment occur at the time when a well is ready for production.

For exploration and evaluation asset acquisitions (farm-in arrangements) in which Statoil has made arrangements to fund a portion of the selling partner's (farmor's) exploration and/or future development expenditures (carried interests), these expenditures are reflected in the Consolidated financial statements as and when the exploration and development work progresses. Statoil reflects exploration and evaluation asset dispositions (farm-out arrangements), when the farmee correspondingly undertakes to fund carried interests as part of the consideration, on a historical cost basis with no gain or loss recognition.

A gain or loss related to a post-tax based disposition of assets on the NCS includes the release of tax liabilities previously computed and recognised related to the assets in question. The resulting gross gain or loss is recognised in full in Other income in the Consolidated statement of income.

Exchanges (swaps) of exploration and evaluation assets are accounted for at the carrying amounts of the assets given up with no gain or loss recognition.

Property, plant and equipment

Property, plant and equipment is reflected at cost, less accumulated depreciation and accumulated impairment losses. The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into operation, the initial estimate of an asset retirement

obligation, if any, and, for qualifying assets, borrowing costs. Property, plant and equipment include assets acquired under the terms of profit sharing agreements (PSAs) in certain countries, and which qualify for recognition as assets of Statoil. State-owned entities in the respective countries, however, normally hold the legal title to such PSA-based property, plant and equipment.

Exchanges of assets are measured at the fair value of the asset given up, unless the fair value of neither the asset received nor the asset given up is reliably measurable.

Expenditure on major maintenance refits or repairs comprises the cost of replacement assets or parts of assets, inspection costs and overhaul costs. Where an asset or part of an asset is replaced and it is probable that future economic benefits associated with the item will flow to Statoil, the expenditure is capitalised. Inspection and overhaul costs, associated with regularly scheduled major maintenance programs planned and carried out at recurring intervals exceeding one year, are capitalised and amortised over the period to the next scheduled inspection and overhaul. All other maintenance costs are expensed as incurred.

Capitalised exploration and evaluation expenditures, development expenditure on the construction, installation or completion of infrastructure facilities such as platforms, pipelines and the drilling of development wells, and field-dedicated transport systems for oil and gas are capitalised as producing oil and gas properties within Property, plant and equipment. Such capitalised costs are depreciated using the unit of production method based on proved developed reserves expected to be recovered from the area during the concession or contract period. Capitalised acquisition costs of proved properties are depreciated using the unit of production method based on total proved reserves. Depreciation of other assets and transport systems used by several fields is calculated on the basis of their estimated useful lives, normally using the straight-line method. Each part of an item of property, plant and equipment with a cost that is significant in relation to the total cost of the item is depreciated separately. For exploration and production assets, Statoil has established separate depreciation categories which as a minimum distinguish between platforms, pipelines and wells.

The estimated useful lives of property, plant and equipment are reviewed on an annual basis, and changes in useful lives are accounted for prospectively. An item of property, plant and equipment is derecognised upon disposal or when no future economic benefits are expected to arise from the continued use of the asset. Any gain or loss arising on derecognition of the asset (calculated as the difference between the net disposal proceeds and the carrying amount of the item) is included in Other income or Operating expenses, respectively, in the period the item is derecognised.

Leases

Leases for which Statoil assumes substantially all the risks and rewards of ownership are reflected as finance leases. When an asset leased by a joint operation or similar arrangement to which Statoil is a party qualifies as a finance lease, Statoil reflects its proportionate share of the leased asset and related obligations. Finance leases are classified in the Consolidated balance sheet within Property, plant and equipment and Finance debt. All other leases are classified as operating leases, and the costs are charged to the relevant operating expense related caption on a straight line basis over the lease term, unless another basis is more representative of the benefits of the lease to Statoil.

Statoil distinguishes between lease and capacity contracts. Lease contracts provide the right to use a specific asset for a period of time, while capacity contracts confer on Statoil the right to and the obligation to pay for certain volume capacity availability related to transport, terminal use, storage, etc. Such capacity contracts that do not involve specified assets or that do not involve substantially all the capacity of an undivided interest in a specific asset are not considered by Statoil to qualify as leases for accounting purposes. Capacity payments are reflected as Operating expenses in the Consolidated statement of income in the period for which the capacity contractually is available to Statoil.

Intangible assets including goodwill

Intangible assets are stated at cost, less accumulated amortisation and accumulated impairment losses. Intangible assets include acquisition cost for oil and gas prospects, expenditures on the exploration for and evaluation of oil and natural gas resources, goodwill and other intangible assets.

Expenses related to the drilling of exploration wells are initially capitalised as intangible assets pending determination of whether potentially economic oil and gas reserves have been discovered by the drilling effort. This evaluation is normally finalised within one year after well completion. Exploration wells that discover potentially economic quantities of oil and natural gas remain capitalised as intangible assets during the evaluation phase of the find, see further information under the Oil and gas exploration and development expenditures section above.

Intangible assets relating to expenditures on the exploration for and evaluation of oil and natural gas resources are not amortised. When the decision to develop a particular area is made, its intangible exploration and evaluation assets are reclassified to Property, plant and equipment.

Goodwill is initially measured at the excess of the aggregate of the consideration transferred and the amount recognised for any non-controlling interest over the fair value of the identifiable assets acquired and liabilities assumed in a business combination at the acquisition date. Goodwill acquired is allocated to each cash generating unit, or group of units, expected to benefit from the combination's synergies. Following initial recognition, goodwill is measured at cost less any accumulated impairment losses.

Financial assets

Financial assets are initially recognised at fair value when Statoil becomes a party to the contractual provisions of the asset. For additional information on fair value methods, refer to the Measurement of fair values section below. The subsequent measurement of the financial assets depends on which category they have been classified into at inception.

At initial recognition, Statoil classifies its financial assets into the following three main categories: Financial investments at fair value through profit or loss, loans and receivables, and available-for-sale (AFS) financial assets. The first main category, financial investments at fair value through profit or loss, further consists of two sub-categories: Financial assets held for trading and financial assets that on initial recognition are designated as fair value through profit and loss. The latter approach may also be referred to as the fair value option.

Cash and cash equivalents include cash in hand, current balances with banks and similar institutions, and short-term highly liquid investments that are readily convertible to known amounts of cash, are subject to an insignificant risk of changes in fair value and have a maturity of three months or less from the acquisition date.

Trade receivables are carried at the original invoice amount less a provision for doubtful receivables which is made when there is objective evidence that Statoil will be unable to recover the balances in full.

A significant part of Statoil's investments in treasury bills, commercial papers, bonds and listed equity securities is managed together as an investment portfolio of Statoil's captive insurance company and is held in order to comply with specific regulations for capital retention. The investment portfolio is managed and evaluated on a fair value basis in accordance with an investment strategy and is accounted for using the fair value option with changes in fair value recognised through profit or loss.

Financial assets are presented as current if they contractually will expire or otherwise are expected to be recovered within 12 months after the balance sheet date, or if they are held for the purpose of being traded. Financial assets and financial liabilities are shown separately in the Consolidated balance sheet, unless Statoil has both a legal right and a demonstrable intention to net settle certain balances payable to and receivable from the same counterparty, in which case they are shown net in the balance sheet.

Inventories

Inventories are stated at the lower of cost and net realisable value. Cost is determined by the first-in first-out method and comprises direct purchase costs, cost of production, transportation and manufacturing expenses.

Impairment

Impairment of property, plant and equipment and intangible assets

Statoil assesses individual assets or groups of assets for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. Assets are grouped into cash generating units (CGUs) which are the smallest identifiable groups of assets that generate cash inflows that are largely independent of the cash inflows from other groups of assets. Normally, separate CGUs are individual oil and gas fields or plants. Each unconventional asset play is considered a single CGU when no cash inflows from parts of the play can be reliably identified as being largely independent of the cash inflows from other parts of the play. In impairment evaluations, the carrying amounts of CGUs are determined on a basis consistent with that of the recoverable amount. Impairment of property, plant and equipment and intangible assets. In Statoil's line of business, judgement is involved in determining what constitutes a CGU. Development in production, infrastructure solutions, markets, product pricing, management actions and other factors may over time lead to changes in CGUs such as the division of one original CGU into several.

In assessing whether a write-down of the carrying amount of a potentially impaired asset is required, the asset's carrying amount is compared to the recoverable amount. The recoverable amount of an asset is the higher of its fair value less cost of disposal and its value in use. Frequently the recoverable amount of an asset proves to be Statoil's estimated value in use, which is determined using a discounted cash flow model. The estimated future cash flows applied are based on reasonable and supportable assumptions and represent management's best estimates of the range of economic conditions that will exist over the remaining useful life of the assets, as set down in Statoil's most recently approved long-term plans. Statoil's long-term plans are reviewed by corporate management and updated at least annually. The plans cover a 10-year period and reflect expected production volumes for oil and natural gas in that period. For assets and CGUs with an expected useful life or timeline for production of expected reserves extending beyond 10 years, the related cash flows include project or asset specific estimates reflecting the relevant period. Such estimates are established on the basis of Statoil's principles and assumptions consistently applied.

In performing a value-in-use-based impairment test, the estimated future cash flows are adjusted for risks specific to the asset and discounted using a real post-tax discount rate which is based on Statoil's post-tax weighted average cost of capital (WACC). The use of post-tax discount rates in determining value in use does not result in a materially different determination of the need for, or the amount of, impairment that would be required if pre-tax discount rates had been used.

Unproved oil and gas properties are assessed for impairment when facts and circumstances suggest that the carrying amount of the asset may exceed its recoverable amount, and at least once a year. Exploratory wells that have found reserves, but where classification of those reserves as proved depends on whether major capital expenditure can be justified or where the economic viability of that major capital expenditure depends on the successful completion of further exploration work, will remain capitalised during the evaluation phase for the exploratory finds. Thereafter it will be considered a trigger for impairment evaluation of the well if no development decision is planned for the near future and there are no concrete plans for future drilling in the licence.

Impairments are reversed, as applicable, to the extent that conditions for impairment are no longer present. Impairment losses and reversals of impairment losses are presented in the Consolidated statement of income as Exploration expenses or Depreciation, amortisation and net impairment losses, on the basis of their nature as either exploration assets (intangible exploration assets) or development and producing assets (property, plant and equipment and other intangible assets), respectively.

Impairment of goodwill

Goodwill is reviewed for impairment annually or more frequently if events or changes in circumstances indicate that the carrying value may be impaired. Impairment is determined by assessing the recoverable amount of the CGU, or group of units, to which the goodwill relates. Where the recoverable amount of the CGU, or group of units, is less than the carrying amount, an impairment loss is recognised. Once recognised, impairments of goodwill are not reversed in future periods.

Financial liabilities

Financial liabilities are initially recognised at fair value when Statoil becomes a party to the contractual provisions of the liability. The subsequent measurement of financial liabilities depends on which category they have been classified into. The categories applicable for Statoil are either financial liabilities at fair value through profit or loss or financial liabilities measured at amortised cost using the effective interest method. The latter applies to Statoil's non-current bank loans and bonds.

Financial liabilities are presented as current if the liability is due to be settled within 12 months after the balance sheet date, or if they are held for the purpose of being traded. Financial liabilities are derecognised when the contractual obligations expire, are discharged or cancelled. Gains and losses arising on the repurchase, settlement or cancellation of liabilities are recognised either in interest income and other financial items or in interest and other finance expenses within Net financial items.

Derivative financial instruments

Statoil uses derivative financial instruments to manage certain exposures to fluctuations in foreign currency exchange rates, interest rates and commodity prices. Such derivative financial instruments are initially recognised at fair value on the date on which a derivative contract is entered into and are subsequently re-measured at fair value through profit and loss. The impact of commodity-based derivative financial instruments is recognised in the Consolidated statement of income under Revenues, as such derivative instruments are related to sales contracts or revenue-related risk management for all significant purposes. The impact of other financial instruments is reflected under Net financial items.

Derivatives are carried as assets when the fair value is positive and as liabilities when the fair value is negative. Derivative assets or liabilities expected to be recovered, or with the legal right to be settled more than 12 months after the balance sheet date are classified as non-current, with the exception of derivative financial instruments held for the purpose of being traded.

Contracts to buy or sell a non-financial item that can be settled net in cash or another financial instrument, or by exchanging financial instruments, as if the contracts were financial instruments, are accounted for as financial instruments. However, contracts that are entered into and continue to be held for the purpose of the receipt or delivery of a non-financial item in accordance with Statoil's expected purchase, sale or usage requirements, also referred to as own-use, are not accounted for as financial instruments. This is applicable to a significant number of contracts for the purchase or sale of crude oil and natural gas, which are recognised upon delivery.

Derivatives embedded in other financial instruments or in non-financial host contracts are recognised as separate derivatives and are reflected at fair value with subsequent changes through profit and loss, when their risks and economic characteristics are not closely related to those of the host contracts, and the host contracts are not carried at fair value. Where there is an active market for a commodity or other non-financial item referenced in a purchase or sale contract, a pricing formula will, for instance, be considered to be closely related to the host purchase or sales contract if the price formula is based on the active market in question. A price formula with indexation to other markets or products will however result in the recognition of a separate derivative. Where there is no active market for the commodity or other non-financial item in question, Statoil assesses the characteristics of such a price related embedded derivative to be closely related to the host contract if the price formula is based on relevant indexations commonly used by other market participants. This applies to a number of Statoil's long-term natural gas sales agreements.

Pension liabilities

Statoil has pension plans for employees that either provide a defined pension benefit upon retirement or a pension dependent on defined contributions and related returns. For defined benefit plans, the benefit to be received by employees generally depends on many factors including length of service, retirement date and future salary levels.

Statoil's proportionate share of multi-employer defined benefits plans are recognised as liabilities in the balance sheet to the extent that sufficient information is available and a reliable estimate of the obligation can be made.

Statoil's net obligation in respect of defined benefit pension plans is calculated separately for each plan by estimating the amount of future benefit that employees have earned in return for their services in the current and prior periods. That benefit is discounted to determine its present value and the fair value of any plan assets is deducted. The discount rate is the yield at the balance sheet date, reflecting the maturity dates approximating the terms of Statoil's obligations. The discount rate for the main part of the pension obligations has been established on the basis of Norwegian mortgage covered bonds, which are considered high quality corporate bonds. The cost of pension benefit plans is expensed over the period that the employees render services and become eligible to receive benefits. The calculation is performed by an external actuary.

The net interest related to defined benefit plans is calculated by applying the discount rate to the net defined benefit liability (asset). The interest cost element is determined by applying the discount rate to the opening present value of the benefit obligation, taking into account material changes in the obligation during the year. The interest income on plan assets is determined by applying the discount rate to the opening present value of the plan assets, adjusted for the effect on the fair value of plan assets of contributions received and benefits paid during the year. The resulting net interest element is presented in the statement of income as part of net pension cost within Net operating income. The difference between net interest income and actual return is recognised in OCI.

Periodic pension cost is accumulated in cost pools and allocated to operating segments and Statoil operated joint operations (licences) on an hours incurred basis and recognised in the statement of income based on the function of the cost.

Past service cost is recognised when a plan amendment (the introduction or withdrawal of, or changes to, a defined benefit plan) or curtailment (a significant reduction by the entity in the number of employees covered by a plan) occurs, or when recognising related restructuring costs or termination benefits. The obligation and related plan assets are re-measured using current actuarial assumptions, and the gain or loss is recognised in the statement of income. Actuarial gains and losses are recognised in full in the Consolidated statement of comprehensive income in the period in which they occur, while

actuarial gains and losses related to provision for termination benefits are recognised in the Consolidated statement of income in the period in which they occur. Due to the parent company Statoil ASA's functional currency being USD, the significant part of Statoil's pension obligations will be payable in a foreign currency (i.e. NOK). As a consequence, actuarial gains and losses related to the parent company's pension obligation include the impact of exchange rate fluctuations.

Contributions to defined contribution schemes are recognised in the statement of income in the period in which the contribution amounts are earned by the employees.

Onerous contracts

Statoil recognises as provisions the net obligation under contracts defined as onerous. Contracts are deemed to be onerous if the unavoidable cost of meeting the obligations under the contract exceeds the economic benefits expected to be received in relation to the contract. A contract which forms an integral part of the operations of a CGU whose assets are dedicated to that contract, and for which the economic benefits cannot be reliably separated from those of the CGU, is included in impairment considerations for the applicable CGU.

Asset retirement obligations (ARO)

Provisions for ARO costs are recognised when Statoil has an obligation (legal or constructive) to dismantle and remove a facility or an item of property, plant and equipment and to restore the site on which it is located, and when a reliable estimate of that liability can be made. The amount recognised is the present value of the estimated future expenditures determined in accordance with local conditions and requirements. Cost is estimated based on current regulations and technology, considering relevant risks and uncertainties. The discount rate used in the calculation of the ARO is a risk-free rate based on the applicable currency and time horizon of the underlying cash flows, adjusted for a credit premium which reflects Statoil's own credit risk. Normally an obligation arises for a new facility, such as an oil and natural gas production or transportation facility, upon construction or installation. An obligation may also crystallise during the period of operation of a facility through a change in legislation or through a decision to terminate operations, or be based on commitments associated with Statoil's ongoing use of pipeline transport systems where removal obligations rest with the volume shippers. The provisions are classified under Provisions in the Consolidated balance sheet. Some of the refining and process plants are deemed to have indefinite lives, in consequence, no ARO has been recognized for these assets.

When a provision for ARO cost is recognised, a corresponding amount is recognised to increase the related property, plant and equipment and is subsequently depreciated as part of the costs of the facility or item of property, plant and equipment. Any change in the present value of the estimated expenditure is reflected as an adjustment to the provision and the corresponding property, plant and equipment. Removal provisions associated with Statoil's role as shipper of volumes through third party transport systems are expensed as incurred.

Measurement of fair values

Quoted prices in active markets represent the best evidence of fair value and are used by Statoil in determining the fair values of assets and liabilities to the extent possible. Financial instruments quoted in active markets will typically include commercial papers, bonds and equity instruments with quoted market prices obtained from the relevant exchanges or clearing houses. The fair values of quoted financial assets, financial liabilities and derivative instruments are determined by reference to mid-market prices, at the close of business on the balance sheet date.

Where there is no active market, fair value is determined using valuation techniques. These include using recent arm's-length market transactions, reference to other instruments that are substantially the same, discounted cash flow analysis, and pricing models and related internal assumptions. In the valuation techniques, Statoil also takes into consideration the counterparty and its own credit risk. This is either reflected in the discount rate used or through direct adjustments to the calculated cash flows. Consequently, where Statoil reflects elements of long-term physical delivery commodity contracts at fair value, such fair value estimates to the extent possible are based on quoted forward prices in the market and underlying indexes in the contracts, as well as assumptions of forward prices and margins where observable market prices are not available. Similarly, the fair values of interest and currency swaps are estimated based on relevant quotes from active markets, quotes of comparable instruments, and other appropriate valuation techniques.

Critical accounting judgements and key sources of estimation uncertainty

Critical judgements in applying accounting policies

The following are the critical judgements, apart from those involving estimations (see below), that Statoil has made in the process of applying the accounting policies and that have the most significant effect on the amounts recognised in the financial statements:

Revenue recognition - gross versus net presentation of traded SDFI volumes of oil and gas production

As described under Transactions with the Norwegian State above, Statoil markets and sells the Norwegian State's share of oil and gas production from the NCS. Statoil includes the costs of purchase and proceeds from the sale of the SDFI oil production in Purchases [net of inventory variation] and Revenues, respectively. In making the judgement, Statoil considered the detailed criteria for the recognition of revenue from the sale of goods and, in particular, concluded that the risk and reward of the ownership of the oil had been transferred from the SDFI to Statoil.

Statoil sells, in its own name, but for the Norwegian State's account and risk, the State's production of natural gas. These gas sales, and related expenditures refunded by the State, are shown net in Statoil's Consolidated financial statements. In making the judgement, Statoil considered the same criteria as for the oil production and concluded that the risk and reward of the ownership of the gas had not been transferred from the SDFI to Statoil.

Key sources of estimation uncertainty

The preparation of the Consolidated financial statements requires that management make estimates and assumptions that affect reported amounts of assets, liabilities, income and expenses. The estimates and associated assumptions are based on historical experience and various other factors that are believed to be reasonable under the circumstances, the result of which form the basis of making the judgements about carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates. The estimates and underlying assumptions are reviewed on an ongoing basis considering the current and expected future market conditions.

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

The matters described below are considered to be the most important in understanding the key sources of estimation uncertainty that are involved in preparing these Consolidated financial statements and the uncertainties that could most significantly impact the amounts reported on the results of operations, financial position and cash flows.

Proved oil and gas reserves. Proved oil and gas reserves may materially impact the Consolidated financial statements, as changes in the proved reserves, for instance as a result of changes in prices, will impact the unit of production rates used for depreciation and amortisation. Proved oil and gas reserves have been estimated by internal qualified professionals on the basis of industry standards and governed by criteria established by regulations of the U.S. Securities Exchange Commission (SEC), which require the use of a price based on a 12-month average for reserve estimation, and which are to be based on existing economic conditions and operating methods and with a high degree of confidence (at least 90% probability) that the quantities will be recovered. The Financial Accounting Standards Board (FASB) requirements for supplemental oil and gas disclosures align with the SEC regulations. Reserves estimates are based on subjective judgements involving geological and engineering assessments of in-place hydrocarbon volumes, the production, historical recovery and processing yield factors and installed plant operating capacity. For future development projects, proved reserves estimates are included only where there is a significant commitment to project funding and execution and when relevant governmental and regulatory approvals have been secured or are reasonably certain to be secured. The reliability of these estimates at any point in time depends on both the quality and quantity of the technical and economic data and the efficiency of extracting and processing the hydrocarbons. An independent third party has evaluated Statoil's proved reserves estimates, and the results of this evaluation do not differ materially from Statoil's estimates. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations. Unless evidence indicates that renewal is reasonably certain, estimates of economically producible reserves only reflect the period before the contracts providing the right to operate expire. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence within a reasonable time.

Expected oil and gas reserves. Expected oil and gas reserves may materially impact the Consolidated financial statements, as changes in the expected reserves, for instance as a result of changes in prices, will impact asset retirement obligations and impairment testing of upstream assets, which in turn may lead to changes in impairment charges affecting operating income. Expected oil and gas reserves are the estimated remaining, commercially recoverable quantities, based on Statoil's judgement of future economic conditions, from projects in operation or justified for development. Recoverable oil and gas quantities are always uncertain, and the expected value is the weighted average, or statistical mean, of the possible outcomes. Expected reserves are therefore typically larger than proved reserves as defined by the SEC rules. Expected oil and gas reserves have been estimated by internal qualified professionals on the basis of industry standards and are used for impairment testing purposes and for calculation of asset retirement obligations. Reserves estimates are based on subjective judgements involving geological and engineering assessments of in-place hydrocarbon volumes, the production, historical recovery and processing yield factors, installed plant operating capacity and operating approval limits. The reliability of these estimates at any point in time depends on both the quality and quantity of the technical and economic data and the efficiency of extracting and processing the hydrocarbons.

Exploration and leasehold acquisition costs. Statoil capitalises the costs of drilling exploratory wells pending determination of whether the wells have found proved oil and gas reserves. Statoil also capitalises leasehold acquisition costs and signature bonuses paid to obtain access to undeveloped oil and gas acreage. Judgements as to whether these expenditures should remain capitalised or written down due to impairment losses in the period may materially affect the operating income for the period.

Impairment/reversal of impairment. Statoil has significant investments in property, plant and equipment and intangible assets. Changes in the circumstances or expectations of future performance of an individual asset may be an indicator that the asset is impaired, requiring the carrying amount to be written down to its recoverable amount. Impairments are reversed if conditions for impairment are no longer present. Evaluating whether an asset is impaired or if an impairment should be reversed requires a high degree of judgement and may to a large extent depend upon the selection of key assumptions about the future.

Unproved oil and gas properties are assessed for impairment when facts and circumstances suggest that the carrying amount of the asset may exceed its recoverable amount, and at least annually. If, following evaluation, an exploratory well has not found proved reserves, the previously capitalised costs are tested for impairment. Subsequent to the initial evaluation phase for a well, it will be considered a trigger for impairment testing of a well if no development decision is planned for the near future and there is no concrete plan for future drilling in the licence. Impairment of unsuccessful wells is reversed, as applicable, to the extent that conditions for impairment are no longer present.

Estimating recoverable amounts involves complexity in estimating relevant future cash flows, based on assumptions about the future, discounted to their present value. Impairment testing requires long-term assumptions to be made concerning a number of often volatile economic factors such as future market prices, refinery margins, currency exchange rates and future output, discount rates and political and country risk among others, in order to establish relevant future cash flows. Impairment testing frequently also requires judgement regarding probabilities and probability distributions as well as levels of sensitivity inherent in the establishment of recoverable amount estimates. Long-term assumptions for major economic factors are made at a group level, and there is a high degree of reasoned judgement involved in establishing these assumptions, in determining other relevant factors such as forward price curves, in estimating production outputs and in determining the ultimate terminal value of an asset.

Employee retirement plans. When estimating the present value of defined benefit pension obligations that represent a long-term liability in the Consolidated balance sheet, and indirectly, the period's net pension expense in the Consolidated statement of income, management make a number of critical assumptions affecting these estimates. Most notably, assumptions made about the discount rate to be applied to future benefit payments and plan assets, the expected rate of pension increase and the annual rate of compensation increase, have a direct and potentially material impact on the amounts presented. Significant changes in these assumptions between periods can have a material effect on the Consolidated financial statements.

Asset retirement obligations. Statoil has significant obligations to decommission and remove offshore installations at the end of the production period. It is difficult to estimate the costs of these decommissioning and removal activities, which are based on current regulations and technology and consider relevant risks and uncertainties. Most of the removal activities are many years into the future and the removal technology and costs are constantly changing. The estimates include assumptions of the time required and the day rates for rigs, marine operations and heavy lift vessels that can vary considerably depending on the assumed removal complexity. As a result, the initial recognition of the liability and the capitalised cost associated with decommissioning and removal obligations, and the subsequent adjustment of these balance sheet items, involve the application of significant judgement.

Derivative financial instruments. When not directly observable in active markets, the fair value of derivative contracts must be computed internally based on internal assumptions as well as directly observable market information, including forward and yield curves for commodities, currencies and interest rates. Changes in internal assumptions, forward and yield curves could materially impact the internally computed fair value of derivative contracts, particularly long-term contracts, resulting in a corresponding impact on income or loss in the Consolidated statement of income.

Income tax. Every year Statoil incurs significant amounts of income taxes payable to various jurisdictions around the world and recognises significant changes to deferred tax assets and deferred tax liabilities, all of which are based on management's interpretations of applicable laws, regulations and relevant court decisions. The quality of these estimates is highly dependent upon management's ability to properly apply at times very complex sets of rules, to recognise changes in applicable rules and, in the case of deferred tax assets, management's ability to project future earnings from activities that may apply loss carry forward positions against future income taxes.

3 Segments

Statoil's operations are managed through the following operating segments: Development and Production Norway (DPN), Development and Production North America (DPNA), Development and Production International (DPI), Marketing, Processing and Renewable Energy (MPR) and Other. The Fuel and Retail segment (FR) was sold on 19 June 2012.

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

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

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

Statoil reports its business through reporting segments which correspond to the operating segments, except for the operating segments DPI and DPNA 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 Other reporting segment includes activities within Global Strategy and Business Development, Technology, Projects and Drilling and the Corporate staffs and services.

In the second quarter 2012, Statoil divested its FR segment through Statoil ASA's sale of its 54% shareholding in Statoil Fuel & Retail ASA (SFR). A gain of NOK 5.8 billion was recognised. In the segment reporting, the gain has been presented in the FR segment as Revenues third party and Other income. The FR segment marketed fuel and related products principally to retail consumers.

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

Segment data for the years ended 31 December 2014, 2013 and 2012 is presented below. The measurement basis of segment profit is Net operating income. In the tables below, deferred tax assets, pension assets and non-current financial assets are not allocated to the segments. Also, the line Additions to PP&E, intangibles and associated companies is excluding movements due to changes in asset retirement obligations.

	Development and Production	Development and Production	Marketing, Processing and Renewable
(in NOK billion)	Norway	International	Energy	Other	Eliminations	Total
Full year 2014
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 (loss) from associated companies	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
Investments in associated companies	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 associated companies	55.1	61.4	7.8	0.8	-	125.1

	Development and Production	Development and Production	Marketing, Processing and Renewable
(in NOK billion)	Norway	International	Energy	Other	Eliminations	Total
Full year 2013 (restated)
Revenues third party and Other income	9.4	16.5	607.5	1.0	-	634.4
Revenues inter-segment	192.7	65.4	1.0	0.1	(259.1)	0.0
Net income (loss) from associated companies	0.1	(0.0)	0.1	(0.0)	-	0.1
Total revenues and other income	202.2	81.9	608.6	1.0	(259.1)	634.5
Net operating income	137.1	16.4	2.6	(1.1)	0.4	155.5
Significant non-cash items recognised
- Depreciation and amortisation	31.6	29.8	2.7	1.3	-	65.4
- Provisions	0.8	4.6	4.1	0.0	-	9.5
- Net impairment losses (reversals)	0.6	2.1	4.3	0.0	-	7.0
- Unrealised (gain) loss on commodity derivatives	5.6	0.0	(0.1)	0.0	-	5.5
- Exploration expenditures written off	0.3	2.8	0.0	0.0	-	3.1
Investments in associated companies	0.2	4.8	2.3	0.2	-	7.4
Non-current segment assets	247.6	286.5	39.3	5.6	-	578.9
Non-current assets, not allocated to segments						60.5
Total non-current assets						646.8
Additions to PP&E, intangibles and associated companies	57.3	52.9	5.9	1.3	-	117.4

	Development and Production	Development and Production	Marketing, Processing and Renewable
(in NOK billion)	Norway	International	Energy	Other	Fuel and Retail	Eliminations	Total
Full year 2012 (restated)
Revenues third party and Other income	7.7	24.3	643.0	1.3	40.2	-	716.5
Revenues inter-segment	213.0	54.5	22.2	0.0	1.5	(291.2)	0.0
Net income (loss) from associated companies	0.1	1.2	0.4	(0.0)	(0.0)	-	1.7
Total revenues and other income	220.8	80.0	665.6	1.3	41.7	(291.2)	718.2
Net operating income	161.7	21.5	15.5	2.6	6.9	(1.6)	206.6
Significant non-cash items recognised
- Depreciation and amortisation	29.2	26.2	2.3	0.9	0.6	-	59.2
- Net impairment losses (reversals)	0.6	0.0	0.6	0.0	0.0	-	1.2
- Unrealised (gain) loss on commodity derivatives	1.4	0.0	1.8	0.0	0.0	-	3.1
- Exploration expenditures written off	0.8	2.3	0.0	0.0	0.0	-	3.1
Investments in associated companies	0.2	4.8	3.2	0.1	-	-	8.3
Non-current segment assets	235.4	248.3	38.5	4.5	-	-	526.7
Non-current assets, not allocated to segments							66.4
Total non-current assets							601.4
Additions to PP&E, intangibles and associated
companies	48.6	54.6	6.2	3.0	0.9	-	113.3

See note 4 Acquisitions and dispositions for information on transactions that affect the different segments.

See note 11 Property, plant and equipment for information on impairment losses that affected the different segments.

See note 12 Intangible assets for information on impairment losses that affected primarily the DPI segment.

See note 19 Pensions for information on financial results from the change in the company's pension plan in Norway.

See note 23 Other commitments, contingent liabilities and contingent assets for information on contingencies that have influenced the DPI and MPR segments.

Revenues by geographical areas

Statoil has business operations in more than 30 countries. When attributing Revenues third party and Other income to the country of the legal entity executing the sale, Norway constitutes 75% and the USA constitutes 15%.

Non-current assets by country

			At 31 December
(in NOK billion)	2014	2013	2012
Norway	289.6	269.6	258.7
USA	182.9	159.2	134.6
Angola	51.3	45.9	42.5
Brazil	29.5	24.5	23.2
Azerbaijan	23.6	19.0	16.7
UK	19.7	13.6	11.1
Canada	17.6	19.9	17.2
Algeria	11.8	9.0	8.7
Other countries	29.5	25.6	22.3
Total non-current assets*	655.6	586.3	535.0

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

Revenues by product type

(in NOK billion)	2014	2013 (restated)	Full year 2012 (restated)
Crude oil	324.6	321.5	367.2
Refined products	104.8	118.9	140.9
Natural gas	99.3	110.4	114.5
Natural gas liquids	59.5	64.5	65.7
Other	18.6	1.3	12.2
Total revenues	606.8	616.6	700.5

4 Acquisitions and dispositions

2014

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

In March 2014 Statoil closed an agreement with BP and in May 2014 Statoil closed an agreement with SOCAR, both entered into in December 2013, to divest a 3.33% working interest and a 6.67% working interest, respectively, in the Shah Deniz project and the South Caucasus Pipeline. Statoil recognised a total gain of NOK 5.4 billion, presented in the line item Other income in the Consolidated statement of income. In the segment reporting, the gain has been presented in the Development and Production International (DPI) segment and the Marketing, Processing and Renewable Energy segment with NOK 5.2 billion and NOK 0.2 billion, respectively. The part of the transaction recognised in the DPI segment was tax exempt under the rules in Norway and Azerbaijan. Proceeds from the sale were NOK 8.2 billion.

In October 2014 Statoil entered into an agreement with Petronas to sell its remaining 15.5% interest in the Shah Deniz project and the South Caucasus Pipeline for a cash consideration of NOK 16.7 billion (USD 2.25 billion) as of the economic date 1 January 2014. The transaction will be recognised in the DPI segment and is expected to be closed in the first half of 2015.

Kai Kos Dehseh oil sands swap agreement

In May 2014 Statoil and its partner PTTEP closed an agreement to swap the two parties' respective interests in the Kai Kos Dehseh oil sands project in Alberta, Canada. Statoil paid a balancing cash consideration of NOK 2.5 billion and assumed a net liability of NOK 0.3 billion. Subsequent to the closing, Statoil continues as 100% owner of the Leismer and Corner projects, while PTTEP owns 100% of the Thornbury, Hangingstone and South Leismer areas. The transaction has been recognised in the DPI segment resulting in an increase in Property, plant and equipment of NOK 4.6 billion, including a transfer from Intangible assets of NOK 1.8 billion, and with no impact on the Consolidated statement of income.

Agreement to sell interests in the Marcellus onshore play

In December 2014 Statoil entered into an agreement to sell a working interest in the non-operated southern Marcellus onshore asset to Southwestern Energy for a cash consideration of NOK 2.9 billion (USD 0.4 billion). Through the transaction Statoil will reduce its ownership share from 29% to 23%. Subsequent to year end 2014, the transaction has been closed and it will be recognised in the DPI segment in the first quarter of 2015.

Sale of interests in licences on the Norwegian continental shelf

In December 2014 Statoil closed an agreement with Wintershall to sell certain ownership interests in licences on the Norwegian continental shelf (NCS). A gain of NOK 5.9 billion has been recognised in the Development and Production Norway (DPN) segment. The gain has been presented in the line item

Other income in the Consolidated statement of income. The transaction was tax exempt under the rules in the Norwegian petroleum tax system and the gain included a release of related deferred tax liabilities. Proceeds from the sale were NOK 8.7 billion (USD 1.25 billion).

2013

Sale of interests in exploration and production licences on the Norwegian continental shelf to Wintershall

In July 2013 a sales transaction with Wintershall, entered into in October 2012, for certain ownership interests in licences on the NCS was closed. Statoil recognised a gain of NOK 6.4 billion. The gain has been presented in the line item Other income in the Consolidated statement of income. In the segment reporting, the gain has been presented in the DPN segment in Revenues third party and Other income. The transaction was tax exempt under the rules in the Norwegian petroleum tax system. Proceeds from the sale were NOK 4.7 billion.

Sale of interests in exploration and production licences on the Norwegian continental shelf and the United Kingdom continental shelf to OMV In October 2013 a sales transaction with OMV, entered into in August 2013, to sell certain ownership interests in licences on the NCS and United Kingdom continental shelf was closed. Statoil recognised a gain of NOK 10.1 billion. The gain has been presented in the line item Other income in the Consolidated statement of income. In the segment reporting, the gain has been presented in the DPN segment and in the DPI segment in Revenues third party and Other income with NOK 6.6 billion and NOK 3.5 billion, respectively. The part of the transaction covering assets on the NCS was tax exempt under the rules in the Norwegian petroleum tax system. Proceeds from the sale were NOK 15.9 billion.

2012

Sale of interests in exploration and production licences on the Norwegian continental shelf

In April 2012 Statoil closed an agreement with Centrica, entered into in November 2011, to sell interests in certain licences on the NCS for a total consideration of NOK 8.6 billion. The consideration included a cash payment of NOK 7.1 billion and a contingent element relating to production in a four year period, capped at NOK 0.6 billion. A gain of NOK 7.5 billion was recognised in the DPN segment in the second quarter 2012 and presented as Revenues third party and Other income. The net book value of the assets taken over by Centrica was NOK 2.0 billion. The transaction was tax exempt under the rules in the Norwegian petroleum tax system and the gain included a release of deferred tax liabilities of NOK 0.9 billion related to the transaction.

Divestment of shares in Statoil Fuel & Retail ASA

On 19 June 2012 Statoil ASA sold its 54% shareholding in Statoil Fuel & Retail ASA (SFR) to Alimentation Couche-Tard for a cash consideration of NOK 8.3 billion. Until the transaction date SFR was fully consolidated in the Statoil group with a 46% non-controlling interest. Statoil recognised a gain of NOK 5.8 billion on the transaction, presented as Other income in the Consolidated financial statements. The gain was tax exempt and presented in the Fuel and Retail segment. The net book value of the assets derecognised as part of the divestment was NOK 7.5 billion.

Acquisition of mineral right leases in the Marcellus shale formation in the United States

In December 2012 Statoil closed an agreement to acquire mineral right leases covering 70,000 net acres in the Marcellus shale area in the northeastern part of the United States. Statoil became the operator of the licences and holds a 100% working interest in these mineral right leases. The transaction was accounted for as an asset acquisition within the DPI segment, with a total consideration of NOK 3.3 billion (USD 0.6 billion).

5 Financial risk management

General information relevant to financial risks

Statoil's business activities naturally expose Statoil to financial risk. Statoil's approach to risk management includes identifying, evaluating and managing risk in all activities using a top-down approach. Statoil utilises correlations between the most important market risks, such as oil and natural gas prices, refined oil product prices, currencies, and interest rates, to calculate the overall market risk and thereby take into account the natural hedges inherent in Statoil's portfolio. Adding the different market risks without considering these correlations would overestimate Statoil's total market risk. This approach allows Statoil to reduce the number of risk management transactions and thereby reduce transaction costs and avoid sub-optimisation.

An important element in risk management is the use of centralised trading mandates. All major strategic transactions are required to be coordinated through Statoil's corporate risk committee. Mandates delegated to the trading organisations within crude oil, refined products, natural gas and electricity are relatively small compared to the total market risk of Statoil.

The corporate risk committee, which is headed by the chief financial officer and includes representatives from the principal business segments, is responsible for defining, developing and reviewing Statoil's risk policies. The chief financial officer, assisted by the committee, is also responsible for overseeing and developing Statoil's Enterprise Risk Management and proposing appropriate measures to adjust risk at the corporate level. The committee meets at least six times per year and regularly reviews risk information relevant to the enterprise Statoil.

Financial risks

Statoil's activities expose Statoil to the following financial risks:

• Market risk (including commodity price risk, currency risk and interest rate risk)
• Liquidity risk
• Credit risk

Market risk

Statoil operates in the worldwide crude oil, refined products, natural gas, and electricity markets and is exposed to market risks including fluctuations in hydrocarbon prices, foreign currency rates, interest rates, and electricity prices that can affect the revenues and costs of operating, investing and financing. These risks are managed primarily on a short-term basis with a focus on achieving the highest risk-adjusted returns for Statoil within the given mandate. Long-term exposures are managed at the corporate level, while short-term exposures are managed according to trading strategies and mandates approved by Statoil's corporate risk committee.

In the marketing of commodities Statoil has established guidelines for entering into derivative contracts in order to manage commodity price, foreign currency rate, and interest rate risks. Statoil uses both financial and commodity-based derivatives to manage the risks in revenues, financial items and the present value of future cash flows.

For more information on sensitivity analysis of market risk see note 25 Financial instruments: fair value measurement and sensitivity analysis of market risk.

Commodity price risk

Commodity price risk represents Statoil's most important short-term market risk. To manage short-term commodity risk, Statoil enters into commoditybased derivative contracts, including futures, options, over-the-counter (OTC) forward contracts, market swaps and contracts for differences related to crude oil, petroleum products, natural gas and electricity.

Derivatives associated with crude oil and refined oil products are traded mainly on the Inter Continental Exchange (ICE) in London, the New York Mercantile Exchange (NYMEX), the OTC Brent market, and crude and refined products swap markets. Derivatives associated with natural gas and electricity are mainly OTC physical forwards and options, NASDAQ OMX Oslo forwards and futures traded on the NYMEX and ICE.

The term of crude oil and refined oil products derivatives is usually less than one year, and the term for natural gas and electricity derivatives is usually three years or less. For more detailed information about Statoil's commodity based derivative financial instruments, see note 25 Financial instruments: fair value measurement and sensitivity analysis of market risk.

Currency risk

Statoil's operating results and cash flows are affected by foreign currency fluctuations and the most significant currency is Norwegian Krone (NOK) against United States Dollar (USD). Statoil manages its currency risk from operating activities with USD as the base currency. Foreign exchange risk is managed at corporate level in accordance with established policies and mandates.

Statoil's cash flows from operating activities deriving from oil and gas sales, operating expenses and capital expenditures are mainly in USD, but taxes and dividends are mainly in NOK. Accordingly, Statoil's currency management is primarily linked to mitigate currency risk related to tax and dividend payments in NOK. This means that Statoil regularly purchases substantial NOK amounts on a forward basis using conventional derivative instruments.

Interest rate risk

Bonds are normally issued at fixed rates in a variety of local currencies (among others USD, Euro and Great Britain Pound). Bonds may be converted to floating USD bonds by using interest rate and currency swaps. Statoil manages its interest rates exposure on its bond debt based on risk and reward considerations from an enterprise risk management perspective. This means that the fix/floating mix on interest rate exposure may vary from time to time. For more detailed information about Statoil's long-term debt portfolio see note 18 Finance debt.

Liquidity risk

Liquidity risk is the risk that Statoil will not be able to meet obligations of financial liabilities when they become due. The purpose of liquidity management is to make certain that Statoil has sufficient funds available at all times to cover its financial obligations.

Statoil manages liquidity and funding at the corporate level, ensuring adequate liquidity to cover Statoil's operational requirements. Statoil has a high focus and attention on credit and liquidity risk. In order to secure necessary financial flexibility, which includes meeting the financial obligations, Statoil maintains a conservative liquidity management policy. To identify future long-term financing needs, Statoil carries out three-year cash forecasts at least monthly. Overall the liquidity is very solid.

The main cash outflows are the quarterly dividend payments and Norwegian petroleum tax payments paid six times per year. If the monthly cash flow forecast shows that the liquid assets one month after tax and dividend payments will fall below the defined policy level, new long-term funding will be considered.

Short-term funding needs will normally be covered by the USD 4.0 billion US Commercial Papers Programme (CP) which is backed by a revolving credit facility of USD 3.0 billion, supported by 20 core banks, maturing in 2017. The facility supports secure access to funding, supported by the best available short-term rating. It has not been drawn.

Statoil raises debt in all major capital markets (USA, Europe and Asia) for long-term funding purposes. The policy is to have a smooth maturity profile with repayments not exceeding five percent of capital employed in any year for the nearest five years. Statoil's non-current financial liability has a weighted average maturity of approximately nine years.

For more information about Statoil's non-current financial liabilities, see note 18 Finance debt.

The table below shows a maturity profile, based on undiscounted contractual cash flows, for Statoil's financial liabilities.

(in NOK billion)	2014	At 31 December 2013
Due within 1 year	131.4	103.6
Due between 1 and 2 years	43.3	30.5
Due between 3 and 4 years	81.3	41.7
Due between 5 and 10 years	90.5	71.0
Due after 10 years	84.3	94.4
Total specified	430.8	341.2

Credit risk

Credit risk is the risk that Statoil's customers or counterparties will cause Statoil financial loss by failing to honour their obligations. Credit risk arises from credit exposures with customer accounts receivables as well as from financial investments, derivative financial instruments and deposits with financial institutions.

Key elements of the credit risk management approach include:

• A global credit risk policy
• Credit mandates
• An internal credit rating process
• Credit risk mitigation tools
• A continuous monitoring and managing of credit exposures

Prior to entering into transactions with new counterparties, Statoil's credit policy requires all counterparties to be formally identified and approved. In addition, all sales, trading and financial counterparties are assigned internal credit ratings as well as exposure limits. Once established, all counterparties are re-assessed regularly and continuously monitored. Counterparty risk assessments are based on a quantitative and qualitative analysis of recent financial statements and other relevant business information. In addition, Statoil evaluates any past payment performance, the counterparties' size and business diversification, and the inherent industry risk. The internal credit ratings reflect Statoil's assessment of the counterparties' credit risk. Exposure limits are determined based on assigned internal credit ratings combined with other factors, such as expected transaction and industry characteristics. Credit mandates define acceptable credit risk thresholds and are endorsed by management and regularly reviewed with regard to changes in market conditions.

Statoil uses risk mitigation tools to reduce or control credit risk both on a counterparty and portfolio level. The main tools include bank and parental guarantees, prepayments and cash collateral. For bank guarantees, only investment grade international banks are accepted as counterparties.

Statoil has pre-defined limits for the absolute credit risk level allowed at any given time on Statoil's portfolio level as well as maximum credit exposures for individual counterparties. Statoil monitors the portfolio on a regular basis and individual exposures against limits on a daily basis. The total credit exposure portfolio of Statoil is geographically diversified among a number of counterparties within the oil and energy sector, as well as larger oil and gas consumers and financial counterparties. The majority of Statoil's credit exposure is with investment grade counterparties.

The following table contains the carrying amount of Statoil's financial receivables and derivative financial instruments that are neither past due nor impaired split by Statoil's assessment of the counterparty's credit risk. Only non-exchange traded instruments are included in derivative financial instruments.

(in NOK billion)	Non-current financial receivables	Trade and other receivables	Non-current derivative financial instruments	Current derivative financial instruments
At 31 December 2014
Investment grade, rated A or above	0.0	20.1	15.2	2.4
Other investment grade	0.0	36.5	11.8	2.7
Non-investment grade or not rated	2.7	17.2	2.9	0.2
Total financial asset	2.7	73.7	29.9	5.3
At 31 December 2013
Investment grade, rated A or above	0.0	17.2	12.5	1.2
Other investment grade	0.8	45.8	9.3	1.6
Non-investment grade or not rated	2.8	12.6	0.3	0.1
Total financial asset	3.5	75.5	22.1	2.9

At 31 December 2014, NOK 12.9 billion of cash was held as collateral to mitigate a portion of Statoil's credit exposure. At 31 December 2013 NOK 7.4 billion was held as collateral. The collateral cash is received as a security to mitigate credit exposure related to positive fair values on interest rate swaps,

cross currency swaps and foreign exchange swaps. Cash is called as collateral in accordance with the master agreements with the different counterparties when the positive fair values for the different swap agreements are above an agreed threshold.

Under the terms of various master netting agreements for derivative financial instruments as of 31 December 2014, NOK 5.2 billion presented as liabilities do not meet the criteria for offsetting. At 31 December 2013, NOK 2.0 billion was not offset. The collateral received and the amounts not offset from derivative financial instrument liabilities, reduces the credit exposure in the derivative financial instruments presented in the table above as they will offset each other in a potential default situation for the counterparty.

6 Remuneration

			Full year
(in NOK billion, except average number of employees)	2014	2013	2012
Salaries*	23.3	23.5	22.7
Pension costs	3.4	4.6	(0.6)
Payroll tax	3.5	3.4	3.3
Other compensations and social costs	2.4	2.5	2.8
Total payroll costs	32.5	34.0	28.2
Average number of employees**	23,300	23,600	27,700

* Salaries include bonuses, severance packages and expatriate costs in addition to base pay.

** Part time employees amount to 2%, 3% and 3% for the years 2014, 2013 and 2012 respectively.

Total payroll expenses are accumulated in cost-pools and partly charged to partners of Statoil operated licences on an hours incurred basis.

The reduction in pension cost in 2014 was mainly caused by a plan amendment gain recognised on the basis of Statoil's change in the pension plan, partly offset by early retirement benefits offered to a defined group of employees above the age of 58 years. The negative pension cost in 2012 was primarily caused by a curtailment gain recognised on the basis of Statoil's discontinuance of the supplementary (gratuity) part of the early retirement scheme. For further information, see note 19 Pensions.

Compensation to the board of directors (BoD) and the corporate executive committee (CEC)

Remuneration to members of the BoD and the CEC during the year was as follows:

			Full year
(in NOK million)*	2014	2013	2012
Current employee benefits	73.2	74.5	74.8
Post-employment benefits	13.0	13.0	13.6
Other non-current benefits	0.0	0.1	0.1
Share based payment benefits	1.1	1.1	1.2
Total	87.3	88.7	89.8

* All figures in the table are presented on accrual basis, in compliance with the statement presented by The Financial Supervisory Authority of Norway in December 2014. This is a change in reporting of remuneration compared to previous years.

At 31 December 2014, 2013 and 2012 there are no loans to the members of the BoD or the CEC.

Share-based compensation

Statoil's share saving plan provides employees with the opportunity to purchase Statoil shares through monthly salary deductions and a contribution by Statoil. If the shares are kept for two full calendar years of continued employment, the employees will be allocated one bonus share for each one they have purchased.

Estimated compensation expense including the contribution by Statoil for purchased shares, amounts vested for bonus shares granted and related social security tax was NOK 0.6 billion, NOK 0.6 billion and NOK 0.5 billion related to the 2014, 2013 and 2012 programs, respectively. For the 2015 program (granted in 2014) the estimated compensation expense is NOK 0.6 billion. At 31 December 2014 the amount of compensation cost yet to be expensed throughout the vesting period is NOK 1.2 billion.

7 Other expenses

Auditor's remuneration

(in NOK million, excluding VAT)	2014	2013	Full year 2012
Audit fee	45	38	44
Audit related fee	8	8	9
Tax fee	0	0	2
Other service fee	0	0	2
Total	53	46	57

In addition to the figures in the table above, the audit fees and audit related fees related to Statoil operated licenses amount to NOK 6 million, NOK 6 million and NOK 7 million for 2014, 2013 and 2012, respectively.

Research and development expenditures

Research and development (R&D) expenditures were NOK 3.0 billion, NOK 3.2 billion and NOK 2.8 billion in 2014, 2013 and 2012, respectively. R&D expenditures are partly financed by partners of Statoil operated licences. Statoil's share of the expenditures has been recognised as expense in the Consolidated statement of income.

8 Financial items

			Full year
(in NOK billion)	2014	2013	2012
Foreign exchange gains (losses) derivative financial instruments	(1.5)	(4.1)	2.1
Other foreign exchange gains (losses)	(0.7)	(4.5)	(1.3)
Net foreign exchange gains (losses)	(2.2)	(8.6)	0.8
Dividends received	0.3	0.1	0.1
Gains (losses) financial investments	1.1	1.9	0.6
Interest income financial investments	0.7	0.6	0.6
Interest income non-current financial receivables	0.1	0.1	0.1
Interest income current financial assets and other financial items	1.8	0.9	0.4
Interest income and other financial items	4.0	3.6	1.8
Interest expense bonds and bank loans and net interest on related derivatives	(4.3)	(1.5)	(2.5)
Interest expense finance lease liabilities	(0.3)	(0.2)	(0.5)
Capitalised borrowing costs	1.6	1.1	1.2
Accretion expense asset retirement obligations	(3.7)	(3.2)	(3.0)
Gains (losses) derivative financial instruments	5.8	(7.4)	3.0
Interest expense current financial liabilities and other finance expense	(0.8)	(0.8)	(0.7)
Interest and other finance expenses	(1.8)	(12.0)	(2.5)
Net financial items	(0.0)	(17.0)	0.1

Statoil's main financial items relate to assets and liabilities categorised in the held for trading category and the amortised cost category. For more information about financial instruments by category see note 25 Financial instruments: fair value measurement and sensitivity analysis of market risk.

The line item Interest expense bonds and bank loans and net interest on related derivatives primarily includes interest expenses of NOK 6.8 billion, NOK 5.4 billion and NOK 5.0 billion from the financial liabilities at amortised cost category, partly offset by net interest on related derivatives from the held for trading category, NOK 2.5 billion, NOK 3.9 billion and NOK 2.5 billion for 2014, 2013 and 2012, respectively.

The line item Gains (losses) derivative financial instruments primarily includes fair value gain from the held for trading category of NOK 5.7 billion, a loss of NOK 7.6 billion and a gain of NOK 2.9 billion for 2014, 2013 and 2012, respectively.

The line item Foreign exchange gains (losses) derivative financial instruments includes a net foreign exchange loss of NOK 13.4 billion, a loss of NOK 4.3 billion and a gain of NOK 3,4 billion from the held for trading category for 2014, 2013 and 2012, respectively.

9 Income taxes

Significant components of income tax expense

			Full year
(in NOK billion)	2014	2013	2012
Current income tax expense in respect of current year	89.6	111.6	138.1
Prior period adjustments	(1.9)	1.3	(0.5)
Current income tax expense	87.6	112.9	137.6
Origination and reversal of temporary differences	(0.6)	(13.4)	0.3
Recognition of previously unrecognised deferred tax assets	0.0	0.0	(3.0)
Change in tax regulations	0.1	0.1	2.3
Prior period adjustments	0.3	(0.4)	0.0
Deferred tax expense	(0.2)	(13.7)	(0.4)
Income tax expense	87.4	99.2	137.2

Reconciliation of nominal statutory tax rate to effective tax rate

			Full year
(in NOK billion)	2014	2013	2012
Income before tax	109.4	138.4	206.7
Calculated income tax at statutory rate *	31.2	42.4	62.9
Calculated Norwegian Petroleum tax **	62.8	71.7	87.4
Tax effect uplift **	(6.4)	(5.2)	(5.3)
Tax effect of permanent differences	(9.1)	(16.1)	(6.3)
Recognition of previously unrecognised deferred tax assets	0.0	0.0	(3.0)
Change in valuation allowance	8.7	3.9	0.3
Change in tax regulations	0.1	0.1	2.3
Prior period adjustments	(1.7)	0.9	(0.5)
Other items	1.7	1.5	(0.6)
Income tax expense	87.4	99.2	137.2
Effective tax rate	79.9 %	71.7 %	66.4 %

*The weighted average of statutory tax rates was 28.5 % in 2014, 30.7 % in 2013 and 30.4 % in 2012. The decrease from 2013 to 2014 was principally due to a change in the geographic mix of income, with a lower proportion of income in 2014 arising in jurisdictions subject to relatively higher tax rates, and a decrease in the Norwegian statutory tax rate from 28% to 27%. The increase from 2012 to 2013 was due to changes in the geographic mix of income.

** When computing the petroleum tax of 51% on income from the Norwegian continental shelf, a tax-free allowance, or uplift, is granted at a rate of 7.5% per year for investments made prior to 5 May 2013. For investments made from 5 May 2013 the rate is 5.5% per year. Transitional rules apply to investments covered by among others Plans for development and operation (PDOs) or Plans for installation and operation (PIOs) submitted to the Ministry of Oil and Energy prior to 5 May 2013. The uplift is computed on the basis of the original capitalised cost of offshore production installations. The uplift may be deducted from taxable income for a period of four years, starting in the year in which the capital expenditure is incurred. Unused uplift may be carried forward indefinitely. At year end 2014 and 2013, unrecognised uplift credits amounted to NOK 21.1 billion and NOK 19.2 billion, respectively.

Deferred tax assets and liabilities comprise

		Property, plant and equipment
(in NOK billion)	Tax losses carried forward	and Intangible assets	ARO	Pensions	Derivatives	Other	Total
Deferred tax at 31 December 2014
Deferred tax assets	36.7	4.6	73.3	7.0	0.2	13.4	135.3
Deferred tax liabilities	(0.0)	(172.6)	0.0	0.0	(12.9)	(8.4)	(193.8)
Net asset (liability) at 31 December 2014	36.7	(167.9)	73.3	7.0	(12.7)	4.9	(58.6)
Deferred tax at 31 December 2013
Deferred tax assets	15.5	3.8	63.8	6.4	0.0	12.2	101.7
Deferred tax liabilities	(0.0)	(148.1)	(0.0)	(0.0)	(11.3)	(5.1)	(164.5)
Net asset (liability) at 31 December 2013	15.5	(144.3)	63.8	6.4	(11.3)	7.1	(62.8)

Changes in net deferred tax liability during the year were as follows:

(in NOK billion)	2014	2013	2012
Net deferred tax liability at 1 January	62.8	77.3	76.8
Charged (credited) to the Consolidated statement of income	(0.2)	(13.7)	(0.4)
Other comprehensive income	(0.9)	(1.5)	1.7
Translation differences and other	(3.0)	0.7	(0.8)
Net deferred tax liability at 31 December	58.6	62.8	77.3

Deferred tax assets and liabilities are offset to the extent that the deferred taxes relate to the same fiscal authority, and there is a legally enforceable right to offset current tax assets against current tax liabilities. After netting deferred tax assets and liabilities by fiscal entity, deferred taxes are presented on the balance sheet as follows:

		At 31 December
(in NOK billion)	2014	2013
Deferred tax assets	12.9	8.2
Deferred tax liabilities	71.5	71.0

Deferred tax assets are recognised based on the expectation that sufficient taxable income will be available through reversal of taxable temporary differences or future taxable income. At year end 2014 and 2013 the deferred tax assets of NOK 12.9 billion and NOK 8.2 billion, respectively, were primarily recognised in Norway and Angola.

Unrecognised deferred tax assets

		At 31 December
(in NOK billion)	2014	2013
Deductible temporary differences	3.2	0.6
Tax losses carried forward	18.0	11.0

Approximately 23% of the unrecognised losses carry-forwards may be carried forward indefinitely. The majority of the remaining part of the unrecognised tax losses expire after 2026. The unrecognised deductible temporary differences do not expire under the current tax legislation. Deferred tax assets have not been recognised in respect of these items because currently there is insufficient evidence to support that future taxable profits will be available to secure utilisation of the benefits.

10 Earnings per share

The weighted average number of ordinary shares is the basis for computing the basic and diluted earnings per share as disclosed in the Consolidated statement of income. The dilutive effect relates to treasury shares.

			At 31 December
(in millions)	2014	2013	2012
Weighted average number of ordinary shares	3,180.0	3,180.7	3,181.5
Weighted average number of ordinary shares, diluted	3,188.9	3,188.9	3,190.2
Earnings per share for income attributable to equity holders of the company:
Basic (NOK)	6.89	12.53	21.66
Diluted (NOK)	6.87	12.50	21.60

11 Property, plant and equipment

	Machinery, equipment and transportation equipment,	Production plants and oil	Refining and manufacturing	Buildings and	Assets under
(in NOK billion)	including vessels	and gas assets	plants	land	development	Total
Cost at 31 December 2013	21.1	869.9	60.2	8.4	135.5	1,095.1
Additions and transfers	1.0	108.4	2.0	0.7	23.8	135.9
Disposals at cost	(0.1)	(8.5)	(1.4)	(0.0)	(8.9)	(18.9)
Effect of changes in foreign exchange	4.1	67.7	3.8	1.1	14.3	91.0
Cost at 31 December 2014	26.1	1,037.5	64.6	10.1	164.7	1,303.0
Accumulated depreciation and impairment losses at 31 December 2013	(15.5)	(540.1)	(44.9)	(3.8)	(3.3)	(607.7)
Depreciation	(1.2)	(71.0)	(1.8)	(0.3)	(0.0)	(74.4)
Impairment losses	(0.3)	(16.1)	(1.2)	(0.2)	(7.1)	(24.8)
Reversal of impairment losses	0.0	0.3	1.8	0.0	0.2	2.3
Accumulated depreciation and impairment disposed assets	0.1	5.7	(0.2)	0.0	(0.0)	5.7
Effect of changes in foreign exchange	(3.2)	(35.4)	(2.0)	(0.5)	(1.0)	(42.0)
Accumulated depreciation and impairment losses at 31 December 2014	(20.1)	(656.7)	(48.2)	(4.8)	(11.1)	(740.9)
Carrying amount at 31 December 2014	6.0	380.8	16.4	5.3	153.6	562.1
Estimated useful lives (years)	3-20	*	15 - 20	20 - 33

	Machinery, equipment and transportation equipment,	Production plants and oil	Refining and manufacturing	Buildings and	Assets under
(in NOK billion)	including vessels	and gas assets	plants	land	development	Total
Cost at 31 December 2012	18.4	816.4	56.6	7.4	99.0	997.8
Additions and transfers	1.6	77.0	3.0	0.8	36.7	119.0
Disposals at cost	(0.5)	(43.7)	(1.1)	(0.1)	(6.0)	(51.4)
Effect of changes in foreign exchange	1.6	20.3	1.6	0.4	5.8	29.7
Cost at 31 December 2013	21.1	869.9	60.2	8.4	135.5	1,095.1
Accumulated depreciation and impairment losses at 31 December 2012	(12.7)	(501.2)	(39.9)	(2.9)	(2.0)	(558.7)
Depreciation	(1.3)	(61.6)	(2.1)	(0.3)	(0.0)	(65.3)
Impairment losses	(0.9)	(1.1)	(2.7)	(0.5)	(2.0)	(7.2)
Reversal of impairment losses	0.0	0.0	0.0	0.0	0.2	0.2
Accumulated depreciation and impairment disposed assets	0.5	33.5	0.3	(0.0)	0.3	34.6
Effect of changes in foreign exchange	(1.1)	(9.7)	(0.5)	(0.1)	0.2	(11.3)
Accumulated depreciation and impairment losses at 31 December 2013	(15.5)	(540.1)	(44.9)	(3.8)	(3.3)	(607.7)
Carrying amount at 31 December 2013	5.6	329.8	15.2	4.6	132.2	487.4
Estimated useful lives (years)	3-20	*	15 - 20	20 - 33

* Depreciation according to unit of production method, see note 2 Significant accounting policies.

The carrying amount of assets transferred to Property, plant and equipment from Intangible assets in 2014 and 2013 amounted to NOK 9.5 billion and NOK 7.0 billion, respectively. In 2013 a redetermination of the Ormen Lange Unit was concluded, the effects of the redetermination on Property, plant and equipment are included in the Additions and transfers line.

Impairments

During 2014, Statoil recognised total net impairment losses of NOK 38.2 billion on Property, plant and equipment and Intangible assets.

(in NOK billion)	Property, plant and equipment	Intangible assets ***	Total
Producing and development assets *	22.5	6.0	28.5
Goodwill *	0.0	4.2	4.2
Acquisition costs related to oil and gas prospects **	0.0	5.5	5.5
Total net impairment losses recognised	22.5	15.7	38.2

* Producing and development assets and goodwill are subject to impairment assessment under IAS 36. The total net impairment losses recognised under IAS 36 amount to NOK 32.7 billion, including impairment of acquisition costs - oil and gas prospects (intangible assets).

** Acquisition costs related to exploration activities are subject to impairment assessment under the successful efforts method.

*** See note 12 Intangible assets.

In assessing the need for impairment of the carrying amount of a potentially impaired asset, the asset's carrying amount is compared to its recoverable amount. The recoverable amount is the higher of fair value less cost of disposal (FVLCOD) and estimated value in use (VIU).

The base discount rate for VIU calculations is 6.5% real after tax. The discount rate is derived from Statoil's weighted average cost of capital. A derived pre-tax discount rate would generally be in the range of 8-12%, depending on asset specific characteristics, such as specific tax treatments, cash flow profiles and economic life. For certain assets a pre-tax discount rate could be outside this range, mainly due to special tax elements (for example permanent differences) affecting the pre-tax equivalent. See note 2 Significant accounting policies for further information regarding impairment on property, plant and equipment.

(in NOK billion)	Impairment method	Carrying amount before impairment	Carrying amount after impairment	Net impairment loss
Development and Production Norway	VIU	5.2	2.9	2.3
Development and Production International	VIU	187.9	168.4	19.5
Marketing, Processing and Renewable Energy	VIU	8.8	7.9	0.9
Development and Production Norway	FVLCOD	18.3	18.3	0.0
Development and Production International	FVLCOD	25.4	15.4	10.0
Marketing, Processing and Renewable Energy	FVLCOD	0.0	0.0	0.0
Total		245.6	212.9	32.7

During 2014 impairment losses of NOK 32.7 billion were recognised, on producing and development assets and goodwill, primarily due to declining commodity price forecasts (primarily oil). The recoverable amount of assets tested for impairment was mainly based on VIU estimates on the basis of internal forecasts on costs, production profiles and commodity prices. For short term commodity prices, observable forward prices have been used, long term commodity price forecasts are based on internal price forecasts. The FVLCOD have partly been established through comparisons with observed market transactions and bids, and partly through internally prepared net present value estimates using assumed market participant assumptions.

Development and Production Norway (DPN)

In the DPN segment impairment losses of NOK 2.3 billion related to two cash generating units on the Norwegian continental shelf were recognised, primarily resulting from reduced short-term oil price forecasts. The impairment reviews were carried out on a VIU basis.

Development and Production International (DPI)

In the DPI segment impairment losses of NOK 29.5 billion were recognised, of which NOK 22.8 related to unconventional onshore assets in North America and NOK 6.7 billion related to other conventional assets. Impairment losses of NOK 23.9 billion were recognised as Depreciation, amortisation and net impairment losses and NOK 5.6 billion as Exploration expenses, based on the impaired assets' nature.

An impairment loss of NOK 10.0 billion was recognised related to the Kai Kos Dehseh oil sands project in Alberta, Canada. The impairment losses were triggered by Statoil's decision to postpone the development of the Corner field, which is part of the Kai Kos Dehseh project, in combination with a general weakening of the market outlook for oil sands projects, including the impact of market factors such as increased cost level and market access for Alberta oil. The recoverable amount was based on the FVLCOD method in which the value was based on specific market parameters which were observed in recent and relevant market transactions.

The other impairment losses in unconventional onshore assets in North America relate to Statoil's US onshore assets, for a total amount of NOK 12.8 billion, including NOK 3.8 billion of goodwill allocated to these assets, primarily resulting from reduced short-term oil price forecasts. These impairment reviews were carried out on a VIU basis.

The impairment losses related to other conventional assets in the DPI segment which were not considered significant on an individual cash generating unit level, primarily resulting from reduced short-term oil price forecasts, were carried out on a VIU basis.

Marketing, Processing and Renewable Energy (MPR)

In the MPR segment net impairment losses of NOK 0.9 billion were recognised related to refineries and midstream assets and allocated goodwill mainly due to changed expectations of future margins. These impairment assessments were carried out on a VIU basis. In 2013 Statoil recognised impairment losses related to refinery assets in the MPR segment of NOK 4.3 billion. The basis for the impairment losses was value in use estimates triggered by lower future expected refining margins.

Sensitivities

Subsequent to year end 2014, commodity prices have continued to be volatile. Significant downward adjustments of Statoil's commodity price assumptions would result in impairment losses on certain producing and development assets in Statoil's portfolio, including goodwill related to US onshore activities. The table below presents an estimate of the carrying amount of producing and development assets, including goodwill, that would be subject to impairment assessment if a further decline in commodity price forecasts over the lifetime of the assets were 15%. The sensitivity has been established on the assumption that all other factors would remain unchanged.

Carrying amount of producing and development assets which would be subject to impairment assessment assuming an additional decline in commodity price forecasts:

(in NOK billion)	Development and Production Norway	Development and Production International	Marketing, Processing and Renewable Energy	Total
Carrying amount subject to impairment assessment in 2014 (after impairment) *	21	184	8	213
Sensitivity: commodity price decline by 15% **	22	237	8	267

* Relates to assets subject to impairment assessment under IAS 36. As a result of these impairment assessments, Statoil recognised a net impairment loss of NOK 32.7 billion in 2014, as described above.

** The sensitivity which is reflected in this line, relates to the carrying amount of assets subject to impairment assessment under IAS 36. Exploration and evaluation assets accounted for under IFRS 6 are not included.

The information in the table above is for indicative purposes only. A significant and prolonged decline in commodity prices would affect other assumptions, e.g. cost level, currency etc. A general decline in commodity price assumptions of 15% would result in mitigating actions by Statoil by optimising the respective business plans in order to reduce the exposure to changes in the macro environment. Considering the substantial uncertainties related to other relevant assumptions that would be triggered by a significant and prolonged decline in commodity price forecasts, Statoil does not disclose the expected impairment amount.

12 Intangible assets

	Exploration	Acquisition costs - oil and gas
(in NOK billion)	expenses	prospects	Goodwill	Other	Total
Cost at 31 December 2013	20.3	58.6	10.5	3.1	92.4
Additions	7.1	1.5	0.0	(0.0)	8.7
Disposals at cost	(0.9)	(0.7)	(0.0)	(0.3)	(1.8)
Transfers	(4.1)	(5.5)	0.0	0.0	(9.5)
Expensed exploration expenditures previously capitalised	(2.7)	(11.1)	0.0	0.0	(13.7)
Effect of changes in foreign exchange	3.1	10.5	1.7	0.6	15.8
Cost at 31 December 2014	22.9	53.4	12.1	3.4	91.8
Accumulated depreciation and impairment losses at 31 December 2013			0.0	(0.9)	(0.9)
Amortisation and impairments for the year			(4.2)	(0.3)	(4.5)
Effect of changes in foreign exchange			(1.0)	(0.2)	(1.2)
Accumulated depreciation and impairment losses at 31 December 2014			(5.2)	(1.4)	(6.6)
Carrying amount at 31 December 2014	22.9	53.4	6.9	2.0	85.2

	Exploration	Acquisition costs - oil and gas
(in NOK billion)	expenses	prospects	Goodwill	Other	Total
Cost at 31 December 2012	18.6	57.3	9.7	2.7	88.3
Additions	6.3	2.0	0.0	0.3	8.7
Disposals at cost	(1.1)	(0.5)	0.0	(0.0)	(1.6)
Transfers	(2.9)	(4.0)	0.0	(0.1)	(7.0)
Expensed exploration expenditures previously capitalised	(1.9)	(1.2)	0.0	0.0	(3.1)
Effect of changes in foreign exchange	1.2	4.9	0.7	0.2	6.9
Cost at 31 December 2013	20.3	58.6	10.5	3.1	92.4
Accumulated depreciation and impairment losses at 31 December 2012			0.0	(0.7)	(0.7)
Amortisation and impairments for the year			0.0	(0.1)	(0.1)
Effect of changes in foreign exchange			0.0	(0.1)	(0.1)
Accumulated depreciation and impairment losses at 31 December 2013			0.0	(0.9)	(0.9)
Carrying amount at 31 December 2013	20.3	58.6	10.5	2.2	91.5

The useful lives of intangible assets are assessed to be either finite or indefinite. Intangible assets with finite useful lives are amortised systematically over their estimated economic lives, ranging between 10-20 years.

During 2014, intangible assets were impacted by impairments of acquisition costs related to exploration activities of NOK 5.7 billion primarily as a result from dry wells and uncommercial discoveries in Angola and the Gulf of Mexico. Additionally, Statoil recognised impairments of NOK 6.0 billion primarily related to unconventional onshore assets in North America and goodwill primarily related to US onshore assets of NOK 4.2 billion.

Impairment losses and reversals of impairment losses are presented as Exploration expenses and Depreciation, amortisation and net impairment losses on the basis of their nature as exploration assets (intangible assets) and other intangible assets, respectively. The impairment losses and reversal of impairment losses are based on recoverable amount estimates triggered by changes in reserve estimates, cost estimates and market conditions. See note 11 Property, plant and equipment further information on the basis for impairment assessments.

The table below shows the aging of capitalised exploration expenditures.

(in NOK billion)		2014	2013
Less than one year		9.2	7.3
Between one and five years		11.4	11.6
Between five and ten years		2.3	1.4
Total		22.9	20.3
The table below shows the components of the exploration expenses.
(in NOK billion)	2014	2013	Full year 2012
Exploration expenditures	23.9	21.8	20.9
Expensed exploration expenditures previously capitalised	13.7	3.1	3.1
Capitalised exploration	(7.3)	(6.9)	(5.9)
Exploration expenses	30.3	18.0	18.1

13 Financial investments and non-current prepayments

Non-current financial investments

(in NOK billion)	2014	At 31 December 2013
Bonds	11.6	10.0
Listed equity securities	6.6	5.6
Non-listed equity securities	1.4	0.9
Financial investments	19.6	16.4

Bonds and Listed equity securities relate to investment portfolios which are held by Statoil's captive insurance company and accounted for using the fair value option.

Non-current prepayments and financial receivables

		At 31 December
(in NOK billion)	2014	2013
Financial receivables interest bearing	3.7	4.5
Prepayments and other non-interest bearing receivables	2.0	4.1
Prepayments and financial receivables	5.7	8.5

Financial receivables interest bearing primarily relate to loans to employees.

Current financial investments

(in NOK billion)	2014	At 31 December 2013
Time deposits	9.8	4.5
Interest bearing securities	49.4	34.8
Financial investments	59.2	39.2

At 31 December 2014 current Financial investments include NOK 6.0 billion investment portfolios which are held by Statoil's captive insurance company and accounted for using the fair value option. The corresponding balance at 31 December 2013 was NOK 5.3 billion.

For information about financial instruments by category, see note 25 Financial instruments: fair value measurement and sensitivity analysis of market risk.

14 Inventories

(in NOK billion)	2014	At 31 December 2013
Crude oil	10.1	15.2
Petroleum products	6.0	7.4
Other	7.7	7.0
Inventories	23.7	29.6

Other inventory consists of natural gas, spare parts and operational materials, including drilling and well equipment.

The write-down of inventories from cost to net realisable value amounted to an expense of NOK 5.0 billion and NOK 0.1 billion in 2014 and 2013, respectively.

15 Trade and other receivables

(in NOK billion)	2014	At 31 December 2013
Trade receivables	57.8	64.9
Current financial receivables	6.9	2.4
Joint venture receivables	8.5	7.8
Associated companies and other related party receivables	0.5	0.4
Total financial trade and other receivables	73.7	75.6
Non-financial trade and other receivables	9.6	6.2
Trade and other receivables	83.3	81.8

For more information about the credit quality of Statoil's counterparties, see note 5 Financial risk management. For currency sensitivities, see note 25 Financial instruments: fair value measurement and sensitivity analysis of market risk.

16 Cash and cash equivalents

		At 31 December
(in NOK billion)	2014	2013
Cash at bank available	13.5	8.5
Time deposits	32.5	37.1
Money market funds	3.6	6.1
Interest bearing securities	30.6	31.4
Restricted cash, including collateral deposits	2.9	2.3
Cash and cash equivalents	83.1	85.3

Restricted cash at 31 December 2014 and 2013 includes collateral deposits related to trading activities of NOK 2.0 billion and NOK 1.9 billion, respectively. Collateral deposits are related to certain requirements set out by exchanges where Statoil is participating. The terms and conditions related to these requirements are determined by the respective exchanges.

17 Shareholders' equity

At 31 December 2014 and 2013, Statoil's share capital of NOK 7,971,617,757.50 comprised 3,188,647,103 shares at a nominal value of NOK 2.50.

Statoil ASA has only one class of shares and all shares have voting rights. The holders of shares are entitled to receive dividends as and when declared and are entitled to one vote per share at general meetings of the company.

Dividends declared and paid per share were NOK 3.60 for the first two quarters of 2014, NOK 7.00 for 2013 and NOK 6.75 for 2012. Interim dividends of NOK 1.80 per share for the third quarter of 2014 were declared in the fourth quarter of 2014 and have been recognised as a liability in the Consolidated financial statements. This amount will be paid in the first quarter of 2015. Interim dividends of NOK 1.80 per share for the fourth quarter of 2014 have been proposed and is subject to approval at the annual general meeting in May 2015.

Total equity in the parent company Statoil ASA provides the basis for distribution of dividend to shareholders. As of 31 December 2014 total equity in Statoil ASA amounted to NOK 358.2 billion, of which NOK 117.0 billion is restricted equity. Total equity in the parent company as of 31 December 2013 was NOK 321.3 billion, of which NOK 112.2 billion was restricted equity. Restricted equity for 2014 is presented in accordance with the requirements in the Norwegian Limited Liabilities Companies Act effective 1 July 2013.

During 2014 a total of 3,381,488 treasury shares were purchased for NOK 0.6 billion and 2,960,972 treasury shares were allocated to employees participating in the share saving plan. In 2013 a total of 3,937,641 treasury shares were purchased for NOK 0.5 billion and 2,878,255 treasury shares were allocated to employees participating in the share saving plan. At 31 December 2014 Statoil had 10,155,249 treasury shares and at 31 December 2013 9,734,733 treasury shares, all of which are related to Statoil's share saving plan. For further information, see note 6 Remuneration.

18 Finance debt

Capital management

The main objectives of Statoil's capital management policy are to maintain a strong financial position and to ensure sufficient financial flexibility. One of the key ratios in the assessment of Statoil's financial robustness is Net interest-bearing debt adjusted (ND) to capital employed adjusted (CE).

(in NOK billion)	2014	At 31 December 2013
Net interest-bearing debt adjusted (ND)	95.6	63.7
Capital employed adjusted (CE)	476.7	419.7
Net debt to capital employed adjusted (ND/CE)	20.0 %	15.2 %

ND is defined as Statoil's interest bearing financial liabilities less cash and cash equivalents and current financial investments, adjusted for collateral deposits and balances held by Statoil's captive insurance company (an increase of NOK 8.0 billion and NOK 7.1 billion for 2014 and 2013, respectively), balances related to the SDFI (a decrease of NOK 1.6 billion and NOK 1.3 billion for 2014 and 2013, respectively) and project financing exposure that does not correlate to the underlying exposure (a decrease of NOK 0.1 billion and NOK 0.2 billion for 2014 and 2013, respectively). CE is defined as Statoil's total equity (including non-controlling interests) and ND.

Non-current finance debt

Finance debt measures at amortised cost

		Weighted average interest rates in % *		Carrying amount in NOK billion at 31 December		Fair value in NOK billion at 31 December **
	2014	2013	2014	2013	2014	2013
Unsecured bonds
United States Dollar (USD)	3.50	3.76	154.4	117.4	165.0	118.4
Euro (EUR)	3.99	4.02	37.6	33.6	43.8	37.7
Great Britain Pound (GBP)	6.08	6.08	15.9	13.8	22.3	17.7
Norwegian kroner (NOK)	4.18	4.18	3.0	3.0	3.5	3.1
Total			210.9	167.8	234.7	176.8
Unsecured loans
Japanese yen (JPY)	4.30	4.30	0.6	0.6	0.9	0.8
Euro (EUR)	-	3.35	-	1.3	-	1.3
Secured bank loans
United States Dollar (USD)	4.20	4.52	0.1	0.2	0.1	0.2
Norwegian kroner (NOK)	3.11	3.20	0.3	0.2	0.3	0.2
Finance lease liabilities			5.4	5.0	5.6	5.0
Total			6.5	7.3	6.9	7.5
Total finance debt			217.4	175.0	241.6	184.3
Less current portion			12.3	9.6	12.3	9.6
Non-current finance debt			205.1	165.5	229.3	174.7

* Weighted average interest rates are calculated based on the contractual rates on the loans per currency at 31 December and do not include the effect of swap agreements.

** The fair value of the non-current financial liabilities is determined using a discounted cash flow model and is classified at Level 2 in the fair value hierarchy. Interest rates used in the model are derived from the LIBOR and EURIBOR forward curves and will vary based on the time to maturity for the noncurrent financial liabilities. The credit premium used is based on indicative pricing from external financial institutions.

Unsecured bonds amounting to NOK 154.4 billion are denominated in USD and unsecured bonds amounting to NOK 43.0 billion are swapped into USD. Two bonds denominated in EUR amounting to NOK 13.5 billion are not swapped. The table does not include the effects of agreements entered into to swap the various currencies into USD. For further information see note 25 Financial instruments: fair value measurement and sensitivity analysis of market risk.

Substantially all unsecured bond and unsecured bank loan agreements contain provisions restricting future pledging of assets to secure borrowings without granting a similar secured status to the existing bondholders and lenders.

Statoil's secured bank loans in USD have been secured by mortgage of shares in a subsidiary with a book value of NOK 2.1 billion, in addition, security includes Statoil's pro-rata share of income from a project. The secured bank loan in NOK has been secured by real estate and land with a total book value of NOK 0.5 billion.

In 2014 Statoil issued the following bonds:

Issuance date	Amount in USD billion Interest rate in %		Maturity date
10 November 2014	0.75	1.25	November 2017
10 November 2014	0.50	floating	November 2017
10 November 2014	0.75	2.25	November 2019
10 November 2014	0.50	2.75	November 2021
10 November 2014	0.50	3.25	November 2024

Out of Statoil's total outstanding unsecured bond portfolio, 45 bond agreements contain provisions allowing Statoil to call the debt prior to its final redemption at par or at certain specified premiums if there are changes to the Norwegian tax laws. The carrying amount of these agreements is NOK 207.9 billion at the 31 December 2014 closing exchange rate.

For more information about the revolving credit facility, maturity profile for undiscounted cash flows and interest rate risk management, see note 5 Financial risk management.

Subsequent to the balance sheet date, Statoil issued euro 3.75 billion in new bonds, see note 27 Subsequent events.

Non-current finance debt maturity profile

(in NOK billion)	2014	At 31 December 2013
Year 2 and 3	27.3	18.2
Year 4 and 5	44.3	30.1
After 5 years	133.5	117.1
Total repayment of non-current finance debt	205.1	165.5
Weighted average maturity (years)	9	10
Weighted average annual interest rate (%)	3.78	4.06

More information regarding finance lease liabilities is provided in note 22 Leases.

Current finance debt

(in NOK billion)	2014	At 31 December 2013
Collateral liabilities	12.9	7.4
Non-current finance debt due within one year	12.3	9.6
Other including bank overdraft	1.3	0.1
Total current finance debt	26.5	17.1
Weighted average interest rate (%)	2.12	2.12

Collateral liabilities relate mainly to cash received as security for a portion of Statoil's credit exposure.

19 Pensions

The Norwegian companies in the group are subject to the requirements of the Mandatory Company Pensions Act, and the company's pension scheme follows the requirements of the Act.

The main pension schemes in Norway are managed by Statoil Pensjon (Statoil's pension fund - hereafter "Statoil Pension"). Statoil Pension is an independent pension fund that covers the employees in Statoil's Norwegian companies. The purpose of Statoil Pension is to provide retirement and disability pension to members and survivor's pension to spouses, registered partners, cohabitants and children. The pension fund's assets are kept separate from the company's and group companies' assets. Statoil Pension is supervised by the Financial Supervisory Authority of Norway ("Finanstilsynet") and is licensed to operate as a pension fund.

Statoil ASA and a number of its subsidiaries have defined benefit retirement plans. In 2014 Statoil ASA made a decision to change the company's main pension plan in Norway from a defined benefit plan to a defined contribution plan. The actual transitioning to the defined contribution plan will take place in 2015. At the same time paid-up policies for the rights vested in the defined benefit plan will be issued. Employees with less than 15 years of future service before their regular retirement age will retain the existing defined benefit plans. For onshore employees between 37 and 51 years of age and offshore employees between 35 and 49 years of age a compensation plan will be established. The plan amendment resulted in the recognition of a gain (net of past service costs related to the compensation plan) of NOK 3.5 billion in the 2014 Consolidated statement of income as the decision to terminate the plan was made in 2014.

The Norwegian National Insurance Scheme ("Folketrygden") provides pension payments (social security) to all retired Norwegian citizens. Such payments are calculated by references to a base amount ("Grunnbeløpet" or "G") annually approved by the Norwegian Parliament. Statoil's plan benefits are generally based on a minimum of 30 years of service and 66% of the final salary level, including an assumed benefit from the Norwegian National Insurance Scheme.

Due to national agreements in Norway, Statoil is a member of both the previous agreement-based early retirement plan ("AFP") and the AFP scheme applicable from 1 January 2011. Statoil will pay a premium for both AFP schemes until 31 December 2015. After that date, premiums will only be due on the latest AFP scheme. The premium in the latest scheme is calculated on the basis of the employees' income between 1 and 7.1 G. The premium is payable for all employees until age 62. Pension from the latest AFP scheme will be paid from the AFP plan administrator to employees for their full lifetime. Statoil has determined that its obligations under this multi-employer defined benefit plan can be estimated with sufficient reliability for recognition purposes. Accordingly, the estimated proportionate share of the AFP plan has been recognised as a defined benefit obligation.

The present values of the defined benefit obligation and the related current service cost and past service cost are measured using the projected unit credit method. The assumptions for salary increases, increases in pension payments and social security base amount are based on agreed regulation in the plans, historical observations, future expectations of the assumptions and the relationship between these assumptions. At 31 December 2014 the discount rate for the defined benefit plans in Norway is established on the basis of seven years' mortgage covered bonds interest rate extrapolated on a yield curve which matches the duration of Statoil's payment portfolio for earned benefits.

Social security tax is calculated based on a pension plan's net funded status and is included in the defined benefit obligation.

Statoil has more than one defined benefit plan, but the disclosure is made in total since the plans are not subject to materially different risks. Pension plans outside Norway are insignificant and are not disclosed separately.

Some Statoil companies have defined contribution plans. The period's contributions are recognised in the Consolidated statement of income as pension cost for the period.

Net pension cost

(in NOK billion)	2014	2013	Full year 2012
Current service cost	4.7	4.0	3.8
Interest cost	3.1	2.5	2.2
Interest (income) on plan asset	(2.6)	(2.1)	(2.5)
Losses (gains) from curtailment, settlement or plan amendment *	(1.9)	0.0	(4.3)
Actuarial (gains) losses related to termination benefits	(0.2)	0.0	(0.0)
Defined benefit plans	3.2	4.4	(0.8)
Defined contribution plans	0.2	0.2	0.2
Total net pension cost	3.4	4.6	(0.6)

* In 2014 Statoil ASA offered early retirement (termination benefits) to a defined group of employees above the age of 58 years. The expenses of NOK 1.6 billion were recognised in the Consolidated statement of income and partly offset the gain of NOK 3.5 billion related to the plan amendment described above.

Pension cost includes associated social security tax and is partly charged to partners of Statoil operated licences.

(in NOK billion)	2014	2013
Defined benefit obligations (DBO)
At 1 January	79.4	65.7
Current service cost	4.7	4.0
Interest cost	3.1	2.5
Actuarial (gains) losses - Demographic assumptions	(0.1)	5.8
Actuarial (gains) losses - Financial assumptions	4.8	4.8
Actuarial (gains) losses - Experience	(2.1)	(1.1)
Benefits paid	(2.0)	(2.5)
Losses (gains) from curtailment, settlement or plan amendment*	(2.9)	0.0
Paid-up policies	(20.4)	0.0
Foreign currency translation	0.3	0.1
At 31 December	65.0	79.4
Fair value of plan assets
At 1 January	62.3	54.5
Interest income	2.6	2.1
Return on plan assets (excluding interest income)	0.9	4.0
Company contributions	0.1	3.1
Benefits paid	(0.7)	(1.6)
Paid-up policies	(20.4)	0.0
Foreign currency translation	0.3	0.2
At 31 December	45.1	62.3
Net benefit liability at 31 December	(19.9)	(17.0)
Represented by:
Asset recognised as non-current pension assets (funded plan)	8.0	5.3
Liability recognised as non-current pension liabilities (unfunded plans)	(27.9)	(22.3)
DBO specified by funded and unfunded pension plans	65.0	79.4
Funded	37.2	57.1
Unfunded	27.9	22.3
Actual return on assets	3.5	6.1

*An amount of NOK 0.9 billion, related to the plan amendment, has been recognised against Property, plant and equipment.

As part of the change of Statoil ASA's main pension plan in Norway the estimated assets and liabilities related to paid-up policies have been excluded from the 31 December 2014 amounts in the table above.

Actuarial losses and gains recognised directly in Other comprehensive income (OCI)

			Full year
(in NOK billion)	2014	2013	2012
Net actuarial (losses) gains recognised in OCI during the year	0.2	(5.5)	5.3
Actuarial (losses) gains related to currency effects on net obligation and foreign exchange translation	(0.2)	(0.4)	0.2
Tax effects of actuarial (losses) gains recognised in OCI	0.9	1.2	(1.7)
Recognised directly in OCI during the year net of tax	0.9	(4.7)	3.8
Cumulative actuarial (losses) gains recognised directly in OCI net of tax	(14.5)	(15.4)	(11.6)

The line item Net actuarial (losses) gains recognised in OCI during the year in 2014 includes actuarial loss charged to partners of Statoil operated licences.

The line item Actuarial (losses) gains related to currency effects on net obligation and foreign exchange translation includes the translation of the net pension obligation in NOK to the functional currency USD for the parent company, Statoil ASA, and the translation of the net pension obligation from the functional currency USD to Statoil's presentation currency NOK.

Actuarial assumptions

	Assumptions used to determine benefit costs in %		Assumptions used to determine benefit obligations in %		Assumptions used to determine the effect of new pension plan in %
		Full year Full year
	2014	2013	2014	2013	At 14 November 2014
Discount rate	4.00	3.75	2.50	4.00	3.00
Rate of compensation increase	3.50	3.25	2.25	3.50	2.75
Expected rate of pension increase	2.50	1.75	1.50	2.50	1.75
Expected increase of social security base amount (G-amount)	3.25	3.00	2.25	3.25	2.50
Weighted-average duration of the defined benefit obligation			19.1	22.2

The assumptions presented are for the Norwegian companies in Statoil which are members of Statoil's pension fund. The defined benefit plans of other subsidiaries are immaterial to the consolidated pension assets and liabilities.

Expected attrition at 31 December 2014 was 2.1%, 2.2%, 1.3%, 0.5% and 0.2% for the employees under 30 years, 30-39 years, 40-49 years, 50-59 years and 60-67 years, respectively. Expected attrition at 31 December 2013 for the same respective age categories was 2.5%, 3.0%, 1.5%, 0.5% and 0.1%.

For population in Norway, the mortality table K2013, issued by The Financial Supervisory Authority of Norway, is used as the best mortality estimate. Implementation of these tables in 2013 resulted in a gross increase in defined benefit obligation of NOK 7.4 billion.

In 2013 Statoil implemented new disability tables for plans in Norway that resulted in a decrease in defined benefit obligation of NOK 1.6 billion. These tables have been developed by the actuary and represent the best estimate to use for plans in Norway.

Sensitivity analysis

The table below presents an estimate of the potential effects of changes in the key assumptions for the defined benefit plans. The following estimates are based on facts and circumstances as of 31 December 2014. Actual results may materially deviate from these estimates.

				Rate of compensation		Expected rate of pension
(in NOK billion)	0.50 %	Discount rate -0.50 %	0.50 %	increase -0.50 %	0.50 %	increase -0.50 %
Changes in:
Defined benefit obligation at 31 December 2014	(5.0)	6.1	2.7	(2.4)	3.6	(3.3)
Service cost 2015	(0.2)	0.3	0.1	(0.1)	0.1	(0.1)

One additional year of longevity in the mortality assumptions would have an increase on the defined benefit obligation at 31 December 2014 of NOK 2.7 billion.

The sensitivity of the financial results to each of the key assumptions has been estimated based on the assumption that all other factors would remain unchanged. The estimated effects on the financial result would differ from those that would actually appear in the Consolidated financial statements because the Consolidated financial statements would also reflect the relationship between these assumptions.

Pension assets

The plan assets related to the defined benefit plans were measured at fair value at 31 December 2014 and 2013. Statoil Pension invests in both financial assets and real estate.

Real estate properties owned by Statoil Pension amounted to NOK 3.2 billion and NOK 3.1 billion of total pension assets at 31 December 2014 and 2013, respectively, and are rented to Statoil companies.

The table below presents the portfolio weighting as approved by the board of the Statoil Pension for 2014. The portfolio weight during a year will depend on the risk capacity.

	Pension assets on investments classes
(in %)	2014	2013	Target portfolio
Equity securities	40.1	39.6	31 - 43
Bonds	38.7	37.6	36 - 48
Money market instruments	13.4	17.2	0 - 29
Real estate	4.8	5.1	5 - 10
Other assets	3.0	0.5
Total	100.0	100.0

* The interval expresses the scope of tactical deviation.

In 2014 100% of the equity securities, 38% of bonds and 86% of money market instruments had quoted market prices in an active market (Level 1). In 2013 100% of the equity securities, 84% of bonds and 96% of money market instruments had quoted market prices in an active market. Statoil does not have any equity securities, bonds or money market instruments classified in Level 3. Real Estate is classified as Level 3. For definition of the various levels, see note 25 Financial instruments: fair value measurement and sensitivity analysis of market risk.

No company contribution is expected to be paid to Statoil Pension in 2015.

20 Provisions

(in NOK billion)	Asset retirement obligations	Other provisions	Total
Non-current portion at 31 December 2013	89.5	12.3	101.7
Current portion at 31 December 2013 reported as trade and other payables	2.1	13.3	15.4
Provisions at 31 December 2013	91.6	25.6	117.2
New or increased provisions	10.1	5.0	15.1
Decrease in the estimates *	(14.0)	(0.2)	(14.2)
Amounts charged against provisions	(2.0)	(5.3)	(7.3)
Effects of change in the discount rate	15.0	0.4	15.5
Reduction due to divestments	(0.9)	(0.2)	(1.1)
Accretion expenses	3.7	(0.0)	3.7
Reclassification and transfer	0.0	(3.7)	(3.7)
Currency translation	5.2	3.8	9.0
Provisions at 31 December 2014	108.8	25.5	134.2
Current portion at 31 December 2014 reported as trade and other payables	1.4	15.7	17.0
Non-current portion at 31 December 2014	107.4	9.8	117.2

Expected timing of cash outflows

(in NOK billion)	Asset retirement obligations	Other provisions	Total
2015 - 2019	11.7	21.9	33.5
2020 - 2024	11.6	0.4	12.0
2025 - 2029	22.8	0.1	22.9
2030 - 2034	20.2	0.6	20.8
Thereafter	42.5	2.5	45.0
At 31 December 2014	108.8	25.5	134.2

* The decrease in the estimates is mainly caused by reduced inflation expectations.

The timing of cash outflows related to asset retirement obligations primarily depends on when the production ceases at the various facilities.

The Other provisions category mainly relates to expected payments on unresolved claims. The timing and amounts of potential settlements in respect of these provisions are uncertain and dependent on various factors that are outside management's control.

See also comments on provisions in note 23 Other commitments, contingent liabilities and contingent assets.

For further information of methods applied and estimates required, see note 2 Significant accounting policies.

21 Trade and other payables

(in NOK billion)	2014	At 31 December 2013
Trade payables	21.8	28.3
Non-trade payables and accrued expenses	25.2	19.0
Joint venture payables	28.9	22.4
Associated companies and other related party payables	6.6	9.5
Total financial trade and other payables	82.5	79.2
Current portion of provisions and other payables	18.1	16.4
Trade and other payables	100.7	95.6

Included in Current portion of provisions and other payables are certain provisions that are further described in note 23 Other commitments, contingent liabilities and contingent assets. For information regarding currency sensitivities, see note 25 Financial instruments: fair value measurement and sensitivity analysis of market risk. For further information on payables to associated companies and other related parties, see note 24 Related parties.

22 Leases

Statoil leases certain assets, notably drilling rigs, vessels and office buildings.

In 2014, net rental expenditures were NOK 22.9 billion (NOK 17.4 billion in 2013 and NOK 17.6 billion in 2012) of which minimum lease payments were NOK 28.4 billion (NOK 21.2 billion in 2013 and NOK 20.0 billion in 2012) and sublease payments received were NOK 5.5 billion (NOK 3.8 billion in 2013 and NOK 2.4 billion in 2012). Net rental expenditures in 2014 include rig cancellation payments of NOK 1.9 billion. No material contingent rent payments have been expensed in 2014, 2013 or 2012.

The information in the table below shows future minimum lease payments due and receivable under non-cancellable operating leases at 31 December 2014:

	Operating leases
(in NOK billion)	Rigs	Vessels	Other	Total	Sublease	Net total
2015	21.6	4.4	1.8	27.7	(3.8)	23.9
2016	17.2	3.1	1.5	21.8	(2.5)	19.3
2017	8.3	2.1	2.0	12.4	(0.9)	11.4
2018	5.7	2.0	1.6	9.3	(0.8)	8.5
2019	4.9	1.7	1.6	8.1	(0.8)	7.3
Thereafter	11.5	6.5	10.4	28.4	(2.1)	26.4
Total future minimum lease payments	69.1	19.8	18.9	107.8	(10.9)	96.8

Statoil had certain operating lease contracts for drilling rigs at 31 December 2014. The remaining significant contracts' terms range from seven months to eight years. Certain contracts contain renewal options. Rig lease agreements are for the most part based on fixed day rates. Certain rigs have been subleased in whole or for part of the lease term mainly to Statoil operated licenses on the Norwegian continental shelf. These leases are shown gross as operating leases in the table above.

Statoil has a long-term time charter agreement with Teekay for offshore loading and transportation in the North Sea. The contract covers the lifetime of applicable producing fields and at year end 2014 included four crude tankers. The contract's estimated nominal amount was approximately NOK 5.0 billion at year end 2014, and it is included in Vessels in the table above.

The category Other includes future minimum lease payments of NOK 4.3 billion related to the lease of two office buildings located in Bergen and owned by Statoil`s pension fund ("Statoil Pension"). These operating lease commitments to a related party extend to the year 2034. NOK 3.2 billion of the total is payable after 2019.

Statoil had finance lease liabilities of NOK 5.4 billion at 31 December 2014. The nominal minimum lease payments related to these finance leases amount to NOK 7.7 billion. Property, plant and equipment includes NOK 5.7 billion for finance leases that have been capitalised at year end (NOK 4.9 billion in 2013), also presented mainly within the category Machinery, equipment and transportation equipment, including Vessels in note 11 Property, plant and equipment.

23 Other commitments, contingent liabilities and contingent assets

Contractual commitments

Statoil had contractual commitments of NOK 67.2 billion at 31 December 2014. The contractual commitments reflect Statoil's share and mainly comprise construction and acquisition of property, plant and equipment. The sale of Statoil`s remaining 15.5% ownership interest in Shah Deniz, announced in October 2014, will reduce contractual commitments related to Shah Deniz expansion by NOK 7.3 billion (USD 1.0 billion) .

As a condition for being awarded oil and gas exploration and production licences, participants may be committed to drill a certain number of wells. At the end of 2014, Statoil was committed to participate in 33 wells, with an average ownership interest of approximately 35%. Statoil's share of estimated expenditures to drill these wells amounts to NOK 8.7 billion. Additional wells that Statoil may become committed to participating in depending on future discoveries in certain licences are not included in these numbers.

Other long-term commitments

Statoil has entered into various long-term agreements for pipeline transportation as well as terminal use, processing, storage and entry/exit capacity commitments and commitments related to specific purchase agreements. The agreements ensure the rights to the capacity or volumes in question, but also impose on Statoil the obligation to pay for the agreed-upon service or commodity, irrespective of actual use. The contracts' terms vary, with durations of up to 30 years.

Take-or-pay contracts for the purchase of commodity quantities are only included in the table below if their contractually agreed pricing is of a nature that will or may deviate from the obtainable market prices for the commodity at the time of delivery.

Obligations payable by Statoil to entities accounted for using the equity method are included gross in the table below. For assets (for example pipelines) that Statoil accounts for by recognising its share of assets, liabilities, income and expenses (capacity costs) on a line-by-line basis in the Consolidated financial statements, the amounts in the table include the net commitment payable by Statoil (i.e. gross commitment less the non-Statoil share).

Nominal minimum other long-term commitments at 31 December 2014:

(in NOK billion)
2015	15.3
2016	14.1
2017	13.2
2018	12.7
2019	12.7
Thereafter	143.3
Total	211.3

The sale of Statoil`s remaining 15.5% ownership interest in Shah Deniz, will reduce commitments related to long-term agreements for pipeline transportation by approximately NOK 60 billion upon closing of the transaction.

Contingent liabilities and contingent assets

In 2014 Statoil received an arbitration ruling award payment which finally concluded a dispute against a counterparty concerning contractual obligations. An amount of NOK 2.8 billion (USD 0.5 billion) has been recognised in the MPR segment and presented as Other income in 2014.

A number of Statoil's long-term gas sales agreements contain price review clauses. Certain counterparties have requested arbitration in connection with price review claims. The related exposure for Statoil has been estimated to an amount equivalent to approximately NOK 4.4 billion for gas delivered prior to year end 2014. Statoil has provided for its best estimate related to these contractual gas price disputes in the Consolidated financial statements, with the impact to the Consolidated statement of income reflected as revenue adjustments.

During the annual audits of Statoil's participation in Block 4, Block 15, Block 17 and Block 31 offshore Angola, the Angolan Ministry of Finance has assessed additional profit oil and taxes due on the basis of activities that currently include the years 2002 up to and including 2011. Statoil disputes the assessments and is pursuing these matters in accordance with relevant Angolan legal and administrative procedures. On the basis of the assessments and continued activity on the four blocks up to and including 2014, the exposure for Statoil at year end 2014 is estimated at NOK 9.3 billion (USD 1.2 billion), the most significant part of which relates to profit oil elements. Statoil has provided in the Consolidated financial statements for its best estimate related to the assessments, reflected in the Consolidated statement of income mainly as a revenue reduction, with additional amounts reflected as interest expenses and tax expenses, respectively.

There is a dispute between the Nigerian National Petroleum Corporation (NNPC) and the partners (Contractor) in Oil Mining Lease (OML) 128 of the unitised Agbami field concerning interpretation of the terms of the OML 128 Production Sharing Contract (PSC). The dispute relates to the allocation between NNPC and Contractor of cost oil, tax oil and profit oil volumes. NNPC claims that in aggregate from the year 2009 to 2014, Contractor has lifted excess volumes compared to the PSC terms, and consequently NNPC has increased its lifting of oil. The Contractor disputes NNPC's position. Arbitration has been initiated in the matter in accordance with the terms of the PSC. The Nigerian Federal Inland Revenue Service is contesting the legality of the arbitration process as far as resolving tax related disputes goes, and is actively pursuing this view through the channels of the Nigerian legal system. The exposure for Statoil at year end 2014 is mainly related to cost oil and profit oil volumes and has been estimated at NOK 1.9 billion (USD 0.3 billion). Statoil has provided in the Consolidated financial statements for its best estimate related to the claims, which has been reflected in the Consolidated statement of income as a reduction of revenue.

Through its ownership in OML 128 in Nigeria, Statoil is party to an ownership interest redetermination process for the Agbami field for which the outcome is uncertain. Statoil has disputed certain aspects of the basis for the redetermination, and an arbitration process has been initiated. The exposure for Statoil at year end 2014 has been estimated to approximately NOK 6.3 billion (USD 0.8 billion). Statoil has made a provision based on its best estimate for the redetermination process. The provision has been reflected within Provisions in the Consolidated balance sheet at 31 December 2014.

In 2014, following a regular review process of Statoil's 2012 Consolidated financial statements, the Financial Supervisory Authority of Norway (the FSA) ordered Statoil to: "Change its future accounting practices for redetermination of CGUs containing onerous contracts. Correct the described error by establishing a separate onerous contract provision for the Cove Point capacity contract in a financial period prior to Q1-2013. The correction shall be presented in the next periodic financial report. Information about the circumstances shall be given in notes to the accounts." Statoil appealed the order and has been granted a stay in carrying out the FSA's order pending the final outcome of the appeal. The appeal is currently being assessed by the Norwegian Ministry of Finance and not yet concluded. If the outcome of the appeal would require implementing the FSA's order, a provision would be recognised against Net operating income in an earlier reporting period than 2013. As the contracts were fully provided for in 2013, there would be no impact on equity at 31 December 2013 or thereafter. The actual amount to be provided in an earlier period would depend on the period in which the provision would be recorded. The FSA order does not specify which period prior to the first quarter 2013 would be relevant for the provision to be recognised. Statoil's reading is that 2011 would be most relevant. There would be no impact on the 2014 financial statements, however, the comparative amounts included therein for 2013 Net operating income and Net income would be NOK 5.6 billion and NOK 5.0 billion higher, respectively. There would be a minor impact on the 2012 Consolidated statement of income, and a NOK 5.0 billion reduction in the 2012 Shareholder's equity.

During the normal course of its business, Statoil is involved in legal proceedings, and several other unresolved claims are currently outstanding. The ultimate liability or asset, in respect of such litigation and claims cannot be determined at this time. Statoil has provided in its Consolidated financial statements for probable liabilities related to litigation and claims based on its best estimate. 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.

Statoil is actively pursuing the above disputes through the contractual and legal means available in each case, but the timing of the ultimate resolutions and related cash flows, if any, cannot at present be determined with sufficient reliability.

Provisions related to claims are reflected within note 20 Provisions.

24 Related parties

Transactions with the Norwegian State

The Norwegian State is the majority shareholder of Statoil and also holds major investments in other Norwegian companies. As of 31 December 2014 the Norwegian State had an ownership interest in Statoil of 67.0% (excluding Folketrygdfondet (Norwegian national insurance fund) of 3.1%). 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. All transactions are considered to be on an arm's length basis.

Total purchases of oil and natural gas liquids from the Norwegian State amounted to NOK 86.4 billion, NOK 92.5 billion and NOK 96.6 billion in 2014, 2013 and 2012, respectively. Purchases of natural gas regarding the Tjeldbergodden methanol plant from the Norwegian State amounted to NOK 0.5 billion, NOK 0.5 billion and NOK 0.4 billion in 2014, 2013 and 2012, respectively. In addition, Statoil ASA sells in its own name, but for the Norwegian State's account and risk, the Norwegian State's gas production. These amounts are presented net. For further information please see in note 2 Significant accounting policies. The most significant items included in the line item Associated companies and other related party payables in note 21 Trade and other payables, are amounts payable to the Norwegian State for these purchases.

Other transactions

In relation to its ordinary business operations such as pipeline transport, gas storage and processing of petroleum products, Statoil also has regular transactions with certain entities in which Statoil has ownership interests. Such transactions are carried out on an arm's length basis and are included within the applicable captions in the Consolidated statement of income.

For information concerning certain lease arrangements with Statoil Pension, see note 22 Leases.

Related party transactions with management are presented in note 6 Remuneration. Management remuneration for 2014 is presented in note 5 Remuneration in the financial statements of the parent company, Statoil ASA.

25 Financial instruments: fair value measurement and sensitivity analysis of market risk

Financial instruments by category

The following tables present Statoil's classes of financial instruments and their carrying amounts by the categories as they are defined in IAS 39 Financial Instruments: Recognition and Measurement. All financial instruments' carrying amounts are measured at fair value or their carrying amounts reasonably approximate fair value except non-current financial liabilities. See note 18 Finance debt for fair value information of non-current bonds, bank loans and finance lease liabilities.

See note 2 Significant accounting policies for further information regarding measurement of fair values.

				Fair value through profit or loss
(in NOK billion)	Note	Loans and receivables	Available for	sale Held for trading	Fair value option	Non-financial assets	Total carrying amount
At 31 December 2014
Assets
Non-current derivative financial instruments		0.0	0.0	29.9	0.0	0.0	29.9
Non-current financial investments	13	0.0	1.4	0.0	18.2	0.0	19.6
Prepayments and financial receivables	13	2.7	0.0	0.0	0.0	2.9	5.7
Trade and other receivables	15	73.7	0.0	0.0	0.0	9.6	83.3
Current derivative financial instruments		0.0	0.0	5.3	0.0	0.0	5.3
Current financial investments	13	9.8	0.0	43.4	6.0	0.0	59.2
Cash and cash equivalents	16	48.9	0.0	34.2	0.0	0.0	83.1
Total		135.2	1.4	112.8	24.2	12.6	286.2

				Fair value through profit or loss
(in NOK billion)	Note	Loans and receivables	Available for	sale Held for trading	Fair value option	Non-financial assets	Total carrying amount
At 31 December 2013
Assets
Non-current derivative financial instruments		0.0	0.0	22.1	0.0	0.0	22.1
Non-current financial investments	13	0.0	0.9	0.0	15.6	0.0	16.4
Prepayments and financial receivables	13	3.5	0.0	0.0	0.0	5.0	8.5
Trade and other receivables	15	75.5	0.0	0.0	0.0	6.2	81.8
Current derivative financial instruments		0.0	0.0	2.9	0.0	0.0	2.9
Current financial investments	13	4.5	0.0	29.4	5.3	0.0	39.2
Cash and cash equivalents	16	47.9	0.0	37.4	0.0	0.0	85.3
Total		131.5	0.9	91.8	20.9	11.2	256.2

(in NOK billion)	Note	Amortised cost	Fair value through profit or loss	Non-financial liabilities	Total carrying amount
At 31 December 2014
Liabilities
Non-current finance debt	18	205.1	0.0	0.0	205.1
Non-current derivative financial instruments		0.0	4.5	0.0	4.5
Trade and other payables	21	82.5	0.0	18.1	100.7
Current finance debt	18	26.5	0.0	0.0	26.5
Dividend payable		5.7	0.0	0.0	5.7
Current derivative financial instruments		0.0	6.6	0.0	6.6
Total		319.8	11.1	18.1	349.1

Note	Amortised cost	Fair value through profit or loss	Non-financial liabilities	Total carrying amount
				165.5
	0.0	2.2	0.0	2.2
21	79.2	0.0	16.4	95.6
18	17.1	0.0	0.0	17.1
				1.5
	261.8	3.7	16.4	281.9
	18	165.5 0.0	0.0 1.5	0.0 0.0

Fair value hierarchy

The following table summarises each class of financial instruments which are recognised in the balance sheet at fair value, split by Statoil's basis for fair value measurement.

(in NOK billion)	Non-current financial investments	Non-current derivative financial instruments - assets	Current financial investments	Current derivative financial instruments -	assets Cash equivalents	Non-current derivative financial instruments - liabilities	Current derivative financial instruments - liabilities	Net fair value
At 31 December 2014
Level 1	11.1	0.0	4.0	0.0	0.0	0.0	0.0	15.1
Level 2	7.0	17.2	45.5	4.7	34.2	(4.5)	(6.6)	97.4
Level 3	1.4	12.7	0.0	0.6	0.0	0.0	(0.0)	14.7
Total fair value	19.6	29.9	49.4	5.3	34.2	(4.5)	(6.6)	127.3
At 31 December 2013
Level 1	8.7	0.0	4.0	0.0	0.0	0.0	(0.0)	12.7
Level 2	6.9	10.1	30.7	1.6	37.4	(2.2)	(1.5)	83.0
Level 3	0.9	12.0	0.0	1.3	0.0	0.0	(0.0)	14.2
Total fair value	16.4	22.1	34.7	2.9	37.4	(2.2)	(1.5)	109.9

Level 1, fair value based on prices quoted in an active market for identical assets or liabilities, includes financial instruments actively traded and for which the values recognised in the Consolidated balance sheet are determined based on observable prices on identical instruments. For Statoil this category will, in most cases, only be relevant for investments in listed equity securities and government bonds.

Level 2, fair value based on inputs other than quoted prices included within Level 1, which are derived from observable market transactions, includes Statoil's non-standardised contracts for which fair values are determined on the basis of price inputs from observable market transactions. This will typically be when Statoil uses forward prices on crude oil, natural gas, interest rates and foreign exchange rates as inputs to the valuation models to determining the fair value of its derivative financial instruments.

Level 3, fair value based on unobservable inputs, includes financial instruments for which fair values are determined on the basis of input and assumptions that are not from observable market transactions. The fair values presented in this category are mainly based on internal assumptions. The internal assumptions are only used in the absence of quoted prices from an active market or other observable price inputs for the financial instruments subject to the valuation.

The fair value of certain earn-out agreements and embedded derivative contracts are determined by the use of valuation techniques with price inputs from observable market transactions as well as internally generated price assumptions and volume profiles. The discount rate used in the valuation is a risk-free rate based on the applicable currency and time horizon of the underlying cash flows adjusted for a credit premium to reflect either Statoil's credit premium, if the value is a liability, or an estimated counterparty credit premium if the value is an asset. In addition a risk premium for risk elements not adjusted for in the cash flow may be included when applicable. The fair values of these derivative financial instruments have been classified in their entirety in the third category within Current derivative financial instruments and Non-current derivative financial instruments - assets in the table above. Another reasonable assumption, that could have been applied when determining the fair value of these contracts, would be to extrapolate the last observed forward prices with inflation. If Statoil had applied this assumption, the fair value of the contracts included would have decreased by approximately NOK 3.5 billion at end of 2014 and decreased by NOK 0.5 billion at end of 2013 and impacted the Consolidated statement of income with corresponding amounts.

The reconciliation of the changes in fair value during 2014 and 2013 for all financial assets classified in the third level in the hierarchy are presented in the following table.

	Non-current financial	Non-current derivative financial instruments -	Current derivative financial instruments -
(in NOK billion)	investments	assets	assets	Total amount
Full year 2014
Opening balance	0.9	12.0	1.3	14.2
Total gains and losses recognised
- in statement of income	(0.0)	0.3	0.6	0.9
- in other comprehensive income	0.0	0.0	0.0	0.0
Purchases	0.3	0.0	0.0	0.3
Sales	0.0	0.4	0.0	0.4
Settlement	(0.0)	0.0	(1.3)	(1.3)
Foreign currency translation differences	0.2	0.1	(0.0)	0.3
Closing balance	1.4	12.7	0.6	14.8
Full year 2013
Opening balance	1.2	16.6	1.4	19.2
Total gains and losses recognised
- in statement of income	(0.4)	(5.4)	1.3	(4.5)
- in other comprehensive income	0.0	0.0	0.0	0.0
Purchases	0.3	0.0	0.0	0.3
Sales	0.0	0.7	0.0	0.7
Settlement	(0.3)	0.0	(1.4)	(1.7)
Foreign currency translation differences	0.1	0.0	(0.0)	0.1
Closing balance	0.9	12.0	1.3	14.2

The assets within Level 3 during 2014 have had a net increase in the fair value of NOK 0.6 billion. Of the NOK 0.9 billion recognised in the Consolidated statement of income during 2014, NOK 0.8 billion is related to changes in fair value of certain earn-out agreements. Related to the same earn-out agreements, NOK 1.3 billion included in the opening balance for 2014 has been fully realised as the underlying volumes have been delivered during 2014 and the amount is presented as settled in the above table.

Substantially all gains and losses recognised in the Consolidated statement of income during 2014 are related to assets held at the end of 2014.

Sensitivity analysis of market risk

Commodity price risk

The table below contains the fair value and related commodity price risk sensitivities of Statoil's commodity based derivatives contracts. For further information related to the type of commodity risks and how Statoil manages these risks, see note 5 Financial risk management.

Statoil's assets and liabilities resulting from commodity based derivatives contracts are mainly related to non-exchange traded derivative instruments, including embedded derivatives that have been bifurcated and recognised at fair value in the Consolidated balance sheet.

Price risk sensitivities at the end of 2014 and 2013 have been calculated assuming a reasonably possible change of 40% in crude oil, refined products, electricity and natural gas prices.

Since none of the derivative financial instruments included in the table below are part of hedging relationships, any changes in the fair value would be recognised in the Consolidated statement of income.

(in NOK billion)	- 40% sensitivity	40% sensitivity
At 31 December 2014
Crude oil and refined products net gains (losses)	(5.8)	5.8
Natural gas and electricity net gains (losses)	0.9	(0.9)
At 31 December 2013
Crude oil and refined products net gains (losses)	(6.6)	6.6
Natural gas and electricity net gains (losses)	(0.2)	0.2

Currency risk

Currency risk constitutes significant financial risk for Statoil. In accordance with approved strategies and mandates total exposure is managed at a portfolio level on a regular basis. For further information related to the currency risk and how Statoil manages these risks, see note 5 Financial risk management.

The following currency risk sensitivities at the end of 2014 and 2013 have been calculated by assuming a 9% reasonably possible change in the main foreign exchange rates that Statoil is exposed to. An increase in the foreign exchange rates by 9% means that the transaction currency has strengthened in value. The estimated gains and the estimated losses following from a change in the foreign exchange rates would impact the Consolidated statement of income.

(in NOK billion)	- 9% sensitivity	9% sensitivity
At 31 December 2014
USD net gains (losses)	8.1	(8.1)
NOK net gains (losses)	(8.3)	8.3
At 31 December 2013
USD net gains (losses)	8.7	(8.7)
NOK net gains (losses)	(8.0)	8.0

Interest rate risk

Interest rate risk constitutes significant financial risk for Statoil. In accordance with approved strategies and mandates total exposure is managed at a portfolio level on a regular basis. For further information related to the interest risks and how Statoil manages these risks, see note 5 Financial risk management.

The following interest rate risk sensitivity has been calculated by assuming a 0.8% reasonably possible changes in the interest rates at the end of 2014. At the end of 2013 a change of 1.0% in the interest rates were viewed as reasonably possible changes. The estimated gains following from a decrease in the interest rates and the estimated losses following from an interest rate increase would impact the Consolidated statement of income.

(in NOK billion)	- 0.8% sensitivity	0.8% sensitivity
At 31 December 2014
Interest rate net gains (losses)	7.1	(7.1)
(in NOK billion)	- 1% sensitivity	1% sensitivity
At 31 December 2013
Interest rate net gains (losses)	6.1	(6.1)

26 Supplementary oil and gas information (unaudited)

In accordance with Financial Accounting Standards Board Accounting Standards Codification "Extractive Activities - Oil and Gas" (Topic 932), Statoil is reporting certain supplemental disclosures about oil and gas exploration and production operations. While this information is developed with reasonable care and disclosed in good faith, it is emphasised that some of the data is necessarily imprecise and represents only approximate amounts because of the subjective judgement involved in developing such information. Accordingly, this information may not necessarily represent the present financial condition of Statoil or its expected future results.

For further information regarding the reserves estimation requirement, see note 2 Significant accounting policies - Critical accounting judgements and key sources of estimation uncertainty - Proved oil and gas reserves.

No new events have occurred since 31 December 2014 that would result in a significant change in the estimated proved reserves or other figures reported as of that date.

The effects of the agreement with PETRONAS to divest Statoil's remaining 15.5% interest in the Shah Deniz project in Azerbaijan and the agreement with Southwestern Energy to reduce Statoil's working interest in the non-operated Southern Marcellus onshore play in the United States will all be included in 2015. The net effect of these changes will be a reduction in proved reserves at year end 2015 of approximately 230 million boe.

Oil and gas reserve quantities

Statoil's oil and gas reserves have been estimated by its qualified professionals in accordance with industry standards under the requirements of the U.S. Securities and Exchange Commission (SEC), Rule 4-10 of Regulation S-X. Statements of reserves are forward-looking statements.

The determination of these reserves is part of an ongoing process subject to continual revision as additional information becomes available. Estimates of proved reserve quantities are imprecise and change over time as new information becomes available. Moreover, identified reserves and contingent resources that may become proved in the future are excluded from the calculations.

Statoil's proved reserves are recognised under various forms of contractual agreements, including production sharing agreements (PSAs) where Statoil's share of reserves can vary due to commodity prices or other factors. Reserves from agreements such as PSAs and buy back agreements are based on the volumes to which Statoil has access (cost oil and profit oil), limited to available market access. At 31 December 2014, 12% of total proved reserves were related to such agreements (18% of total oil, condensate and natural gas liquids (NGL) reserves and 8% of total gas reserves). This compares with 14% and 9% of total proved reserves for 2013 and 2012, respectively. Net entitlement oil and gas production from fields with such agreements was 95 million boe during 2014 (93 million boe for 2013 and 89 million boe for 2012). Statoil participates in such agreements in Algeria, Angola, Azerbaijan, Libya, Nigeria and Russia.

Statoil is recording, as proved reserves, volumes equivalent to our tax liabilities under negotiated fiscal arrangements (PSAs) where the tax is paid on behalf of Statoil. Reserves are net of royalty oil paid in kind and quantities consumed during production.

Rule 4-10 of Regulation S-X requires that the appraisal of reserves is based on existing economic conditions, including a 12-month average price prior to the end of the reporting period, unless prices are defined by contractual arrangements. Oil reserves at year-end 2014 have been determined based on a 12-month average 2014 Brent blend price equivalent to USD 101.27/bbl. The slight decrease in oil price from 2013, when the average Brent blend price was USD 108.02/bbl result in minor effect on the profitable oil to be recovered from the accumulations, and on Statoil's proved oil reserves under PSAs and similar contracts. Gas reserves at year end 2014 have been determined based on achieved gas prices during 2014 giving a volume weighted average gas price of 1.9 NOK/Sm3. The comparable volume weighted average gas price used to determine gas reserves at year end 2013 was 2.13 NOK/Sm3. The slight decrease in gas prices from 2013 result in no material effect on gas reserves. NGL reserves at year end 2014 have been determined based on achieved NGL prices during 2014 giving a volume weighted average NGL price of USD 57.03/boe. The corresponding volume weighted NGL price at year end 2013 was USD 62.32/boe. The slight decrease in NGL prices from 2013 has had no material effect in NGL reserves at year end 2014. These changes are all included in the revision category in the tables below.

From the Norwegian continental shelf (NCS), Statoil is responsible for managing, transporting and selling the Norwegian State's oil and gas on behalf of the Norwegian State's direct financial interest (SDFI). These reserves are sold in conjunction with the Statoil reserves. As part of this arrangement, Statoil delivers and sells gas to customers in accordance with various types of sales contracts on behalf of the SDFI. In order to fulfil the commitments, Statoil utilises a field supply schedule which provides the highest possible total value for the joint portfolio of oil and gas between Statoil and the SDFI.

Statoil and the SDFI receive income from the joint natural gas sales portfolio based upon their respective share in the supplied volumes. For sales of the SDFI natural gas, to Statoil and to third parties, the payment to the Norwegian State is based on achieved prices, a net back formula calculated price or market value. All of the Norwegian State's oil and NGL is acquired by Statoil. The price Statoil pays to the SDFI for the crude oil is based on market reflective prices. The prices for NGL are either based on achieved prices, market value or market reflective prices.

The regulations of the owner's instruction, as described above, may be changed or withdrawn by the Statoil ASA's general meeting. Due to this uncertainty and the Norwegian State's estimate of proved reserves not being available to Statoil, it is not possible to determine the total quantities to be purchased by Statoil under the owner's instruction.

Topic 932 requires the presentation of reserves and certain other supplemental oil and gas disclosures by geographical area, defined as country or continent containing 15% or more of total proved reserves. Norway contains 68% of total proved reserves at 31 December 2014 and no other country contains reserves approaching 15% of total proved reserves. Accordingly, management has determined that the most meaningful presentation of geographical areas would be Norway and the continents of Eurasia (excluding Norway), Africa and Americas.

The following tables reflect the estimated proved reserves of oil and gas at 31 December 2011 through 2014, and the changes therein.

		Consolidated companies				Equity accounted
	Norway	Eurasia excluding Norway	Africa	Americas	Subtotal	Americas	Total
Net proved oil and condensate reserves in million barrels oil equivalent
At 31 December 2011	996	114	293	373	1,775	95	1,870
Revisions and improved recovery	92	12	42	14	160	(8)	152
Extensions and discoveries	77	85	-	52	213	-	213
Purchase of reserves-in-place	-	-	-	0	0	-	0
Sales of reserves-in-place	(11)	-	-	(1)	(12)	-	(12)
Production	(185)	(17)	(53)	(43)	(299)	(5)	(303)
At 31 December 2012	968	193	281	395	1,837	82	1,919
	-	-	-	-		-
Revisions and improved recovery	133	16	40	18	207	(16)	191
Extensions and discoveries	19	47	8	34	108	-	108
Purchase of reserves-in-place	13	-	-	-	13	-	13
Sales of reserves-in-place	(40)	(15)	-	(2)	(57)	-	(57)
Production	(174)	(15)	(58)	(46)	(294)	(4)	(298)
At 31 December 2013	918	227	271	399	1,815	63	1,877
Revisions and improved recovery	143	10	85	(4)	235	(3)	232
Extensions and discoveries	3	-	5	145	153	-	153
Purchase of reserves-in-place	-	-	-	20	20	-	20
Sales of reserves-in-place	(5)	(27)	(2)	-	(34)	-	(34)
Production	(173)	(14)	(64)	(51)	(301)	(4)	(306)
At 31 December 2014	886	196	296	508	1,887	55	1,942

Proved reserves of bitumen in Americas, representing less than 2% of Statoil's proved reserves, is included as oil in the table above.

		Consolidated companies				Equity accounted	Total
	Norway	Eurasia excluding Norway	Africa	Americas	Subtotal	Americas	Total
Net proved NGL reserves in million barrels oil equivalent
At 31 December 2011	373	-	20	12	406	-	406
Revisions and improved recovery	58	-	0	7	65	-	65
Extensions and discoveries	24	-	-	29	53	-	53
Purchase of reserves-in-place	-	-	-	1	1	-	1
Sales of reserves-in-place	(5)	-	-	(0)	(5)	-	(5)
Production	(45)	-	(2)	(2)	(50)	-	(50)
At 31 December 2012	405	-	18	47	469	-	469
Revisions and improved recovery	25	-	(0)	4	28	-	28
Extensions and discoveries	1	-	-	10	11	-	11
Purchase of reserves-in-place	0	-	-	-	0	-	0
Sales of reserves-in-place	(21)	-	-	-	(21)	-	(21)
Production	(42)	-	(1)	(4)	(47)	-	(47)
At 31 December 2013	368	-	16	56	441	-	441
Revisions and improved recovery	(2)	-	1	5	4	-	4
Extensions and discoveries	3	-	-	18	21	-	21
Purchase of reserves-in-place	-	-	-	-	-	-	-
Sales of reserves-in-place	(10)	-	-	(2)	(12)	-	(12)
Production	(42)	-	(2)	(7)	(51)	-	(51)
At 31 December 2014	318	-	15	69	403	-	403

		Consolidated companies				Equity accounted	Total
	Norway	Eurasia excluding Norway	Africa	Americas	Subtotal	Americas	Total
Net proved gas reserves in billion standard cubic feet
At 31 December 2011	15,689	608	431	952	17,681	-	17,681
Revisions and improved recovery	824	29	(49)	(39)	766	-	766
Extensions and discoveries	279	-	-	352	630	-	630
Purchase of reserves-in-place	-	-	-	18	18	-	18
Sales of reserves-in-place	(305)	-	-	(14)	(319)	-	(319)
Production	(1,483)	(62)	(41)	(161)	(1,748)	-	(1,748)
At 31 December 2012	15,003	575	341	1,107	17,027	-	17,027
	-	-	-	-		-
Revisions and improved recovery	391	187	27	382	987	-	987
Extensions and discoveries	920	1,236	-	112	2,268	-	2,268
Purchase of reserves-in-place	5	-	-	-	5	-	5
Sales of reserves-in-place	(295)	(3)	-	(2)	(300)	-	(300)
Production	(1,264)	(72)	(40)	(196)	(1,571)	-	(1,571)
At 31 December 2013	14,761	1,923	328	1,404	18,416	-	18,416
Revisions and improved recovery	439	32	8	197	676	-	676
Extensions and discoveries	79	-	-	364	443	-	443
Purchase of reserves-in-place	-	-	-	-	-	-	-
Sales of reserves-in-place	(355)	(681)	-	(15)	(1,051)	-	(1,051)
Production	(1,229)	(56)	(38)	(242)	(1,565)	-	(1,565)
At 31 December 2014	13,694	1,218	299	1,708	16,919	-	16,919

The effect of the farm out of Shah Deniz and the reduced working interest in the non-operated Southern Marcellus is not included in the table above, but will be included in 2015 after the closing date of the transaction.

		Consolidated companies				Equity accounted	Total
		Eurasia excluding
	Norway	Norway	Africa	Americas	Subtotal	Americas	Total
Net proved reserves in million barrels oil equivalent
At 31 December 2011	4,165	222	390	555	5,331	95	5,426
Revisions and improved recovery	297	17	33	14	361	(8)	353
Extensions and discoveries	150	85	-	144	378	-	378
Purchase of reserves-in-place	-	-	-	4	4	-	4
Sales of reserves-in-place	(71)	-	-	(4)	(74)	-	(74)
Production	(495)	(28)	(63)	(74)	(660)	(5)	(665)
At 31 December 2012	4,046	296	360	639	5,340	82	5,422
	-	-	-	-		-
Revisions and improved recovery	227	49	44	90	411	(16)	395
Extensions and discoveries	183	268	8	64	523	-	523
Purchase of reserves-in-place	14	-	-	-	14	-	14
Sales of reserves-in-place	(113)	(15)	-	(2)	(131)	-	(131)
Production	(441)	(28)	(66)	(85)	(621)	(4)	(625)
At 31 December 2013	3,916	569	346	705	5,537	63	5,600
Revisions and improved recovery	219	16	87	36	359	(3)	356
Extensions and discoveries	20	-	5	227	253	-	253
Purchase of reserves-in-place	-	-	-	20	20	-	20
Sales of reserves-in-place	(78)	(148)	(2)	(5)	(233)	-	(233)
Production	(434)	(24)	(72)	(102)	(631)	(4)	(635)
At 31 December 2014	3,644	413	364	882	5,304	55	5,359

Proved reserves of bitumen in Americas, representing less than 2% of Statoil's proved reserves, is included as oil in the table above. The effect of the farm out of Shah Deniz and the reduced working interest in the non-operated Southern Marcellus is not included in the table above, but will be included in 2015 after the closing date of the transaction.

		Consolidated companies			Equity accounted		Total
	Norway	Eurasia excluding Norway	Africa	Americas	Subtotal	Americas	Total
Net proved oil and condensate reserves in million barrels oil equivalent
At 31 December 2011
Developed	637	102	208	101	1,048	37	1,085
Undeveloped	359	11	84	272	727	58	785
At 31 December 2012
Developed	547	79	221	164	1,010	38	1,049
Undeveloped	421	114	61	231	827	44	870
At 31 December 2013
Developed	548	63	197	212	1,020	32	1,052
Undeveloped	370	164	74	187	795	30	826
At 31 December 2014
Developed	559	63	243	267	1,133	24	1,156
Undeveloped	327	133	52	242	754	32	786
Net proved NGL reserves in million barrels oil equivalent At 31 December 2011
Developed	282	-	11	3	296	-	296
Undeveloped	91	-	9	10	110	-	110
At 31 December 2012
Developed	296	-	11	27	334	-	334
Undeveloped	109	-	7	20	135	-	135
At 31 December 2013
Developed	287	-	10	34	330	-	330
Undeveloped	82	-	7	22	111	-	111
At 31 December 2014
Developed	258	-	9	42	310	-	310
Undeveloped	60	-	6	27	93	-	93
Net proved gas reserves in billion standard cubic feet At 31 December 2011
Developed	12,661	371	293	404	13,730	-	13,730
Undeveloped At 31 December 2012	3,027	237	138	548	3,951	-	3,951
Developed	12,073	343	226	567	13,210	-	13,210
Undeveloped	2,931	232	115	540	3,817	-	3,817
At 31 December 2013
Developed	11,580	467	209	817	13,073	-	13,073
Undeveloped	3,181	1,455	120	586	5,343	-	5,343
At 31 December 2014
Developed	11,227	312	191	946	12,677	-	12,677
Undeveloped	2,467	906	108	762	4,242	-	4,242
Net proved oil, condensate, NGL and gas reserves in million barrels oil equivalent At 31 December 2011
Developed	3,175	168	272	175	3,790	37	3,827
Undeveloped	990	54	118	380	1,541	58	1,599
At 31 December 2012
Developed	2,994	140	272	292	3,698	38	3,737
Undeveloped	1,052	155	88	347	1,642	44	1,686
At 31 December 2013
Developed	2,898	146	244	392	3,679	32	3,711
Undeveloped	1,018	423	103	314	1,858	30	1,888
At 31 December 2014
Developed	2,818	119	287	477	3,701	24	3,725
Undeveloped	826	295	78	405	1,603	32	1,635

The conversion rates used are 1 standard cubic meter = 35.3 standard cubic feet, 1 standard cubic meter oil equivalent = 6.29 barrels of oil equivalent (boe) and 1,000 standard cubic meter gas = 1 standard cubic meter oil equivalent.

Capitalised cost related to Oil and Gas production activities

Consolidated companies

			At 31 December
(in NOK billion)	2014	2013	2012
Unproved properties	97.5	83.8	76.0
Proved properties, wells, plants and other equipment	1,178.8	984.1	896.8
Total capitalised cost	1,276.3	1,068.0	972.8
Accumulated depreciation, impairment and amortisation	(687.2)	(543.7)	(498.2)
Net capitalised cost	589.1	524.3	474.5

Net capitalised cost related to equity accounted investments as of 31 December 2014 was NOK 7.2 billion, NOK 5.9 billion in 2013 and NOK 4.9 billion in 2012. The reported figures are based on capitalised costs within the upstream segments in Statoil, in line with the description below for result of operations for oil and gas producing activities.

Expenditures incurred in Oil and Gas Property Acquisition, Exploration and Development Activities

These expenditures include both amounts capitalised and expensed.

Consolidated companies

		Eurasia excluding
(in NOK billion)	Norway	Norway	Africa	Americas	Total
Full year 2014
Exploration expenditures	7.0	2.5	7.3	7.1	23.9
Development costs	52.2	13.4	13.3	22.7	101.7
Acquired proved properties	0.0	0.0	0.0	4.7	4.7
Acquired unproved properties	0.0	0.0	(0.0)	2.3	2.3
Total	59.3	15.9	20.6	36.8	132.6
Full year 2013
Exploration expenditures	7.9	3.8	2.7	7.4	21.8
Development costs	51.8	8.5	11.6	26.4	98.3
Acquired proved properties	2.2	0.0	0.0	0.0	2.2
Acquired unproved properties	0.0	0.4	0.0	1.8	2.2
Total	61.9	12.7	14.3	35.6	124.5
Full year 2012
Exploration expenditures	5.2	4.1	3.8	7.8	20.9
Development costs	45.7	3.2	12.2	28.7	89.8
Acquired proved properties	0.0	0.0	0.0	0.3	0.3
Acquired unproved properties	0.0	0.4	0.0	6.0	6.4
Total	50.9	7.7	16.0	42.8	117.4

Expenditures incurred in Oil and Gas Development Activities related to equity accounted investments was NOK 1.6 billion in 2014 and NOK 0.4 billion in 2013 and 2012.

Results of Operation for Oil and Gas Producing Activities

As required by Topic 932, the revenues and expenses included in the following table reflect only those relating to the oil and gas producing operations of Statoil.

The result of operations for oil and gas producing activities contains the two upstream reporting segments Development and Production Norway (DPN) and Development and Production International (DPI) as presented in note 3 Segments. The figures in the "other" lines relate to gains and losses from

commodity based derivatives, transportation and processing costs within the upstream segments, upstream business administration and business development as well as gains and losses from sales of oil and gas interests.

Income tax expense is calculated on the basis of statutory tax rates adjusted for uplift and tax credits. No deductions are made for interest or other elements not included in the table below.

Consolidated companies

		Eurasia excluding
(in NOK billion)	Norway	Norway	Africa	Americas	Total
Full year 2014
Sales	1.8	4.3	5.0	3.9	15.0
Transfers	172.6	6.1	32.6	28.6	239.9
Other revenues	7.7	5.7	0.7	(1.0)	13.1
Total revenues	182.1	16.1	38.3	31.4	268.1
Exploration expenses	(5.4)	(2.6)	(9.2)	(13.2)	(30.3)
Production costs	(22.3)	(1.3)	(4.0)	(5.6)	(33.1)
Depreciation, amortisation and net impairment losses	(40.0)	(4.9)	(14.1)	(37.9)	(96.8)
Other expenses	(2.9)	(1.5)	(0.3)	(10.3)	(14.9)
Total costs	(70.5)	(10.1)	(27.5)	(67.0)	(175.2)
Results of operations before tax	111.6	6.0	10.9	(35.6)	92.9
Tax expense	(74.8)	(0.5)	(8.4)	(0.4)	(84.0)
Results of operations	36.8	5.5	2.5	(36.0)	8.8
Net income from equity accounted investments	(0.0)	1.0	0.0	(1.7)	(0.7)
Consolidated companies
		Eurasia
(in NOK billion)	Norway	excluding Norway	Africa	Americas	Total
Full year 2013
Sales	0.3	4.0	3.9	4.1	12.3
Transfers	192.5	7.4	30.9	27.1	257.9
Other revenues	9.3	3.9	0.2	0.4	13.8
Total revenues	202.1	15.3	35.0	31.6	284.0
Exploration expenses	(5.5)	(3.4)	(1.6)	(7.5)	(18.0)
Production costs	(22.3)	(1.5)	(3.9)	(4.3)	(32.0)
Depreciation, amortisation and net impairment losses	(32.2)	(2.4)	(13.3)	(16.2)	(64.1)
Other expenses	(5.1)	(1.6)	(0.5)	(9.3)	(16.5)
Total costs	(65.1)	(8.9)	(19.3)	(37.3)	(130.6)
Results of operations before tax	137.0	6.4	15.7	(5.7)	153.4
Tax expense	(90.9)	(2.0)	(8.1)	(1.0)	(102.0)
Results of operations	46.1	4.4	7.6	(6.7)	51.4
Net income from equity accounted investments	0.1	0.3	0.0	(0.3)	0.1

Consolidated companies

		Eurasia
(in NOK billion)	Norway	excluding Norway	Africa	Americas	Total
Full year 2012
Sales	0.2	6.1	10.3	5.2	21.8
Transfers	212.6	6.8	27.3	20.5	267.2
Other revenues	7.9	1.3	0.2	1.0	10.4
Total revenues	220.7	14.2	37.8	26.7	299.4
Exploration expenses	(3.5)	(3.6)	(3.4)	(7.6)	(18.1)
Production costs	(22.2)	(1.1)	(3.5)	(3.9)	(30.7)
Depreciation, amortisation and net impairment losses	(29.8)	(3.0)	(10.7)	(12.5)	(56.0)
Other expenses	(3.6)	(1.9)	(0.5)	(6.8)	(12.8)
Total costs	(59.1)	(9.6)	(18.1)	(30.8)	(117.6)
Results of operations before tax	161.6	4.6	19.7	(4.1)	181.8
Tax expense	(115.7)	(2.0)	(10.8)	3.1	(125.4)
Results of operations	45.9	2.6	8.9	(1.0)	56.4
Net income from equity accounted investments	0.1	0.5	0.0	0.8	1.4

Standardised measure of discounted future net cash flows relating to proved oil and gas reserves

The table below shows the standardised measure of future net cash flows relating to proved reserves. The analysis is computed in accordance with Topic 932, by applying average market prices as defined by the SEC, year end costs, year end statutory tax rates and a discount factor of 10% to year end quantities of net proved reserves. The standardised measure of discounted future net cash flows is a forward-looking statement.

Future price changes are limited to those provided by existing contractual arrangements at the end of each reporting year. Future development and production costs are those estimated future expenditures necessary to develop and produce year-end estimated proved reserves based on year-end cost indices, assuming continuation of year-end economic conditions. Pre-tax future net cash flow is net of decommissioning and removal costs. Estimated future income taxes are calculated by applying the appropriate year-end statutory tax rates. These rates reflect allowable deductions and tax credits and are applied to estimated future pretax net cash flows, less the tax basis of related assets. Discounted future net cash flows are calculated using a discount rate of 10% per year. Discounting requires a year-by-year estimate of when future expenditures will be incurred and when reserves will be produced. The standardised measure of discounted future net cash flows prescribed under Topic 932 requires assumptions as to the timing and amount of future development and production costs and income from the production of proved reserves. The information does not represent management's estimate or Statoil's expected future cash flows or the value of its proved reserves and therefore should not be relied upon as an indication of Statoil's future cash flow or value of its proved reserves.

(in NOK billion)	Norway	Eurasia excluding Norway	Africa	Americas	Total
At 31 December 2014
Consolidated companies
Future net cash inflows	1,467.9	203.4	213.6	323.0	2,207.9
Future development costs	(166.8)	(59.9)	(12.3)	(51.7)	(290.8)
Future production costs	(439.8)	(91.6)	(58.3)	(142.7)	(732.4)
Future income tax expenses	(606.8)	(8.1)	(48.6)	(34.0)	(697.5)
Future net cash flows	254.5	43.8	94.4	94.6	487.3
10 % annual discount for estimated timing of cash flows	(99.7)	(27.8)	(28.1)	(41.9)	(197.6)
Standardised measure of discounted future net cash flows	154.7	16.0	66.3	52.7	289.8
Equity accounted investments
Standardised measure of discounted future net cash flows	-	-	-	5.1	5.1
Total standardised measure of discounted future net cash flows including equity accounted investments	154.7	16.0	66.3	57.8	294.8
		Eurasia excluding
(in NOK billion)	Norway	Norway	Africa	Americas	Total
At 31 December 2013
Consolidated companies
Future net cash inflows	1,700.2	273.7	205.2	257.5	2,436.6
Future development costs	(200.0)	(80.8)	(16.0)	(38.9)	(335.7)
Future production costs	(471.3)	(125.4)	(54.8)	(104.3)	(755.8)
Future income tax expenses	(740.9)	(12.2)	(50.0)	(24.0)	(827.1)
Future net cash flows	288.0	55.3	84.4	90.3	518.0
10 % annual discount for estimated timing of cash flows	(120.8)	(39.7)	(27.6)	(41.3)	(229.4)
Standardised measure of discounted future net cash flows	167.2	15.6	56.8	49.0	288.6
Equity accounted investments
Standardised measure of discounted future net cash flows	-	-	-	4.8	4.8
Total standardised measure of discounted future net cash flows including equity accounted investments	167.2	15.6	56.8	53.8	293.4
(in NOK billion)	Norway	Eurasia excluding Norway	Africa	Americas	Total
At 31 December 2012
Consolidated companies
Future net cash inflows	1,812.8	138.6	203.4	228.5	2,383.3
Future development costs	(196.1)	(39.6)	(16.2)	(41.2)	(293.1)
Future production costs	(499.1)	(39.8)	(55.4)	(90.9)	(685.2)
Future income tax expenses	(862.7)	(15.0)	(48.9)	(25.1)	(951.7)
Future net cash flows	254.9	44.2	82.9	71.3	453.3
10 % annual discount for estimated timing of cash flows	(113.2)	(25.0)	(27.6)	(34.7)	(200.5)
Standardised measure of discounted future net cash flows	141.7	19.2	55.3	36.6	252.8
Equity accounted investments
Standardised measure of discounted future net cash flows	-	-	-	1.0	1.0
Total standardised measure of discounted future net cash flows including equity accounted investments	141.7	19.2	55.3	37.6	253.8

Changes in the standardised measure of discounted future net cash flows from proved reserves

(in NOK billion)	2014	2013	2012
Consolidated companies
Standardised measure at beginning of year	288.6	252.8	302.1
Net change in sales and transfer prices and in production (lifting) costs related to future production	(98.3)	(24.0)	9.6
Changes in estimated future development costs	(32.3)	(54.9)	(63.7)
Sales and transfers of oil and gas produced during the period, net of production cost	(232.6)	(243.2)	(275.1)
Net change due to extensions, discoveries, and improved recovery	23.1	10.6	11.1
Net change due to purchases and sales of minerals in place	(25.1)	(33.9)	(13.4)
Net change due to revisions in quantity estimates	126.1	126.5	114.3
Previously estimated development costs incurred during the period	99.6	95.1	88.7
Accretion of discount	77.3	81.4	84.4
Net change in income taxes	63.3	78.2	(5.2)
Total change in the standardised measure during the year	1.2	35.8	(49.3)
Standardised measure at end of year	289.8	288.6	252.8
Equity accounted investments
Standardised measure at end of year	5.1	4.8	1.0
Standardised measure at end of year including equity accounted investments	294.8	293.4	253.8

In the table above, each line item presents the sources of changes in the standardised measure value on a discounted basis, with the Accretion of discount line item reflecting the increase in the net discounted value of the proved oil and gas reserves due to the fact that the future cash flows are now one year closer in time.

27 Subsequent events

On 10 February 2015 Statoil issued bonds of EUR 3.75 billion, equivalent to NOK 32.1 billion at the transaction date. The bonds have maturities of 4-20 years. All of the bonds are unconditionally guaranteed by Statoil Petroleum AS.

On 5 February 2015 the board of directors proposed to declare a dividend for the fourth quarter of 2014 of NOK 1.80 per share.

Parent company financial statements

STATEMENT OF INCOME STATOIL ASA - NGAAP

(in NOK billion)	Note	2014	Full year 2013
Revenues	4	410.5	416.6
Net income from subsidiaries and other equity accounted companies	12	24.2	49.6
Total revenues and other income		434.7	466.2
Purchases [net of inventory variation]		(401.1)	(403.8)
Operating expenses		(11.2)	(9.5)
Selling, general and administrative expenses		(2.6)	(3.0)
Depreciation, amortisation and net impairment losses	11	(0.8)	(1.0)
Exploration expenses		(2.0)	(1.0)
Net operating income		16.9	47.9
Net financial items	9	(19.4)	(14.7)
Income before tax		(2.5)	33.2
Income tax	10	8.6	6.2
Net income		6.1	39.4

BALANCE SHEET STATOIL ASA - NGAAP

			At 31 December
(in NOK billion)	Note	2014	2013
ASSETS
Property, plant and equipment	11	5.7	5.3
Intangible assets		0.2	0.2
Investments in subsidiaries and other equity accounted companies	12	474.6	389.9
Deferred tax assets	10	16.7	7.1
Pension assets	19	7.9	5.2
Derivative financial instruments		0.2	(0.0)
Prepayments and financial receivables		0.5	4.9
Receivables from subsidiaries and other equity accounted companies	13	68.6	69.4
Total non-current assets		574.4	481.9
Inventories	14	15.3	16.7
Trade and other receivables	15	43.6	48.5
Receivables from subsidiaries and other equity accounted companies	13	21.0	19.0
Derivative financial instruments	3	1.3	0.1
Financial investments	13	53.2	33.9
Cash and cash equivalents	16	71.5	77.0
Total current assets		206.0	195.2
Total assets		780.4	677.1

BALANCE SHEET STATOIL ASA - NGAAP

			At 31 December
(in NOK billion)	Note	2014	2013
EQUITY AND LIABILITIES
Share capital		8.0	8.0
Additional paid-in capital		17.3	17.3
Reserves for valuation variances		109.0	104.3
Retained earnings		223.9	191.8
Total equity	17	358.2	321.3
Finance debt	18	201.3	162.6
Liabilities to subsidiaries		0.1	0.1
Pension liabilities	19	27.7	22.2
Provisions	20	2.1	2.0
Derivative financial instruments	3	5.2	0.6
Total non-current liabilities		236.4	187.5
Trade and other payables	21	29.1	37.9
Current tax payable		0.6	0.1
Finance debt	18	24.7	16.8
Dividends payable	17	11.4	22.3
Liabilities to subsidiaries	13	114.7	90.7
Derivative financial instruments	3	5.4	0.6
Total current liabilities		185.9	168.3
Total liabilities		422.3	355.8
Total equity and liabilities		780.4	677.1

STATEMENT OF CASH FLOWS STATOIL ASA - NGAAP

(in NOK billion)	2014	Full year 2013
Income before tax	(2.5)	33.2
Depreciation, amortisation and net impairment losses	0.8	1.0
(Gains) losses on foreign currency transactions and balances	15.8	16.9
(Gains) losses from dispositions	(0.0)	0.0
(Increase) decrease in other items related to operating activities	2.6	14.7
(Increase) decrease in net derivative financial instruments	3.9	(0.4)
Interest received	1.2	4.3
Interest paid	(4.5)	(3.3)
Taxes paid	(0.1)	(0.0)
(Increase) decrease in working capital	1.4	(3.5)
Cash flows provided by operating activities	18.5	62.9
Capital expenditures and investments	(11.7)	(63.2)
(Increase) decrease in financial investments	(11.0)	(23.3)
(Increase) decrease in other non-current items	5.9	(0.4)
Proceeds from sale of assets and businesses	(0.0)	41.4
Cash flows used in investing activities	(16.9)	(45.5)
New finance debt	20.5	62.6
Repayment of finance debt	(9.5)	(5.5)
Dividend paid	(33.7)	(21.5)
Net current finance debt and other	(0.8)	(7.0)
Increase (decrease) in financial receivables and payables to/from subsidiaries	12.6	(29.2)
Cash flows provided by (used in) financing activities	(10.9)	(0.6)
Net increase (decrease) in cash and cash equivalents	(9.2)	16.8
Effect of exchange rate changes on cash and cash equivalents	3.8	2.7
Cash and cash equivalents at the beginning of the period	77.0	57.4
Cash and cash equivalents at the end of the period	71.5	77.0

Notes to the Financial statements Statoil ASA

1 Organisation and basis of presentation

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

Statoil ASA is listed on the Oslo Stock Exchange (Norway) and the New York Stock Exchange (USA).

Statoil ASA's business consists principally of the exploration, production, transportation, refining and marketing of petroleum and petroleum-derived products and other forms of energy. The activities are mainly carried out through ownership of, participation in or cooperation with other companies. All the Statoil group's net assets on the Norwegian continental shelf are owned by Statoil ASA's 100% owned operating subsidiary, Statoil Petroleum AS.

The functional currency of Statoil ASA is United States Dollar (USD), based on an evaluation of the company's primary economic environment and related cash flows, while its presentation currency is Norwegian Krone (NOK). The USD to NOK rates of exchange employed at year-end 2014 and 2013 are 7.43 and 6.08, respectively.

2 Significant accounting policies

Statement of compliance

The financial statements of Statoil ASA ("the company") are prepared in accordance with the Norwegian Accounting Act of 1998 and good accounting practice (NGAAP).

Basis of preparation

The financial statements are prepared on the historical cost basis with some exceptions, as detailed in the accounting policies set out below. These policies have been applied consistently to all periods presented in these financial statements. Certain amounts in the comparable years have been restated to conform to current year presentation. The subtotals and totals in some of the tables may not equal the sum of the amounts shown due to rounding.

The statement of cash flows has been prepared in accordance with the indirect method.

Changes in accounting policies in the current period

With effect from 2014, the company changed its policy for the recognition of income tax positions for which payment has been made despite the company disputing the tax claim involved. While previously only amounts virtually certain of being refunded to the company were reflected as assets for positions involving such disputed income tax amounts, as of 2014 the company reflects as assets any disputed amounts that probably will be refunded. The corresponding impact will be within the line items Net income from subsidiaries and other equity accounted companies and Income tax in the statement of income. Disputed income tax positions will now be reflected in the balance sheet if a refund from the relevant tax authority is probable. This ensures that the accounts better and more consistently reflect the underlying facts and evaluations in each case, and consequently provide more relevant information, independently of whether an income tax dispute occurs in a tax regime (such as for instance Norway) that requires up-front payment in disputed matters, or in a tax regime where disputed payments are not due until a dispute has been legally settled in Statoil's disfavour.

The change in accounting policy is not material to the statement of income, the balance sheet and the statement of cash flows for the periods covered by these financial statements, and comparative figures have not been adjusted.

Subsidiaries, associated companies and jointly controlled entities

Shareholdings and interests in subsidiaries, associated companies (companies in which the company does not have control, or joint control, but has the ability to exercise significant influence over operating and financial policies; generally when the ownership share is between 20% and 50%) and jointly controlled entities are accounted for using the equity method. The company applies the equity method on the basis of the respective entities' financial reporting prepared in compliance with the Statoil group's NGAAP accounting principles. Goodwill included in the balance sheets of subsidiaries and associated companies is depreciated over ten years on a straight-line basis, and the related depreciation expense is included in the company's statement of income under Net income from subsidiaries and other equity accounted companies.

Expenses related to the Statoil group as operator of jointly controlled assets

Indirect operating expenses incurred by the company, such as personnel expenses, are accumulated in cost pools. Such expenses are allocated in part on an hours incurred cost basis to Statoil Petroleum AS, to other group companies, and to licences where Statoil Petroleum AS or other group companies are operators. Costs allocated in this manner reduce the expenses in the company's statement of income.

Asset transfers between the company and its subsidiaries

Transfers of assets and liabilities between the company and the entities that it directly or indirectly controls are accounted for at the carrying amounts of the assets and liabilities transferred.

Foreign currency translation

The company's transactions in foreign currencies are translated to United States Dollar (USD) at the foreign exchange rate at the dates of the transactions. Monetary assets and liabilities denominated in foreign currencies are translated to USD at the foreign exchange rate at the balance sheet date. Foreign exchange differences arising on translation are recognised in the statement of income. Non-monetary assets are translated using the exchange rate at the dates of the transactions.

Presentation currency

For the purpose of the financial statements, the statement of income and the balance sheet are translated from functional currency, USD, into the presentation currency, Norwegian Krone (NOK). The assets and liabilities of the company are translated into NOK at the foreign exchange rate at the balance sheet date. The income and expenses of the company are translated using the foreign exchange rates on the dates of the transactions.

Revenue recognition

Revenues associated with sale and transportation of crude oil, petroleum and chemical products, and other merchandise are recorded when title and risk pass to the customer, which normally is at the point of delivery of the goods, based on the contractual terms of the agreements. Sales and purchases of physical commodities, which are not settled net, are presented on a gross basis as Revenues and Purchases [net of inventory variation] in the statement of income. Activities related to the trading of commodity based derivative instruments are reported on a net basis, with the margin included in Revenues.

Transactions with the Norwegian State and with Statoil Petroleum AS

The company markets and sells the Norwegian State's and Statoil Petroleum AS's share of oil and gas production from the Norwegian continental shelf. The Norwegian State's participation in petroleum activities is organised through the State's direct financial interest (SDFI). All purchases and sales of SDFI's and Statoil Petroleum AS's oil production are classified as Purchases [net of inventory variation] and Revenues, respectively. The company sells, in its own name, but for the Norwegian State's and Statoil Petroleum AS's account and risk, the Norwegian state's and Statoil Petroleum AS's production of natural gas. This sale and related expenditures refunded by the Norwegian State and by Statoil Petroleum AS are recorded net in the company's financial statements.

Employee benefits

Wages, salaries, bonuses, social security contributions, paid annual leave and sick leave are accrued in the period in which the associated services are rendered by employees of the company. The accounting policy for pensions and share-based payments is described below.

Share-based payments

The company operates an employee bonus share program. The cost of equity-settled transactions (bonus share awards) with employees is measured by reference to the estimated fair value at the date at which they are granted and is recognised as an expense over the average vesting period of 2.5 years. The awarded shares are accounted for as salary expense and recognised as an equity transaction (included in retained earnings).

Research and development

Research and development costs which are expected to generate probable future economic benefits are considered for capitalisation as intangible assets under the applicable NGAAP requirements. All other research and development expenditure is expensed as incurred. Subsequent to initial recognition, any capitalised development costs are reported at cost less accumulated amortisation and accumulated impairment losses.

Income tax

Income tax in the statement of income for the year comprises current and deferred tax expense. Income tax is recognised in the statement of income except when it relates to items recognised directly in equity, in which case it is recognised in equity.

Current tax consists of the expected tax payable on the taxable income for the year and any adjustment to tax payable for previous years. Uncertain tax positions and potential tax exposures are analysed individually and the best estimate of the probable amount for liabilities to be paid (unpaid potential tax exposure amounts, including penalties) and assets to be received (disputed tax positions for which payment has already been made) in each case is recognised within current tax or deferred tax as appropriate. Interest income and interest expenses relating to tax issues are estimated and recognised in the period in which they are earned or incurred, and are presented within Net financial items in the statement of income.

Deferred tax assets and liabilities are recognised for the future tax consequences attributable to differences between the carrying amounts of existing assets and liabilities and their respective tax bases, subject to the initial recognition exemption. The amount of deferred tax is based on the expected manner of realisation or settlement of the carrying amount of assets and liabilities, using tax rates enacted or substantially enacted at the balance sheet date.

A deferred tax asset is recognised only to the extent that it is probable that future taxable profits will be available against which the asset can be utilised. In order for a deferred tax asset to be recognised based on future taxable income, convincing evidence is required, taking into account the existence of contracts, observable prices in active markets, expected volatility of trading profits and similar facts and circumstances.

Property, plant and equipment

Property, plant and equipment is reflected at cost, less accumulated depreciation and accumulated impairment losses. The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into operation, the initial estimate of a decommissioning obligation, if any, and, for qualifying assets, borrowing costs.

Expenditure on major maintenance refits or repairs comprises the cost of replacement assets or parts of assets, inspection costs and overhaul costs. Where an asset or part of an asset is replaced and it is probable that future economic benefits associated with the item will flow to the company, the expenditure is capitalised. Inspection and overhaul costs, associated with regularly scheduled major maintenance programs planned and carried out at recurring intervals exceeding one year, are capitalised and amortised over the period to the next scheduled inspection and overhaul. All other maintenance costs are expensed as incurred.

Depreciation is calculated on the basis of the assets' estimated useful lives, normally using the straight-line method. Each part of an item of Property, plant and equipment with a cost that is significant in relation to the total cost of the item is depreciated separately.

The estimated useful lives of Property, plant and equipment are reviewed on an annual basis and changes in useful lives are accounted for prospectively. An item of Property, plant and equipment is derecognised upon disposal or when no future economic benefits are expected to arise from the continued use of the asset. Any gain or loss arising on derecognition of the asset (calculated as the difference between the net disposal proceeds and the carrying amount of the item) is included in Other income or Operating expenses, respectively, in the period the item is derecognised.

Leases

Leases for which the company assumes substantially all the risks and rewards of the ownership are reflected as finance leases within Property, plant and equipment and Finance debt. Capitalised leases are depreciated over the shorter of the estimated useful life of the asset or the lease term, using the depreciation methods described above, depending on the nature of the leased asset. All other leases are classified as operating leases and the costs are charged to the relevant operating expense related caption on a straight-line basis over the lease term, unless another basis is more representative of the benefits of the lease to the company.

The company distinguishes between lease and capacity contracts. Lease contracts provide the right to use a specific asset for a period of time, while capacity contracts confer on the company the right to and the obligation to pay for certain volume capacity availability related to transport, storage and so on. Such capacity contracts that do not involve specified assets or that do not involve substantially all the capacity of an undivided interest in a specific asset are not considered by the company to qualify as leases for accounting purposes. Capacity payments are reflected as Operating expenses in the statement of income in the period for which the capacity contractually is available to the company.

Financial assets

Financial assets representing loans and receivables are carried at amortised cost using the effective interest method. Trading securities classified as current Financial investments are recognised at fair value with gains and losses reflected in the statement of income.

Trade receivables are carried at the original invoice amount less a provision for doubtful receivables which is made when there is objective evidence that the company will be unable to recover the balances in full.

Financial assets are presented as current if they contractually will expire or otherwise are expected to be recovered within 12 months after the balance sheet date, or if they are held for the purpose of being traded.

Inventories

Inventories are stated at the lower of cost and net realisable value. Cost is determined by the first-in first-out method and comprises direct purchase costs, transportation and manufacturing expenses.

Derivative financial instruments

The following accounting policies are applied for the principal financial instruments and commodity-based derivatives:

• Currency swap agreements are recognised at fair value in the balance sheet and changes in fair value are recognised in the statement of income.
• Interest rate swap agreements are valued according to the lower of cost or market principle.
• Commodity-based derivatives traded on organised exchanges are valued at fair market value and the resulting gains and losses are recognised in the statement of income. Other commodity-based derivatives are valued according to the lower of cost or market principle.

Cash and cash equivalents

Cash and cash equivalents include cash in hand, current balances with banks and similar institutions, and short-term highly liquid investments that are readily convertible to known amounts of cash, are subject to an insignificant risk of changes in fair value, and have a maturity of three months or less from the acquisition date.

Impairment of property, plant and equipment

The company assesses assets or groups of assets for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. Individual assets are grouped based on lowest levels with separately identifiable and largely independent cash inflows.

In assessing whether a write-down of the carrying amount of a potentially impaired asset is required, the asset's carrying amount is compared to the recoverable amount. Frequently the recoverable amount of an asset proves to be the company's estimated value in use, which is determined using a discounted cash flow model. In performing a value-in-use based impairment test, the estimated future cash flows are adjusted for risks specific to the asset and discounted using a real post-tax discount rate which is based on the company's post-tax weighted average cost of capital (WACC).

If assets are determined to be impaired, the carrying amounts of those assets are written down to the recoverable amount which is the higher of fair value less costs to sell and value in use. Impairments are reversed as applicable to the extent that conditions for impairment are no longer present.

Financial liabilities

Interest-bearing loans and borrowings are initially recognised at cost and subsequently measured at amortised cost using the effective interest method. Amortised cost is calculated by taking into account any issue costs as well as discount or premium on settlement. Gains and losses arising on the repurchase, settlement or cancellation of liabilities are recognised either in interest income and other financial items or in interest and other finance expenses within Net financial items. Financial liabilities are presented as current if the liabilities are due to be settled within 12 months after the balance sheet date, or if they are held for the purpose of being traded.

Dividends payable

Dividends for the year are reflected as Dividends payable within current liabilities. The dividends payable require general assembly approval before distribution.

Pension liabilities

Statoil ASA has pension plans that either provide employees with a defined pension benefit upon retirement or a pension dependent on defined contributions and related returns. For defined benefit plans the benefit to be received by employees generally depends on many factors including length of service, retirement date and future salary levels. The company applies IAS 19 Employee Benefits.

The company's proportionate shares of multi-employer defined benefit plans are recognised as liabilities in the balance sheet to the extent that sufficient information is available and a reliable estimate of the obligation can be made.

The company's net obligation in respect of defined benefit pension plans is calculated separately for each plan by estimating the amount of future benefit that employees have earned in return for their services in the current and prior periods. That benefit is discounted to determine its present value and the fair value of any plan assets is deducted. The discount rate is the yield at the balance sheet date, reflecting the maturity dates approximating the terms of the company's obligations. The discount rate for the main part of the pension obligations has been established on the basis of Norwegian mortgage covered bonds, which are considered high quality corporate bonds. The cost of pension benefit plans is expensed over the period that the employees render services and become eligible to receive benefits. The calculation is performed by an external actuary.

The net interest related to defined benefit plans is calculated by applying the discount rate to the net defined benefit liability (asset). The interest cost element is determined by applying the discount rate to the opening present value of the benefit obligation, taking into account material changes in the obligation during the year. The interest income on plan assets is determined by applying the discount rate to the opening present value of the plan assets, adjusted for the effect on the fair value of plan assets of contributions received and benefits paid during the year. The resulting net interest element is presented in the statement of income as part of net pension cost within Net operating income. The difference between net interest income and actual return is recognised in the company's Retained earnings.

Past service cost is recognised when plan amendment (the introduction or withdrawal of, or changes to, a defined benefit plan) or curtailment (a significant reduction by the entity in the number of employees covered by a plan) occurs, or when recognising related restructuring cost or termination benefits. The obligation and related plan assets are re-measured using current actuarial assumptions, and the gain or loss is recognised in the statement of income. Actuarial gains and losses are recognised in full in the company's Retained earnings in the period in which they occur, while actuarial gains and losses related to provision for termination benefits are recognised in the statement of income in the period in which they occur. Due to the company's functional currency being USD, the significant part of the company's pension obligations will be payable in a foreign currency (ie. NOK). As a consequence, actuarial gains and losses include the impact of exchange rate fluctuations.

Contributions to defined contribution schemes are recognised in the statement of income in the period in which the contribution amounts are earned by the employees.

Provisions

Provisions are recognised when the company has a present obligation (legal or constructive) as a result of a past event, it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. If the effect of the time value of money is material, provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and, where appropriate, the risks specific to the liability.

Onerous contracts

The company recognises as Provisions the net obligation under contracts defined as onerous. Contracts are deemed to be onerous if the unavoidable costs of meeting the obligations under the contract exceed the economic benefits expected to be received in relation to the contract. A contract which forms an integral part of the operations of a cash generating unit whose assets are dedicated to that contract, and for which the economic benefits cannot be reliably separated from those of the cash generating unit, is included in impairment considerations for the applicable cash generating unit.

Use of estimates

Preparation of the financial statements requires the company to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as disclosures of contingencies. Actual results may ultimately differ from the estimates and assumptions used.

The nature of the company's operations, and the many countries in which the company operates, is subject to changing economic, regulatory and political conditions. The company does not believe it is vulnerable to the risk of a near-term severe impact as a result of any concentration of its activities.

3 Financial risk management and derivatives

Financial risks

Statoil ASA's activities expose the company to the following financial risks:

• Market risk (including commodity price risk, currency risk and interest rate risk)
• Credit risk
• Liquidity risk

Market risk

Statoil ASA ("the company") operates in the worldwide crude oil, refined products, natural gas, and electricity markets and is exposed to market risks including fluctuations in hydrocarbon prices, foreign currency rates, interest rates, and electricity prices that can affect the revenues and costs of operating, investing and financing. For the marketing of Statoil's commodities Statoil ASA has established guidelines for entering into derivative contracts in order to manage the commodity price, foreign currency rate and interest rate risk. The company uses both financial and commodity-based derivatives to manage the risks in revenues, financial items and the present value of future cash flows.

Commodity price risk

Commodity price risk represents Statoil ASA's most important short-term market risk. To manage the short-term commodity risk, Statoil ASA enters into commodity-based derivative contracts, including futures, options, over-the-counter (OTC) forward contracts, market swaps and contracts for differences related to crude oil, petroleum products, natural gas and electricity.

Derivatives associated with crude oil and refined oil products are traded mainly on the InterContinental Exchange (ICE) in London, the New York Mercantile Exchange (NYMEX), the OTC Brent market, and in crude and refined products swaps markets. Derivatives associated with natural gas and electricity are mainly OTC physical forwards and options, NASDAQ OMX Oslo forwards, and futures traded on the NYMEX and ICE.

The term of oil and refined oil products derivatives is usually less than one year and the term for natural gas and electricity derivatives is usually three years or less.

Currency risk

Statoil ASA's operating results and cash flows are affected by foreign currency fluctuations of the most significant currencies Norwegian Krone (NOK) against United States Dollar (USD). Foreign exchange risk is managed at corporate level in accordance with policies and mandates.

Statoil ASA's cash flows from operating activities deriving from oil and gas sales, operating expenses and capital expenditures, are mainly in USD, but taxes and dividends are in NOK. Accordingly, Statoil ASA's currency management is primarily linked to mitigate currency risk related to tax and dividend payments in NOK. This means that Statoil ASA regularly purchase substantial NOK amounts on a forward basis using conventional derivative instruments.

At the end of 2014 the following currency risk sensitivity has been calculated by assuming a 9% change in the foreign currency exchange rate between NOK and USD. At the end of 2013 an assumption of 9% was used in the calculation. An increase in the foreign exchange rate by 9% means that the transaction currency has strengthened in value.

(in NOK billion)	Gains	Losses
At 31 December 2014
Norwegian kroner (9% sensitivity)	7.8	(7.8)
At 31 December 2013
Norwegian kroner (9% sensitivity)	10.4	(10.4)

Interest rate risk

Bonds are normally issued at fixed rates in a variety of local currencies (among others USD, Euro and Great Britain Pound). Bonds may be converted to floating USD bonds by using interest rate and currency swaps. Statoil ASA manages its interest rates exposure on its bond debt based on risk and reward considerations from an enterprise risk management perspective. This means that the fix/floating mix on interest rate exposure may vary from time to time. For more detailed information about Statoil ASA's long-term debt portfolio see note 18 Finance debt.

For the interest rate risk sensitivity a change of 0.8% in the interest rates has been used in the calculation by the end of 2014. By end of 2013 a change of 1.0% in the interest rates was viewed as a reasonably possible change. A decline in the interest rates results in a gain while increased interest rates result in a loss. Included in the interest rate sensitivity are changes in fair value of interest rate derivative financial instruments currently recognised at fair value in the balance sheet since the fair value is lower than the cost price for the instruments at year end 2014 and 2013. When the interest rate declines the fair value of these instruments will be higher than the cost price and therefore the full change in fair value due to an interest rate decline will not be recognised in the statement of income. The estimated gains and losses are presented in the following table.

(in NOK billion)	Gains	Losses
At 31 December 2014
Interest rate risk (0.8% sensitivity)	0.1	(0.1)
At 31 December 2013
Interest rate risk (1.0% sensitivity)	0.1	(0.1)

Liquidity risk

Liquidity risk is the risk that Statoil ASA will not be able to meet obligations of financial liabilities when they become due. The purpose of liquidity management is to make certain that Statoil ASA has sufficient funds available at all times to cover its financial obligations.

Statoil ASA manages liquidity and funding at the corporate level, ensuring adequate liquidity to cover Statoil's operational requirements. Statoil ASA has a high focus and attention on credit and liquidity risk. In order to secure necessary financial flexibility, which includes meeting Statoil ASA's financial obligations, Statoil ASA maintains a conservative liquidity management policy. To identify future long-term financing needs, Statoil ASA carries out threeyear cash forecasts at least monthly. Overall the liquidity is very solid.

The main cash outflows are the quarterly dividend payments and tax payments. If the monthly cash flow forecast shows that the liquid assets one month after tax and dividend payments will fall below the defined policy level, new long-term funding will be considered.

For information about Statoil ASA's non-current financial liabilities, see note 18 Finance debt.

Mainly all of Statoil ASA's financial liabilities related to derivative financial instruments, both exchange traded and non-exchange traded commodity-based derivatives together with financial derivatives, with the exception of some interest rate derivatives classified as non-current in the balance sheet, fall due within one year, based on the underlying delivery period of the contracts included in the portfolio. The interest rate derivatives classified as non-current in the balance sheet fall due from 2017 till 2043.

Credit risk

Credit risk is the risk that Statoil ASA's customers or counterparties will cause the company financial loss by failing to honour their obligations. Credit risk arises from credit exposures with customer accounts receivables as well as from financial investments, derivative financial instruments and deposits with financial institutions.

Key elements of the credit risk management approach include:

• A global credit risk policy
• Credit mandates
• Internal credit rating process
• Credit risk mitigation tools
• A continuous monitoring and managing of credit exposures

Prior to entering into transactions with new counterparties, the credit policy requires all counterparties to be formally identified and approved. In addition, all sales, trading and financial counterparties are assigned internal credit ratings as well as exposure limits. Once established, all counterparties are re-assessed minimum annually and continuously monitored. Counterparty risk assessments are based on a quantitative and qualitative analysis of recent financial and other relevant business information. In addition, Statoil ASA evaluates any past payment performance, the counterparties' size and business diversification, and the inherent industry risk. The internal credit ratings reflect Statoil ASA's assessment of the counterparties' credit risk. Exposure limits are determined based on assigned internal credit ratings combined with other factors, such as expected transaction and industry characteristics. Credit mandates define acceptable credit risk thresholds and are endorsed by management and regularly reviewed with regard to changes in market conditions.

Statoil ASA uses risk mitigation tools to reduce or control credit risk both on a counterparty and portfolio level. The main tools include bank and parental guarantees, prepayments and cash collateral. For bank guarantees only investment grade international banks are accepted as counterparties.

Statoil ASA has pre-defined limits for the minimum average credit rating allowed at any given time on the group portfolio level as well as maximum credit exposures for individual counterparties. Statoil ASA monitors the portfolio on a regular basis and individual exposures versus limits on a daily basis. The total credit exposure portfolio of Statoil ASA is geographically diversified among a number of counterparties within the oil and energy sector, as well as larger oil and gas consumers and financial counterparties. The majority of the company's credit exposure is with investment grade counterparties.

Fair value measurement of derivative financial instruments

Statoil ASA measures Derivative financial instruments at fair value if the instruments are part of a trading portfolio and traded at an authorised exchange. This might typically be for forward contracts traded at the Nordic electricity exchange NASDAQ OMX Oslo. Other derivative financial instruments are recognised in the balance sheet at the lowest of the cost price and the fair value. Changes in the carrying value of the derivative financial instruments are recognised in the statements of income either within Revenues or within the Net financial items. Statoil ASA's portfolio of derivative financial instruments consists of commodity-based derivative contracts as well as interest rate and foreign exchange rate derivative instruments.

The following table contains the estimated fair values and the net carrying amounts of Statoil ASA's derivative financial instruments, except for the interest rate derivatives and the cross currency interest rate derivatives where the table contains the fair value adjustments and the currency revaluations presented as foreign currency instruments. Accrued interests are presented within current Finance debt.

(in NOK billion)	Fair value of assets	Fair value of liabilities	Net fair value
At 31 December 2014
Foreign currency instruments	0.9	(8.0)	(7.1)
Interest rate instruments	0.0	(1.7)	(1.7)
Crude oil and refined products	0.5	(0.8)	(0.3)
Natural gas and electricity	0.0	(0.1)	(0.1)
Total	1.5	(10.6)	(9.1)
At 31 December 2013
Foreign currency instruments	0.1	(0.5)	(0.4)
Interest rate instruments	0.0	(0.6)	(0.6)
Crude oil and refined products	0.0	0.0	0.0
Natural gas and electricity	0.1	(0.1)	(0.1)
Total	0.1	(1.2)	(1.1)

In addition to the fair value of financial derivative instruments recognised in the Balance sheet, Statoil ASA has entered into interest rate swap and cross currency swap agreements where the fair value at year end 2014 and 2013 was higher than the cost, hence the fair value adjustments related to these agreements are not recognised in the Balance sheet. At 31 December 2014 the fair value adjustments not recognised were NOK 16.1 billion. By end of 2013 the fair value adjustments not recognised were NOK 7.0 billion.

When determining the fair value of the Derivative financial instruments, Statoil ASA uses prices quoted in an active market to the extent possible. When this is not available, the company uses inputs that either directly or indirectly are observable in the market as a basis for valuation techniques such as discounted cash flow analysis or pricing models. For the financial instruments recognised in Statoil ASA's balance sheet the fair value is measured by using valuation techniques. For this measurement typically Statoil ASA uses forward prices on crude oil, natural gas, interest rates, and foreign exchange rates as inputs into the valuation techniques used to determining the fair value of its Derivative financial instruments.

4 Revenues

(in NOK billion)	2014	Full year 2013
Revenues third party	371.2	371.2
Intercompany revenues	39.3	45.3
Revenues	410.5	416.6

5 Remuneration

Statoil ASA remuneration in 2014

(in NOK billion, except average number of employees)	2014	Full year 2013
Salaries 1)	19.6	19.8
Pension costs	3.2	4.4
Social security tax	3.0	3.0
Other compensations	2.1	2.1
Total	27.8	29.3
Average number of employees 2)	20,300	20,600

1) Salaries include bonuses, severance packages and expatriate costs in addition to base pay.

2) Part time employees amount to 3% for both of the years 2014 and 2013.

Total payroll expenses are accumulated in cost-pools and partly charged to partners of Statoil operated licences on an hours incurred basis.

The reduction in pension cost in 2014 was mainly caused by a plan amendment gain recognised on the basis of Statoil's change in the pension plan, partly offset by early retirement benefits offered to a defined group of employees above the age of 58 years. For further information, see note 19 Pensions.

Compensation to the board of directors (BoD) and the corporate executive committee (CEC)

Remuneration to members of the BoD and the CEC during the year was as follows:

Board of directors remuneration in 2014

Members of the board (in NOK thousand)	Board remuneration	Audit committee	Compensation committee	HSEE committee	Total remuneration
Svein Rennemo	709	-	82	-	790
Grace Reksten Skaugen	452	-	123	-	575
Jakob Stausholm	361	200	-	-	562
Bjørn Tore Godal	361	-	82	123	566
Lill Heidi Bakkerud	361	-	-	82	443
Maria Johanna Oudeman	466	96	46	-	609
Catherine Hughes	545	96	-	21	662
James Mulva	482	33	-	61	576
Stig Lægreid	361	-	-	82	443
Øystein Løseth*	93	33	-	-	126
Ingrid Elisabeth di Valerio	361	130	-	-	491
Total	4,553	589	333	368	5,843

* Member from 1 October 2014

Management remuneration in 2014 (in NOK thousand) 1)

	Fixed remuneration
Members of corporate executive committee	Fixed pay 3)	LTI 4), 6)	Annual variable pay 7)	Taxable benefits in kind	Taxable compensation	Non-taxable benefits in kind	Estimated pension cost 8)	Estimated present value of pension obligation 4), 9), 10)
Lund Helge 4), 5), 9)	5,640	2,165	0	249	8,054	199	6,008	73,944
Reitan Torgrim 9)	3,283	761	1,066	126	5,237	0	879	16,339
Bacher Lars Christian 9)	3,256	739	1,034	363	5,393	428	685	15,879
Dodson Timothy	3,496	803	1,124	175	5,597	313	1,343	32,689
Øvrum Margareth	3,779	867	1,457	250	6,352	98	1,349	48,701
Nylund Arne Sigve 5)	2,984	725	1,421	108	5,239	0	773	26,646
Sætre Eldar - CEO 5)	1,370	0	689	35	2,094	0	989	46,769
Sætre Eldar - MPR	2,685	858	901	143	4,588	0	0	0
Anfinnsen Tor Martin 5)	817	0	239	90	1,147	0	234	22,196
Maloney William 2), 8)	4,333	2,167	2,167	960	9,627	166	713	0
Knight John 2), 3)	7,132	2,845	2,845	1,133	13,955	0	0	0

Helge Lund has received salary and benefits that amounts to NOK 1.8 million in 2014 after his resignation as chief executive officer.

1) All figures in the table for 2014 and 2013 are presented on accrual basis, in compliance with the statement presented by The Financial Supervisory Authority of Norway in December 2014. This is a change in reporting of the remuneration figures from previous years.

• 2) William Maloney and John Knight's remuneration is in local currency US Dollar and British Pound, respectively. The figures in the table are presented in NOK, using average currency rates in 2014. The change in currency rates during the year, such as strengthening of USD and GBP versus NOK, impacts the development from 2013 to 2014.
• 3) Fixed pay consist of base salary, holiday allowance and any other administrative benefits. The figures are presented on accrual basis. John Knight's fixed pay also includes a cash supplement that replaces his defined contribution pension plan in 2014.
• 4) Helge Lund resigned from his position as CEO of Statoil 15 October 2014. The pension liability listed in the table above represents the estimated present value of his pension obligation as of 31 December 2014. The increase to the Estimated present value of pension obligation is mainly due to changes in actuarial assumptions. In line with the company's LTI policy, resignation during the lock-in period is regarded as a non-fulfilment of the LTI obligations. Following his resignation Helge Lund is obliged to pay back to Statoil a total of NOK 5.1 million, calculated based on the value of the locked shares acquired under the LTI program.
• 5) Following Helge Lund's resignation, Eldar Sætre resumed role as acting CEO with immediate effect on 15 October 2014, and Tor Martin Anfinnsen replaced Eldar Sætre as acting executive vice president for MPR. Arne Sigve Nylund replaced Øystein Michelsen from January 2014.
• 6) The fixed long-term incentive (LTI) element implies an obligation to invest the net amount in Statoil shares. A lock-in period of 3 years applies for the investment. The LTI element is presented the year it is granted for the members of the corporate executive committee employed by Statoil ASA. Members of the corporate executive committee employed by non-Norwegian subsidiaries have an LTI scheme deviating from the model used in the parent company. A net amount equivalent to the annual variable pay is used for purchasing Statoil shares, and the figures are presented on accrual basis.
• 7) Annual variable pay includes holiday allowance, and is presented on accrual basis.
• 8) Estimated pension cost is calculated based on actuarial assumptions and pensionable salary (mainly base salary) at 31 December 2013 and is recognised as pension cost in the Statement of income for 2014. Payroll tax is not included. William Maloney is employed by a non-Norwegian entity and his pension cost reflects the payment under the entity's defined contribution plan made in 2014.
• 9) Torgrim Reitan and Lars Christian Bacher will be transferred to a defined contribution plan from 1 April 2015, and the Estimated present value of pension obligation per 31 December 2014 reflects this change. Estimated present value of pension obligation related to Helge Lund, Torgrim Reitan and Lars Christian Bacher, are based on the estimated value of paid-up policies and rights letters to be issued in 2015, related to Helge Lund's resignation and the termination of Torgrim Reitan and Lars Christian Bacher's defined benefit pension plan. Estimated present value of pension obligation for the rest of the members of the corporate executive committee employed by Statoil ASA, are presented with a defined benefit obligation.
• 10) The increases in Estimated present value of pension obligation for the CEC members not mentioned in foot note 9), are due to changes to the actuarial assumptions.

Management remuneration in 2013 (in NOK thousand) 1)

	Fixed remuneration
Members of corporate executive committee	Fixed pay 3)	LTI 5)	Annual variable pay 6)	Taxable benefits in kind	Taxable compensation	Non-taxable benefits in kind	Estimated 4), 7) pension cost	Estimated present value of pension obligation 4)
Lund Helge 4)	7,234	2,112	3,677	669	13,692	503	5,413	56,362
Reitan Torgrim	3,012	689	1,255	133	5,090	-	627	16,257
Sjøblom Tove Stuhr 8)	194	-	-	16	210	16	684	18,870
Bacher Lars Christian	3,188	671	1,015	366	5,240	427	711	15,425
Dodson Timothy	3,321	750	1,553	139	5,763	318	972	24,792
Øvrum Margareth	3,627	840	1,448	194	6,110	108	1,103	43,166
Michelsen Øystein	3,419	838	-	334	4,591	191	834	35,993
Sætre Eldar	3,422	838	1,195	367	5,823	-	1,003	42,360
Maloney William 2)	4,101	2,352	2,352	786	9,590	159	627	-
Knight John 2)	5,170	3,065	3,065	753	12,053	-	1,034	-

1) All figures in the table for 2014 and 2013 are presented on accrual basis, in compliance with the statement presented by The Financial Supervisory Authority of Norway in December 2014. This is a change in reporting of the remuneration figures from previous years, and the figures may differ from previous reporting.

2) William Maloney and John Knight's remuneration is based in local currency US Dollar and British Pound, respectively. The figures in the table are presented in NOK value, using average currency rates in 2013.

• 3) Fixed pay consists of base salary, holiday allowance and any other administrative benefits. The figures are presented on accrual basis and differ from previous reporting.
• 4) The Estimated pension cost and Estimated present value of pension obligation related to Helge Lund have been adjusted compared to previous year's estimates, based on an updated accounting assessment related to the profile of his existing pension plan.
• 5) The fixed long-term incentive (LTI) element implies an obligation to invest the net amount in Statoil shares. A lock-in period of 3 years applies for the investment. The LTI element is presented the year it is granted for the members of the Corporate Executive Committee employed by Statoil ASA. Members of the Corporate Executive Committee employed by non-Norwegian subsidiaries have an LTI scheme deviating from the model used in the parent company. A net amount equivalent to the annual variable pay is used for purchasing Statoil shares, and the figures are presented on accrual basis and differ from previous reporting.
• 6) The figures related to Annual variable pay for 2013 are presented on accrual basis including holiday allowance and differ from previous reporting.
• 7) Estimated Pension cost is calculated based on actuarial assumptions and pensionable salary (mainly base salary) at 31 December 2012 and is recognised as pension cost in the Statement of income for 2013. Payroll tax is not included. Members of the corporate executive committee employed by non-Norwegian subsidiaries have a defined contribution plan.
• 8) Tove Stuhr Sjøblom left Statoil's corporate executive committee 1 February 2013

Statement on remuneration and other employment terms for Statoil's Corporate Executive Committee

Pursuant to the Norwegian Public Limited Liability Companies Act, section 6-16 a, the board will present the following statement regarding remuneration of Statoil's Corporate Executive Committee to the 2015 Annual General Meeting.

1. Remuneration policy and concept for the accounting year 2015

1.1 Policy and principles

In general the company's established remuneration principles and concepts will be continued in the accounting year 2015. As described in section 1.2 the general pension scheme in the parent company has been changed. The changes will be implemented in 2015.

The remuneration concept is an integrated part of our values based performance framework. It has been designed to:

• reflect our global competitive market strategy and local market conditions
• strengthen the common interests of employees in the Statoil group and its shareholders
• be in accordance with statutory regulations and good corporate governance
• be fair, transparent and non-discriminatory
• reward and recognise delivery and behaviour equally
• differentiate on the basis of responsibilities and performance
• reward both short- and long-term contributions and results

1.2 The remuneration concept for the corporate executive committee

Statoil's remuneration concept for the corporate executive committee consists of the following main elements:

• Fixed remuneration (base salary and long-term incentive LTI)
• Variable pay
• Benefits (primarily pension, insurance and share savings plan)

Fixed remuneration consists of base salary and an LTI programme. Statoil will continue the established LTI system in the form of fixed compensation with an obligation to invest in Statoil shares for a limited number of senior executives and key professional positions. The purpose of the LTI scheme is alignment with shareholder interests and retention. Members of the corporate executive committee are included in the scheme.

The only variable pay element for parent company executives is the annual variable pay scheme which has a maximum potential of 50% of the fixed remuneration. The company's performance based variable pay concept will be continued in 2015.

The main benefit programmes applicable to senior executives are the general pension scheme, the insurance scheme and the employee share savings plan. Statoil has decided to implement a defined contribution scheme as the new general pension scheme. With the exception of employees who are 15 years or less from regular retirement age or who have the defined benefit scheme included in their individual agreements, all employees will be transferred to the new scheme. The employees exempted from transfer will retain the defined benefit scheme.

Deviations from the general principles outlined below pertaining to two members of the corporate executive committee, implemented with effect as of 1 January 2011, are described in section 3.1 below. These deviations have also been described in previous Statements on remuneration and other employment terms for Statoil's corporate executive committee.

	Main Elements - Statoil Executive Remuneration
Remuneration Element	Objective	Award level	Performance criteria
Base Salary	Attract and retain the right high-performing individuals providing competitive but not market-leading terms.	We offer base salary levels which are aligned with the individual's responsibility and performance at a level which is competitive in the markets in which we operate.	The evaluation of performance is based on the fulfilment of pre-defined goals; see "Annual Variable Pay" below. The base salary is normally subject to annual review
Long-Term Incentive (LTI)	Strengthen the align- ment of top manage- ment and shareholder interests and retention of key employees.	The LTI system is a fixed, monetary compensation calculated as a portion of the participant's base salary; ranging from 20 – 30 per cent depending on the individual's position. On behalf of the participant, the company acquires shares equivalent to the net annual amount. The grant is subject to a three year lock-in period and then released for the participant's disposal. Deviations applicable for executive vice presidents employed outside the parent company are described in section 3.1 below.	In Statoil ASA, LTI is a fixed remuneration element. Participation in the long-term incentive (LTI) scheme and the size of the annual LTI element are reflective of the level and impact of the position and not directly linked to the incumbent's performance.
Annual Variable Pay	Drive and reward individuals for annual achievement of busi ness objectives and behaviour goals.	The chief executive officer is entitled to an annual variable pay ranging from 0 – 50 % of his fixed remuneration. Target value is 25%. Correspondingly, the executive vice presidents have an annual variable pay scheme with a pay-out in the range of 0 – 40%. Target value is 20%. Deviations applicable for executive vice presidents employed outside the parent company are described in section 3.1 below. The deviations will also apply in 2015.	Achievement of annual performance goals (delivery and behaviour), in order to create long-term and sustainable shareholder value. A balanced scorecard covering goals related to our five strategic objectives (People and organisation, Health, safety and environment, Operations, Market and Finance) are measured and assessed along with individual behaviour goals. Developments to the performance management system in Statoil will be implemented for the chief executive officer and executive vice presidents in 2015. Further details in section 2.1 below.
Pension & Insurance Schemes	Provide competitive postemployment and other benefits.	The new general occupational pension plan is a defined contribution scheme with a contribution level of 7% /22% below/above 7.1 G. The defined benefit scheme will be retained by a grandfathered group of employees. The benefit scheme has a pension level amounting to 66 percent of the pensionable salary conditional on a minimum of 30 years of service. Pension from the national insurance scheme is taken into account when estimating the pension. In order to draw a full pension from Statoil's defined benefit scheme the employment with the company needs to be maintained until the pensionable age.	N/A
Employee Share Savings Plan	Align and strengthen employee and share- holder interests and remunerate for long term commitment and value creation.	Offer to purchase Statoil shares in the market limited to 5% of annual base salary.	If shares are kept for two calendar years of continued employment, the participants will be allocated bonus shares proportionate to their purchase.

[1] Target value reflects fully satisfactory goal achievement

1.3 Pension and insurance schemes

The pension schemes for members of the corporate executive committee, including the chief executive officer, constitute supplementary individual agreements to the company's general pension plans.

The chief executive officer and one of the executive vice presidents have individual pension terms according to a previous standard arrangement implemented in October 2006. Subject to specific terms those executives are entitled to a pension amounting to 66 per cent of pensionable salary and a retirement age of 62. When calculating the number of years of membership in Statoil's general pension plan, these agreements grant the right to an extra contribution time corresponding to half a year of extra membership for each year the individual has served as executive vice president.

In addition, two members of the corporate executive committee have individually agreed retirement age of 65 and an early retirement pension level amounting to 66 % of pensionable salary.

The individual pension terms for executive vice presidents outlined above are results of commitments according to previous established agreements.

Following a board decision 7 February 2012, the company's standard pension arrangements for executive vice presidents deviating from Statoil ASA's general pension plan have been discontinued and have not been applied for new appointments to the corporate executive committee.

Pension accruals for pensionable salary above 12 times the national insurance basic amount (G) are recognised as an unfunded defined benefit pension plan, i.e. not funded in a separate legal entity.

In addition to the pension benefits outlined above, the executive vice presidents in the parent company are offered disability and dependents' benefits in accordance with Statoil's general pension plan. Members of the corporate executive committee are covered by the general insurance schemes applicable within Statoil.

One of the executive vice presidents employed outside the parent company has a defined contribution scheme with 16 % in contribution in accordance with the framework established in the local employment company. The pension contribution is paid into a separate legal entity.

1.4 Severance pay arrangements

The chief executive officer and the executive vice presidents are entitled to a severance payment equivalent to six months' salary, commencing at the time of expiry of a six months' notice period, when the resignation is at the request from the company. The same amount of severance payment is also payable if the parties agree that the employment should be discontinued and the executive vice president gives notice pursuant to a written agreement with the company. Any other payment earned by the executive vice president during the period of severance payment will be fully deducted. This relates to earnings from any employment or business activity where the executive vice president has active ownership.

The entitlement to severance payment is conditional on the chief executive officer or the executive vice president not being guilty of gross misconduct, gross negligence, disloyalty or other material breach of his/her duties.

As a general rule, the chief executive officer's / executive vice president's own notice will not instigate any severance payment.

1.5 Other benefits

Statoil has a share savings plan available to all employees including members of the corporate executive committee. The share savings plan entails an offer to purchase Statoil shares in the market limited to five per cent of annual gross salary. If the shares are kept for two full calendar years of continued employment the employees will be allocated bonus shares proportionate to their purchase. Shares to be used for sale and transfer to employees are acquired by Statoil in the market, in accordance with the authorisation from the annual general meeting.

The members of the corporate executive committee have benefits in kind such as company car and electronic communication.

1.6 Terms and conditions for new President and Chief Executive Officer Eldar Sætre

Effective 4 February 2015 Statoil's board of directors appointed Eldar Sætre as new President and Chief Executive Officer of Statoil, following an acting period since October 15 2014. The chief executive officer's annual base salary compensation is NOK 5,700,000 and an additional fixed remuneration element of NOK 2,000,000. Only the base salary is included in the pensionable income. The chief executive officer will participate in an annual variable pay scheme with a target level of 25%, and participation to the Company's 2015 LTI scheme with a value of 30% (gross) of base salary. The pension terms remain unchanged according to previously established pension agreement, as described in section 1.3 above.

2. Performance management, assessment and results essential for variable pay for 2014

Individual salary and annual variable pay reviews are based on the performance evaluation in our performance management system.

Performance is evaluated in two dimensions; business delivery and behaviour. Behaviour goals are based on our core values and leadership principles and address the behaviour required and expected in order to achieve our delivery goals. Business delivery is defined through the company's performance framework "Ambition to Action", which addresses strategic objectives, KPIs and actions across the five perspectives; People and Organisation, HSE, Operations, Market and Finance. Generally, Statoil believes in setting ambitious targets to inspire and drive strong performance.

In 2014, the main objectives and KPIs for each perspective were as outlined below. Each perspective was in addition supported by comprehensive plans and actions.

Strategic objectives		2014 result assessment
People and organisation	The strategic objectives and actions address global capabilities.	Statoil's organisational efficiency programme portfolio delivered efficiency gains in 2014.
HSE	The strategic objectives and actions address safety, security and sustainability.	The positive trend for the serious incident frequency continued and is at its lowest level ever. There were no serious well incidents, whereas the number of oil and gas leakages is still too high. The Security improvement programme is being implemented according to plan. Total CO2 reduction was better than the set targets.
Operations	The strategic objectives and actions address reliable and cost efficient operations, and value driven technology development.	Production regularity improved significantly and production came in above target. Unit production cost remained in the targeted first quartile set against an industry peer group. Unit finding cost increased and ended above target.
Market	The strategic objectives and actions address stakeholder trust, value chain optimisation and an exploration driven resource strategy.	Exploration results were lower than in the record year 2013 and below the target. The company added 540 million barrels of oil equivalents from exploration and the organic reserve replacement ratio (RRR) was around 1. Downstream results ended well above targets.
Finance	The strategic objectives address shareholder return, financial robustness and cost & capital discipline.	Total Shareholder Return (TSR) ended in the fourth quartile, while RoACE was in the second quartile. Both KPI's are measured against an industry peer group. The efficiency improvement programmes launched to improve performance are on track.

Board assessment of the CEO's performance. In its assessment of the chief executive officer's performance, and consequently his merit adjustment and annual variable pay for 2014, the board has put emphasis on the improvements within HSE, a solid delivery on production efficiency and progress on the improvement programmes. However, both the relative TSR and RoAce were below target in 2014 and have affected the board's evaluation of the performance. Eldar Sætre is assessed for his performance as chief executive officer in the fourth quarter of 2014, whilst as executive vice president Marketing, Processing and Renewable energy (MPR) for the first three quarters of 2014.

Before final conclusions of the performance assessment are drawn, sound judgement and hindsight information are applied. Measured KPI results are reviewed against their strategic contribution, sustainability and significant changes in assumptions.

This balanced approach, which involves a broad set of goals defined in relation to both the delivery and behaviour dimensions and an overall performance evaluation, is viewed to significantly reduce the likelihood that remuneration policies may stimulate excessive risk-taking or have other material adverse effects.

2.1 Developments to the Performance Management model

To increase the focus on key deliveries in Statoil's performance management system, and further strengthen the link between company results and individual reward, developments to the concept will be implemented for the Corporate Executive Committee in 2015.

The Business Delivery part of the performance management model will be adjusted to give a stronger emphasis on actual end results and output oriented parameters. This adjustment will have direct impact on remuneration for the executives, as achievement on these parameters will be linked directly to their variable reward. However, the principle of weighting delivery and behaviour equally (50/50) is still maintained.

3. Execution of the remuneration policy and principles in 2014

3.1 Deviations from the Statement on Executive remuneration 2014

Two members of the executive committee had variable pay schemes deviating from the description in section 1.2 above. The individuals in question are employed by Statoil Gulf Services LLC in Houston and Statoil Global Employment Company Ltd. in London. These schemes entail a framework for variable pay of 75-100% of the base salary for each of the elements (annual variable pay and LTI) is performance based. The contracts also include a provision for severance payment of 12 months' base salary.

The board's overall assessment is that the extended framework implemented with effect from 1 January 2011 for the variable pay schemes for these executives is in alignment with the market, but not market leading for positions at this level at the respective locations.

3.2 Changes to the Corporate Executive Committee

Effective 1 January 2014 Arne Sigve Nylund assumed responsibilities as executive vice president for Development and Production Norway, succeeding Øystein Michelsen. Following Statoil president and chief executive officer Helge Lund's resignation, the board appointed Eldar Sætre as acting chief executive officer effective 15 October 2014. Tor Martin Anfinnsen was appointed acting executive vice president for MPR, succeeding Eldar Sætre.

3.3 Changes to the individual terms in 2014

The pension terms for one of the executive vice presidents employed outside the parent company was changed effective 1 January 2014. In lieu of participating in the subsidiary's at any time prevailing defined contribution pension scheme, the executive vice president will be paid a monthly cash supplement. The monthly cash supplement will be calculated on the basis of 20% of the Executive Vice President's base salary (being the contribution the subsidiary would have made to the defined contribution pension scheme) less the at any time prevailing Employer National Insurance Contribution.

Following president and chief executive officer Helge Lund's resignation a termination agreement was entered into. Helge Lund's termination date was 9 February 2015. Helge Lund received base salary and benefits compensation up until this date, and did not receive variable pay for the performance year 2014. The LTI scheme and Share Saving Plan was closed in accordance with the company policy. The company issued a paid-up policy and pension right letters for his pension accruals, in accordance with his individual pension agreement.

The individual terms for Eldar Sætre as acting in the position as President and chief executive officer of Statoil ASA (in the period from 15 October 2014 to 3 February 2015), involved an annual base salary compensation of NOK 5,700,000. Furthermore it included participation in an annual variable pay scheme with a target level of 25%, and participation to the company's 2015 LTI scheme with a value of 30% (gross) of base salary. Other terms and conditions were unchanged.

3.4 Impact of the revised Government Guidelines of 13 February 2015 for executive remuneration

In general, the revisions to the Guidelines will further limit the company's flexibility in offering competitive executive terms and conditions. In 2015 we will execute an assessment to address the implications of the revised guidelines with due regard to the "comply or explain" principle.

4. The decision-making process

The decision-making process for implementing or changing remuneration policies and concepts, and the determination of salaries and other remuneration for corporate executive committee, are in accordance with the provisions of the Norwegian public limited liability companies act sections 5-6 and 6-16 a and the board's rules of procedure. The board's rules of procedure are available at www.statoil.com/board.

The board of directors has appointed a designated compensation and executive development committee. The compensation and executive development committee is a preparatory body for the board. The committee's main objective is to assist the board of directors in its work relating to the terms of employment for Statoil's chief executive officer and the main principles and strategy for the remuneration and leadership development of our senior executives. The board of directors determines the chief executive officer's salary and other terms of employment.

The compensation and executive development committee answers to the board of Statoil ASA for the performance of its duties. The work of the committee in no way alters the responsibilities of the board of directors or the individual board members.

For further details about the roles and responsibilities of the compensation and executive development committee, please refer to the committee's instructions available at www.statoil.com/compensationcommittee.

A complete statement on remuneration and other employment terms for Statoil's corporate executive committee is also available at Statoil.com

6 Share-based compensation

Statoil's share saving plan provides employees with the opportunity to purchase Statoil shares through monthly salary deductions and a contribution by Statoil. If the shares are kept for two full calendar years of continued employment, the employees will be allocated one bonus share for each one they have purchased.

Estimated compensation expense including the contribution by Statoil ASA for purchased shares, amounts vested for bonus shares granted and related social security tax was NOK 0.5 billion in both 2014 and 2013. For the 2015 program (granted in 2014) the estimated compensation expense is NOK 0.5 billion. At 31 December 2014 the amount of compensation cost yet to be expensed throughout the vesting period is NOK 1.1 billion.

7 Auditor's remuneration

(in NOK million, excluding VAT)	2014	Full year 2013
Audit fee	9	9
Audit related fee	5	5
Other service fee	0	0
Total	14	14

There are no fees incurred related to tax services.

8 Research and development expenditures

Research and development expenditures were NOK 0.1 billion in both 2014 and 2013.

9 Financial items

		Full year
(in NOK billion)	2014	2013
Foreign exchange gains (losses) derivative financial instruments	(1.5)	(4.1)
Other foreign exchange gains (losses)	(15.6)	(12.6)
Net foreign exchange gains (losses)	(17.1)	(16.7)
Interest income from group companies	2.3	3.0
Interest income current financial assets and other financial items	0.8	1.2
Interest income and other financial items	3.1	4.3
Interest expense to group companies	(0.8)	(0.4)
Interest expense non-current finance debt	(4.5)	(1.6)
Interest expense current financial liabilities and other finance expense	(0.1)	(0.3)
Interest and other finance expenses	(5.4)	(2.3)
Net financial items	(19.4)	(14.7)

10 Income taxes

Income tax expense

(in NOK billion)	2014	Full year 2013
Current taxes	0.6	0.5
Change in deferred tax	8.0	5.7
Income tax expense	8.6	6.2

Reconciliation of Norwegian nominal statutory tax rate to effective tax rate

		Full year
(in NOK billion)	2014	2013
Income before tax	(2.5)	33.2
Nominal tax rate (27% for 2014 and 28% for 2013)	0.7	(9.3)
Tax effect of:
Permanent differences caused by NOK being the tax currency	4.7	0.4
Permanent differences related to equity accounted companies	5.4	14.0
Other permanent differences	(0.2)	0.5
Income tax prior years	(1.3)	0.4
Other	(0.7)	0.2
Total	8.6	6.2
Effective tax rate	-345.0 %	18.7 %

Significant components of deferred tax assets and liabilities were as follows:

(in NOK billion)	2014	At 31 December 2013
Deferred tax - assets
Inventory	0.5	0.0
Tax losses carry forward	8.1	0.1
Pensions	5.2	4.4
Long term provisions	1.6	1.6
Derivatives and long term debt	0.8	0.4
Other non-current items	0.8	1.0
Total deferred tax assets	17.0	7.5
Deferred tax - liabilites
Property, plant and equipment	0.3	0.2
Derivatives and long term debt	0.0	0.2
Total deferred tax liabilities	0.3	0.4
Net deferred tax assets / (liabilities)	16.7	7.1

At 31 December 2014, Statoil ASA had recognised net Deferred tax assets of NOK 16.7 billion, as it is considered probable that taxable profit will be available to utilize the deferred tax assets.

The movement in deferred income tax

(in NOK billion)	2014	2013
Deferred income tax assets / (liabilities) at 1 January	7.1	1.0
Charged to the income statement	8.0	5.7
Other	1.6	0.4
Deferred income tax assets / (liabilities) at 31 December	16.7	7.1

11 Property, plant and equipment

	Machinery, equipment and
(in NOK billion)	transportation	equipment Buildings and land	Vessels	Other	Total
Cost at 31 December 2013	2.9	2.4	4.0	1.0	10.3
Additions and transfers	0.4	(0.1)	0.0	(0.1)	0.2
Effect of changes in foreign exchange	0.7	0.5	0.9	0.2	2.4
Cost at 31 December 2014	4.0	2.9	4.9	1.2	12.9
Accumulated depreciation and impairment losses at 31 December 2013	(2.0)	(0.6)	(1.5)	(0.9)	(5.1)
Depreciation	(0.5)	(0.1)	(0.2)	(0.0)	(0.9)
Effect of changes in foreign exchange	(0.5)	(0.2)	(0.4)	(0.2)	(1.3)
Accumulated depreciation and impairment losses at 31 December 2014	(3.0)	(0.9)	(2.1)	(1.1)	(7.2)
Carrying amount at 31 December 2014	0.9	1.9	2.8	0.0	5.7
Estimated useful lives (years)	3 - 10	20 - 33	15 - 20

12 Investments in subsidiaries and other equity accounted companies

(in NOK billion)	2014	2013
Investments at 1 January	389.9	328.5
Net income from subsidiaries and other equity accounted companies	24.2	49.6
Additional paid-in equity	11.5	62.0
Pension adjustments	(0.5)	(0.1)
Distributions	(21.6)	(36.6)
Translation adjustments	71.2	27.8
Divestment	0.0	(41.4)
Investments at 31 December	474.6	389.9

The closing balance of Investments at 31 December of NOK 474.6 billion consist of investments in subsidiaries amounting to NOK 473.8 billion and investments in other equity accounted companies amounting to NOK 0.8 billion. In 2013, the amounts were NOK 389.2 billion and NOK 0.7 billion respectively.

In 2014 Net income from subsidiaries and other equity accounted companies was impacted by net impairment losses related to Property, plant and equipment and exploration assets of NOK 32.3 billion after tax, primarily resulting from reduced short term oil price forecasts. For more information see the Consolidated financial statements of Statoil note 11 Property, plant and equipment.

Amortisation and impairment of goodwill amounts to NOK 2.8 billion in 2014. Amortisation of goodwill amounted to NOK 1.0 billion in 2013.

Distributions during 2014 mainly consist of dividends from group companies of NOK 17.7 billion and group contribution from Statoil Petroleum AS of NOK 3.9 billion after tax. In 2013 the group contribution from Statoil Petroleum AS was NOK 3.2 billion after tax.

On 1 January 2013, Statoil ASA sold its shares in Statoil North America Inc. to Statoil Investment Americas AS, a subsidiary of Statoil Petroleum AS, for a cash consideration of NOK 41.4 billion.

The acquisition cost for investments in subsidiaries and other equity accounted companies are NOK 365.6 billion in 2014 and NOK 285.7 billion in 2013. The companies are founded by Statoil ASA,

Ownership in certain subsidiaries and other equity accounted companies

Name	in %	Country of incorporation	Name	in %	Country of incorporation
Statholding AS	100	Norway	Statoil Nigeria Deep Water AS	100	Norway
Statoil Angola Block 15 AS	100	Norway	Statoil Nigeria Outer Shelf AS	100	Norway
Statoil Angola Block 15/06 Award AS	100	Norway	Statoil Norsk LNG AS	100	Norway
Statoil Angola Block 17 AS	100	Norway	Statoil North Africa Gas AS	100	Norway
Statoil Angola Block 31 AS	100	Norway	Statoil North Africa Oil AS	100	Norway
Statoil Angola Block 38 AS	100	Norway	Statoil Orient AG	100	Switzerland
Statoil Angola Block 39 AS	100	Norway	Statoil OTS AB	100	Sweden
Statoil Angola Block 40 AS	100	Norway	Statoil Petroleum AS	100	Norway
Statoil Apsheron AS	100	Norway	Statoil Shah Deniz AS	100	Norway
Statoil Azerbaijan AS	100	Norway	Statoil Sincor AS	100	Norway
Statoil BTC Finance AS	100	Norway	Statoil SP Gas AS	100	Norway
Statoil Coordination Centre NV	100	Belgium	Statoil Tanzania AS	100	Norway
Statoil Danmark AS	100	Denmark	Statoil Technology Invest AS	100	Norway
Statoil Deutschland GmbH	100	Germany	Statoil UK Ltd	100	United Kingdom
Statoil do Brasil Ltda	100	Brazil	Statoil Venezuela AS	100	Norway
Statoil Exploration Ireland Ltd.	100	Ireland	Statoil Venture AS	100	Norway
Statoil Forsikring AS	100	Norway	Statoil Metanol ANS	82	Norway
Statoil Færøyene AS	100	Norway	Mongstad Refining DA	79	Norway
Statoil Hassi Mouina AS	100	Norway	Mongstad Terminal DA	65	Norway
Statoil Indonesia Karama AS	100	Norway	Tjeldbergodden Luftgassfabrikk DA	51	Norway
Statoil New Energy AS	100	Norway	Naturkraft AS	50	Norway
Statoil Nigeria AS	100	Norway	Vestprosess DA	34	Norway

13 Financial assets and liabilities

Non-current receivables from subsidiaries and other equity accounted companies

		At 31 December
(in NOK billion)	2014	2013
Interest bearing receivables from subsidiaries and other equity accounted companies	66.4	66.4
Non-interest bearing receivables from subsidiaries	2.2	3.0
Receivables from subsidiaries and other equity accounted companies	68.6	69.4

Interest bearing receivables from subsidiaries and other equity accounted companies at 31 December 2014 are due later than five years, except for NOK 16.0 billion which is due within the next five years. Of the Non-interest bearing receivables from subsidiaries at 31 December 2014, NOK 1.3 billion relates to pension, see note 19 Pensions. Correspondingly, NOK 2.0 billion related to pension at 31 December 2013.

Current receivables from subsidiaries and other equity accounted companies

Receivables from subsidiaries and other equity accounted companies include group contributions from Statoil Petroleum AS before tax of NOK 5.0 billion at 31 December 2014 and NOK 4.0 billion at 31 December 2013.

Current financial investments

(in NOK billion)	2014	At 31 December 2013
Time deposits	9.8	4.5
Interest bearing securities	43.4	29.5
Financial investments	53.2	33.9

Current Financial investments at 31 December 2014 and 2013 are considered to be trading securities, measured at fair value with gains and losses recognized in the statement of income. The cost price for current financial investments was NOK 55.2 billion at 31 December 2014 and NOK 34.1 billion at 31 December 2013.

Current liabilities to subsidiaries

Liabilities to subsidiaries includes current liabilities to Statoil Petroleum AS of NOK 27.6 billion and liabilities related to Statoil group's internal bank arrangements of NOK 83.3 billion at 31 December 2014. The corresponding amounts were NOK 27.6 billion and NOK 56.7 billion at 31 December 2013.

14 Inventories

(in NOK billion)	2014	At 31 December 2013
Crude oil	7.8	8.8
Petroleum products	3.6	5.1
Other	3.8	2.8
Inventories	15.3	16.7

Other inventory consists mainly of natural gas.

The write-down of inventories from cost to net realisable value amounts to an expense of NOK 2.8 billion and NOK 0.0 billion in 2014 and 2013, respectively.

15 Trade and other receivables

(in NOK billion)	2014	At 31 December 2013
Trade receivables	38.3	46.1
Other receivables	5.3	2.4
Trade and other receivables	43.6	48.5

16 Cash and cash equivalents

		At 31 December
(in NOK billion)	2014	2013
Cash at bank available	3.4	1.7
Time deposits	32.4	37.1
Money market funds	3.6	6.1
Interest bearing securities	30.5	31.2
Collateral deposits	1.6	0.9
Cash and cash equivalents	71.5	77.0

Collateral deposits of NOK 1.6 billion at 31 December 2014 and NOK 0.9 billion at 31 December 2013 are related to trading activities. The trading activities are related to certain requirements set out by exchanges where the company is participating. The terms and conditions related to these requirements are determined by the respective exchanges.

17 Equity and shareholders

Change in equity

		At 31. December
(in NOK billion)	2014	2013
Shareholders' equity at 1 January	321.3	280.6
Net income	6.1	39.4
Actuarial gain (loss) defined benefit pension plans	0.9	(4.4)
Foreign currency translation adjustments	52.8	28.3
Ordinary dividend	(22.9)	(22.3)
Value of stock compensation plan	0.1	(0.2)
Treasury shares purchased	(0.1)	(0.1)
Total equity at 31 December	358.2	321.3

The accumulated foreign currency translation effect as of 31 December 2014 increased total equity by NOK 70.9 billion. At 31 December 2013 the corresponding effect was an increase in total equity of NOK 18.2 billion.

Common stock

	Number of shares	NOK per value	At 31 December Common stock
Authorised and issued	3,188,647,103	2.50	7,971,617,757.50
Treasury shares	10,155,249	2.50	25,388,122.50
Total outstanding shares	3,198,802,352	2.50	7,997,005,880.00

There is only one class of shares and all the shares have the same voting rights.

During 2014 a total of 3,381,488 treasury shares were purchased for NOK 0.6 billion and 2,960,972 treasury shares were allocated to employees participating in the share saving plan. In 2013 a total of 3,937,641 treasury shares were purchased for NOK 0.5 billion and 2,878,255 treasury shares were allocated to employees participating in the share saving plan. At 31 December 2014 Statoil had 10,155,249 treasury shares and at 31 December 2013 9,734,733 treasury shares, all of which are related to Statoil's share saving plan. For further information, see note 6 Share-based compensation.

The board of directors is authorised on behalf of the company to acquire Statoil shares in the market. The authorisation may be used to acquire Statoil shares with an overall nominal value of up to NOK 27.5 million. Such shares acquired in accordance with the authorisation may only be used for sale and transfer to employees of the Statoil group as part of the group's share saving plan approved by the board. The minimum and maximum amount that may be paid per share will be NOK 50 and NOK 500, respectively. The authorisation is valid until the next ordinary general meeting.

	The 20 largest shareholders at 31 December 2014 (in %)	Account type	Ownership in %
1	The Norwegian State (Ministry of Petroleum and Energy)		67.00
2	Folketrygdfondet (Norwegian national insurance fund)		3.12
3	Deutsche Bank Trust Co. Americas	Nominee	3.01
4	Clearstream Banking	Nominee	2.40
5	State Street Bank and Trust Co.	Nominee	0.72
6	State Street Bank and Trust Co.	Nominee	0.71
7	State Street Bank and Trust Co.	Nominee	0.49
8	State Street Bank and Trust Co.	Nominee	0.47
9	The Bank of New York Mellon	Nominee	0.47
10	Blackrock		0.45
11	State Street Bank and Trust Co.	Nominee	0.44
12	Six SIS AG	Nominee	0.36
13	J.P. Morgan Chase Bank N.A. London	Nominee	0.34
14	The Northern Trust Company LTD.	Nominee	0.33
15	J.P. Morgan Chase Bank N.A. London	Nominee	0.33
16	KLP Aksje Norge		0.32
17	UBS AG	Nominee	0.30
18	The Northern Trust Company LTD.	Nominee	0.29
19	Euroclear Bank S.A./N.V.(BA)	Nominee	0.28
20	The Bank of New York Mellon SA/NVT	Nominee	0.25

Members of the board of directors, corporate executive committee and corporate assembly holding shares as of 31 December 2014:

Board of directors		Corporate executive committee
Svein Rennemo	10,000	Eldar Sætre	29,163
Grace Reksten Skaugen	400	Torgrim Reitan	24,030
Bjørn Tore Godal	0	Margareth Øvrum	37,284
Jakob Stausholm	50,000	Lars Christian Bacher	21,422
Maria Johanna Oudeman	0	Tim Dodson	23,982
James Mulva	0	William Maloney**	43,700
Catherine Hughes	3,850	John Knight	71,046
Øystein Løseth*	0	Arne Sigve Nylund	6,859
Lill-Heidi Bakkerud	330	Tor Martin Anfinnsen***	8,747
Ingrid Elisabeth di Valerio	2,241
Stig Lægreid	1,519
		Corporate assembly (in total)	15,357

* Øystein Løseth has been a board member since 1 October 2014

** American Depository Receipts (ADR)

*** Tor Martin Anfinnsen has been member of the corporate executive committee since 16 October 2014

18 Finance debt

Non-current finance debt

		At 31 December
(in NOK billion)	2014	2013
Unsecured bonds	209.4	168.5
Unsecured loans	0.6	0.5
Finance lease liabilities	3.3	2.9
Total finance debt	213.3	172.0
Less current portion	12.0	9.3
Non-current finance debt	201.3	162.6
Weighted average interest rate (%)	3.86	3.89

Statoil ASA uses currency swaps to manage foreign exchange risk on its non-current financial liabilities. From 1 January 2014 Statoil ASA changed the presentation of the currency swaps in the balance sheet. As of 31 December 2014 currency swaps were presented as Derivative financial instruments in the balance sheet and are not reflected in the table above. As of 31 December 2013 the currency swaps were presented as Finance debt in the balance sheet and are reflected in the table above. For information about the interest rate risk management, see note 3 Financial risk management and derivatives.

In 2014 Statoil ASA issued the following bonds:

Issuance date	Amount in USD billion	Interest rate in %	Maturity date
10 November 2014	0.75	1.25	November 2017
10 November 2014	0.5	floating	November 2017
10 November 2014	0.75	2.25	November 2019
10 November 2014	0.5	2.75	November 2021
10 November 2014	0.5	3.25	November 2024

Substantially all unsecured bond and unsecured bank loan agreements contain provisions restricting future pledging of assets to secure borrowings without granting a similar secured status to the existing bond holders and lenders.

Out of Statoil ASA total outstanding unsecured bond portfolio, 45 bond agreements contain provisions allowing Statoil to call the debt prior to its final redemption at par or at certain specified premiums if there are changes to the Norwegian tax laws. The carrying amount of these agreements is NOK 207.9 billion at the 31 December 2014 closing exchange rate.

Statoil ASA has an undrawn revolving credit facility for USD 3.0 billion supported by 20 core banks. As of 31 December 2014 and 2013, Statoil ASA had no amount drawn under any committed revolving credit facility.

Non-current finance debt repayment profile

(in NOK billion)
2016	8.2
2017	18.9
2018	27.1
2019	17.0
Thereafter	130.1
Total	201.3

More information regarding finance lease liabilities is provided in note 22 Leases.

Current finance debt

		At 31 December
(in NOK billion)	2014	2013
Collateral liabilities and other current financial liabilities	12.7	7.4
Non-current finance debt due within one year	12.0	9.3
Current finance debt	24.7	16.8
Weighted average interest rate (%)	2.19	2.09

Collateral liabilities and other current financial liabilities relate mainly to cash received as security for a portion of Statoil ASA's credit exposure.

19 Pensions

Statoil ASA (Statoil) is subject to the Mandatory Company Pensions Act, and the company's pension scheme follows the requirements of the Act.

Statoil's pension scheme is managed by Statoil Pensjon (Statoil's pension fund - hereafter "Statoil Pension"). Statoil Pension is an independent pension fund that covers employees of Statoil ASA. The purpose of Statoil Pension is to provide retirement and disability pension to members and survivor's pension to spouses, registered partners, cohabitants and children. The pension fund's assets are kept separate from the company's assets. Statoil Pension is supervised by the Financial Supervisory Authority of Norway ("Finanstilsynet") and is licensed to operate as a pension fund.

In 2014 Statoil made a decision to change the company's main pension plan from defined benefit plan to defined contribution plan. The actual transitioning to the defined contribution plan will take place in 2015. At the same time paid-up policies for the rights vested in the defined benefit plan will be issued. Employees with less than 15 years of future service before their regular retirement age will retain the existing defined benefit plans. For onshore employees between 37 and 51 years of age and offshore employees between 35 and 49 years of age a compensation plan will be established. The plan amendment resulted in the recognition of a gain (net of past service costs related to the compensation plan) of NOK 3.5 billion in the 2014 Statement of income as the decision to terminate the plan was made in 2014.

The Norwegian National Insurance Scheme ("Folketrygden") provides pension payments (social security) to all retired Norwegian citizens. Such payments are calculated by reference to a base amount ("Grunnbeløpet" or "G") annually approved by the Norwegian Parliament. Statoil's plan benefits are generally based on a minimum of 30 years of service and 66% of the final salary level, including an assumed benefit from the Norwegian National Insurance Scheme.

Due to national agreements in Norway, Statoil is a member of both the previous agreement-based early retirement plan ("AFP") and the AFP scheme applicable from 1 January 2011. Statoil will pay premium for both AFP schemes until 31 December 2015. After that date, premiums will only be due on the latest AFP scheme. The premium in the latest scheme is calculated on the basis of the employees' income between 1 and 7.1 G. The premium is payable for all employees until age 62. Pension from the latest AFP scheme will be paid from the AFP plan administrator to employees for their full lifetime. Statoil has determined that its obligation under this multi-employer defined benefit plan can be estimated with sufficient reliability for recognition purposes. Accordingly, the estimated proportionate share of the AFP plan has been recognised as a defined benefit obligation.

The present values of the defined benefit obligation and the related current service cost and past service cost are measured using the projected unit credit method. The assumptions for salary increases, increases in pension payments and social security base amount are based on agreed regulation in the plans, historical observations, future expectations of the assumptions and the relationship between these assumptions. At 31 December 2014 the discount rate for the defined benefit plans is established on the basis of seven years' mortgage covered bonds interest rate extrapolated on a yield curve which matches the duration for Statoil's payment portfolio for earned benefits.

Social security tax is calculated based on the pension plan's net funded status and is included in the defined benefit obligation.

Statoil has more than one defined benefit plan, but the disclosure is made in total since the plans are not subject to materially different risks.

Net pension cost

		Full year
(in NOK billion)	2014	2013
Current service cost	4.7	3.9
Interest cost	3.0	2.4
Interest (income) on plan asset	(2.5)	(2.1)
Losses (gains) from curtailment, settlement or plan amendment*	(1.9)	0.0
Actuarial (gains) losses related to termination benefits	(0.2)	0.0
Defined benefit plans	3.2	4.4
Total net pension cost	3.2	4.4

*In 2014 Statoil offered early retirement (termination benefits) to a defined group of employees above the age of 58 years. The expenses of NOK 1.6 billion were recognised in the Statement of income and partly offset the gain of NOK 3.5 billion related to the plan amendment described above.

Pension cost includes associated social security tax and is partly charged to partners of Statoil operated licences.

(in NOK billion)	2014	2013
Defined benefit obligations (DBO)
At 1 January	75.6	61.5
Current service cost	4.7	3.9
Interest cost	3.0	2.4
Actuarial (gains) losses - Demographic assumptions	(0.1)	5.8
Actuarial (gains) losses - Financial assumptions	4.6	4.7
Actuarial (gains) losses - Experience	(2.0)	(1.1)
Benefits paid	(2.0)	(2.4)
Losses (gains) from curtailment, settlement or plan amendment*	(2.8)	0.0
Paid-up policies	(20.4)	0.0
Change in receivable from subsidiary related to termination benefits	0.7	0.7
At 31 December	61.3	75.6
Fair value of plan assets
At 1 January	60.6	53.2
Interest income	2.5	2.1
Return on plan assets (excluding interest income)	0.8	3.9
Company contributions	0.0	2.9
Benefits paid	(0.7)	(1.5)
Paid-up policies	(20.4)	0.0
At 31 December	42.8	60.6
Net benefit liability at 31 December	(18.6)	(15.0)
Represented by:
Asset recognised as non-current pension assets (funded plan)	7.9	5.2
Asset recognised as non-current receivables from subsidiary**	1.3	2.0
Liability recognised as non-current pension liabilities (unfunded plans)	(27.7)	(22.2)
DBO specified by funded and unfunded pension plans	61.3	75.6
Funded	34.9	55.3
Unfunded	26.5	20.2
Actual return on assets	3.3	6.0

*An amount of NOK 0.9 billion, related to plan amendment, has been recognised against Property, plant and equipment.

** Asset recognised as non-current receivables from subsidiary relates to termination benefits.

As part of the change of Statoil's main pension plan the estimated assets and liabilities related to paid-up policies have been excluded from the 31 December 2014 amounts in the table above.

Actuarial losses and gains recognised directly in retained earnings

		Full year
(in NOK billion)	2014	2013
Net actuarial (losses) gains recognised in retained earnings during the year	1.7	(5.5)
Actuarial (losses) gains related to currency effects on net obligation and foreign exchange translation	(0.1)	(0.3)
Tax effects of actuarial (losses) gains recognised in retained earnings	(0.2)	1.2
Recognised directly in retained earnings during the year net of tax	1.4	(4.6)
Cumulative actuarial (losses) gains recognised directly in retained earnings net of tax	(13.5)	(14.9)

The line item Net actuarial (losses) gains recognised in retained earnings during the year in 2014 includes actuarial loss charged to partners of Statoil operated licences.

The line item Actuarial (losses) gains related to currency effects on net obligation and foreign exchange translation includes the translation of the net pension obligation in NOK to the functional currency USD and the translation of the net pension obligation from the functional currency USD to Statoil's presentation currency NOK.

Actuarial assumptions

	Assumptions used to determine benefit costs in %		Assumptions used to determine benefit obligations in %		Assumptions used to determine the effect of new pension plan in %
		Full year		Full year
	2014	2013	2014	2013	At 14 November 2014
Discount rate	4.00	3.75	2.50	4.00	3.00
Rate of compensation increase	3.50	3.25	2.25	3.50	2.75
Expected rate of pension increase	2.50	1.75	1.50	2.50	1.75
Expected increase of social security base amount (G-amount)	3.25	3.00	2.25	3.25	2.50
Number of employees (including pensioners)*			9,469	23,348
Weighted-average duration of the defined benefit obligation			19.1	22.2

* Number of employees listed above is related to the main defined benefit plan. In addition, all employees are members of the AFP plan and different groups of employees are members of other unfunded plans.

Expected attrition at 31 December 2014 was 2.1%, 2.2%, 1.3%, 0.5% and 0.2% for the employees under 30 years, 30-39 years, 40-49 years, 50-59 years and 60-67 years, respectively. Expected attrition at 31 December 2013 for the same respective age categories was 2.5%, 3.0%, 1.5%, 0.5% and 0.1%.

The mortality table K2013, issued by The Financial Supervisory Authority of Norway, is used as the best mortality estimate. Implementation of these tables in 2013 resulted in a gross increase in defined benefit obligation of NOK 7.4 billion.

In 2013 Statoil implemented new disability tables that resulted in a decrease in defined benefit obligation of NOK 1.6 billion. These tables have been developed by the actuary and represent the best estimate to use for Statoil.

Sensitivity analysis

The table below presents an estimate of the potential effects of changes in the key assumptions for the defined benefit plans. The following estimates are based on facts and circumstances as of 31 December 2014. Actual results may materially deviate from these estimates.

		Discount rate	Rate of compensation increase		Expected rate of pension increase
(in NOK billion)	0.5 %	-0.5 %	0.5 %	-0.5 %	0.5 %	-0.5 %
Changes in:
Defined benefit obligation at 31 December 2014	(5.0)	6.1	2.7	(2.4)	3.6	(3.3)
Service cost 2015	(0.2)	0.3	0.1	(0.1)	0.1	(0.1)

One additional year of longevity in the mortality assumptions would have an increase on the defined benefit obligation at 31 December 2014 of NOK 2.7 billion.

The sensitivity of the financial results to each of the key assumptions has been estimated based on the assumption that all other factors would remain unchanged. The estimated effects on the financial result would differ from those that would actually appear in the financial statements because the financial statements would also reflect the relationship between these assumptions.

Pension assets

The plan assets related to the defined benefit plans were measured at fair value at 31 December 2014 and 2013. Statoil Pension invests in both financial assets and real estate.

Real estate properties owned by Statoil Pension amounted to NOK 3.2 billion and NOK 3.1 billion of total pension assets at 31 December 2014 and 2013, respectively, and are rented to Statoil companies.

The table below presents the portfolio weighting as approved by the Board of Statoil Pension for 2014. The portfolio weight during a year will depend on the risk capacity.

	Pension assets on investments classes
(in %)	2014	2013	Target portfolio
Equity securities	40.1	39.6	31 - 43
Bonds	38.7	37.6	36 - 48
Money market instruments	13.4	17.2	0 - 29
Real estate	4.8	5.1	5 - 10
Other assets	3.0	0.5
Total	100.0	100.0

* The interval expresses the scope of tactical deviation.

No company contribution is expected to be paid to Statoil Pension in 2015.

20 Provisions

(in NOK billion)	Provisions
Non-current portion at 31 December 2013	2.0
Current portion at 31 December 2013 reported as trade and other payables	4.3
Provisions at 31 December 2013	6.3
New or increased provisions	1.1
Decrease in estimate	(0.2)
Amounts charged against provisions	(2.1)
Reclassification and transfer	(0.1)
Currency translation	0.7
Provisions at 31 December 2014	5.7
Current portion at 31 December 2014 reported as trade and other payables	3.7
Non-current portion at 31 December 2014	2.1

21 Trade and other payables

(in NOK billion)	2014	At 31 December 2013
Trade payables	10.9	16.4
Non-trade payables, accrued expenses and provisions	11.7	12.0
Associated companies and other related party payables	6.5	9.5
Trade and other payables	29.1	37.9

22 Leases

Statoil ASA leases certain assets, notably vessels and office buildings.

In 2014, net rental expenditures were NOK 3.3 billion (NOK 1.9 billion in 2013) of which minimum lease payments were NOK 3.9 billion (NOK 2.4 billion in 2013) and sublease payments received were NOK 0.6 billion in 2014 (NOK 0.4 in 2013). Contingent rents expensed were immaterial both years. Net rental expenditures in 2014 include rig cancellation payments of NOK 1.2 billion.

The information in the table below shows future minimum lease payments under non-cancellable leases at 31 December 2014. Amounts related to finance leases include future minimum lease payments for assets recognised in the financial statements at year end 2014.

				Finance leases
(in NOK billion)	Operating leases	Operating sublease	Minimum lease payments	Discount element	Net present value minimum lease payments
2015	2.7	(0.2)	0.4	(0.0)	0.4
2016	2.3	(0.2)	0.4	(0.0)	0.4
2017	1.8	(0.2)	0.4	(0.0)	0.3
2018	1.6	(0.2)	0.4	(0.1)	0.3
2019	1.5	(0.2)	0.4	(0.1)	0.3
Thereafter	9.5	(1.2)	2.3	(0.7)	1.6
Total future minimum lease payments	19.4	(2.2)	4.3	(1.0)	3.3

Statoil ASA has a long term time charter agreement with Teekay for offshore loading and transport in the North Sea. The contract covers the life time of applicable producing fields and at year end 2014 includes four crude tankers. The contract's estimated nominal amount is approximately NOK 5.0 billion at year end 2014, and is accounted for as Operating leases.

As of 2014, Operating leases include future minimum lease payments of NOK 4.3 billion related to the lease of two office buildings located in Bergen and owned by Statoil Pension. These operational lease commitments to a related party extend in time to the year 2034. NOK 3.2 billion of the total is payable after 2019.

Statoil ASA leases three LNG vessels on behalf of Statoil and the State's direct financial interest (SDFI). Statoil ASA accounts for the combined Statoil and SDFI share of these agreements as finance leases in the balance sheet, and further accounts for the SDFI related portion as Operating sublease. The finance leases included in the balance sheet reflect the original lease term of 20 years from 2006. In addition, Statoil has the option to extend the leases for two additional periods of five years each.

Property, plant and equipment include the following amounts for leases that have been capitalised at 31 December 2014 and 2013.

		At 31 December
(in NOK billion)	2014	2013
Vessels	4.9	4.0
Accumulated depreciation	(2.1)	(1.5)
Capitalised amount	2.8	2.5

23 Other commitments and contingencies

Contractual commitments

Statoil ASA had contractual commitments of NOK 7.9 billion at 31 December 2014. The contractual commitments reflect the Statoil ASA share and comprise financing commitments related to exploration activities.

Other long-term commitments

Statoil ASA has entered into various long-term agreements for pipeline transportation as well as terminal use, processing, storage and entry/exit capacity commitments and commitments related to specific purchase agreements. The agreements ensure the rights to the capacity or volumes in question, but also impose on the company the obligation to pay for the agreed-upon service or commodity, irrespective of actual use. The contracts' terms vary, with duration of up to 30 years.

Take-or-pay contracts for the purchase of commodity quantities are only included in the table below if their contractually agreed pricing is of a nature that will or may deviate from the obtainable market prices for the commodity at the time of delivery.

Obligations payable by Statoil ASA to entities accounted for using the equity method are included gross in the table below. For assets (e.g. pipelines) that the company accounts for by recognising its share of assets, liabilities, income and expenses (capacity costs) on a line-by-line basis in the financial statements, the amounts in the table include the net commitment payable by Statoil ASA (i.e. gross commitment less Statoil ASA's ownership share).

Nominal minimum commitments at 31 December 2014:

(in NOK billion)
2015	11.9
2016	10.8
2017	10.4
2018	10.2
2019	9.7
Thereafter	46.0

Total 99.0

Guarantees

Statoil ASA has provided parent company guarantees covering liabilities of subsidiaries with operations in Algeria, Angola, Azerbaijan, Brazil, Canada, Denmark, Germany, Greenland, India, Ireland, Libya, the Netherlands, Nigeria, Norway, Sweden, United Kingdom, the United States of America and Venezuela. The company has also counter-guaranteed certain bank guarantees covering liabilities of subsidiaries in Angola, Brazil, Canada, Greenland, the Netherlands, Norway, United Kingdom and the United States of America.

Contingencies

Statoil ASA is the participant in certain entities ("DAs") in which the company has unlimited responsibility for its proportionate share of such entities' liabilities, if any, and also participates in certain companies ("ANSs") in which the participants in addition have joint and several liability. For further details, refer to note 12 Investments in subsidiaries and other equity accounted investments.

A number of Statoil ASA's long-term gas sales agreements contain price review clauses. Certain counterparties have requested arbitration in connection with price review claims. The related exposure for Statoil ASA has been estimated to an amount equivalent to approximately NOK 4.4 billion for gas delivered prior to year end 2014. Statoil ASA has provided for its best estimate related to these contractual gas price disputes in the financial statements, with the impact to the statement of income reflected as revenue adjustments.

On 10 March 2014, following a regular review process of Statoil's 2012 Consolidated financial statements, the Financial Supervisory Authority of Norway (the FSA) concluded that it had identified three errors, related to interpretation and application of IFRS accounting principles for determination of cash generating units (CGUs) and impairment evaluations. For further information, reference is made to note 23 Other commitments and contingencies in the 2014 Consolidated financial statements.

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

Provisions related to claims and disputes are reflected within note 20 Provisions.

24 Related parties

The Norwegian State is the majority shareholder of Statoil ASA and also holds major investments in other Norwegian companies. This ownership structure means that Statoil ASA participates in transactions with parties that are under a common ownership structure and therefore meet the definition of a related party. All transactions are considered to be on an arm's length basis.

Transactions with the Norwegian State

Total purchases of oil and natural gas liquids from the Norwegian State amounted to NOK 86.4 billion and NOK 92.5 billion in 2014 and 2013, respectively. Purchases of natural gas regarding Tjeldbergodden methanol plant from the Norwegian State amounted to NOK 0.5 billion in both 2014 and 2013. In addition, Statoil ASA sells in its own name, but for the Norwegian State's account and risk, the Norwegian State's gas production. These amounts are presented net. For further information please see in note 2 Significant accounting policies. The major part included in the line item Associated companies and other related parties payables in note 21 Trade and other payables, are amounts payable to the Norwegian State for these purchases.

Transactions with internally owned companies

Revenue transactions with related parties are presented in note 4 Revenues. Total intercompany revenues amounted to NOK 37.3 billion and NOK 45.3 billion in 2014 and 2013, respectively. Intercompany revenues are attributed to sales of crude oil and sales of refined products to Statoil Refining Denmark AS, Statoil Marketing and Trading Inc and Statoil OTS AB.

Statoil ASA buys volumes from its subsidiaries and sells them into the market. Total purchases of goods from subsidiaries amounted to NOK 170.7 billion and NOK 174.9 billion in 2014 and 2013, respectively. The major part of intercompany purchases of goods is attributed to Statoil Petroleum AS.

In relation to its ordinary business operations, Statoil ASA has regular transactions with group companies in which Statoil has ownership interests. Statoil ASA makes purchases from group companies amounting to NOK 4.7 billion and NOK 3.6 billion in 2014 and 2013, respectively.

Statoil ASA sells natural gas and pipeline transport on a back to back basis to Statoil Petroleum AS. All of the risks related to these purchases are carried by Statoil Petroleum AS and are therefore not reflected in Statoil ASA's financial statements.

Expenses incurred by the company, such as personnel expenses, are accumulated in cost pools. Such expenses are allocated in part on an hours incurred cost basis to Statoil Petroleum AS, to other group companies, and to licences where Statoil Petroleum AS or other group companies are operators. Cost allocated in this manner is not reflected in Statoil ASA's financial statements. Expenses allocated to group companies amounted to NOK 37.0 billion and NOK 40.3 billion in 2014 and 2013, respectively. The major part of the allocation is related to Statoil Petroleum AS.

Current receivables and current liabilities from subsidiaries and other equity accounted companies are included in note 13 Financial assets and liabilities.

25 Subsequent events

On 10 February 2015 Statoil ASA issued bonds of EUR 3.75 billion, equivalent to NOK 32.1 billion at the transaction date. The bonds have maturities of 4-20 years. All of the bonds are unconditionally guaranteed by Statoil Petroleum AS.

Report of KPMG on the financial statements of Statoil ASA

To the annual shareholders' meeting of Statoil ASA

INDEPENDENT AUDITOR'S REPORT

Report on the financial statements

We have audited the accompanying financial statements of Statoil ASA, which comprise the financial statements of the parent company Statoil ASA and the consolidated financial statements of Statoil ASA and its subsidiaries. The parent company financial statements comprise the balance sheet as at 31 December 2014, the statement of income and statement of cash flows for the year then ended, and a summary of significant accounting policies and other explanatory information. The consolidated financial statements comprise the balance sheet as at 31 December 2014, and the statement of income, statement of other comprehensive income, statement of changes in equity and statement of cash flows for the year then ended, and a summary of significant accounting policies and other explanatory information.

The board of directors and chief executive officer's responsibility for the financial statements

The board of directors and chief executive officer are responsible for the preparation and fair presentation of the parent company financial statements in accordance with the Norwegian Accounting Act and accounting standards and practices generally accepted in Norway and for the consolidated financial statements in accordance with International Financial Reporting Standards as adopted by the EU, and for such internal control as the board of directors and chief executive officer determine is necessary to enable the preparation of financial statements that are free from material misstatement, whether due to fraud or error.

Auditor's responsibility

Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit in accordance with laws, regulations, and auditing standards and practices generally accepted in Norway, including International Standards on Auditing. Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity's preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion on the separate financial statements

In our opinion, the parent company financial statements are prepared in accordance with the law and regulations and present fairly, in all material respects, the financial position of Statoil ASA as at 31 December 2014, and of its financial performance and its cash flows for the year then ended in accordance with the Norwegian Accounting Act and accounting standards and practices generally accepted in Norway.

Opinion on the consolidated financial statements

In our opinion, the consolidated financial statements are prepared in accordance with the law and regulations and present fairly, in all material respects, the financial position of Statoil ASA and its subsidiaries as at 31 December 2014, and of its financial performance and its cash flows for the year then ended in accordance with International Financial Reporting Standards as adopted by the EU.

Report on other legal and regulatory requirements

Opinion on the board of directors' report and the statements on corporate governance and corporate social responsibility Based on our audit of the financial statements as described above, it is our opinion that the information presented in the board of directors' report and in the statements on corporate governance and corporate social responsibility concerning the financial statements, the going concern assumption and the proposal for the allocation of the profit is consistent with the financial statements and complies with the law and regulations.

Opinion on accounting registration and documentation

Based on our audit of the financial statements as described above, and control procedures we have considered necessary in accordance with the International Standard on Assurance Engagements (ISAE) 3000, «Assurance Engagements Other than Audits or Reviews of Historical Financial Information», it is our opinion that the management has fulfilled its duty to produce a proper and clearly set out registration and documentation of the company's accounting information in accordance with the law and bookkeeping standards and practices generally accepted in Norway.

Stavanger, 10 March 2015 KPMG AS

Mona Irene Larsen Egbert Eeftink State Authorised Public Accountant (Norway) ¹

1) Appointed as the responsible auditor by KPMG AS according to the Auditor's Act section 2-2

(Translation has been made for information purposes only)

Recommendation of the corporate assembly

Resolution:

At its meeting of 18 March 2015 the corporate assembly discussed the 2014 annual accounts of Statoil ASA and the Statoil group, and the board of directors' proposal for the allocation of net income.

The corporate assembly recommends that the annual accounts and the allocation of net income proposed by the board of directors are approved.

Oslo, 18 March 2015

Olaug Svarva Chair of the corporate assembly

Corporate assembly

Olaug Svarva, Idar Kreutzer, Karin Aslaksen, Greger Mannsverk, Steinar Olsen, Ingvald Strømmen, Rune Bjerke, Barbro Hætta, Siri Kalvig, Eldfrid Irene Hognestad, Steinar Kåre Dale, Per Martin Labråthen, Anne K. S. Horneland, Jan-Eirik Feste, Hilde Møllerstad, Terje Venold, Tone Lunde Bakker and Kjersti Kleven.