Dear shareholder,

2016 was a challenging year for the oil and gas industry. Across the industry, the financial results were impacted by the continued low price environment and Statoil ended up with a negative net income of USD 2.9 billion. In this situation, it is encouraging to see how well the company has delivered on its improvement programme and that the operational performance has continued to be strong. Statoil is now well positioned to for the future.

The board of directors has in its work focused both on short term measurements to secure the company’s position in a challenging environment, and more long term through the work of sharpening our strategy. Protecting and enhancing shareholder value guides the board of directors in its work and priorities – short and long term.

Strong safety performance is essential for the company’s operations. Last year we experienced the worst imaginable, with a fatality on a yard in South Korea and a helicopter crash outside Bergen that took 13 lives.

Further, the serious incident frequency, measured as incidents per million hours worked for both Statoil employees and contractors, increased from 0.6 in 2015 to 0.8 in 2016. Together with the administration, the board of directors has focused on new steps to reinforce safety measures and get back to a positive trend to improve our safety performance.

The response to the market challenge through our improvement programme delivered annualised efficiency gains of USD 3.2 billion measured against a 2013 baseline, USD 700 million above the USD 2.5 billion target. As the company moves from an improvement programme to an improvement culture, new targets are set.

The board of directors have during the year worked closely with the administration to review and confirm Statoil’s sharpened strategy. Statoil has set clear principles for the development of a distinct and competitive portfolio. Statoil will develop long-term value on the

Norwegian continental shelf, deepen in core areas and develop new growth options internationally, and grow value creation in its marketing and midstream business. The company is making progress in creating a material industrial position in new energy solutions, primarily focused on offshore wind.

Responding to the climate challenge and preparing Statoil for a low carbon future is an integrated part of our strategy. Concrete actions to reduce greenhouse gas emissions in the operations have been implemented, and steps have been taken to build a more resilient portfolio. The updated climate roadmap captures the new set of measurements to be implemented.

Statoil remains committed to shareholder value creation and maintained the dividend during the year. A resolution is proposed to the annual general meeting to maintain the dividend at USD 0.2201 per share in the fourth quarter, and to continue the scrip dividend programme through to the third quarter of 2017.

The board of directors believes the company is well prepared to deal with the current market situation and has the competence, capacity and leadership necessary to create new opportunities and long-term value for our shareholders.

I would like to thank our shareholders for their continued investment, as well as the many employees of Statoil for all the dedication and commitment they show every day.

Øystein Løseth

Chair of the board

Statoil, Annual Report on Form 20-F 2016 3

4 Statoil, Annual Report on Form 20-F 2016

Dear fellow shareholder,

Safety and security is our top priority in Statoil. And while 2016 was a year of many achievements, we also experienced the worst thinkable. We had a contractor fatality during construction work in South Korea, and on 29 April we lost 13 colleagues when a helicopter crashed on its way from Gullfaks B to Bergen.

For the year as a whole, our serious incident frequency came in at 0.8, an increase from the two previous years. We are not satisfied with this development and have taken several steps to reinforce safety measures throughout the company.

In 2016, we saw oil prices below USD 30 per barrel and while prices increased towards the end of the year, our average realised liquids price was still below USD 40 per barrel for the year as a whole.

We delivered our cost improvement programme above target. The next step will be to go from project mode to a culture of continuous improvement, and we have set a target of achieving USD 1 billion in additional cost improvements in 2017.

By reworking solutions from reservoir to market, we have transformed our opportunity set. The break-even price for our “Next generation” portfolio of projects (those sanctioned since 2015 or planned for sanction with start up by 2022), is now at USD 27 per barrel of oil equivalent (boe).

Organic capex for 2016 was USD 10.1 billion, a USD 3 billion reduction from the original guiding. Production for the full year was 1,978 mboe per day, a slight increase from 2015 due to continued high production efficiency and despite high turnaround activity. Our reserve-replacement ratio (RRR) was 93%.

“High value, low carbon” is at the core of our sharpened strategy. We believe the winners in the energy transition will be the producers which can deliver at low cost and with low carbon emissions.

Statoil is pursuing a distinct and value-driven strategy:

· On the Norwegian continental shelf (NCS) we have a unique position which we will leverage further to build our future business and maximise value

· In our international upstream business, we will focus, deepen and explore further. Brazil is a core area for us, together with our position in the highly flexible US onshore business

· For the Marketing, Midstream and Processing (MMP) business area, the job is to secure flow assurance by accessing premium markets and strengthening asset-backed trading, based on a ‘capex light’ approach

· In the New Energy Solutions (NES) business area, we are building a profitable business with the long-term potential to account for 15-20% of our capex in 2030, provided that we can access and mature attractive opportunities

Our commitment to long-term sustainable value creation, is in line with the principles of the UN Global Compact.

We believe a low carbon footprint will make us more competitive in the future. We also believe there are attractive business opportunities in the transition to a low-carbon economy. Statoil intends to be part of this transformation in order to fulfil our purpose of turning natural resources into energy for people and progress for society. Our Climate roadmap explains how we plan to achieve this and how we will develop our business, supporting the ambitions of the Paris climate agreement.

I look forward to further strengthening Statoil in 2017, pursuing the priorities set out at our Capital markets update: resetting our cost base, transforming our opportunity set and continuing to chase improvements. We have sharpened our strategy as an energy company towards 2030, and are ready to capitalise on high-value opportunities.

Eldar Sætre

President and Chief Executive Officer

Statoil ASA

Statoil, Annual Report on Form 20-F 2016 5

STATOIL AT A GLANCE

Our history

The company was founded as The Norwegian State Oil company (Statoil) in 1972, and became listed on the Oslo Børs (Norway) and New York Stock Exchange (US) in June 2001. Statoil merged with Hydro`s oil and gas division in October 2007.

Statoil is an international energy company with operations in over 30 countries. We are headquartered in Stavanger, Norway with approximately 20,500 employees worldwide. We create value through safe and efficient operations, innovative solutions and technology. Statoil’s competitiveness is founded on our values-based performance culture, with a strong commitment to transparency, cooperation and continuous operational improvement.

Our shareholders

The Norwegian State is the largest shareholder in Statoil, with a direct ownership interest of 67%. Its ownership interest is managed by the Norwegian Ministry of Petroleum and Energy. US investors hold 9.6%, Norwegian Private owners hold 8.9%, other European investors hold 7.1%, UK investors hold 5.1% and others hold 1.5%.

Our business areas

We have eight business areas:

· Development and Production Norway

· Development and Production International

· Development and Production USA

· Marketing, Midstream and Processing

· Technology, Projects and Drilling

· Exploration

· Global Strategy and Business Development

· New Energy Solutions

Our strategy

Statoil is an energy company committed to long-term value creation in a low carbon future. Statoil will develop and maximise the value of its unique Norwegian continental shelf position, its international oil and gas business and its growing new energy business; focusing on safety, cost and carbon efficiency. Statoil is a values based company where empowered people collaborate to shape the future of energy.

Our values

Open, Collaborative, Courageous and Caring.

Our dividend policy

It is Statoil's ambition to grow the annual cash dividend, measured in USD per share, in line with long term underlying earnings. Statoil announces dividends on a quarterly basis. In May 2016, the annual general meeting approved the introduction of a two-year scrip dividend programme commencing from the fourth quarter of 2015.

6 Statoil, Annual Report on Form 20-F 2016

Key figures and highlights

(in USD million, unless stated otherwise)		For the year ended 31 December
(in USD million, unless stated otherwise)		2016	2015	2014	2013	2012

Financial information⁴⁾
Total revenues and other income³⁾		45,873	59,642	99,264	108,318	123,660
Net operating income		80	1,366	17,878	26,572	35,808
Operating expenses		(9,025)	(10,512)	(11,657)	(12,669)	(10,467)
Net income		(2,902)	(5,169)	3,887	6,713	12,234
Non-current finance debt		27,999	29,965	27,593	27,197	18,137
Net interest-bearing debt before adjustments		18,372	13,852	12,004	9,542	7,057
Total assets		104,530	109,742	132,702	145,572	140,921
Share capital		1,156	1,139	1,139	1,139	961
Non-controlling interest		27	36	57	81	121
Total equity		35,099	40,307	51,282	58,513	57,468
Net debt to capital employed ratio before adjustments		34.4%	25.6%	19.0%	14.0%	10.9%
Net debt to capital employed ratio adjusted		35.6%	26.8%	20.0%	15.2%	12.4%
Calculated ROACE based on Average Capital Employed before adjustments		(4.7%)	(8.9%)	3.4%	11.3%	18.7%

Operational information
Equity oil and gas production (mboe/day)		1,978	1,971	1,927	1,940	2,004
Proved oil and gas reserves (mmboe)		5,013	5,060	5,359	5,600	5,422
Reserve replacement ratio (annual)		0.93	0.55	0.62	1.28	0.99
Reserve replacement ratio (three-year average)		0.70	0.81	0.97	1.15	1.01
Production cost equity volumes (USD/boe)		5.0	5.9	7.6	7.5	7.2

Share information¹⁾
Diluted earnings per share USD		(0.91)	(1.63)	1.21	2.14	3.80
Share price at Oslo Børs (Norway) on 31 December in NOK		158.40	123.70	131.20	147.00	139.00
Dividend per share USD ²⁾		0.88	1.07	0.97	1.15	1.21
Weighted average number of ordinary shares outstanding (in thousands)		3,194,880	3,179,443	3,179,959	3,180,684	3,181,546

1)	See section 5.1 Shareholder information for a description of how dividends are determined and information on share repurchases.
2)	Proposed cash dividend for the second quarter of 2016. From and including the third quarter of 2015, dividends were declared in USD. Dividends in previous periods were declared in NOK. Figures for 2015 and earlier periods are presented using the Central Bank of Norway year end rates for Norwegian kroner.
3)	Total revenues and other income for 2013 and 2012 are restated.
4)	On 1 January 2016 Statoil changed its presentation currency from Norwegian kroner (NOK) to US dollar (USD), mainly in order to better reflect the underlying USD exposure of Statoil’s business activities and to align with industry practice. Comparative figures have been represented in USD to reflect the change. For further details, reference is made to Note 26 Change of presentation currency to the Consolidated Financial Statements.

Statoil, Annual Report on Form 20-F 2016 7

About the report

This document constitutes the Annual report on Form 20-F in accordance with the US Securities and Exchange Act of 1934 applicable to foreign private issuers. A cross reference to the Form 20-F requirements are set out in section 5.10 in this report. The Annual report on Form 20-F and other related documents are filed with the US Securities and Exchange Commission (the SEC).

Financial reporting terms used in this report are in accordance with International Financial Reporting Standards (IFRS) as adopted by the European union (EU) and also comply with IFRS as issued by the International Accounting Standards Board (IASB), effective at 31 December 2016. This document should be read in conjunction with the cautionary statement in section 5.7 Forward-looking statement.

The Statoil Annual report and Form 20-F may be downloaded from Statoil’s website at [Statoil.com/annualreport2016]. No other material on Statoil’s website forms any part of such document. References to this document or other documents on Statoil’s website are included as an aid to their location and are not incorporated by reference into this document. All of the SEC filings made available electronically by Statoil may be obtained from the SEC at 100 F Street, N.E., Washington D.CC. 20549, United States or on the SEC’s website at www.sec.gov.

8 Statoil, Annual Report on Form 20-F 2016

2.1 Strategy and market overview

Statoil’s business environment

Market overview

2016 was another year of sub-par growth, with global economic GDP growth easing from 2.6% to 2.3%. This was largely driven by the slowdown in OECD economies, with non-OECD economies gaining momentum over the year. In the United States, consumer spending remained healthy, but investment contracted and resulted in GDP growth decelerating from 2.6% in 2015 to 1.6%. Economic expansion continued at a moderate pace in the Euro-zone at 1.7%, supported by private consumption and higher employment. The economy in the United Kingdom held up well despite the EU Leave vote, while in contrast Japan logged relatively modest growth. Emerging markets maintained their growth rate from 2015, partly due to Russia heading towards economic recovery during the year. 2016 saw China's growth stabilise due to intensified stimulus efforts amidst the continued slowdown since 2012, caused by economic rebalancing. India’s GDP growth rate eased to 6.6% on the sudden demonetarisation of large currency notes that hampered consumption. Several major forces are at play in the global economy and will continue to affect demand, including relatively low commodity prices, low interest rates, increased policy uncertainty and weak world trade.

Global oil demand grew by a healthy 1.5 mmbbl per day in 2016. Production from non-Opec countries reacted to lower prices and declined by 0.9 mmbbl, with most of the decline taking place in North America and China. However, Opec added 1.1 mmbbl per day to production. This resulted in an oversupplied market throughout 2016, with storage levels moderately increasing.

The first half of 2016 saw a downward trend in gas prices, which reflected both market balance and surrounding competitive fuels. However, in the second half of 2016, markets have strengthened due to a rebounding commodity market and demand responding to weak gas prices in the first half of 2016.

Oil prices and refining margins

Higher than usual volatility characterised the oil market in 2016 as it did in the previous year, with the price of dated Brent moving in a range between USD 26 per barrel to USD 55 per barrel.

Oil prices

The oil market is generally volatile and has been highly volatile since June 2014. The average price for dated Brent crude in 2016 was USD 43.7 per barrel, down USD 10 per barrel from 2015. The dated Brent oil price started the year on a downward trajectory and hit a low of USD 26 per barrel in the second half of January. Positive market sentiment driven by healthy demand growth and significant supply disruptions pushed the price of dated Brent up to around USD 50 per barrel by the end of second quarter. The return of disrupted volumes during the summer and signs of weakening demand growth sent prices down again towards USD 40 per barrel early in August. The price of dated Brent recovered somewhat again in the third quarter after Opec and Russia agreed to come up with a plan to freeze or cut their production. The Opec meeting in late November concluded with an agreement among the members to cut joint output by 1.2 mmbbl per day effective 1 January 2017, alongside a non-Opec cut of around 0.6 mmbbl per day. The immediate effect of this announcement was an increase in the dated Brent price towards USD 53 per barrel. The futures market for Brent at the Intercontinental Exchange (ICE) was in contango throughout 2016.

Over the course of 2016, North American tight oil has provided the largest share of non-Opec declines that offset continued growth in Opec production. While US shale production has been in decline over much of the past two years, productivity gains and cost reductions have accelerated, planting the seeds of future growth. Specifically, enhanced completions and extended-reach laterals have allowed producers to do more with less. Nowhere is this more evident than in the Permian basin of West Texas. As oil prices have increased during the course of the year, the Permian has recorded the largest rebound in drilling rigs. At current levels, the Permian basin is home to almost 50% of all oil rigs in the US, up from 30% in early 2013. From a pricing perspective, declining production, an abundance of infrastructure, and the lifting of the crude export ban have caused most North American grades to price close to their technical refining values, reflective of the ongoing de-bottlenecking of US onshore crude pipeline infrastructure. These narrow differentials relative to global waterborne crudes have caused rail loadings to fall precipitously with all indications being that this trend is set to continue in the years ahead.

Refinery margins

2016 was a solid year for European refinery margins. Through 2015, a surplus of crude oil had been converted to a surplus of products, incentivised by strong margins. By early 2016, diesel stocks were building fast and diesel margins were low. Refineries then shifted to maximise gasoline output, in expectation of a strong summer gasoline market. However, summer gasoline demand disappointed, leading to stocks building and sharply falling gasoline margins. Weak product prices through the summer led to constrained refinery throughput and supported demand. By the fourth quarter, the gasoline market rebalanced and diesel stocks fell

Statoil, Annual Report on Form 20-F 2016 9

again. This caused refinery margins to improve again in the fourth quarter. The average margin for an upgraded refinery in North West Europe was solid and in line with 2014, but well below 2015 margins.

Natural gas prices

Natural gas prices declined throughout 2015 but stabilised in the second quarter of 2016. The fourth quarter of 2016 experienced a robust price recovery due to consumption growth in Asia and Europe. Henry Hub experienced its lowest annual price in over a decade through 2016.

Gas prices – Europe

NBP prices fell from an average of USD 7.5/MMBtu in first quarter 2015 to USD 5.4/MMBtu in fourth quarter 2015. The decline continued in first quarter 2016, averaging USD 4.3/MMBtu, before falling to a decade low of USD 3/MMBtu in August 2016. Since August’s low point, average monthly prices have strengthened, closing 2016 at USD 6.2/MMBtu and resulting in an annual 2016 average of USD 5/MMBtu.

EU gas consumption continued to grow in 2016 as power generation responded to higher priced coal and outages of nuclear reactors in France. Furthermore, heating demand has responded to a more normal European weather pattern. EU indigenous gas production held at a record low of 125 bcm as the Dutch government revised the production limit at the Groningen field down to 24 bcm. European imports from Russia were at a record high of 179 bcm and imports from Norway were at the same record level as in 2015, 108 bcm. Record levels of pipeline imports have been encouraged by a small downturn in LNG deliveries to Europe. LNG supplies into North Western Europe have diminished, whilst imports into Southern Europe remain constant.

Gas prices - North America

Gas prices were volatile in 2016, falling below USD 2/MMBtu early in the year, before rising above USD 3/MMBtu at the end of the year. The Henry Hub average of USD 2.4/MMBtu was the lowest annual price in over a decade, down from USD 2.6/MMBtu in 2015 largely as a result of oversupply. US gas producers responded to the falling prices by withdrawing rigs to the lowest level in decades. Gas production fell throughout the year as a result. Demand for gas was strong in 2016, with natural gas replacing coal in the power sector and LNG exports starting from the Gulf Coast.

Global LNG prices

LNG prices fell throughout 2015 from an average of USD 7.3/MMBtu in first quarter 2015 to USD 4.5/MMBtu in first quarter 2016, but stabilised in second quarter of 2016 at an average of USD 4.9/MMBtu. The second half of 2016 experienced robust price recovery to average USD 8/MMBtu in fourth quarter 2016, largely due to consumption growth in Asia and the Middle East, further intensified by lower-than-expected ramp-up of new LNG facilities as well as unplanned outages.

Statoil’s corporate strategy

Statoil is an energy company committed to long-term value creation in a low carbon future. Statoil creates value by turning natural resources into energy for people and progress for society. Statoil will develop and maximise the value of its unique NCS position, its international oil and gas business and its growing new energy business, focusing on safety, cost and carbon efficiency. Statoil is a values-based company where empowered people collaborate to shape the future of energy.

To succeed in turning Statoil’s vision into reality, Statoil pursues a strategy to:

· Deepen and prolong the NCS position

· Grow material and profitable international positions

· Provide energy for a low-carbon future through growth in New Energy Solutions (NES)

· Focused and value-adding mid- and downstream

In addition, Statoil will research, develop, and deploy technology to create opportunities and enhance the value of Statoil’s current and future assets.

Deepen and prolong the NCS position

For more than 40 years, Statoil has explored, developed and produced oil and gas from the NCS. Statoil aims to deepen and prolong its position by accessing and maturing opportunities into valuable production. At the same time, Statoil plans to improve the reliability, efficiency and lifespan of fields already in production. The NCS represents approximately two thirds of Statoil’s equity production at 1,235 mboe per day in 2016.

10 Statoil, Annual Report on Form 20-F 2016

· Exploration: Statoil continues to be a committed NCS explorer across mature, growth and frontier areas. In 2016, Statoil participated in 14 exploration wells on the NCS, resulting in 11 discoveries. Statoil was awarded 29 licenses in mature areas in Norway’s Awards for Predefined Areas (APA) 2016 round (result announced January 2017), 16 as operator and 13 as non-operating partner, and five licenses in frontier areas in Norway’s 23rd concession round, four as operator and one as partner

· Development: The Johan Sverdrup Phase 1 project is progressing in line with schedule. Production drilling started in the first quarter of 2016. Pre-sanction for Johan Sverdrup Phase 2 is scheduled for the first quarter of 2017. Statoil increased its equity interest in the UK part of the Utgard license and submitted the Utgard Plan for Development and Operation (PDO) in the second quarter of 2016. The PDOs for Byrding and Trestakk were delivered and the PDO for Oseberg Vestflanken 2 was approved during 2016

· Production: Gullfaks Rimfaksdalen came on-stream. Production started at Fram C, tied into existing infrastructure in the Fram and Troll area

Statoil has completed two share transactions resulting in a 20.1 per cent equity ownership in Lundin Petroleum AB. Lundin is our partner in several fields, including a 22.6% interest in the unitised Johan Sverdrup field development. Statoil also acquired 25% of Byrding.

By the end of 2016, Statoil had achieved CO₂ emission reductions in excess of 1 million tonnes per year compared to a 2008 baseline on the NCS, primarily through better energy management and improved energy efficiency. Our 2020 target is to deliver 1.2 million tonnes of CO₂ emission reductions compared to 2008. In August 2016, the Norwegian petroleum industry announced its ambition to implement CO₂ reduction measures corresponding to 2.5 million tonnes on the NCS by 2030 compared to 2020. Statoil’s commitment is to deliver 2.0 million tonnes of this CO₂ reduction target.

Grow material and profitable international positions

International oil and gas production represented approximately one third of Statoil’s equity production at 744 mboe per day in 2016. Statoil will continue to explore, develop, and produce oil and gas opportunities outside Norway to enhance Statoil’s upstream portfolio.

· Exploration: Statoil continues to explore internationally for oil and gas. Statoil participated in nine exploration wells internationally, of which three were discoveries, including the Baccalieu discovery in Canada. Statoil added exploration acreage in Brazil, Canada, New Zealand, Russia, the UK and the US Gulf of Mexico, accessed exploration acreage in Ireland and Turkey and entered two new countries, Mexico and Uruguay. A joint venture comprising Statoil, BP and Total was awarded Blocks 1 and 3 in the Saline Basin in Mexico, with Statoil as the operator.

· Development: Statoil strengthened its strategic partnership with Petrobras in Brazil. Construction progress continued as planned on Peregrino Phase II

· Production: Heidelberg and Julia production came on-stream in the US Gulf of Mexico and, along with operator BP and other partners, significant advances have been made towards the award of a licence extension for Azeri-Chirag Guneshli (ACG) in Azerbaijan. The In Salah southern fields in Algeria and the Corrib field in Ireland both had major ramp-ups in 2016

In Brazil, Statoil acquired a 66% interest in and became the operator license of BM-S-8, which contains a substantial part of the Carcará field. Operatorship was assumed and appraisal activities began on BM-C-33. In the US, Statoil increased its stake in the Eagle Ford field and assumed full operatorship. Statoil continued to focus its portfolio with a partial divestment of non-core Marcellus acreage and agreeing the sale of its oil sands business in Canada.

Provide energy for a low-carbon future
Statoil recognises that opportunities are increasingly available in producing low carbon energy.

In 2016 Statoil launched Statoil Energy Ventures, a USD 200 million venture capital fund dedicated to investing in attractive and ambitious growth companies in renewable energy. This fund made its first investments in United Wind Inc. and later in ChargePoint Inc., Convergent Energy and Power Inc. and Oxford Photovoltaics Ltd., and is continuing to evaluate market opportunities. Statoil has also continued to explore new business opportunities in carbon capture and storage as well as other potential new energy markets.

· Development: The 402 MW Dudgeon Offshore Wind Park development started installation in the first quarter of 2016 and is expected to be fully commissioned by the fourth quarter of 2017

· Production: In 2016, Statoil signed a letter of intent to become operator of the Sheringham Shoal Offshore Wind Farm in January 2017; it currently produces from an installed capacity of 317 MW. Statoil has a 40% ownership stake of the Scira consortium which produces electricity from the Sheringham Shoal wind park

Statoil partnered with E.ON to develop the 385 MW Arkona wind farm offshore Germany, with start-up planned for 2019. In the US, Statoil was declared the provisional winner of the US government’s wind lease sale offshore New York, with a potential generation capacity of more than 1.8 GW.

Statoil will also start production from the world's first floating windfarm, Hywind Scotland, in the fourth quarter of 2017. Statoil's partner in the 30 MW project is Masdar, which acquired 25% of the project in January 2017. The project will also include an innovative battery storage solution, Batwind, which represents the company's first wind development with integrated energy storage.

Statoil, Annual Report on Form 20-F 2016 11

Statoil has delivered a feasibility study to the Norwegian government for part of a Norwegian carbon capture and storage (CCS) value chain. The scope has been to find commercial methods to inject CO₂ volumes arriving via ship into an underground reservoir on the NCS. Statoil’s long experience with CO₂ storage from Sleipner and Snøhvit has been valuable, finding commercial and technical means to store large volumes of third party CO₂ in order to accommodate the world’s need for CCS solutions.

Focused and value-adding mid- and downstream

The prime objective for Statoil’s mid- and downstream activities is to process and transport its oil and gas production (including the Norwegian State’s petroleum) competitively to premium markets, securing maximum value realisation. The main focus is on:

· Safe and efficient operations

· Continuous improvement in operational regularity, HSE and costs

· Flow assurance and marketing of Statoil’s equity production (crude oil, natural gas, related products) and the State’s Direct Financial Interest (SDFI) volumes for maximum value creation

· Utilisation of the Asset Backed Trading model across commodities to capture margin opportunities

· Maintaining Statoil’s position as a leading European gas supplier

· A capital lean asset structure

Strategic focus is directed at optimising the value of Statoil’s flexible Norwegian gas production assets that supply Europe and at Statoil’s midstream activities in North America, where Statoil’s onshore portfolio is developing. Statoil achieved strong marketing trading results across all commodities.

Research, development, and deployment of technology to unlock opportunities and enhance value
Statoil believes that technology is a critical success factor for value creation. Statoil’s technology development activities aim to increase access to new oil and gas resources at competitive cost, reduce field development, drilling and operating costs, and CO₂ and other greenhouse gas emissions. Statoil’s technology efforts focus on the following priority areas:

· Business-critical technologies: Upstream technologies are prioritised, primarily in the areas of Exploration, Reservoir, Drilling and Well, and Subsea Production Systems. Statoil’s main focus has been on cost reduction, for example Statoil’s simplified subsea production concept Cap-X^TMhas been developed to enable possible future development projects in the Barents Sea

· Strengthening Statoil’s licence to operate: Statoil has strengthened its commitment to sustainability. For the oil & gas and new energy value chains, technology development is concentrated on increased energy efficiency for power generation and reduced CO₂ emissions. For renewables, technological improvements to reduce cost in the areas of construction and maintenance for both fixed and floating offshore wind applications is a priority

· Expanding Statoil’s capabilities: Statoil continues its broader research efforts for both the oil and gas value chain and new value chains. Work is conducted both in-house and in collaboration with academia, research institutes and suppliers and through venture activities

· Capturing the value of digitalisation: Statoil is exploring the opportunities of digitalisation in the energy industry. In 2016, the focus has been determining the optimal approach to accelerate digitalisation to capture a greater value potential

At the capital markets update (CMU) on 7 February 2017, Statoil shared its sharpened strategy to respond to the changing business context. Geopolitical shifts, challenges in accessing new oil and gas resources, changing market dynamics, digitalisation and a global transition towards a low carbon economy are increasing uncertainty and volatility. This change in outlook drives the need to build a more resilient, diverse and option-rich portfolio, delivered by an agile organisation that embraces change and empowers its people. To deliver on the sharpened strategy and fulfill the strategic intent of “high value, low carbon”, Statoil will continue to build opportunities to optimise its portfolio around the following pillars:

· Norwegian continental shelf – Build on unique position to maximise and develop long-term value

· International Oil & Gas – Focus geographically to deepen core areas and develop growth options

· New Energy Solutions – Create a new material industrial position

· Midstream and Marketing – Secure market access and grow value creation through cycles

The following strategic principles guide Statoil in shaping a robust, balanced and distinct portfolio:

12 Statoil, Annual Report on Form 20-F 2016

1. Cash generation capacity

Generating positive cash flows from operations, even at low oil and gas prices, in order to sustain dividend and investment capacity through the cycle.

2. Capex flexibility

Having sufficient flexibility in organic capital expenditure to be able to respond to market downturns and avoid value destructive decisions.

3. Capture value from cycles

Ensuring the ability and capacity to act counter-cyclically to capture value through the cycles.

4. Low-carbon advantage

Maintaining competitive advantage as a leading company in carbon efficient oil and gas production, while building a low carbon business to capture new opportunities in the energy transition.

Group outlook

Statoil’s plans address the current environment while continuing to invest in high-quality projects. Statoil continues to reiterate its efforts and commitment to deliver on its priorities of high value creation, increased efficiency and competitive shareholder return.

· Organic capital expenditures for 2017 (i.e. excluding acquisitions, capital leases and other investments with significant different cash flow pattern) are estimated at around USD 11 billion

· Statoil intends to continue to mature its large portfolio of exploration assets and estimates a total exploration activity level of around USD 1.5 billion for 2017, excluding signature bonuses

· Statoil expects to achieve an additional USD 1 billion in efficiency improvements in 2017 for a total of USD 4.2 billion

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

· For the period 2016 – 2020, organic production growth is expected to come from new projects resulting in around 3% CAGR (Compound Annual Growth Rate)

· The equity production for 2017 is estimated to be around 4-5% above the 2016 level

· Scheduled maintenance activity is estimated to reduce quarterly production by approximately 10 mboe per day in the first quarter of 2017. In total, maintenance is estimated to reduce equity production by around 30 mboe per day for the full fiscal year 2017, which is lower than the 2016 impact

· Indicative effects from Production sharing agreements (PSA-effect) and US royalties are estimated to be around 150 mboe per day in 2017 based on an oil price of USD 40 per barrel and 165 mboe per day based on an oil price of USD 70 per barrel

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

Statoil, Annual Report on Form 20-F 2016 13

2.2 BUSINESS OVERVIEW

History

On 18 September 1972, Statoil was formed by a decision of the Norwegian parliament and incorporated as a limited liability company under the name Den norske stats oljeselskap AS. Being a company owned 100% by the Norwegian State, Statoil's initial role was to be the government's commercial instrument in the development of the oil and gas industry in Norway. Growing in parallel with the Norwegian oil and gas industry, Statoil’s operations have primarily been focused on exploration, development and production of oil and gas on the Norwegian continental shelf (NCS).

During the 1980s, Statoil grew substantially through the development of the NCS. Statoil also became a major player in the European gas market by entering into large sales contracts for the development and operation of gas transport systems and terminals. During the same decade, Statoil was involved in manufacturing and marketing in Scandinavia and established a comprehensive network of service stations. This line of business was fully divested in 2012.

In 2001, Statoil was listed on the Oslo and New York stock exchanges and became a public limited company under the name Statoil ASA, 67% majority owned by the Norwegian State. Since then, substantial investments both on the NCS and internationally, have grown our business. The merger with Hydro's oil and gas division on 1 October 2007 further strengthened Statoil’s ability to fully realise the potential of the NCS. Enhanced utilisation of expertise to design and manage operations in various environments have expanded our upstream activities outside our traditional area of offshore production. This includes the development of heavy oil and shale gas projects and projects that focus on other forms of energy, such as offshore wind and carbon capture and storage.

Activities

Statoil is an international energy company primarily engaged in oil and gas exploration and production activities, organised under the laws of Norway and subject to the provisions of the Norwegian Public Limited Liability Companies Act. In addition to being the leading operator on the Norwegian continental shelf (NCS), Statoil has also substantial international activities and is present in several of the most important oil and gas provinces in the world. Our activities span operations in more than 30 countries and employs approximately 20,500 employees worldwide.

Our access to crude oil in the form of equity, governmental and third party volumes makes Statoil a large seller of crude oil, and Statoil is the second-largest supplier of natural gas to the European market. Processing and refining are also part of our operations.

Statoil’s registered office is at Forusbeen 35, 4035 Stavanger, Norway and the telephone number of its registered office is +47 51 99 00 00.

Our competitive position

Key factors affecting competition in the oil and gas industry are oil and gas supply and demand, exploration and production costs, global production levels, alternative fuels, and environmental and governmental regulations. When acquiring assets and licences for exploration, development and production and in refining, marketing and trading of crude oil, natural gas and related products, Statoil competes with other integrated oil and gas companies.

Statoil's ability to remain competitive will depend, among other things, on continuous focus on reducing costs and improving efficiency. It will also depend on technological innovation to maintain long-term growth in reserves and production and the ability to seize opportunities in new areas.

The information about Statoil's competitive position in the strategic report is based on a number of sources; e.g. investment analyst reports, independent market studies, and our internal assessments of our market share based on publicly available information about the financial results and performance of market players.

Improvement programmes

Improvement programmes are Statoil’s response to the industrial challenge that has emerged over the recent years characterised by reducing prices for our products and declining returns. More specifically, the ambition is to realise positive production effects and capex and operating cost savings to improve financial results and cash-flows. For 2017 Statoil targets additional annual efficiency improvements of USD 1 billion on top of the already achieved USD 3.2 billon.

14 Statoil, Annual Report on Form 20-F 2016

CORPORATE STRUCTURE

Business areas

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

Development and Production Norway (DPN)

DPN manages Statoil’s upstream activities on the Norwegian continental shelf (NCS) and explores for and extracts crude oil, natural gas and natural gas liquids. The business area’s ambition is to continue Statoil’s leading position on the NCS and ensure maximum value creation through continuously improved HSE and operational performance.

Development and Production International (DPI)

DPI manages Statoil’s worldwide upstream activities that are not included in the DPN and Development and Production USA (DPUSA) business areas. It explores for and extracts crude oil, natural gas and natural gas liquids. DPI's ambition is to build a large and profitable international production portfolio comprising activities ranging from accessing new opportunities to delivering on profitable projects in a range of complex environments.

Development and Production United States (DPUSA)

DPUSA manages Statoil’s upstream activities in the USA and Mexico. DPUSA's ambition is to develop a material and profitable position in the US and Mexico, including the deep water regions of the Gulf of Mexico and unconventional oil and gas in the US.

Marketing, Midstream and Processing (MMP)

MMP manages Statoil’s marketing and trading activities related to oil products and natural gas, transportation, processing and manufacturing, and the development of oil and gas. MMP seeks to maximise value creation in Statoil's midstream and marketing business.

Technology, Projects and Drilling (TPD)

TPD is accountable for the global project portfolio, well deliveries, new technologies and sourcing across Statoil. TPD seeks to provide safe and secure, efficient and cost-competitive global well and project delivery, technological excellence, and research and development. Cost-competitive procurement is an important contributory factor for maximising value for Statoil.

Exploration (EXP)

EXP manages Statoil’s worldwide exploration activities with the aim of positioning Statoil as one of the leading global exploration companies and this is achieved through accessing high potential new acreage in priority basins, globally prioritising and drilling more significant wells in growth and frontier basins, delivering near-field exploration on the NCS and other select areas, and achieving step-change improvements in performance.

New Energy Solutions (NES)

NES reflects Statoil’s long-term goal to complement our oil and gas portfolio with profitable renewable energy and other low-carbon energy solutions. NES is responsible for wind farms, carbon capture and storage as well as other renewable energy and low-carbon energy solutions.

Global Strategy and Business Development (GSB)

GSB sets the corporate strategy, business development and merger and acquisition activities for Statoil. The ambition of the GSB business area is to closely link corporate strategy, business development and merger and acquisition activities to actively drive Statoil's corporate development.

Reporting segments

Statoil reports its business in the following reporting segments:

· DPN reporting segment - Development and Production Norway – the DPN business area

· DPI reporting segment - Development and Production International, which combines the DPI and the DPUSA business areas

· MMP reporting segment - Marketing, Midstream and Processing – the MMP business area

· Other – which includes activities in NES, TPD, GSB and Corporate staffs and support functions

Activities relating to the EXP business area are fully allocated to - and presented in - the relevant development and production reporting segment. Activities relating to the TPD and GSB business areas are partly allocated to - and presented in - the relevant development and production reporting segments.

Presentation

In the following sections in the report, the operations are reported according to the reporting segment. Underlying activities or business clusters are presented according to how the reporting segment organises its operations.

Statoil, Annual Report on Form 20-F 2016 15

See note 3 Segments to the Consolidated financial statements for further details.

As required by the SEC, Statoil prepares its disclosures about oil and gas reserves and certain other supplementary oil and gas disclosures based on geographic areas. Statoil’s geographical areas are defined by country and continent and consist of Norway, Eurasia excluding Norway, Africa, and the Americas.

SEGMENT REPORTING

Internal transactions in oil and gas volumes occur between our reporting segments before being sold in the market. The pricing policy for internal transfers is based on estimated market prices. See Production volumes and prices in section 2.8 Operating and financial performance for further information.

We eliminate intercompany sales when combining the results of reporting segments. Intercompany sales include transactions recorded in connection with our oil and natural gas production in the DPN or the DPI business areas and also in connection with the sale, transportation or refining of our oil and natural gas production in the MMP business area. Certain types of transportation costs are reported in both the MMP and the DPUSA business areas.

The DPN business area produces oil and natural gas which is sold internally to the MMP business area. A large share of the oil produced by the DPI and DPUSA business areas is also sold through the MMP business area. The remaining oil and gas from the DPI and the DPUSA business areas is sold directly in the market. For intercompany sales and purchases, Statoil has established a market-based transfer pricing methodology for the oil and natural gas that meets the requirements as to applicable laws and regulations.

In 2016, the average transfer price for natural gas was USD 3.42 per mmbtu. The average transfer price was USD 5.17 per mmbtu in 2015 and USD 6.55 in 2014. For oil sold from DPN to MMP, the transfer price is the applicable market-reflective price minus a cost recovery rate.

The following table shows certain financial information for the four reporting segments, including intercompany eliminations for each of the years in the three-year period ending 31 December 2016. For additional information please refer to note 3 Segments to the Consolidated financial statements.

16 Statoil, Annual Report on Form 20-F 2016

Segment performance		For the year ended 31 December
(in USD million)		2016	2015	2014

Development & Production Norway
Total revenues and other income		13,077	17,339	28,926
Net operating income		4,451	7,161	17,753
Non-current segment assets¹⁾		27,816	27,706	35,243

Development & Production International
Total revenues and other income		6,657	8,200	13,661
Net operating income		(4,352)	(8,729)	(2,703)
Non-current segment assets¹⁾		36,181	37,475	44,912

Marketing, Midstream and Processing
Total revenues and other income		44,979	58,106	95,171
Net operating income		623	2,931	2,608
Non-current segment assets¹⁾		4,450	5,588	6,234

Other
Total revenues and other income		39	354	118
Net operating income		(423)	(129)	(199)
Non-current segment assets¹⁾		352	690	688

Eliminations²⁾
Total revenues and other income		(18,880)	(24,357)	(38,612)
Net operating income		(219)	133	420
Non-current segment assets¹⁾		-	-	-

Statoil group
Total revenues and other income		45,873	59,642	99,264
Net operating income		80	1,366	17,878
Non-current segment assets¹⁾		68,799	71,458	87,077

1)	Deferred tax assets, pension assets, equity accounted investments and non-current financial assets are not allocated to segments.
2)	Includes elimination of inter-segment sales and related unrealised profits, mainly from the sale of crude oil and products. Inter-segment revenues are based upon estimated market prices.

Statoil, Annual Report on Form 20-F 2016 17

The following tables show total revenues by country.

2016 Total revenues and other income by country	Crude oil	Natural gas	Natural gal liquids	Refined products	Other	Total sales
(in USD million)	Crude oil	Natural gas	Natural gal liquids	Refined products	Other	Total sales

Norway	20,544	7,973	3,580	4,135	(497)	35,735
USA	3,073	957	455	1,110	867	6,463
Sweden	0	0	0	1,379	(53)	1,326
Denmark	0	0	0	1,518	14	1,532
Other	690	272	1	0	(27)	936

Total revenues (excluding net income (loss) from equity accounted investments and other income	24,307	9,202	4,036	8,142	305	45,993

2015 Total revenues and other income by country	Crude oil	Natural gas	Natural gas liquids	Refined products	Other	Total sales
(in USD million)	Crude oil	Natural gas	Natural gas liquids	Refined products	Other	Total sales

Norway	22,741	10,811	4,932	5,644	1,454	45,582
US	3,718	1,133	532	1,605	933	7,922
Sweden	0	0	0	1,762	115	1,877
Denmark	0	0	0	1,750	8	1,759
Other	1,347	446	17	0	722	2,532

Total revenues (excluding net income (loss) from equity accounted investments and other income	27,806	12,390	5,482	10,761	3,232	59,671

2014 Total revenues and other income by country	Crude oil	Natural gas	Natural gas liquids	Refined products	Other	Total sales
(in USD million)	Crude oil	Natural gas	Natural gas liquids	Refined products	Other	Total sales

Norway	40,899	12,817	8,799	8,718	2,864	74,096
US	7,933	2,212	643	2,379	1,351	14,518
Sweden	0	0	0	2,636	260	2,896
Denmark	0	0	0	3,050	37	3,087
Other	2,970	704	65	0	963	4,702

Total revenues (excluding net income (loss) from equity accounted investments and other income	51,803	15,732	9,506	16,782	5,475	99,299

RESEARCH AND DEVELOPMENT

Statoil is a technology-intensive company and research and development is an integral part of our strategy. Our technology strategy is about prioritising technology for value creation that enables us to achieve growth and access, and sets the direction for technology development and implementation for the future. Our focus is on low cost, low carbon solutions and re-using standardised technologies.

We continuously research, develop and deploy innovative technologies to create opportunities and enhance the value of Statoil’s current and future assets. Statoil’s technology development activities aim to reduce field development, drilling and operating costs, and CO₂and other greenhouse gas emissions. We utilise a range of tools for the development of new technologies:

· In-house research and development (R&D)

· Cooperation with academia and research institutes

· 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

Research and development expenditures were USD 298 million, USD 344 million and USD 476 million in 2016, 2015 and 2014, respectively.

18 Statoil, Annual Report on Form 20-F 2016

2.3 DPN - DEVELOPMENT AND PRODUCTION NORWAY

OVERVIEW

The Development and Production Norway (DPN) reporting segment is responsible for field development and operations on the Norwegian continental shelf (NCS) which includes the North Sea, the Norwegian Sea and the Barents Sea. DPN aims to ensure safe and efficient operations and to maximise the value potential from the NCS. For proved reserves development see Development of reserves in Proved oil and gas reserves in section 2.8 Operating and financial performance.

Key events and portfolio developments in 2016:

Statoil, Annual Report on Form 20-F 2016 19

· In January, Statoil announced the acquisition of 11.93% of the shares and votes in Lundin Petroleum AB (Lundin) for a total cash purchase price of SEK 4.6 billion (USD 0.5 billion), and in May, Statoil announced divestment of its entire 15% interest in Edvard Grieg for an increased shareholding in Lundin. The transaction also included divestment of a 9% interest in the Edvard Grieg oil pipeline and a 6% interest in the Utsira High gas pipeline, and in addition payment of cash consideration of USD 64 million to Lundin. Statoil now owns 20.1% of the shares in Lundin.

· On 1 March, the drilling of the first well of the Johan Sverdrup field development commenced.

· On 12 March, the Goliat field came on stream with Eni Norge as operator.

· In June, the plan for development and operation for Oseberg Vestflanken 2 was approved by the Ministry of Petroleum and Energy.

· In June, the Njord Future project was established to secure long-term production for both the Njord and Hyme fields. The Njord field was temporarily shut in, and both the Njord A and Njord B platforms were towed to shore.

· On 9 August, Statoil and its partners submitted the plan for development and operation for the Utgard gas and condensate discovery to the Norwegian and UK authorities. The plan for development and operation was approved on 17 January 2017.

· On 19 August, Statoil and its partners submitted the plan for development and operation of the Byrding oil and gas discovery. On 30 December, Statoil completed the acquisition of Wintershall’s 25% interest in Byrding, increasing Statoil’s interest to 70%. The plan for development and operation of the Byrding discovery was approved on 17 January 2017.

· Gullfaks Rimfaksdalen started production ahead of schedule on 24 August.

· Volve ceased production on 17 September.

· The plan for development and operation of the Trestakk discovery was submitted on 1 November.

· On 24 December, the Ivar Aasen field came on stream with Aker BP as operator.

Fields in production on the NCS

The following table shows DPN's average daily entitlement for the years ending 31 December 2016, 2015 and 2014.

Production level maintained by new fields and new wells from existing fields. See chapter "Fields under development on the NCS" for future production replacement.

	For the year ended 31 December
	2016			2015			2014
	Oil and NGL	Natural gas		Oil and NGL	Natural gas		Oil and NGL	Natural gas
Area production	mbbl/day	mmcm/day	mboe/day	mbbl/day	mmcm/day	mboe/day	mbbl/day	mmcm/day	mboe/day

Statoil operated fields	511	86	1,049	545	88	1,100	533	78	1,027
Partner operated fields	70	17	177	50	13	132	55	16	157
Equity accounted production	8	-	8	-	-	-	-	-	-

Total	589	103	1,235	595	101	1,232	588	95	1,184

20 Statoil, Annual Report on Form 20-F 2016

The following tables show the NCS production by fields in which Statoil was participating during the year ended 31 December 2016.

Field	Geographical area	Statoil's equity interest in %	On stream	Licence expiry date		Average daily production in 2016 mboe/day



Statoil operated fields
Troll Phase 1 (Gas)	The North Sea	30.58	1996	2030		159.4
Åsgard	The Norwegian Sea	34.57	1999	2027		93.1
Gullfaks	The North Sea	51.00	1986	2036		83.8
Oseberg	The North Sea	49.30	1988	2031		76.2
Kvitebjørn	The North Sea	39.55	2004	2031		63.3
Visund	The North Sea	53.20	1999	2034		59.8
Snøhvit	The Barents Sea	36.79	2007	2035		47.4
Statfjord Unit	The North Sea	44.34	1979	2026		44.8
Tyrihans	The Norwegian Sea	58.84	2009	2029		44.6
Sleipner Vest	The North Sea	58.35	1996	2028		42.5
Grane	The North Sea	36.61	2003	2030		41.5
Troll Phase 2 (Oil)	The North Sea	30.58	1995	2030		39.8
Gudrun	The North Sea	36.00	2014	2028		35.0
Snorre	The North Sea	33.28	1992	2018	¹⁾	32.8
Valemon	The North Sea	53.78	2015	2031		29.0
Kristin	The Norwegian Sea	55.30	2005	2033	²⁾	19.1
Mikkel	The Norwegian Sea	43.97	2003	2020	³⁾	17.4
Fram	The North Sea	45.00	2003	2024		16.8
Vigdis area	The North Sea	41.50	1997	2024		13.8
Morvin	The Norwegian Sea	64.00	2010	2027		11.6
Alve	The Norwegian Sea	85.00	2009	2029		10.5
Tordis area	The North Sea	41.50	1994	2024		10.3
Urd	The Norwegian Sea	63.95	2005	2026		10.1
Heidrun	The Norwegian Sea	13.04	1995	2024	⁴⁾	9.5
Sleipner Øst	The North Sea	59.60	1993	2028		9.4
Gungne	The North Sea	62.00	1996	2028		5.2
Norne	The Norwegian Sea	39.10	1997	2026		4.0
Volve	The North Sea	59.60	2008	2028		3.5
Veslefrikk	The North Sea	18.00	1989	2020	⁵⁾	2.7
Statfjord Nord	The North Sea	21.88	1995	2026		2.4
Hyme	The Norwegian Sea	35.00	2013	2014	⁶⁾	2.0
Njord	The Norwegian Sea	20.00	1997	2021	⁷⁾	1.4
Fram H Nord	The North Sea	49.20	2014	2024		1.4
Statfjord Øst	The North Sea	31.69	1994	2026	⁸⁾	1.3
Gimle	The North Sea	65.13	2006	2034	⁹⁾	1.2
Tune	The North Sea	50.00	2002	2032	¹⁰⁾	1.1
Sygna	The North Sea	30.71	2000	2026	¹¹⁾	0.9
Heimdal	The North Sea	29.44	1985	2021		0.7

Total Statoil operated fields						1,049.4

Statoil, Annual Report on Form 20-F 2016 21

Field	Geographical area	Statoil's equity interest in %	Operator	On stream	Licence expiry date		Average daily production in 2016 mboe/day



Partner Operated Fields
Ormen Lange	The Norwegian Sea	25.35	Shell	2007	2041	¹²⁾	73.9
Skarv	The Norwegian Sea	36.16	Aker BP ASA	2013	2033	¹³⁾	43.9
Goliat	The Barents Sea	35.00	Eni Norge AS	2016	2042		17.9
Ekofisk area	The North Sea	7.60	ConocoPhillips	1971	2028		13.6
Marulk	The North Sea	50.00	Eni Norge AS	2012	2025		11.6
Sigyn	The North Sea	60.00	ExxonMobil	2002	2022		5.9
Edvard Grieg	The North Sea	0.00	Lundin Norway AS	2015	2035	¹⁴⁾	4.8
Vilje	The North Sea	28.85	Aker BP ASA	2008	2021		4.1
Ringhorne Øst	The North Sea	14.82	ExxonMobil	2006	2030		1.4
Ivar Aasen	The North Sea	41.47	Aker BP ASA	2016	2029	¹⁵⁾	0.2
Enoch	The North Sea	11.78	Repsol Sinopec	2007	2018		0.1

Total Partner Operated Fields							177.3

Equity accounted production
Lundin Petroleum AB		20.10	Lundin Petroleum AB				8.1

Total Development and Production Norway (DPN) including share of equity accounted production							1,234.8

1) PL089 expires in 2024 and PL057 expires in 2018 (prolonged from 2016 to 2018).

2) PL134D expires in 2027 and PL199 expires in 2033.

3) PL092 expires in 2020 and PL121 expires in 2022.

4) PL095 expires in 2024 and PL124 expires in 2025.

5) PL052 expires in 2020 and PL053 in 2031.

6) PL348 expires in 2029.

7) PL107 expires in 2021 and PL132 expires in 2023.

8) PL037 expires in 2026 and PL089 expires in 2024.

9) PL120B expires in 2034 and PL050DS expires in 2023.

10) PL034 expires in 2020. PL053 expires in 2031 and PL190 in 2032.

11) PL037 expires in 2026 and PL089 expires in 2024.

12) PL209/250 expires in 2041 and PL208 expires in 2040.

13) PL212/262 expires in 2033 and PL159 expires in 2029.

14) From 1 January to 30 June 2016 Statoil owned a 15% interest in the Edvard Grieg field. On 30 June 2016 this interest was sold to Lundin. The Edvard Grieg swap agreement was a part of Statoil increasing the ownership in Lundin.

15) PL001B, PL452BS and PL242 expire in 2036. PL 338BS expire in 2029.

Main producing fields on
the NCS

Statoil operated fields

Troll is both the largest gas field on the NCS and a major oil field. The Troll field regions are connected to the Troll A, B and C platforms. Troll gas is mainly exported and produced at Troll A, while oil is mainly produced at Troll B and C. Fram and Fram H Nord are tie-ins to Troll C.

The Åsgard field includes the Åsgard A production and storage ship for oil, the Åsgard B semi-submersible floating production platform for gas, and the Åsgard C storage vessel for condensate. In 2015 Statoil started the world first subsea gas compressor train

22 Statoil, Annual Report on Form 20-F 2016

on Åsgard, and the second train was started in February 2016. Mikkel and Morvin are tie-ins to Åsgard. The Trestakk development will be a tie-in to Åsgard A with production start planned in 2019.

Gullfaks has been developed with three large concrete production platforms. Since production started on Gullfaks in 1986, several satellite fields have been developed with subsea wells that are remotely controlled from the Gullfaks A and C platforms.

The Oseberg area includes the Oseberg Field Centre, Oseberg C, Oseberg East and Oseberg South production platforms. Oil and gas from the satellites are transported to Oseberg Field Centre for processing and transportation.

Kvitebjørn is a gas and condensate field developed with an integrated accommodation, drilling and processing facility with a steel jacket.

Visund is an oil and gas field that includes a floating drilling, production and living quarter unit and two subsea templates.

Partner-operated fields

Ormen Lange operated by Shell, is a deepwater gas field in the Norwegian Sea. The well stream is transported to an onshore processing and export plant at Nyhamna.

Skarv is an oil and gas field located in the Norwegian Sea, with BP as operator. The field development includes a floating production, storage and offloading vessel (FPSO) and five subsea multi-well installations.

Goliat is the first oil field to be developed in the Barents Sea. The field is being developed by means of 22 subsea wells tied back to a circular floating production, storage and offloading vessel (FPSO). The oil is offloaded to shuttle tankers. The Goliat field is operated by Eni and started production 12 March 2016.

Ekofisk is operated by ConocoPhillips. It consists of the Ekofisk, Tor, Eldfisk and Embla fields. The Eldfisk II project delivered a new PDQ platform early 2015 that will serve as Eldfisk field center.

Marulk is operated by Eni. It is a gas- and condensate field developed as a tie-back to the Norne FPSO.

Ivar Aasen is an oil and gas field located in the North Sea. The development includes a fixed steel jacket with partial processing and living quarters tied in as a satellite to Edvard Grieg for further processing and export. The Ivar Aasen development is operated by Aker BP ASA and started production 24 December 2016.

Exploration on the NCS

Statoil holds exploration acreage and actively explores for new resources in all three regions on the NCS, the Norwegian Sea, the North Sea and the Barents Sea.

In 2016 Statoil was awarded five licences (four as operator) in the 23^rd concession round for frontier areas, 29 licences (16 as operator) in the Awards for Predefined Areas (APA) round 2016 for mature areas and completed several farm-in transactions with other companies, notably in the Barents Sea.

Throughout 2016, as part of the industry initiative Barents Sea Exploration Collaboration (BaSEC), Statoil have been preparing for a drilling campaign of five to seven wells in the Barents Sea that will commence in 2017,

In 2016 Statoil completed a six well appraisal campaign of the Krafla discovery in the North Sea and made five new discoveries. The campaign set a record in drilling efficiency, with the Beerenberg well taking only nine days from spud to reaching total depth of 2,694 meters below the seabed.

In 2016 Statoil and its partners completed 14 exploratory wells and made 11 discoveries in Norway. In 2017 Statoil expects to complete 16 to18 exploration wells on the NCS, with the Barents Sea campaign being at the core of the activity plan.

	Exploratory wells drilled¹⁾
	2016	2015	2014

North Sea
Statoil operated	9	11	11
Partner operated	2	3	7
Norwegian Sea
Statoil operated	2	5	0
Partner operated	0	1	1
Barents Sea
Statoil operated	0	0	9
Partner operated	1	1	1
Total (gross)	14	21	29

1) Wells completed during the year, including appraisals of earlier discoveries.

Statoil, Annual Report on Form 20-F 2016 23

Fields under development on the NCS

Statoil’s major development projects on the NCS as of 31 December 2016:

Johan Sverdrup (Statoil 40.03%, operator, with additional 4.54% indirect interest held through Lundin) is an oil discovery in the North Sea. A plan for development and operation was submitted in February 2015 and approved by the Norwegian authorities in August 2015. Phase 1 of the development will consist of 35 production and water injection wells and a field centre with four platforms: A living quarter platform, a wellhead platform with permanent drilling facility, a processing platform and a riser and utility platform. Crude oil will be exported to Mongstad through a 274 km long dedicated pipeline, and gas will be exported to the gas processing facility at Kårstø through a 156 km long pipeline via a subsea connection to the Statpipe pipeline. On 1 March 2016, the drilling of the first well of the Johan Sverdrup field development commenced. Production is expected to start in 2019.

Aasta Hansteen (Statoil 51%, operator) is a deep water gas discovery in the Norwegian Sea. The field development concept includes three subsea templates tied in to a floating processing unit with gas export through a new pipeline, Polarled, to Nyhamna and further exportation through the Langeled pipeline. The Aasta Hansteen processing unit can also serve as a hub for other potential discoveries in the area. On 9 January 2016, the living quarter was lifted onto the topside, which is under construction in South Korea. On 27 July 2016, the final megablock was lifted onto the substructure in South Korea. Production is expected to start in 2018.

Gina Krog (Statoil 58.7%, operator) is an oil and gas discovery in the North Sea. The field development concept includes a steel-jacket platform and a total of 15 wells. Oil will be exported via offshore loading from a floating storage unit. Due to the high condensate content, the rich gas will be exported via Sleipner, where it will be further processed. The development concept also includes gas injection in order to maximise the recovery factor for the field. On 20 July 2015, the drilling of the first well of the Gina Krog field development commenced, and the drilling operations continued in 2016. On 23 August 2016, all the topside modules had been lifted in place, and the Gina Krog platform was complete in the field. Production is expected to start in 2017.

The Utgard development (Statoil 38.44% interest in the Norwegian and 38% in the UK sector, operator) will include two wells in a standard subsea concept, with one drilling target on each side of the UK-Norwegian maritime border. Gas and condensate will be piped through a new pipeline to the Sleipner field for processing and further transportation to market. On 17 January 2017, the plan for development and operation and the field development plan were approved by Norwegian and UK authorities. Production is expected to start in 2019.

The Trestakk discovery (Statoil 59.1%, operator) will be developed with five wells, three producers and two injectors, to be tied in to the Åsgard A installation for processing, measurement and gas injection. On 1 November, 2016, Statoil, on behalf of the licensees, submitted the plan for development and operation. Production is expected to start in 2019.

Oseberg Vestflanken 2 (Statoil 49.3%, operator) is the development of the oil and gas structures Alfa, Gamma and Kappa. The well stream will be routed to the Oseberg field centre through a new pipeline. The plan for development and operation was approved by the Ministry of Petroleum and Energy in June, 2016. The discoveries will be developed using an unmanned wellhead platform. Production is expected to start in 2018.

Gullfaks C subsea compression (Statoil 51%, operator), an increased gas recovery project for the Gullfaks Sør Brent reservoir, includes the installation of a subsea compressor solution in the vicinity of the L/M template in order to prolong the gas production plateau at Gullfaks C and increase the recoverable reserves from the Gullfaks Sør Brent reservoir. The compressor is expected to come on stream in 2017.

Byrding (Statoil 70%, operator) will be developed as a subsea installation with one well drilled from an existing template on Fram H-Nord. On 17 January 2017, the Norwegian Ministry of Petroleum and Energy approved the plan for development and operation. Production is expected to start in 2017.

Troll B gas module (Statoil 30.58%, operator), a new gas module being installed to increase the processing capacity at Troll B, was sanctioned in September 2016, and is expected to be brought on stream in 2018.

24 Statoil, Annual Report on Form 20-F 2016

Martin Linge (Statoil 19%) is an oil and gas field operated by Total, near the British sector of the North Sea. The reservoir is complex with gas under high pressure and high temperatures. The development includes a fixed steel jacket platform with processing and export facilities, with electric power to be supplied from Kollsnes. The operator expects production to start in 2018.

Decommissioning on the NCS

Under the Petroleum Act, the Norwegian government has imposed strict procedures for removal and disposal of offshore oil and gas installations. The Convention for the Protection of the Marine Environment of the Northeast Atlantic (OSPAR) stipulates similar procedures.

Huldra ceased production in September 2014, after 13 years in production. The permanent plugging and abandonment of wells has been ongoing in 2016 with removal of topside facilities planned in 2019.

Volve ceased production in September 2016, after more than eight years in production. The permanent plugging of wells was finalised during 2016, and the removal of subsea templates is expected to be completed in 2017.

During 2016, there were permanent plugging and abandonment operations at Statfjord, Visund, Tune, Kristin and Heimdal. The partner-operated field Ekofisk also had ongoing removal and plugging activities.

For further information about decommissioning, see note 2 Significant accounting policies to the Consolidated financial statements.

Statoil, Annual Report on Form 20-F 2016 25

2.4 DPI - DEVELOPMENT AND PRODUCTION INTERNATIONAL

DPI overview

Statoil is present in several of the most important oil and gas provinces in the world. The Development and Production International (DPI) reporting segment covers all development and production of oil and gas outside the Norwegian continental shelf (NCS).

DPI is present in more than 20 countries and had production in 11 countries in 2016. DPI produced 38% of Statoil's total equity production of oil and gas in 2016. For information about proved reserves development see section 2.8 Proved oil and gas reserves.

The map shows the countries where DPI has activity.

Key events and portfolio developments in 2016 and early 2017:

· In January, the Heidelberg field achieved first oil. The field is located in the Green canyon area of the Gulf of Mexico with Anadarko as the operator. Discovery was made in 2009, and sanctioning took place in 2013

· Operations at the In Salah Southern Fields project in Algeria started in March

· In April, the Julia field achieved first oil, on time and under budget. Julia is located in the Walker Ridge area of the Gulf of Mexico near Jack and St Malo. ExxonMobil is the operator

· In May, Statoil divested its operated acreage in the Marcellus West Virginia to EQT Corporation for USD 407 million in cash. The transaction was completed in July

· In July, Statoil announced acquisition of Petrobras’ 66% operated interest in the offshore licence BM-S-8 in Brazil’s Santos Basin. This licence contains a substantial part of the Carcará pre-salt oil discovery. The transaction was completed in November

· The third processing train on the In Amenas field in Algeria, which was damaged in the January 2013 terrorist attack, restarted in July, and the In Amenas Gas Compression project came into operation in February 2017. The compression project has enabled increased production and thereby capacity to utilize all three trains

· In December, the drilling of the first well of the Mariner field development commenced

· In December, Statoil increased its ownership in the deep-water Vito discovery from 30.0% to 36.89%, after exercising pre-emption rights on the Freeport-McMoran sale to Anadarko. The field is located in the Mississippi Canyon area. A final investment decision is expected in 2018 with first production in 2021

· In December, on request of US authorities, Statoil has become operator of record for blocks MC941 and MC942 in the Gulf of Mexico following the bankruptcy of Bennu Oil & Gas LLC. With the bankruptcy proceedings still ongoing, the full implications for Statoil are still to be determined

· In 2016, Statoil completed transactions to increase its equity interest to 100% in the UK continental shelf licence (P312) of the Utgard field, which spans the UK-Norway maritime border. In March 2016, Statoil’s purchase of a 31% equity interest from Talisman Sinopec North Sea Limited was completed, and in June the purchase of a 45% operated equity share from JX Nippon was completed. In January 2017, the plan for development and operation for the Utgard field was approved by the Norwegian and UK authorities. For more information, see Fields under development on the NCS in section 2.3 DPN – Development and production Norway

· In December, Statoil signed an agreement to divest its 100% owned Kai Kos Dehseh (KKD) oil sands projects in the Canadian province of Alberta to Athabasca Oil Corporation. The transaction covers the producing Leismer demonstration plant and the undeveloped Corner project, along with a number of midstream contracts associated with Leismer’s production. Following this transaction, Statoil will no longer own or operate any oil sands assets. As part of the transaction, Statoil will own just below 20% of Athabasca’s shares, and this will be managed as a financial investment. The transaction was completed 31 January 2017. For more information about the transaction see note 4 Acquisitions and disposals to the Consolidated financial statements.

International production

Statoil's entitlement production outside Norway was about 32% of Statoil's total entitlement production in 2016.

The following table shows DPI's average daily entitlement production of liquids and natural gas for the years ending 31 December 2016, 2015 and 2014. Entitlement production volumes are Statoil’s share of the volumes distributed to the partners according to production sharing agreement (PSA) (see section 5.6 Terms and abbreviations). For US assets entitlement production is expressed net of royalty interests. For all other countries royalties paid in-cash are included in entitlement production and royalties payable in-kind are excluded.

	For the year ended 31 December
	2016			2015			2014
	Oil and NGL	Natural gas		Oil and NGL	Natural gas		Oil and NGL	Natural gas
Production area	mboe/day	mmcm/day	mboe/day	mboe/day	mmcm/day	mboe/day	mboe/day	mmcm/day	mboe/day

Americas	189	18	299	177	17	283	155	19	272
Africa	203	5	232	211	5	241	179	3	198
Eurasia	32	3	50	36	1	44	37	4	64
Equity accounted production	10	-	10	12	-	12	12	-	12
Total	435	25	592	436	23	580	383	26	546

Statoil, Annual Report on Form 20-F 2016 27

The table below provides information about the fields that contributed to production in 2016

Field		Country	Statoil's equity interest in %	Operator	On stream	Licence expiry date	Average daily equity production in 2016 mboe/day



Americas							341.5
Marcellus ¹⁾		US	Varies	Statoil/others	2008	HBP²⁾	119.7
Bakken ¹⁾		US	Varies	Statoil/others	2011	HBP²⁾	51.1
Eagle Ford ¹⁾		US	Varies	Statoil/others	2010	HBP²⁾	40.8
Peregrino		Brazil	60.00	Statoil	2011	2034	37.5
Leismer Demo		Canada	100.00	Statoil	2010	HBP²⁾	20.4
Tahiti		US	25.00	Chevron	2009	HBP²⁾	17.3
Caesar Tonga		US	23.55	Anadarko	2012	HBP²⁾	12.6
St. Malo		US	21.50	Chevron	2014	HBP²⁾	12.2
Jack		US	25.00	Chevron	2014	HBP²⁾	9.3
Hibernia/Hibernia Southern Extension³⁾		Canada	Varies	HMDC	1997	2027	8.9
Julia		US	50.00	ExxonMobil	2016	HBP²⁾	5.1
Terra Nova		Canada	15.00	Suncor	2002	2022	4.9
Heidelberg		US	12.00	Anadarko	2016	HBP²⁾	1.6

Africa							308.0
Block 17		Angola	23.33	Total	2001	2022-34⁴⁾	146.1
Agbami		Nigeria	20.21	Chevron	2008	2024	46.3
Block 15		Angola	13.33	ExxonMobil	2004	2026-32⁴⁾	42.1
In Salah		Algeria	31.85	Sonatrach/BP/Statoil	2004	2027	38.4
Block 31		Angola	13.33	BP	2012	2031	21.7
In Amenas		Algeria	45.90	Sonatrach/BP/Statoil	2006	2022	13.4

Eurasia							83.6
ACG		Azerbaijan	8.56	BP	1997	2024	53.9
Corrib		Ireland	36.50	Shell	2015	2031	17.6
Kharyaga		Russia	30.00	Zarubezhneft	1999	2032	9.4
Alba		UK	17.00	Chevron	1994	HBP²⁾	2.6
Jupiter		UK	30.00	ConocoPhillips	1995	HBP²⁾	0.2

Total Development and Production International (DPI)							733.0

Equity accounted production
Petrocedeño⁵⁾		Venezuela	9.68	Petrocedeño	2008	2033	10.3

Total Development and Production International (DPI) including share of equity accounted production							743.4

1)	Statoil’s actual equity interest can vary depending on wells and area.
2)	Held by Production (HBP): A company’s right to own and operate an oil and gas lease is perpetuated beyond its original primary term, as long thereafter as oil and gas is produced in paying quantities. In the case of Canada, in addition to continuing to be in production, other regulatory requirements must be met.
3)	Statoil's equity interests are 5.0% in Hibernia and 9.0% in Hibernia Southern Extension.
4)	Varies by field.
5)	Petrocedeño is a non-consolidated company and accounted for pursuant to the equity accounting method. It produces extra-heavy crude oil from the Junin area in the Orinoco Belt.

28 Statoil, Annual Report on Form 20-F 2016

Americas

Statoil has had strong growth in production and continues to optimize its portfolio within US shale since entering the first play in 2008. Statoil entered the Marcellus shale gas play, located in the Appalachian region in north east US, in 2008 through a partnership with Chesapeake Energy Corporation; Statoil has continued to optimize its North America onshore portfolio through acreage acquisition and divestments since 2008. In 2012, Statoil became an operator in the Marcellus through the purchase of additional acreage in the State of West Virginia and Ohio. The most recent divestments occurred in 2016 with divestment of West Virginia to EQT and Antero Resources. At the end of 2016, Statoil continues operatorship in the State of Ohio.

Statoil entered the Bakken tight oil play through the acquisition of Brigham Exploration Company in December 2011. Statoil's net acreage position in Bakken and Three Forks shale formation at the end of 2016 was 241,000 acres.

Statoil entered the Eagle Ford shale formation located in southwest Texas in 2010. In 2013, Statoil became operator for 50% of the Eagle Ford acreage. As part of a global transaction in December 2015 with Repsol, which acquired Talisman in May 2015, Statoil increased its working interest and took full operatorship of all of the assets in the Eagle Ford Shale. As a result, Statoil has a total working interest of 63%. Our joint venture partner, Repsol, continues to hold 37% working interest.

US gathering system

Statoil’s participates in gathering and facilities for initial processing of oil and gas in the Bakken, Eagle Ford and Marcellus assets in the US. This includes crude and natural gas gathering systems, fresh water supply systems, salt water disposal wells, oil and gas treatment and processing facilities to provide flow assurance for Statoil’s upstream production. Midstream assets in Bakken are owned and operated 100% by Statoil. In Eagle Ford, Statoil is the operator for 100% of the midstream assets outside of the Oak, Karnes, DeWitt and Bee (KDB) area with a working interest of 63%. In the KDB area of Eagle Ford, Statoil has an ownership interest of 25.2% in Edwards Lime Gathering LLC, which is operated by Energy Transfer Partners L.P. For Marcellus, Statoil has operated assets in Marcellus South in Monroe Country, Ohio while in the Marcellus non-operated areas both in the North and South, Statoil’s working interest ranges from 16.25% to 32.5% depending on gathering system and number of JV partners which include Williams Energy and Anadarko.

As of 1 January 2016 responsibility for the US gathering system has been transferred from MMP to DPI North America.

Statoil is positioned in the Gulf of Mexico for the following offshore developments:

The Tahiti oil field is located in the Green Canyon area and is produced through a floating spar facility. As of 31 December 2016, there were 12 production wells in operation, and additional wells will be phased in over time to fully develop the field.

The Caesar Tonga oil field is located in the Green Canyon area. As of 31 December 2016, there were seven producing wells tied back to the Anadarko-operated Constitution spar host, and additional production wells will be phased in over time.

The Jack and St. Malo oil fields are located in the Walker Ridge area. The fields are subsea tie-backs to the Chevron operated Walker Ridge Regional Host facility. First production was achieved in December 2014. As of 31 December 2016, there were three wells producing on Jack and six wells producing for St. Malo. Additional production wells will be phased in over time.

The Julia oil field is located in the Walker Ridge area of the Gulf of Mexico near Jack and St Malo. First oil was in April 2016 and two wells are currently online. Additional production wells are currently being drilled and completed and will come online in 2017.

The Heidelberg oil field is located in the Green Canyon area. First oil was on January 2016 and four wells are currently online.

Canada

Statoil has interests in the Jeanne d'Arc Basin offshore the province of Newfoundland and Labrador in the partner operated producing oil fields Terra Nova, Hibernia and Hibernia Southern Extension. In January 2017, Statoil completed the transaction to fully divest the 123,200 net acres of oil sands leases in Alberta which form the Kai Kos Dehseh project to Athabasca Oil Corporation.

Brazil

The Peregrino field is a heavy oil field located in the Campos Basin, about 85 kilometres off the coast of Rio de Janeiro. The field came on stream in 2011. The oil is produced from two wellhead platforms with drilling capability and it is processed on the Peregrino FPSO and offloaded to shuttle tankers. Statoil holds a 60% ownership interest in the field and is operator.

Africa

Angola

The deep water blocks 17, 15 and 31 contributed with 38% of Statoil’s equity liquid production outside Norway in 2016. Each block is governed by a PSA which sets out the rights and obligations of the participants, including mechanisms for sharing of the production with the Angolan state oil company Sonangol.

Statoil, Annual Report on Form 20-F 2016 29

Block 17 has production from four FPSOs; CLOV, Dalia, Girassol and Pazflor.

Block 15 has production from four FPSOs: Kizomba A, Kizomba B, Kizomba C-Mondo, and Kizomba C-Saxi Batuque.

Block 31 has production from the PSVM FPSO.

The FPSOs serve as production hubs and each receives oil from more than one field and a large number of wells. In 2016, new wells were added and set into production on all three blocks.

Nigeria

Statoil has a 20.2% interest in the Agbami deep water field which is located 110 km off the coast of the Central Niger Delta region. The field is developed with subsea wells connected to an FPSO. The Agbami field straddles the two licences OML 127 and OML 128 and is operated by Chevron under a Unit Agreement. Statoil has 53.85% interest in OML 128.

For information related to the Agbami redetermination process and the dispute between the Nigerian National Petroleum Corporation and the partners in Oil Mining Lease (OML) 128 concerning certain terms of the OML 128 Production Sharing Contract (PSC), see note 23 Other commitments and contingencies to the Consolidated financial statements.

Algeria

The In Salah onshore gas development is a joint operatorship between Sonatrach, BP and Statoil. The Northern fields have been operating since 2004, and the Southern fields project started production from two fields (Garet el Befinat and Hassi Moumene) in March 2016. The remaining two fields (Gour Mahmoud and In Salah) will start production in 2017. The Southern fields are tied back into the Northern fields’ existing facilities.

The In Amenas onshore development is a gas development which contains significant liquid volumes. The In Amenas infrastructure includes a gas treatment plant composed of three processing trains. The production facility is connected to the Sonatrach distribution system. The facilities are operated through a joint operatorship between Sonatrach, BP and Statoil. The third processing train, which was damaged in the January 2013 terrorist attack, restarted in July 2016. The In Amenas Gas Compression project, which was led by BP, came into operation in February 2017. The compressors will make it possible to reduce wellhead pressure and thereby increase production.

Separate PSAs including mechanisms for revenue sharing, govern the rights and obligations of the Parties and establish joint operatorships between Sonatrach, BP and Statoil for In Salah and In Amenas.

Eurasia

Production largely consists of the output from the Azeri-Chirag-Gunashli oil field in the Caspian Sea and the Corrib gas field off Ireland’s northwest coast, which has successfully ramped up production since its start up in December 2015. The cessation of production from Jupiter in the UK North Sea has been declared and the decommissioning of the wells started in fourth quarter of 2016.

International exploration

Statoil has reduced exploration drilling activity outside Norway in 2016 and prioritised new access efforts and prospect maturation to support an increased drilling activity in 2017 and onwards.

Brazil is one of Statoil’s core exploration areas, where in 2016 Statoil successfully completed an appraisal program in BM-C-33, which includes the Pao de Acucar, Seat and Gavea discoveries.

In Canada Statoil and its partners completed a 19-month drilling campaign in the Bay du Nord area, making two new oil discoveries, Baccalieu and Bay de Verde.

In 2016 Statoil secured a position in Turkey through a partnership with Valeura Energy Inc. in the Thrace region in the European north-western part of Turkey.

In December 2016, Mexico’s deepwater bidding round, Round 1.4, took place in Mexico City. A joint venture comprised of Statoil, BP and Total was awarded 2 licenses in Block 1 and Block 3 in the Saline Basin, with Statoil as the operator.

In 2016 Statoil and its partners completed nine exploratory wells and made three discoveries internationally. In 2017 Statoil’s international exploration drilling activity will comprise growth opportunities in basins where Statoil already is established with discoveries and producing fields, such as Canada, Brazil and the UK as well as new frontier opportunities like Suriname and Indonesia. Statoil expects to complete 12 to 14 exploration wells internationally in 2017.

30 Statoil, Annual Report on Form 20-F 2016

	Exploratory wells drilled¹⁾
	2016	2015	2014

Americas
Statoil operated	5	8	4
Partner operated	2	2	5
Africa
Statoil operated	0	3	7
Partner operated	0	3	4
Other regions
Statoil operated	0	2	2
Partner operated	2	0	1
Total (gross)	9	18	23

1) Wells completed during the year, including appraisals of earlier discoveries.

Fields under development internationally

This section covers all the sanctioned projects and selected pre-sanctioned projects.

Americas

US
The Stampede oil field is located in the Green Canyon area. The development includes a tension-leg platform (TLP) with downhole gas lift and water injection from start of production. Hess is the operator, and Statoil has a 25% working interest. Start of production is expected in 2018.

TVEX is an extension to Tahiti field, targeting shallower reservoirs above the existing main Tahiti reservoir, which is located in Green Canyon in Gulf of Mexico. Chevron is the operator, and Statoil has a 25% working interest. Start of production is expected in fourth quarter of 2018.

The Big Foot oil field is located in Walker Ridge area. The development includes a dry tree TLP with a drilling rig. Chevron is the operator, and Statoil has a 27.5% working interest. Start of production is expected in 2018. Initial plans called for production to start in late 2015, however, installation was halted and the TLP moved to sheltered waters following damage to subsea installation tendons in late May 2015

US Onshore operations use hydraulic fracturing to recover resources. Despite reduction in investment and activity level in recent years in shale plays Bakken, Eagle Ford and Marcellus, production growth continues. The increase in onshore production despite investment reduction is attributed to higher recovery per well due to enhanced completion and improved operational efficiency.

Canada

The Hebron field, operated by Exxon Mobil, is located in the Jeanne d'Arc basin offshore Newfoundland near the partner-operated producing fields Terra Nova, Hibernia and Hibernia Southern Extension. The Hebron field will be developed using a fixed gravity base structure (GBS) and first oil is expected in late 2017. The topside was constructed in Korea and was transported to Newfoundland during 2016, whereas the GBS was constructed in Newfoundland. The topside and GBS were successfully tested and mated in December 2016. Statoil working interest was reduced from 9.7% to 9.01% effective 1 January 2016 due to a redetermination process.

Statoil has made oil discoveries in the Flemish Pass offshore Newfoundland comprising the Bay du Nord project, and work is on-going to assess options for developing Bay du Nord. Statoil is the operator of Bay du Nord and holds a 65% working interest.

Brazil

Peregrino phase II (Statoil 60%, operator) includes the Peregrino South and Southwest discoveries. The development consists of one wellhead platform tied back to the existing floating production, storage and offloading vessel. In December 2014, Statoil approved the investment decision for the development of the second phase of the Peregrino oil field. Following a programme improving project economics, project execution started in April, 2016. In September 2016, the plan for development was formally approved by the Brazilian national agency of petroleum, natural gas and biofuels (ANP). Production is expected to start in late 2020.

Statoil, Annual Report on Form 20-F 2016 31

In November 2016, Statoil completed the acquisition of 66% operated share from Petrobras in licence BM-S-8 in the Santos basin. This licence contains a substantial part of the pre-salt discovery Carcará. Carcará straddles both BM-S-8 and open acreage to the north. The definition of the development concept and the subsequent development of licence are dependent on ownership of the open acreage. The open acreage is expected to be included in the licencing round in 2017.

In August 2016, Statoil took over the operatorship of licence BM-C-33 from Repsol Sinopec Brasil. Statoil has 35% equity interest in this licence which is located in the Campos basin. Work is on-going to assess options for developing the discoveries in the licence. For information regarding exploration activity in BM-C-33 see International exploration earlier in this section.

Africa

Tanzania

Statoil has made several large gas discoveries in Block 2 offshore Tanzania. Statoil is the operator of Block 2 and holds a 65% working interest. The licence is located in the Indian Ocean 100 km off the southern part of Tanzania. Work is on-going to assess options for developing the discoveries, including the construction of an onshore LNG plant jointly with the co-venturers in Blocks 1 and 4 which are operated by BG Tanzania (100% owned by Shell).

Eurasia
United Kingdom

Mariner (Statoil 65.11%, operator) is a heavy oil development in the UK, where Statoil is the operator. The field development concept includes a production, drilling and living quarter platform based on a steel jacket. Oil will be exported by offshore loading from a floating storage unit. The development concept includes a possible future subsea tie-in of Mariner East, a small heavy oil discovery. The Mariner B storage vessel arrived Scotland on 26 August 2016, after a two-month voyage from South Korea. On 1 December 2016, the drilling of the first well of the Mariner field development commenced. Production from Mariner is expected to start in 2018.

Bressay (Statoil 81.6%, operator) is also a heavy oil discovery. In February 2016, Statoil decided to pause the concept selection work on Bressay. The partnership has agreed an extension of the licence period until end 2019 with the UK Oil and Gas Authority (OGA).

32 Statoil, Annual Report on Form 20-F 2016

2.5 MMP - MARKETING, MIDSTREAM AND PROCESSING

MMP overview

The Marketing, Midstream and Processing (MMP) reporting segment is responsible for marketing, trading, processing and transporting of crude oil and condensate, natural gas, NGL and refined products, including operation of Statoil operated refineries, terminals and processing plants. In addition, MMP is responsible for developing transportation solutions for natural gas, liquids and crude oil from Statoil assets including pipelines, shipping, trucking and rail. The business activities are organised in the following business clusters: Marketing and Trading, Asset Management and Processing and Manufacturing.

Key events in 2016:

· Statoil had a strong increase in delivered sales of crude oil into Asia during 2016, based on West African equity production and shipping capability

· The South Riding Point Terminal in Grand Bahamas sustained damage in the hurricane Matthew in October and was closed to traffic for a period

· Major planned turnarounds at both Kalundborg and Mongstad refineries, Tjeldbergodden methanol plant and Gassled facilities

Marketing and Trading

The Marketing and Trading business cluster (MT) is responsible for the marketing, trading and transportation of all products from Statoil’s upstream, processing and refining business and for power and emissions trading.

MMP handles Statoil's own volumes, the Norwegian state's direct financial interest (SDFI) equity production of crude oil and NGL and third-party volumes, representing approximately 50% of all Norwegian liquids exports. MMP is also responsible for marketing SDFI’s gas together with Statoil’s own volumes and third party gas, representing approximately 70% of all Norwegian gas exports. See the Norwegian state’s participation and SDFI oil and gas marketing and sale in Applicable laws and regulations in section 2.7 Corporate.

Marketing and trading of gas and LNG

Statoil’s gas marketing and trading business is conducted from Norway and from offices in Belgium, the UK, Germany, the USA and Singapore.

Europe

The major export markets for gas from the NCS are Germany, France, the UK, Belgium, the Netherlands, Italy and Spain. LNG from the Snøhvit field, combined with third party LNG cargoes, allow Statoil to reach global gas markets. The major part of the gas is sold to counterparties through bi-lateral sales and the remaining volumes over the trading desk through all the main European trading hubs. The bi-lateral sales are mainly carried out with large industrial customers, power producers and local distribution companies. A few of Statoil’s long-term gas contracts contain contractual price review mechanisms that can be triggered by the buyer or seller at regular intervals, or under certain given circumstances.

Statoil is active on both physical and exchange markets such as the Intercontinental Exchange (ICE). Statoil expects to continue to optimise the market value of the gas through a mix of bi-lateral contracts and trading via its production, transportation systems and downstream assets.

USA

Statoil Natural Gas LLC (SNG), a wholly-owned subsidiary, has a gas marketing and trading organization in Stamford, Connecticut that markets natural gas to local distribution companies, industrial customers and power generators. SNG also markets equity production volumes from the Gulf of Mexico, Eagle Ford and Marcellus and transports some of the northern Marcellus production to New York City and to Niagara, providing access to the greater Toronto area.

In addition, SNG has long-term capacity contracts with Dominion Resources Inc., which owns the Cove Point LNG re-gasification terminal in Maryland. LNG is sourced from the Snøhvit LNG facility in Norway. Due to continuing low gas prices in the US, almost all of Statoil's LNG cargoes have been diverted away from the US and delivered into higher-priced markets in Europe, South-America and Asia.

Statoil, Annual Report on Form 20-F 2016 33

Marketing and trading of liquids

MMP is responsible for the sale of Statoil's and the SDFI’s crude oil and NGL, in addition to commercial optimisation of the refineries and terminals. The liquids marketing and trading business is conducted from Norway, UK, Singapore, US and Canada. The main crude oil market for Statoil is northwest Europe.

MMP also markets equity volumes from DPI assets located in Canada, US, Brazil, Angola, Nigeria, Algeria, Azerbaijan and UK, as well as third party volumes. Value is maximised through marketing, physical and financial trading and through optimisation of own and leased capacity such as refineries, processing, terminals, storages, pipelines, railcars and vessels.

Production plants

Statoil owns and is operator of the Mongstad refinery in Norway including the Mongstad Heat and Power Plant (MHPP). The refinery is a medium-sized refinery built in 1975, with a crude oil and condensate distillation capacity of 226,000 barrels per day. The refinery is directly linked to offshore fields through two crude oil pipelines, to the crude oil terminal at Sture and the gas processing plant at Kollsnes through an NGL/condensate pipeline, and to Kollsnes by a gas pipeline. MHPP produces heat and power from gas received from Kollsnes and from the refinery. It has capacity of approximately 280 megawatts of electric power and 350 megawatts of process heat.

Statoil has an ownership interest of 34% in Vestprosess, which transports and processes NGL and condensate. The Vestprosess pipeline connects the Kollsnes and Sture plants to Mongstad.

Statoil owns and is operator of the Kalundborg refinery in Denmark, which has a crude oil and condensate distillation capacity of 108,000 barrels per day. The refinery is connected via one gasoline and one gas oil pipeline to the terminal at Hedehusene near Copenhagen, and most of its products are sold locally.

Statoil has an ownership interest of 82% in the methanol plant at Tjeldbergodden. It receives natural gas from the Norwegian Sea through the Haltenpipe pipeline. In addition, Statoil holds a 50.9% ownership interest in the air separation unit Tjeldbergodden Luftgassfabrikk DA.

The following table shows operating statistics for the plants at Mongstad, Kalundborg and Tjeldbergodden.

		Throughput¹⁾			Distillation capacity²⁾			On stream factor %³⁾			Utilisation rate %⁴⁾
Refinery		2016	2015	2014	2016	2015	2014	2016	2015	2014	2016	2015	2014

Mongstad		9.8	11.9	9.2	9.3	9.3	9.3	94.4	97.6	93.4	93.9	93.4	90.0
Kalundborg		5.0	5.2	4.5	5.4	5.4	5.4	98.0	98.5	91.8	91.0	91.0	82.0
Tjeldbergodden		0.76	0.92	0.83	0.95	0.95	0.95	94.8	98.5	88.4	94.8	98.5	97.1

1)	Actual throughput of crude oils, condensates, NGL, feed and blendstock, measured in million tonnes. Higher than distillation capacity for Mongstad due to high volumes of fuel oil and NGL not going through the crude distillation unit. Higher than distillation capacity for Kalundborg, due to volumes of kero, naphta, gasoil and biodiesel-additive not going through the crude-/condensate units.
2)	Nominal crude oil and condensate distillation capacity, and methanol production capacity, measured in million tonnes.
3)	Composite reliability factor for all processing units, excluding turnarounds.
4)	Composite utilisation rate for all processing units, stream day utilisation.

Terminals and storage

Statoil has a 65% ownership interest in Mongstad crude oil terminal. Crude oil is landed at Mongstad through pipelines from the NCS and by crude tankers from the market. The Mongstad terminal has a storage capacity of 9.4 million barrels of crude oil.

The Sture crude oil terminal receives crude oil through pipelines from the North Sea. The terminal is part of the Oseberg Transportation System (Statoil interest 36.2%). The processing facilities at Sture stabilise Oseberg crude oil and recover LPG mix (propane and butane) and naphtha.

Statoil operates the South Riding Point Terminal, which is located on Grand Bahamas Island and consists of two shipping berths and ten storage tanks, with a storage capacity of 6.75 million barrels of crude oil. The terminal has facilities to blend crude oils, including heavy oils. The main damages suffered in the Matthew hurricane in October were related to the loading infrastructure at the Sea Island, and Berth 2 is still out of operation. Statoil is in the process of scoping the reconstruction.

Statoil UK holds one third share of the interests in the Aldbrough Gas Storage in UK, operated by SSE Hornsea Ltd.

34 Statoil, Annual Report on Form 20-F 2016

Statoil Deutschland Storage GmbH holds a 23.7% stake in the Etzel Gas Lager in the northern part of Germany which has a total of nineteen caverns and secures regularity for gas deliveries from the NCS.

Statoil UK holds a 27.3% stake in the Teesside terminal, which stabilises unstable oil from the Ekofisk area and several other Norwegian and UK fields and recovers NGL.

Pipelines

Statoil is a significant shipper in the NCS gas pipeline system. Most gas pipelines on the NCS that are accessed by third-party customers are owned by a single joint venture, Gassled, with regulated third-party access. The Gassled system is operated by the independent system operator Gassco AS, which is wholly owned by the Norwegian state. Statoil’s current ownership share in Gassled is 5%. See Gas sales and transportation from the NCS in section 2.7 Corporate for further information.

MMP is technical service provider (TSP) for the Kårstø and Kollsnes gas processing plants in accordance with the technical service agreement between Statoil and Gassco AS, included as Exhibit 4(a)(i) to Form 20-F. MMP also performs the TSP role for the larger share of the Gassco operated gas pipeline infrastructure.

In addition, MMP manages Statoil’s ownership in the following pipelines in the Norwegian gas transportation system: Oseberg oil transportation system, Grane oil pipeline, Kvitebjørn oil pipeline, Troll oil pipeline I and II, Edvard Grieg oil pipeline, Utsira High gas pipeline, Valemon rich gas pipeline, Haltenpipe, Norpipe and Mongstad gas pipeline.

Statoil Deutschland GmbH held a 30.8% stake in the Norddeutsche Erdgas Transversale (NETRA) overland gas transmission pipeline via Jordgas Transport GmbH, which was sold during 2016 to Open Grid Europe GmbH and Gasuni Deutschland Transport Services GmbH.

Polarled (Statoil 37.1%, operator) will secure a gas export pipeline for fields in the Norwegian Sea. The project is aligned with the Aasta Hansteen field development.

The Johan Sverdrup oil and gas export pipelines (Statoil 40.0%, operator) will provide export from the Johan Sverdrup field.

Statoil, Annual Report on Form 20-F 2016 35

2.6 OTHER GROUP

The Other reporting segment includes activities in New Energy Solutions (NES), Global Strategy and Business Development (GSB), Technology, Projects and Drilling (TPD) and corporate staffs and support functions.

New Energy Solutions (NES)

The NES business area reflects Statoil’s aspirations to gradually complement its oil and gas portfolio with profitable renewable energy and other low-carbon energy solutions. Offshore wind and carbon capture and storage have been key focus areas in 2016.

Key events in 2016:

· Acquisition of a 50% stake in the Arkona asset in the German part of the Baltic Sea

· Launch of Statoil Energy Venture Fund and 4 subsequent investments

· Agreement to increase UK presence through increasing owner share in the Dogger Bank projects

· Signed a letter of intent to take over as operator of the Sheringham Shoal wind farm in 2017

· Statoil has concluded a 25% farm down in the Hywind Scotland project

· Winner of US Government’s wind lease sale of 79,350 acres offshore New York

The Sheringham Shoal offshore wind farm (Statoil 40%, operator from 2017) located off the coast of Norfolk, UK, was formally opened in September 2012. The wind farm is in full production with 88 turbines and an installed capacity of 317 megawatt (MW). Following divestment in 2014, it is now owned 40% by Statkraft, a Norwegian wholly state-owned company, 40% by Statoil and 20% by the UK Green Investment Bank (GIB). The wind farm's annual production is approximately 1.1 terawatt hours (TWh) and it has the capacity to provide power to approximately 220,000 households. Statkraft and Statoil have signed a letter of intent that Statoil takes over as operator of Sheringham Shoal in 2017.

The Dudgeon offshore wind farm (Statoil 35%, operator) is located in the Greater Wash area off the English east coast, short distance from Sheringham Shoal. A final investment decision for the 402 MW project was made in July 2014. The wind farm is expected to produce 1.7 TWh yearly from 67 turbines, with the capacity to provide power for around 410,000 households. On 7 January 2017, the first turbine was energised. On 7 February 2017, the first turbine was set in production, delivering electric power to the UK national grid. The wind farm is expected to be in full operation in fourth quarter 2017.

The Dogger Bank area has a total consented capacity of 4.8 GW and is potentially the largest offshore wind farm development in the world. Statoil and Statkraft, together with RWE and SSE, are partners in the Forewind consortium, each with a 25% equity stake. In February and August 2015, the consortium received consent from the UK authorities for four projects, each with a capacity of 1200 MW. Statoil has recently signed an agreement to acquire Statkraft’s share in Dogger Bank, the final shareholding is pending, among other things, partner approval.

The Arkona offshore wind farm (Statoil 50%) is being developed in the German part of the Baltic Sea, and the operations and maintenance base will be located in Sassnitz on the island of Rügen. In April 2016, Statoil acquired a 50% share in AWE-Arkona-Windpark Entwicklungs-GmbH from E.ON Climate & Renewables. A final investment decision for the up to 385 MW project was made in April 2016. All main construction contracts have been awarded, and fabrication has started. The wind farm is expected to supply approximately 400,000 German households from 60 turbines, and to be in full operation in 2019.

The Hywind Scotland pilot wind park (Statoil 75%, operator) is a floating wind pilot park using the Hywind concept, developed and owned by Statoil. The project is located at Buchan Deep, approximately 25 km off Peterhead on the east coast of Scotland. Statoil will install 5 Siemens 6MW turbines, a total capacity of 30MW. Production is expected to be 0.14 TWh/year, powering around 20,000 households. The project was sanctioned in October 2015. The planned first deliveries to the grid are in fourth quarter 2017. This is the next step in Statoil’s strategy towards deployment of the first utility scale floating wind farms.

Statoil is the winner of the New York Wind Energy Area lease, following the December 2016 BOEM lease sale, with a winning bid of USD 42.5 million. The lease is 321 km², large enough to support one or more offshore wind developments with a total capacity of more than 1GW. The lease is located approximately 20 km directly south of Long Island. The project will be further matured during 2017.

Since 1996, Statoil has proven experience in carbon capture and storage (CCS) and has continued to develop competence through research engagement in the Technical Centre Mongstad (TCM) and offshore operations in Sleipner and Snøhvit. Statoil will seek to deploy our competence and experience in other CCS projects, continue to evaluate opportunities to reduce carbon dioxide emissions and explore carbon dioxide for enhanced oil recovery (EOR) possibilities. Statoil has on behalf of the Norwegian Ministry of Petroleum and Energy (MPE) performed a feasibility study for establishing a CO2 storage on the NCS. The MPE intends to issue a tender process at the end of this year for planning, construction and operation of such CO2 storage as a part of a full CCS value chain from three industrial sources in Norway.

36 Statoil, Annual Report on Form 20-F 2016

In February 2016, Statoil launched the Statoil Energy Ventures Fund, a new energy investment fund dedicated to investing in attractive and ambitious growth companies in low carbon energy, supporting Statoil’s strategy of growth in new energy solutions. The Statoil Energy Ventures Fund, will invest up to USD 200 million over a period of four to seven years. During 2016, the fund made four investments in four different segments. United Wind is a distributed wind generation company based in New York that offers to install wind turbines on small property owner's land in exchange for a 20-year lease arrangement. ChargePoint is the largest electric vehicle charging infrastructure company in the USA with plans to expand globally in light of the growth in electric vehicles sales. Convergent Energy & Power is a US based energy storage project developer that builds, finances, owns and operates storage projects on behalf of large utilities and commercial and industrial customers. Oxford PV is a third generation solar technology company based in Oxford, UK that is developing a perovskites material that has the potential to make a significant increase in the efficiency of silicon photovoltaic panels.

Global Strategy and Business Development (GSB)

The Global Strategy and Business Development (GSB) business area is Statoil’s functional centre for strategy and business development. GSB is responsible for Statoil’s global strategy processes and identifies and delivers inorganic business development opportunities, including corporate mergers and acquisitions. This is achieved through close collaboration across geographic locations and business areas. Statoil's strategy forms the basis for guiding the company’s business development focus.

GSB also hosts a number of corporate functions including Statoil’s Corporate Sustainability function, which is shaping the company’s strategic response to sustainability issues and reporting on Statoil’s sustainability performance.

Corporate staffs and support functions

Corporate Staffs and support functions comprise the non-operating activities supporting Statoil, and include headquarters and central functions that provide business support such as finance and control, corporate communication, safety, audit, legal services and people and organisation.

Technology, Projects and Drilling (TPD)

The business area Technology, Projects and Drilling (TPD) is responsible for the development and execution of projects, well deliveries, procurement, research and technology in Statoil.

The TPD organisation was restructured 1 January 2016 to reduce cost, increase efficiency and secure high quality execution. All project expertise was integrated in one Project development organisation (PRD), and all expertise within technology, research and innovation was integrated in one Research and technology organisation (R&T).

Research and Technology (R&T) delivers technical expertise to projects, business developments and assets. Further, R&T drives research, innovation and implementation of new technology across Statoil, to secure both short and long term business needs.

Project Development (PRD) develops and executes all major facility developments, modifications and field decommissioning.

Drilling and Well (D&W) provides cost efficient well deliveries and rig management, including expertise and support to drilling and well operations globally in Statoil.

Procurement and Supplier Relations (PSR) manages the supply chain, conducts all procurements and provides management of contracts in accordance with business needs.

Statoil, Annual Report on Form 20-F 2016 37

Project startups and completions 2016	Statoil's interest	Operator	Area	Type

Heidelberg	12.00%	Anadarko	Gulf of Mexico	Oil
Snorre A drilling facilities upgrade	33.28%	Statoil	North Sea	Improved oil recovery
Goliat	35.00%	Eni	Barents Sea	Oil and gas
In Salah Southern fields	31.85%	Sonatrach/BP/Statoil	Algeria	Gas
Julia	50.00%	ExxonMobil	Gulf of Mexico	Oil
Gullfaks Rimfaksdalen	51.00%	Statoil	North Sea	Oil
B11 removal	5.00%	Gassco¹⁾	North Sea	Field decommissioning
Ivar Aasen	41.47%	Aker BP	North Sea	Oil and gas
- held through Lundin	0.28%
1) Statoil is technical operator

Ongoing projects with expected startups and completions 2017-2020	Statoil's interest	Operator	Area	Type

Gina Krog	58.70%	Statoil	North Sea	Oil and gas
Gullfaks C subsea compression	51.00%	Statoil	North Sea	Improved gas recovery
Dudgeon offshore wind farm	35.00%	Statoil	North Sea, off English coast	Wind
Hywind Scotland pilot wind park	75.00%	Statoil	North Sea, off Scottish coast	Wind
Volve decommissioning	59.60%	Statoil	North Sea	Field decommissioning
Byrding	70.00%	Statoil	North Sea	Oil and associated gas
Hebron	9.01%	ExxonMobil	Newfoundland, Canada	Oil
Tahiti vertical expansion	25.00%	Chevron	Gulf of Mexico	Oil
Aasta Hansteen	51.00%	Statoil	Norwegian Sea	Gas
Polarled	37.10%	Statoil	Norwegian Sea	Gas export pipeline
Oseberg Vestflanken 2	49.30%	Statoil	North Sea	Oil and gas
Mariner	65.11%	Statoil	North Sea	Oil
Troll B gas module	30.58%	Statoil	North Sea	Increased processing capacity
Big Foot	27.50%	Chevron	Gulf of Mexico	Oil
Martin Linge	19.00%	Total	North Sea	Oil and gas
Stampede	25.00%	Hess	Gulf of Mexico	Oil
Arkona offshore wind farm	50.00%	E.ON	Baltic Sea, off German coast	Wind
Johan Sverdrup	40.03%	Statoil	North Sea	Oil and associated gas
- held through Lundin	4.54%
Johan Sverdrup export pipelines, JoSEPP	40.03%	Statoil	North Sea	Oil and gas export pipelines
- held through Lundin	4.54%
Utgard Norwegian sector	38.44%	Statoil	North Sea	Gas and condensate
UK sector	38.00%
Trestakk	59.10%	Statoil	North Sea	Oil and associated gas
Huldra decommissioning	19.87%	Statoil	North Sea	Field decommissioning
Peregrino phase II	60.00%	Statoil	Brazil	Oil

Startups beyond 2020
In our world-class portfolio, an additional 35-40 projects are in the early phase.

38 Statoil, Annual Report on Form 20-F 2016

2.7 CORPORATE

APPLICABLE LAWS AND REGULATIONS

Statoil operates in more than 30 countries and is exposed to, and committed to compliance with, a number of laws and regulations globally.

This article focuses primarily on Norwegian laws specific for Statoil`s core activities, taking into account that the majority of Statoil’s production is produced on the NCS, the ownership structure of the company and that Statoil is registered and has its headquarters in Norway.

Norwegian petroleum laws and licensing system

The principal laws governing Statoil’s petroleum activities in Norway are the Norwegian Petroleum Act and the Norwegian Petroleum Taxation Act.

Norway is not a member of the European Union (EU), but Norway is a member of the European Free Trade Association (EFTA). The EU and the EFTA Member States have entered into the Agreement on the European Economic Area, referred to as the EEA Agreement, which provides for the inclusion of EU legislation in the national law of the EFTA Member States (except Switzerland). Statoil’s business activities are subject to both the EFTA Convention and EU laws and regulations adopted pursuant to the EEA Agreement.

For further information about the jurisdictions in which Statoil operates, see sections 2.2 Business overview and 2.10 Risk review.

Under the Petroleum Act, the Norwegian Ministry of Petroleum and Energy (“MPE”) is responsible for resource management and for administering petroleum activities on the NCS. The main task of the MPE is to ensure that petroleum activities are conducted in accordance with the applicable legislation, the policies adopted by the Norwegian Parliament (the Storting) and relevant decisions of the Norwegian State.

The Storting's role in relation to major policy issues in the petroleum sector can affect Statoil in two ways: firstly, when the Norwegian State acts in its capacity as majority owner of Statoil shares and, secondly, when the Norwegian State acts in its capacity as regulator:

· The Norwegian State's shareholding in Statoil is managed by the Ministry of Petroleum and Energy. The Ministry of Petroleum and Energy will normally decide how the Norwegian State will vote on proposals submitted to general meetings of the shareholders. However, in certain exceptional cases, it may be necessary for the Norwegian State to seek approval from the Storting before voting on a certain proposal. This will normally be the case if Statoil issues additional shares and such issuance would significantly dilute the Norwegian State's holding, or if such issuance would require a capital contribution from the Norwegian State in excess of government mandates. A decision by the Norwegian State to vote against a proposal on Statoil’s part to issue additional shares would prevent Statoil from raising additional capital in this manner and could adversely affect Statoil’s ability to pursue business opportunities. For more information about the Norwegian State's ownership, see Risks related to state ownership in section 2.10 Risk review and Major shareholders in section 5.1 Shareholder information

· The Norwegian State exercises important regulatory powers over Statoil, as well as over other companies and corporations on the NCS. As part of its business, Statoil or the partnerships to which Statoil is a party, frequently need to apply for licences and other approval of various kinds from the Norwegian State. Although Statoil is majority-owned by the Norwegian State, it does not receive preferential treatment with respect to licences granted by or under any other regulatory rules enforced by the Norwegian State

The principal laws governing Statoil’s petroleum activities in Norway and on the NCS are the Norwegian Petroleum Act of 29 November 1996 (the "Petroleum Act") and the regulations issued thereunder, and the Norwegian Petroleum Taxation Act of 13 June 1975 (the "Petroleum Taxation Act"). The Petroleum Act sets out the principle that the Norwegian State is the owner of all subsea petroleum on the NCS, that exclusive right to resource management is vested in the Norwegian State and that the Norwegian State alone is authorised to award licences for petroleum activities as well as determine its terms. Licensees are required to submit a plan for development and operation (PDO) to the Ministry of Petroleum and Energy for approval. For fields of a certain size, the Storting has to accept the PDO before it is formally approved by the Ministry of Petroleum and Energy. Statoil is dependent on the Norwegian State for approval of its NCS exploration and development projects and its applications for production rates for individual fields.

Production licences are the most important type of licence awarded under the Petroleum Act and are normally awarded for an initial exploration period, which is typically six years, but which can be shorter. The maximum period is ten years. During this exploration period, the licensees must meet a specified work obligation set out in the licence. If the licensees fulfil the obligations set out in the initial license period, they are entitled to require that the licence be prolonged for a period specified at the time when the licence is awarded, typically 30 years.

Statoil, Annual Report on Form 20-F 2016 39

The terms of the production licences are decided by the Ministry of Petroleum and Energy. A production licence grants the holder an exclusive right to explore for and produce petroleum within a specified geographical area. The licensees become the owners of the petroleum produced from the field covered by the licence. Production licences are awarded to group of companies forming a joint venture at the Ministry’s discretion. The members of the joint venture are jointly and severally responsible to the Norwegian State for obligations arising from petroleum operations carried out under the licence. The Ministry of Petroleum and Energy decides the form of the joint operating agreements and accounting agreements.

The governing body of the joint venture is the management committee. In licences awarded since 1996 where the state's direct financial interest (SDFI) holds an interest, the Norwegian State, acting through Petoro AS, may veto decisions made by the joint venture management committee, which, in the opinion of the Norwegian State, would not be in compliance with the obligations of the licence with respect to the Norwegian State's exploitation policies or financial interests. This power of veto has never been used.

Interests in production licences may be transferred directly or indirectly subject to the consent of the Ministry of Petroleum and Energy and the approval of the Ministry of Finance of a corresponding tax treatment position. In most licences, there are no pre-emption rights in favour of the other licensees. However, the SDFI, or the Norwegian State, as appropriate, still holds pre-emption rights in all licences.

The day-to-day management of a field is the responsibility of an operator appointed by the Ministry of Petroleum and Energy. The operator is in practice always a member of the joint venture holding the production licence, although this is not legally required. The terms of engagement of the operator are set out in the joint operating agreement.

Licensees are required to submit a plan for development and operation (PDO) to the Ministry of Petroleum and Energy for approval. For fields of a certain size, the Storting has to accept the PDO before it is formally approved by the Ministry of Petroleum and Energy.

If important public interests are at stake, the Norwegian State may instruct Statoil and other licensees on the NCS to reduce the production of petroleum. The last time the Norwegian State instructed a reduction in oil production was in 2002.

A licence from the Ministry of Petroleum and Energy is also required in order to establish facilities for the transportation and utilisation of petroleum. Ownership of most facilities for the transportation and utilisation of petroleum in Norway and on the NCS is organised in the form of joint ventures. The participants' agreements are similar to the joint operating agreements.

Licensees are required to prepare a decommissioning plan before a production licence or a licence to establish and use facilities for the transportation and utilisation of petroleum expires or is relinquished, or the use of a facility ceases. On the basis of the decommissioning plan, the Ministry of Petroleum and Energy makes a decision as to the disposal of the facilities.

For an overview of Statoil’s activities and shares in Statoil’s production licences on the NCS, see section 2.5 Development and Production Norway (DPN).

Gas sales and transportation from the NCS

Statoil markets gas from the NCS on its own behalf and on the Norwegian State's behalf. Gas is transported through the Gassled pipeline network to customers in the UK and mainland Europe.

Most of Statoil’s and the Norwegian State's gas produced on the NCS is sold under gas contracts to customers in the European Union (EU), and changes in EU legislation may affect Statoil's marketing of gas.

The Norwegian gas transport system, consisting of the pipelines and terminals through which licensees on the NCS transport their gas, is owned by a joint venture called Gassled. The Norwegian Petroleum Act of 29 November 1996 and the pertaining Petroleum Regulation establish the basis for non- discriminatory third-party access to the Gassled transport system.

The tariffs for the use of capacity in the transport system are determined by applying a formula set out in separate tariff regulations stipulated by the Ministry of Petroleum and Energy. The tariffs are paid on the basis of booked capacity, not on the basis of the volumes actually transported.

For further information, see Pipelines in section 2.5 MMP – Marketing, Midstream and Processing.

The Norwegian State's participation

The Norwegian State's policy as a shareholder in Statoil has been and continues to be to ensure that petroleum activities create the highest possible value for the Norwegian State.

40 Statoil, Annual Report on Form 20-F 2016

In 1985, the Norwegian State established the State's direct financial interest (SDFI) through which the Norwegian State has direct participating interests in licences and petroleum facilities on the NCS. As a result, the Norwegian State holds interests in a number of licences and petroleum facilities in which Statoil also hold interests. Petoro AS, a company wholly owned by the Norwegian State, was formed in 2001 to manage the SDFI assets.

SDFI oil and gas marketing and sale

Statoil markets and sells the Norwegian State's oil and gas together with Statoil’s own production. The arrangement has been implemented by the Norwegian State.

At an extraordinary general meeting held on 25 May 2001, the Norwegian State, as sole shareholder, approved an instruction to Statoil setting out specific terms for the marketing and sale of the Norwegian State's oil and gas. This resolution is referred to as the Owner's instruction.

Statoil is obliged under the Owner's instruction to jointly market and sell the Norwegian State's oil and gas as well as Statoil’s own oil and gas. The overall objective of the marketing arrangement is to obtain the highest possible total value for Statoil’s oil and gas and the Norwegian State's oil and gas, and to ensure an equitable distribution of the total value creation between the Norwegian State and Statoil.

Withdrawal or amendment

· The Norwegian State may at any time utilise its position as majority shareholder of Statoil to withdraw or amend the marketing instruction

HSE regulation

Statoil’s petroleum operations are subject to extensive laws and regulations relating to health, safety and the environment (HSE).

With business operations in more than 30 countries, Statoil is subject to a wide variety of HSE laws and regulations concerning its products, operations and activities. Laws and regulations may be jurisdiction specific, but also international regulations, conventions or treaties, as well as EU directives and regulations, are relevant.

As a result of the Macondo incident, in 2011, the US Department of the Interior created two new agencies to administer operations and activities in the Gulf of Mexico - the Bureau of Safety and Environmental Enforcement (BSEE) and the Bureau of Offshore Energy Management (BOEM). The department also issued new regulations to address the respective roles of the new agencies. Application of these regulations has the potential to affect Statoil’s operations in the US. Similarly, the effects from implementing the EU offshore Safety Directive in EU-member states' legislation will affect operations in relevant EU member countries.

See also Risk factors in section 2.10 Risk review.

Taxation of Statoil

Statoil is subject to ordinary Norwegian corporate income tax and to a special petroleum tax relating to its offshore activities in Norway. Statoil’s profits, both from offshore oil and natural gas activities and from onshore activities, are subject to Norwegian corporate income tax. The standard corporate income tax rate has been reduced from 25% in 2016 to 24% in 2017. In addition, a special petroleum tax is levied on profits from petroleum production and pipeline transportation on the NCS. The special petroleum tax rate has been increased from 53% in 2016 to 54% in 2017. The special petroleum tax rate is applied to relevant income in addition to the standard income tax rate, resulting in a 78% marginal tax rate on income subject to the special petroleum tax. For further information, see note 9 Income taxes to the Consolidated financial statements.

Statoil's international petroleum activities are subject to tax pursuant to local legislation. Fiscal regulation of Statoil’s upstream operations is generally based on corporate income tax regimes and/or PSAs.

SUBSIDIARIES AND PROPERTIES

Significant subsidiaries

The following table shows significant subsidiaries and equity accounted companies directly held by Statoil ASA as of 31 December 2016.

Our voting interest in each company is equivalent to our equity interest.

Statoil, Annual Report on Form 20-F 2016 41

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 Refining Norway AS	100	Norway
Statoil Azerbaijan AS	100	Norway	Statoil Shah Deniz AS	100	Norway
Statoil BTC Finance AS	100	Norway	Statoil Sincor AS	100	Norway
Statoil Coordination Centre NV	100	Belgium	Statoil SP Gas AS	100	Norway
Statoil Danmark AS	100	Denmark	Statoil Tanzania AS	100	Norway
Statoil Deutschland GmbH	100	Germany	Statoil Technology Invest AS	100	Norway
Statoil do Brasil Ltda	100	Brazil	Statoil UK Ltd	100	United Kingdom
Statoil Exploration Ireland Ltd.	100	Ireland	Statoil Venezuela AS	100	Norway
Statoil Forsikring AS	100	Norway	Statoil Metanol ANS	82	Norway
Statoil Færøyene AS	100	Norway	Mongstad Terminal DA	65	Norway
Statoil Hassi Mouina AS	100	Norway	Tjeldbergodden Luftgassfabrikk DA	51	Norway
Statoil Indonesia Karama AS	100	Norway	Naturkraft AS	50	Norway
Statoil New Energy AS	100	Norway	Vestprosess DA	34	Norway
Statoil Nigeria AS	100	Norway	Lundin Petroleum AB	20	Sweden

42 Statoil, Annual Report on Form 20-F 2016

Property, plant and equipment

Statoil has interests in real estate in many countries throughout the world. However, no individual property is significant. The largest office buildings are the Statoil's head office located at Forusbeen 50, NO-4035, Stavanger, Norway which comprises approximately 135,000 square meters of office space, and the 65,500-square-metre office building located at Fornebu on the outskirts of Norway's capital Oslo. Both office buildings are leased.

For a description of our significant reserves and sources of oil and natural gas, see Proved oil and gas reserves in section 2.8 Operating and financial performance below, and note 27 Supplementary oil and gas information (unaudited) to the Consolidated financial statements. For a description of our operational refineries, terminals and processing plants, see section 2.5 MMP – Marketing, midstream and processing.

Related party transactions

See note 24 Related parties to the Consolidated financial statements for information concerning related parties.

Insurance

Statoil's insurance coverage includes deductibles that must be met prior to recovery. Statoil's external insurance is subject to caps, exclusions and limitations, and there is no assurance that such coverage will adequately protect Statoil against liability from all potential consequences and damages.

Statoil, Annual Report on Form 20-F 2016 43

2.8 OPERATING AND FINANCIAL PERFORMANCE

PROVED OIL AND GAS RESERVES

Proved oil and gas reserves were estimated to be 5,013 mmboe at year end 2016, compared to 5,060 mmboe at the end of 2015.

Statoil's proved reserves are estimated and presented in accordance with the Securities and Exchange Commission (SEC) Rule 4-10 (a) of Regulation S-X, revised as of January 2009, and relevant Compliance and Disclosure Interpretations (C&DI) and Staff Accounting Bulletins, as issued by the SEC staff. For additional information, see Proved oil and gas reserves in note 2 Significant accounting policies to the Consolidated financial statements. For further details on proved reserves, see also note 27 Supplementary oil and gas information (unaudited) in the Consolidated financial statements.

Changes in proved reserves estimates are most commonly the result of revisions of estimates due to observed production performance, extensions of proved areas through drilling activities or the inclusion of proved reserves in new discoveries through the sanctioning of new development projects. These are sources of additions to proved reserves that are the result of continuous business processes and can be expected to continue to add reserves in the future.

Proved reserves can also be added or subtracted through the acquisition or disposal of assets. Changes in proved reserves can also be due to factors outside management control, such as changes in oil and gas prices. Lower oil and gas prices normally allow less oil and gas to be recovered from the accumulations. However, for fields with PSAs and similar contracts, a reduced oil price may result in higher entitlement to the produced volume. These changes are included in the revisions category in the table below.

The principles for booking proved gas reserves are limited to contracted gas sales or gas with access to a robust gas market.

In Norway and the UK, Statoil recognises reserves as proved when a development plan is submitted, as there is reasonable certainty that such a plan will be approved by the regulatory authorities. Outside these territories, reserves are generally booked as proved when regulatory approval is received, or when such approval is imminent. Reserves from new discoveries, upward revisions of reserves and purchases of proved reserves are expected to contribute to maintaining proved reserves in future years. Undrilled well locations US onshore are generally booked as proved undeveloped reserves when a development plan has been adopted and the well locations are scheduled to be drilled within five years,

Approximately 91% of our proved reserves are located in OECD countries. Norway is by far the most important contributor in this category, followed by the United States (US), Canada and Ireland.

44 Statoil, Annual Report on Form 20-F 2016

Of Statoil's total proved reserves, 7% are related to PSAs in non-OECD countries such as Azerbaijan, Angola, Algeria, Nigeria, Libya and Russia. Other non-OECD reserves are related to concessions in Brazil and Venezuela, representing less than 2% of Statoil's total proved reserves. These are included in proved reserves in the Americas.

Significant changes in our proved reserves in 2016 were:

• Negative revisions due to lower commodity prices compared to last year, resulted in a reduction of approximately 60 million boe

• The negative revisions are more than offset by positive revisions due to better performance of producing fields, maturing of improved recovery projects, and reduced uncertainty due to further drilling and production experience. The net effect of the positive and negative revisions is an increase of 409 million boe in 2016. A significant part of these positive revisions are related to large, producing fields offshore Norway where production is declining less than previously assumed for the proved reserves due to continuous improvement activities

• Proved reserves from new discoveries have also been added through the sanctioning of new field development projects in 2016, Svale Nord, Trestakk and Utgard in Norway and Julia in US. The new projects added a total of 66 million boe. New discoveries with proved reserves booked in 2016 are all expected to start production within a period of five years

• The net effect of purchase and sale increased the reserves by 39 million boe in 2016

The 2016 entitlement production was 673 million boe, an increase of 1.6% compared to 2015.

Proved reserves as of 31 December 2016	Proved reserves
	Oil and Condensate	NGL	Natural Gas	Total oil and gas
	(mmboe)	(mmboe)	(bcf)	(mmboe)

Developed
Norway	543	213	9,223	2,399
Eurasia excluding Norway	43	-	188	76
Africa	200	10	171	240
Americas	320	53	1,002	552
Total Developed proved reserves	1,105	277	10,584	3,268

Undeveloped
Norway	689	76	3,628	1,411
Eurasia excluding Norway	28	-	-	28
Africa	22	6	110	47
Americas	190	14	316	260
Total Undeveloped proved reserves	928	95	4,054	1,746

Total proved reserves	2,033	372	14,637	5,013

Statoil, Annual Report on Form 20-F 2016 45

Proved reserves in Norway

A total of 3,811 million boe is recognised as proved reserves in 61 fields and field development projects on the NCS, representing 76% of Statoil's total proved reserves. Of these, 54 fields and field areas are currently in production, 35 of which are operated by Statoil. Three new field development projects added reserves categorised as extensions and discoveries during 2016, Svale Nord, Trestakk and Utgard. Production experience, further drilling and improved recovery on several of Statoil's producing fields in Norway also contributed positively to the revisions of the proved reserves in 2016.

The net effect of the transaction with Lundin Petroleum AB (Lundin), including sale of Statoil’s equity share in the Edvard Grieg field and acquisition of a 20.1% share in Lundin, results in an increase in Statoil’s proved reserves of 50 million boe. The volume corresponding to our relative share of Lundin’s share in fields carrying proved reserves is included as reserves in an equity accounted company.

Of the proved reserves on the NCS, 2,399 million boe, or 63%, are proved developed reserves. Of the total proved reserves in this area, 60% are gas reserves related to large offshore gas fields such as Troll, Snøhvit, Oseberg, Ormen Lange, Tyrihans, Visund, Aasta Hansteen and Åsgard and 40% are liquid reserves.

Proved reserves in Eurasia, excluding Norway

In this area, Statoil has proved reserves of 104 million boe related to three fields and field developments in Azerbaijan, Ireland and Russia. Eurasia excluding Norway represents 2% of Statoil's total proved reserves, Azerbaijan being the main contributor with the Azeri-Chirag-Gunashli fields. All fields are producing. Of the proved reserves in Eurasia, 76 million boe or 73% are proved developed reserves.

Of the total proved reserves in this area, 68% are liquid reserves and 32% are gas reserves.

46 Statoil, Annual Report on Form 20-F 2016

Proved reserves in Africa

Statoil recognises proved reserves of 287 million boe related to 28 fields and field developments in several West and North African countries, including Algeria, Angola, Libya and Nigeria. Africa represents 6% of Statoil's total proved reserves. Angola is the primary contributor to the proved reserves in this area, with 24 of the 28 fields.

In Angola, Statoil has proved reserves in Block 15, Block 17 and Block 31, with production from all three blocks.

In Algeria and Nigeria, all fields are in production. Murzuq and Mabruk did not have any production in 2016 due to the political unrest in Libya.

Statoil, Annual Report on Form 20-F 2016 47

Of the total proved reserves in Africa, 240 million boe, or 84%, are proved developed reserves. Of the total proved reserves in this area, 83% are liquid reserves and 17% are gas reserves.

Proved reserves in the Americas

In North and South America, Statoil has proved reserves equal to 812 million boe in a total of 18 fields and field development projects. This represents 16% of Statoil's total proved reserves. Eleven of these fields are located in the US, eight of which are offshore field developments in the Gulf of Mexico and three are onshore tight reservoir assets. Five are located in Canada and two in South America.

In the US, six of the eight fields in the Gulf of Mexico are producing. Field development is ongoing on Big Foot and Stampede. The onshore tight reservoir assets Marcellus, Eagle Ford and Bakken are all in production. In Canada, proved reserves are related both to offshore field developments, and to the Leismer field in the Kai Kos Dehseh oil sands project in Alberta. The effect of the divestment of the oil sands projects will be included in 2017.

Of the total proved reserves in the Americas, 552 million boe, or 68%, are proved developed reserves. Of the total proved reserves in this area, 71% are liquid reserves and 29% gas reserves.

48 Statoil, Annual Report on Form 20-F 2016

Reserves replacement

The reserves replacement ratio is defined as the sum of additions and revisions of proved reserves divided by produced volumes in any given period. The following table presents the changes in reserves in each category relating to the reserve replacement ratio for the years 2016, 2015 and 2014. For additional information regarding changes in proved reserves, see note 27 Supplemental oil and gas information (unaudited) to the Consolidated financial statements.

The usefulness of the reserves replacement ratio is limited by the volatility of oil prices, the influence of oil and gas prices on PSA reserve booking, sensitivity related to the timing of project sanctions and the time lag between exploration expenditure and the booking of reserves.

	For the year ended 31 December
Change in proved reseres (million boe)	2016	2015	2014

Revisions and improved recovery	409	(42)	356
Extensions and discoveries	179	627	253
Purchase of petroleum-in-place	65	13	20
Sales of petroleum-in-place	(27)	(235)	(233)

Total reserve additions	626	363	395
Production	(673)	(662)	(635)

Net change in proved reserves	(47)	(299)	(240)

	For the year ended 31 December
Reserves replacement ratio (including purchases and sales)	2016	2015	2014

Annual	0.93	0.55	0.62
Three-year-average	0.70	0.81	0.97

Development of reserves

In 2016, approximately 299 million boe were converted from undeveloped to developed proved reserves. The start-up of production from Ivar Aasen, Goliat, Gullfaks Rimfaksdalen and Svale Nord in Norway, together with Julia and Heidelberg in the US increased the proved developed reserves by 127 million boe during 2016. The remaining 172 million boe of the converted volume is related to development activities on producing fields. Over the last five years Statoil has converted 1,962 million boe of proved undeveloped reserves to proved developed reserves.

Statoil, Annual Report on Form 20-F 2016 49

Net proved reserves in million barrels oil equivalent	Total	Developed	Undeveloped

At 31 December 2015	5,060	3,515	1,546
Revisions and improved recovery	409	138	271
Extensions and discoveries	179	-	179
Purchase of reserves-in-place	65	2	63
Sales of reserves-in-place	(27)	(13)	(14)
Production	(673)	(673)	-
Moved from undeveloped to developed	-	299	(299)

At 31 December 2016	5,013	3,268	1,746

The new development projects added a total of 66 million boe of proved undeveloped reserves in 2016. Further drilling in the Bakken, Marcellus and Eagle Ford onshore plays in the US increased the proved area and added proved undeveloped reserves. These additions are categorized as extensions and together with extensions on other existing fields, this added a total of 112 million boe of proved undeveloped reserves. In total this adds up to an increase of 179 million boe from Extensions and discoveries.

Lower commodity prices had an effect on both undeveloped and developed reserves resulting in earlier economic cut-off. The negative revisions are more than offset by positive revisions based on new information available either from drilling of new wells or from production experience, resulting in an improved understanding of the fields. The net effect of revision of estimate on existing fields added 138 million boe proved developed reserves and 271 million boe proved undeveloped reserves.

The net effect of the purchase and sale transactions done in 2016, increased the proved undeveloped reserves by 49 million boe.

		Oil and Condensate	NGL	Natural gas	Total
		(mmboe)	(mmboe)	(bcf)	(mmboe)

2016	Proved reserves end of year	2,033	372	14,637	5,013
	Developed	1,105	277	10,584	3,268
	Undeveloped	928	95	4,054	1,746
2015	Proved reserves end of year	2,091	364	14,624	5,060
	Developed	1,104	290	11,901	3,515
	Undeveloped	987	74	2,723	1,546
2014	Proved reserves end of year	1,942	403	16,919	5,359
	Developed	1,156	310	12,677	3,725
	Undeveloped	786	93	4,242	1,635

As of 31 December 2016, the total proved undeveloped reserves amounted to 1,746 million boe, 81% of which are related to fields in Norway. The Troll and Snøhvit fields, which have continuous development activities, represent the largest undeveloped assets in Norway together with fields not yet in production, such as Johan Sverdrup, Aasta Hansteen and Gina Krogh. The largest assets with respect to proved undeveloped reserves outside Norway are Stampede, Marcellus and Bakken in the US.

All these fields are either producing, or will start production within the next five years. For fields with proved reserves where production has not yet started, investment decisions have already been sanctioned and investments in infrastructure and facilities have commenced. Some development activities will take place more than five years from the disclosure date, but these are mainly related to incremental type of spending, such as drilling of additional wells from existing facilities, in order to secure continued production. There are no material development projects, which would require a separate future investment decision by management, included in our proved reserves. For our onshore plays in the USA, Marcellus, Eagle Ford and Bakken, all proved undeveloped reserves are limited to wells that are scheduled to be drilled within five years.

In 2016, Statoil incurred USD 8,115 million in development costs relating to assets carrying proved reserves, USD 6,188 million of which was related to proved undeveloped reserves.

Additional information about proved oil and gas reserves is provided in note 27 Supplementary oil and gas information (unaudited) to the Consolidated financial statements.

Preparations of reserves estimates

Statoil's annual reporting process for proved reserves is coordinated by a central corporate reserves management (CRM) team consisting of qualified professionals in geosciences, reservoir and production technology and financial evaluation. The team has an

50 Statoil, Annual Report on Form 20-F 2016

average of more than 21 years' experience in the oil and gas industry. CRM reports to the senior vice president of finance and control in the Technology, Drilling and Projects business area and is thus independent of the Development & Production business areas in Norway, North America and International. All the reserves estimates have been prepared by Statoil's technical staff.

Although the CRM team reviews the information centrally, each asset team is responsible for ensuring that it is in compliance with the requirements of the SEC and Statoil's corporate standards. Information about proved oil and gas reserves, standardised measures of discounted net cash flows related to proved oil and gas reserves and other information related to proved oil and gas reserves, is collected from the local asset teams and checked by CRM for consistency and conformity with applicable standards. The final numbers for each asset are quality-controlled and approved by the responsible asset manager, before aggregation to the required reporting level by CRM.

The aggregated results are submitted for approval to the relevant business area management teams and the corporate executive committee.

The person with primary responsibility for overseeing the preparation of the reserves estimates is the manager of the CRM team. The person who presently holds this position has a bachelor's degree in earth sciences from the University of Gothenburg, and a master's degree in petroleum exploration and exploitation from Chalmers University of Technology in Gothenburg, Sweden. She has 31 years' experience in the oil and gas industry, 30 of them with Statoil. She is a member of the Society of Petroleum Engineering (SPE) and vice-chair of the UNECE Expert Group on Resource Classification (EGRC).

DeGolyer and MacNaughton report

Petroleum engineering consultants DeGolyer and MacNaughton have carried out an independent evaluation of Statoil's proved reserves as of 31 December 2016 using Statoil provided data. The evaluation accounts for 100% of Statoil's proved reserves. The aggregated net proved reserves estimates prepared by DeGolyer and MacNaughton do not differ materially from those prepared by Statoil when compared on the basis of net equivalent barrels.

	Oil and Condensate	NGL/LPG	Sales Gas	Oil Equivalent
Net proved reserves at 31 December 2016	(mmbbls)	(mmbbl)	(bcf)	(mmboe)

Estimated by Statoil	2,033	372	14,637	5,013
Estimated by DeGolyer and MacNaughton	2,244	324	13,685	5,007

A reserves audit report summarising this evaluation is included as Exhibit 15 (a)(iii).

Operational statistics

Developed and undeveloped acreage

The table below shows the total gross and net developed and undeveloped oil and gas acreage, in which Statoil had interests at 31 December 2016.

A gross value reflects wells or acreage in which Statoil has interests (presented as 100%). The net value corresponds to the sum of the fractional working interests owned in gross wells or acreages.

		Norway	Eurasia excluding Norway	Africa	Americas	Oceania 1)	Total
At 31 December 2016 (in thousands of acres)		Norway	Eurasia excluding Norway	Africa	Americas	Oceania 1)	Total

Developed and undeveloped oil and gas acreage
Acreage developed	- gross	915	90	823	845	-	2,673
	- net	339	21	267	240	-	868
Acreage undeveloped	- gross	12,485	40,593	17,922	32,665	18,125	121,789
	- net	5,127	18,275	7,420	13,425	9,052	53,299

1) Acreage in Australia

The largest concentrations of developed acreage in Norway are in the Troll, Skarv, Snøhvit, Oseberg area and Ormen Lange. In Africa, the Algerian gas development projects In Amenas and In Salah represent the largest concentrations of developed acreage (gross and net).

Statoil's largest undeveloped acreage concentration is in Russia with 16% of the total acreage and 48% of the total acreage in Eurasia excluding Norway. A large part of the net acreage in Russia represents Statoil’s share of a joint venture with Rosneft. The largest

Statoil, Annual Report on Form 20-F 2016 51

concentration of undeveloped acreage in the Americas is Canada, with 33% of the total for this geographic area. In Africa, the largest acreage concentration is in South Africa, representing 38% of the total for this geographic area. In Oceania Statoil holds undeveloped acreage in Australia and New Zealand.

Statoil holds acreage in numerous concessions, blocks and leases. The terms and conditions regarding expiration dates vary significantly from property to property. Work programs are designed to ensure that the exploration potential of any property is fully evaluated before expiration.

Acreage related to several of these concessions, blocks and leases are scheduled to expire within the next three years. Any acreage which has already been evaluated to be non-profitable may be relinquished prior to the current expiration date. In other cases, Statoil may decide to apply for an extension if more time is needed in order to fully evaluate the potential of the properties. Historically, Statoil has generally been successful in obtaining such extensions.

Most of the undeveloped acreage that will expire within the next three years is related to early exploration activities where no production is expected in the foreseeable future. The expiration of these leases, blocks and concessions will therefore not have any material impact on our reserves.

Productive oil and gas wells

The number of gross and net productive oil and gas wells, in which Statoil had interests at 31 December 2016, are shown in the table below.

		Norway	Eurasia excluding Norway	Africa	Americas	Total
At 31 December 2016		Norway	Eurasia excluding Norway	Africa	Americas	Total

Number of productive oil and gas wells
Oil wells	- gross	865	175	480	3,337	4,857
	- net	293.5	25.4	72.4	817.2	1,208.4
Gas wells	- gross	202	6	97	2,049	2,354
	- net	88.6	2.2	37.5	509.8	638.1

The total gross number of productive wells as of end 2016 includes 404 oil wells and 15 gas wells with multiple completions or wells with more than one branch.

Net productive and dry oil and gas wells drilled

The following tables show the net productive and dry exploratory and development oil and gas wells completed or abandoned by Statoil in the past three years. Productive wells include exploratory wells in which hydrocarbons were discovered, and where drilling or completion has been suspended pending further evaluation. A dry well is one found to be incapable of producing sufficient quantities to justify completion as an oil or gas well.

	Norway	Eurasia excluding Norway	Africa	Americas	Oceania	Total

Year 2016
Net productive and dry exploratory wells drilled	5.5	0.7	-	6.4	-	12.6
- Net dry exploratory wells drilled	1.4	0.7	-	1.9	-	3.9
- Net productive exploratory wells drilled	4.1	-	-	4.6	-	8.7

Net productive and dry development wells drilled	47.4	1.6	5.2	133.5	-	187.8
- Net dry development wells drilled	4.2	0.2	0.2	-	-	4.6
- Net productive development wells drilled	43.3	1.5	4.9	133.5	-	183.2

Year 2015
Net productive and dry exploratory wells drilled	10.2	1.0	2.5	2.6	-	16.3
- Net dry exploratory wells drilled	4.6	0.4	0.5	0.9	-	6.4
- Net productive exploratory wells drilled	5.6	0.7	2.0	1.7	-	9.9

Net productive and dry development wells drilled	32.1	4.1	10.6	228.8	-	275.6
- Net dry development wells drilled	3.6	-	4.3	0.3	-	8.2
- Net productive development wells drilled	28.6	4.1	6.3	228.5	-	267.4

Year 2014
Net productive and dry exploratory wells drilled	12.0	1.0	4.7	3.4	3.6	24.7
- Net dry exploratory wells drilled	3.4	1.0	2.7	1.6	3.6	12.2
- Net productive exploratory wells drilled	8.6	-	2.0	1.9	-	12.5

Net productive and dry development wells drilled	26.9	2.7	8.5	386.1	-	424.2
- Net dry development wells drilled	3.5	-	1.1	1.2	-	5.8
- Net productive development wells drilled	23.4	2.7	7.4	384.9	-	418.4

52 Statoil, Annual Report on Form 20-F 2016

Statoil, Annual Report on Form 20-F 2016 53

Exploratory and development drilling in process

The following table shows the number of exploratory and development oil and gas wells in the process of being drilled by Statoil at 31 December 2016.

		Norway	Eurasia excluding Norway	Africa	Americas	Total
At 31 December 2016		Norway	Eurasia excluding Norway	Africa	Americas	Total

Number of wells in progress
Development wells	- gross	52	8	16	355	431
	- net	18.6	0.9	3.6	113.7	136.8
Exploratory wells	- gross	3	-	-	1	4
	- net	1.6	-	-	0.2	1.8

Delivery commitments

On behalf of the Norwegian State's direct financial interest (SDFI), Statoil is responsible for managing, transporting and selling the Norwegian state's oil and gas from the Norwegian continental shelf (NCS). These reserves are sold in conjunction with Statoil's own reserves. As part of this arrangement, Statoil delivers gas to customers under various types of sales contracts. In order to meet the commitments, we utilize a field supply schedule that ensures the highest possible total value for Statoil and SDFI's joint portfolio of oil and gas.

The majority of our gas volumes in Norway are sold under long-term contracts with take-or-pay clauses. Statoil's and SDFI's annual delivery commitments under these agreements are expressed as the sum of the expected off-take under these contracts. As of 31 December 2016, the long-term commitments from NCS for the Statoil/SDFI arrangement totaled approximately 329 bcm.

Statoil and SDFI's delivery commitments, expressed as the sum of expected off-take for the calendar years 2017, 2018, 2019 and 2020, are 57.2, 44.6, 39.3 and 37.3 bcm, respectively. Any remaining volumes after covering our bilateral agreements, will be sold by trading activities at the hubs.

Statoil's currently developed gas reserves in Norway are more than sufficient to meet our share of these commitments for the next four years.

PRODUCTION VOLUMES AND PRICES

The business overview is in accordance with our segment's operations as of 31 December 2016, whereas certain disclosures on oil and gas reserves are based on geographical areas as required by the Securities and Exchange Commission (SEC). For further information about extractive activities, see sections 2.3 DPN - Development and Production Norway and 2.4 DPI - Development and Production International.

Statoil prepares its disclosures for oil and gas reserves and certain other supplemental oil and gas disclosures by geographical area, as required by the SEC. The geographical areas are defined by country and continent. They are Norway, Eurasia excluding Norway, Africa and the Americas.

For further information about disclosures concerning oil and gas reserves and certain other supplemental disclosures based on geographical areas as required by the SEC, see note 27 Supplementary Oil and Gas Information (unaudited) to the Consolidated financial statements.

Entitlement production

The following table shows Statoil's Norwegian and international entitlement production of oil and natural gas for the periods indicated. The stated production volumes are the volumes to which Statoil is entitled, pursuant to conditions laid down in licence agreements and production-sharing agreements. The production volumes are net of royalty oil paid in kind, and of gas used for fuel and flaring. Our production is based on our proportionate participation in fields with multiple owners and does not include production of the Norwegian State's oil and natural gas. Production of an immaterial quantity of bitumen is included as oil production. NGL includes both LPG and naphtha. For further information on production volumes see section 5.6 Terms and abbreviations.

54 Statoil, Annual Report on Form 20-F 2016

	Consolidated companies					Equity accounted
	Norway	Eurasia excluding Norway	Africa	Americas	Subtotal	Norway	Eurasia excluding Norway	Americas	Subtotal	Total

Oil and Condensate (mmbbls)
2014	173	14	64	51	301	-	-	4	4	306
2015	174	13	75	57	319	-	-	4	4	324
2016	169	12	72	60	313	2	0	4	6	320

NGL (mmbbls)
2014	42	-	2	7	51	-	-	-	-	51
2015	44	-	3	7	54	-	-	-	-	54
2016	46	-	2	9	58	0	-	-	0	58

Natural gas (bcf)
2014	1,229	56	38	242	1,565	-	-	-	-	1,565
2015	1,306	16	63	215	1,600	-	-	-	-	1,600
2016	1,338	34	60	227	1,659	1	0	-	2	1,661

Combined oil, condensate, NGL and gas (mmboe)
2014	434	24	72	102	631	-	-	4	4	635
2015	450	16	88	103	658	-	-	4	4	662
2016	454	18	85	110	666	3	0	4	7	673

The only field containing more than 15% of total proved reserves based on oil equivalent barrels is the Troll field.

Entitlement production								2016	2015	2014

Troll field ¹⁾
Oil and Condensate (mmbbls)								15	14	14
NGL (mmbbls)								2	2	2
Natural gas (bcf)								321	386	317
Combined oil, condensate, NGL and gas (mmboe)								74	85	73

1) Note that Troll is also included in Norway stated above.

Statoil, Annual Report on Form 20-F 2016 55

	For the year ended 31 December
Operational data	2016	2015	2014	16-15 change	15-14 change

Prices
Average Brent oil price (USD/bbl)	43.7	52.4	98.9	(17%)	(47%)
Development and Production Norway average liquids price (USD/bbl)	39.4	48.2	90.6	(18%)	(47%)
Development and Production International average liquids price (USD/bbl)	35.8	42.9	85.6	(17%)	(50%)
Group average liquids price (USD/bbl)	37.8	45.9	88.6	(18%)	(48%)
Group average liquids price (NOK/bbl)	317	371	559	(14%)	(34%)
Transfer price natural gas (USD/mmbtu)	3.42	5.17	6.55	(34%)	(21%)
Average invoiced gas prices - Europe (USD/mmbtu)	5.17	7.08	9.54	(27%)	(26%)
Average invoiced gas prices - North America (USD/mmbtu)	2.13	2.62	4.39	(19%)	(40%)
Refining reference margin (USD/bbl)	4.8	8.0	4.7	(40%)	70%

Entitlement production (mboe per day)
Development and Production Norway entitlement liquids production	589	595	588	(1%)	1%
Development and Production International entitlement liquids production	435	436	383	(0%)	14%
Group entitlement liquids production	1,024	1,032	971	(1%)	6%
Development and Production Norway entitlement gas production	646	637	595	1%	7%
Development and Production International entitlement gas production	157	144	163	9%	(12%)
Group entitlement gas production	803	781	758	3%	3%
Total entitlement liquids and gas production	1,827	1,812	1,729	1%	5%

Equity production (mboe per day)
Development and Production Norway equity liquids production	589	595	588	(1%)	1%
Development and Production International equity liquids production	555	569	538	(2%)	6%
Group equity liquids production	1,144	1,165	1,127	(2%)	3%
Development and Production Norway equity gas production	646	637	595	1%	7%
Development and Production International equity gas production	188	170	205	11%	(17%)
Group equity gas production	834	806	801	3%	1%
Total equity liquids and gas production	1,978	1,971	1,927	0%	2%

Liftings (mboe per day)
Liquids liftings	1017	1,035	967	(2%)	7%
Gas liftings	824	802	779	3%	3%
Total liquids and gas liftings	1842	1,837	1,746	0%	5%

Marketing, Midstream and Processing sales volumes
Crude oil sales volumes (mmbl)	811	829	811	(2%)	2%
Natural gas sales Statoil entitlement (bcm)	44.3	44.0	43.1	1%	2%
Natural gas sales third-party volumes (bcm)	8.6	8.6	8.1	0%	6%

Production cost (USD/boe)
Production cost entitlement volumes	5.4	6.5	8.5	(17%)	(24%)
Production cost equity volumes	5.0	5.9	7.6	(17%)	(22%)

56 Statoil, Annual Report on Form 20-F 2016

Sales prices

The following tables present realised sales prices.

	Norway	Eurasia excluding Norway	Africa	Americas

Year ended 31 December 2016
Average sales price oil and condensate in USD per bbl	43.1	42.0	41.4	32.9
Average sales price NGL in USD per bbl	24.4	-	21.9	13.1
Average sales price natural gas in USD per mmbtu	5.2	4.8	4.0	2.1

Year ended 31 December 2015
Average sales price oil and condensate in USD per bbl	52.2	50.7	49.4	39.4
Average sales price NGL in USD per bbl	30.1	-	26.2	12.5
Average sales price natural gas in USD per mmbtu	7.1	4.6	5.6	2.6

Year ended 31 December 2014
Average sales price oil and condensate in USD per bbl	98.3	101.3	95.6	78.3
Average sales price NGL in USD per bbl	59.3	-	59.7	37.3
Average sales price natural gas in USD per mmbtu	9.5	5.4	9.2	4.4

Statoil, Annual Report on Form 20-F 2016 57

Sales volumes

Sales volumes include lifted entitlement volumes, the sale of SDFI volumes and marketing of third-party volumes. In addition to Statoil’s own volumes, we market and sell oil and gas owned by the Norwegian State through the Norwegian State's share in production licences. This is known as the State's Direct Financial Interest or SDFI. For additional information, see section SDFI oil and gas marketing and sale in Applicable laws and regulations in section 2.7 Corporate. The following table shows the SDFI and Statoil sales volume information on crude oil and natural gas for the periods indicated. The Statoil natural gas sales volumes include equity volumes sold by the MMP segment, natural gas volumes sold by the DPI segment and ethane volumes.

		For the year ended 31 December
Sales Volumes		2016	2015	2014

Statoil:¹⁾
Crude oil (mmbbls)²⁾		372	378	353
Natural gas (bcm)		48	47	45

Combined oil and gas (mmboe)		674	671	637

Third party volumes:³⁾
Crude oil (mmbbls)²⁾		294	290	304
Natural gas (bcm)		9	9	8

Combined oil and gas (mmboe)		348	344	355

SDFI assets owned by the Norwegian State:⁴⁾
Crude oil (mmbbls)²⁾		148	149	148
Natural gas (bcm)		40	42	37

Combined oil and gas (mmboe)		398	412	379

Total:
Crude oil (mmbbls)²⁾		814	816	805
Natural gas (bcm)		96	97	90

Combined oil and gas (mmboe)		1,420	1,427	1,371

1)	The Statoil volumes included in the table above are based on the assumption that volumes sold were equal to lifted volumes in the relevant year. Volumes lifted by DPI but not sold by MMP, and volumes lifted by DPN or DPI and still in inventory or in transit may cause these volumes to differ from the sales volumes reported elsewhere in this report by MMP.
2)	Sales volumes of crude oil include NGL and condensate. All sales volumes reported in the table above include internal deliveries to our manufacturing facilities.
3)	Third party volumes of crude oil include both volumes purchased from partners in our upstream operations and other cargos purchased in the market. The third party volumes are purchased either for sale to third parties or for our own use. Third party volumes of natural gas include third party LNG volumes related to our activities at the Cove Point regasification terminal in the US.
4)	SDFI volumes in columns 2015 and 2014 are updated to reflect total sales volumes natural gas (bcm). Previously third party volumes sold from storage were excluded.

58 Statoil, Annual Report on Form 20-F 2016

FINANCIAL REVIEW – GROUP PROFIT AND LOSS ANALYSIS

Our results over the last years have been heavily influenced by the drop in prices, leading to lower earnings and impairment losses, while at the same time achievements from our improvement programme affected earnings positively.

Total equity liquids and gas production was 1,978 mboe, 1,971 mboe, 1,927 mboe per day in 2016, 2015 and 2014, respectively.

From 2015 to 2016, the average daily total equity production level was maintained. Increased production from new fields coming on stream, ramp-up on various existing fields and high operational performance, was offset by reduced ownership shares as a result of divestments, expected natural decline at mature fields and operational challenges. The 2% increase in total equity production from 2014 to 2015 was primarily due to start-up and ramp-up on various fields and higher gas sales from the NCS, partially offset by expected natural decline and divestments and redeterminations.

Total entitlement liquids and gas production was 1,827 mboe per day in 2016 compared to 1,812 mboe in 2015 and 1,729 mboe per day in 2014. The total entitlement production in 2016 was up 1% and the development was almost flat for the same reasons as described above. The benefit of a lower effect from production sharing agreements (PSA effect) mainly driven by the reduction in prices, added to the slight increase in entitlement production. From 2014 to 2015, entitlement production was up 5% for the same reasons as described above and the benefit from lower PSA effects.

The PSA effect was 109 mboe, 116 mboe and 157 mboe per day in 2016, 2015 and 2014, respectively. Over time, the volumes lifted and sold will equal the entitlement production, but they may be higher or lower in any period due to differences between the capacity and timing of the vessels lifting our volumes and the actual entitlement production during the period.

Income statement under IFRS	For the year ended 31 December
(in USD million)	2016	2015	2014	16-15 change	15-14 change

Revenues	45,688	57,900	96,708	(21%)	(40%)
Net income from equity accounted investments	(119)	(29)	(34)	>(100%)	17%
Other income	304	1,770	2,590	(83%)	(32%)

Total revenues and other income	45,873	59,642	99,264	(23%)	(40%)

Purchases [net of inventory variation]	(21,505)	(26,254)	(47,980)	(18%)	(45%)
Operating expenses and selling, general and administrative expenses	(9,787)	(11,433)	(12,815)	(14%)	(11%)
Depreciation, amortisation and net impairment losses	(11,550)	(16,715)	(15,925)	(31%)	5%
Exploration expenses	(2,952)	(3,872)	(4,666)	(24%)	(17%)

Net operating income	80	1,366	17,878	(94%)	(92%)

Net financial items	(258)	(1,311)	20	80%	N/A

Income before tax	(178)	55	17,898	N/A	(100%)

Income tax	(2,724)	(5,225)	(14,011)	(48%)	(63%)

Net income	(2,902)	(5,169)	3,887	44%	N/A

On 1 January 2016 Statoil changed its presentation currency from Norwegian kroner (NOK) to US dollar (USD), mainly in order to better reflect the underlying USD exposure of Statoil’s business activities and to align with industry practice.

Total revenues and other income amounted to USD 45,873 million in 2016 compared to USD 59,642 million in 2015 and USD 99,264 million in 2014.

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.

For additional information regarding sales, see the Sales volume table in section 2.8 above.

Statoil, Annual Report on Form 20-F 2016 59

The 21% decrease in revenues from 2015 to 2016 was mainly due to the drop in liquids and gas prices, lower refinery margins and increased losses from reflecting the changes in fair value of derivatives and market value of storage and physical contracts. The 40% decrease in revenues from 2014 to 2015 was mainly due to the significant reduction in both liquids and gas prices. Stronger refinery margins in 2015 and higher volumes of both liquids and gas sold partially offset the decrease.

Other income was USD 304 million in 2016 compared to USD 1,770 million in 2015 and USD 2,590 million in 2014. Other income in 2016 was mainly related to gain from sale of the Edvard Grieg field on the NCS and proceeds from an insurance settlement. In both 2015 and 2014, other income mainly consisted of gain from the two step divestments of the ownership interest in the Shah Deniz project in Azerbaijan. In addition, a settlement following an arbitration ruling in Statoil’s favour, impacted other income in 2014.

As a result of the factors explained above, total revenue and other income decreased by 23% in 2016. In 2015, the decrease was 40%.

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. See SDFI oil and gas marketing and sale in section 2.7 Corporate for more details.

Purchases [net of inventory variation] amounted to USD 21,505 million in 2016 compared to USD 26,254 million in 2015 and USD 47,980 million in 2014. The 18% decrease from 2015 to 2016 was mainly related to the decrease in liquids and gas prices. The 45% decrease from 2014 to 2015 was mainly related to the decrease in prices for liquids and gas and other oil products and lower volumes of crude, other oil products and gas sold.

Operating expenses and selling, general and administrative expenses amounted to USD 9,787 million in 2016 compared to USD 11,433 million in 2015, and USD 12,815 million in 2014.

The 14% decrease from 2015 to 2016 was mainly as a result of the on-going cost improvement initiatives and the NOK/USD exchange rate development. Lower operation and maintenance costs, decreased diluent cost and reduced transportation costs added to the decrease. Higher provisions, ramp-up and start-up of production on new fields partially offset the decrease in operating costs.

The 11% decrease from 2014 to 2015 was mainly due to lower operation and maintenance costs, reduced royalties due to lower liquids prices, decreased transportation costs in addition to positive effects from on-going cost initiatives. A curtailment gain related to the change of pension plan included in 2014, partially offset the decrease.

Depreciation, amortisation and net impairment losses amounted to USD 11,550 million in 2016 compared to USD 16,715 million in 2015 and USD 15,925 million in 2014. Included in these totals were net impairment losses of USD 1,301 million, USD 5,526 million and USD 4,134 million for 2016, 2015 and 2014 respectively, primarily triggered by the reduced commodity price assumption and commodity forward prices.

The net impairment losses of USD 1,301 million in 2016 were mainly related to impairment of unconventional onshore assets in the USA, including an impairment of the held for sale Kai Kos Dehseh oil sands project in Canada, and conventional offshore assets in the development phase in the DPN segment. Net reversals related to other conventional assets in the DPI segment (USD 19 million) and a refinery in the MMP segment (USD 74 million) had an offsetting effect. See note 10 Property, plant and equipment to the Consolidated financial statements.

Compared to 2015, the 31% decrease was mainly due to lower impairment of assets in 2016 and reduced depreciation on mature fields. Higher proved reserves estimate and the NOK/USD exchange rate development in 2016 added to the decrease, partially offset by start-up and ramp-up of production on several fields.

Compared to 2014, the 5% increase in 2015 was mainly due to increased impairment charges and start-up and ramp-up of production of several fields. Reduced overall depreciation because of net impairments of assets in both 2014 and 2015 with a corresponding lower basis for depreciation partially offset the increase.

Exploration expenses	For the year ended 31 December
(in USD million)	2016	2015	2014	16-15 change	15-14 change

Exploration expenditures (activity)	1,437	2,860	3,730	(50%)	(23%)
Expensed, previously capitalised exploration expenditures	808	213	369	>100%	(42%)
Capitalised share of current period's exploration activity	(285)	(1,151)	(1,161)	(75%)	(1%)
Impairments, net of reversals	992	1,951	1,728	(49%)	13%

Exploration expenses	2,952	3,872	4,666	(24%)	(17%)

60 Statoil, Annual Report on Form 20-F 2016

In 2016, exploration expenses were USD 2,952 million, a 24% decrease compared with 2015 when exploration expenses were USD 3,872 million. Exploration expenses were USD 4,666 million in 2014.

The 24% decrease in exploration expenses in 2016 was mainly due to lower net impairment of exploration prospects and signature bonuses, lower drilling activity and less expensive wells being drilled. The decrease was partially offset by a higher portion of expenditures capitalised in previous years being expensed in 2016 and a lower capitalisation rate on exploration expenditures incurred in 2016 compared to 2015.

In 2015, exploration expenses were down 17% compared to 2014 mainly due to a lower level of drilling activity and a lower portion of previously capitalised expenditures being expensed in 2015. Increased impairment of exploration prospects and signature bonuses in 2015 compared to 2014 partially offset the increase.

As a result of the factors explained above, net operating income was USD 80 million in 2016, compared to USD 1,366 million in 2015. In 2014, net operating income was USD 17,878 million. The significant decrease in 2016 was primarily driven by the drop in liquids and gas prices, lower refinery margins and lower gains on sale of assets. The decrease was partially offset by lower net impairment charges in 2016 compared to 2015 and a reduction in operating, depreciation and exploration costs. The decrease in net operating income from 2014 to 2015 was mainly due to the drop in prices in 2015 leading to lower earnings and increased impairment charges.

Net financial items amounted to a loss of USD 258 million in 2016, compared to a loss of USD 1,311 million in 2015 and a gain of USD 20 million in 2014. The reduced loss of USD 1,053 million in 2016 is mainly due to gain on derivatives due to decrease in EUR and GBP interest rates related to our long term debt portfolio of USD 470 million for 2016, compared to a loss of USD 491 million for 2015. The decrease in 2015 was mainly related to loss of USD 491 million on derivatives related to the long term debt portfolio in 2015, compared to a gain of USD 904 million in 2014, mainly due to changes in the interest yield curves.

Income taxes were USD 2,724 million in 2016, equivalent to an effective tax rate of more than 100%, compared to USD 5,225 million, equivalent to an effective tax rate of more than 100% in 2015. In 2014, income taxes were USD 14,011 million, equivalent to an effective tax rate of 78%.

In 2016 and 2015 our group income before tax (a loss of USD 178 million in 2016 and a profit of USD 55 million in 2015) is a combination of large profits in territories with higher statutory tax rates (taking account of Norwegian Petroleum Tax including uplift) and approximately the same amount of losses in territories with lower statutory tax rates and so our effective tax rate is distorted. In addition, the “weighted average statutory tax rate” (which we calculate before taking into account Norwegian Petroleum Tax including uplift for comparability) is also distorted.

In 2016, the effective rate of tax on the profit earned by our DPN business approximated the statutory tax rate (taking account of Norwegian Petroleum Tax including uplift) but the effective tax rate on DPI losses was negative due to the inability to currently recognise tax losses and other deferred tax assets arising from those losses, primarily in the USA. Overall this results in a significant income tax charge on a relatively small group loss before tax.

The effective tax rate in 2015 was primarily influenced by losses, mainly caused by impairments recognised in countries where deferred tax assets could not be recognised, partially offset by tax exempted gains on sale of assets including Statoil’s interest in the Shah Deniz project. The effective tax rate in 2015 was also influenced by the de-recognition of deferred tax assets within the DPI segment due to uncertainty related to future taxable income.

The decrease from 2014 to 2015 was mainly caused by losses, impairments and provisions in entities with higher than average statutory tax rates. Effective tax rate in 2014 was primarily influenced by losses, mainly caused by impairments, recognised in countries where deferred tax assets could not be recognised partially offset by tax exempted gains on sale of assets. The effective tax rate in 2014 was also influenced by the recognition of a non-cash tax income following a verdict in the Norwegian Supreme Court in February 2014.

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 25% (27% in 2014 and 2015), and income in other countries is taxed at the applicable income tax rates in the various countries.

In 2016, net income was negative USD 2,902 million compared to negative USD 5,169 million in 2015 and positive USD 3,887 million in 2014. The increase was mainly due to lower income taxes and lower loss on net financial items, partially offset by the decrease in net operating income as explained above. The significant decrease from 2014 to 2015 was mainly due to the drop in prices, leading to lower earnings and impairment losses. Increased losses on net financial items related to derivatives added to the decrease, which was partially offset by the reduction in income taxes.

Statoil, Annual Report on Form 20-F 2016 61

The board of directors proposes to the annual general meeting (AGM) to maintain a dividend of USD 0.2201 per ordinary share for the fourth quarter, and continue the scrip programme giving shareholders the option to receive the dividend for the fourth quarter in cash or newly issued shares in Statoil at a 5% discount. The Annual ordinary dividends for 2016 amounted to an aggregate total of USD 1,934 million. Considering the proposed dividend, USD 4,543 million will be transferred from retained earnings in the parent company. For 2015, annual ordinary dividends amounted to an aggregate total of USD 2,860 million and USD 3,628 million in 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 the timing of a Cove Point related onerous contract provision to a financial period prior to the first quarter of 2013, in which Statoil originally reflected the provision. Statoil did not accept the FSA’s conclusion and appealed the order to the Norwegian Ministry of Finance in accordance with due process for such matters under Norwegian regulation. In 2016, the Norwegian Ministry of Finance denied Statoil’s appeal. Statoil has decided not to pursue the matter further, as it does not impact any comparative financial periods presented in the annual Consolidated financial statements of 2016. Further reference is made to Note 23 Other commitments, contingent liabilities and contingent assets of Statoil’s 2015 Financial Statements.

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

FINANCIAL REVIEW – SEGMENTS PERFORMANCE

DPN profit and loss analysis

Net operating income in 2016 was USD 4,451 million, compared to USD 7,161 million in 2015 and USD 17,753 million in 2014. The USD 2,710 million decrease from 2015 to 2016 was mainly due to lower prices on liquids and gas, partly offset by reduced operating expenses, decreased depreciation and net impairment losses. The USD 10,592 million decrease from 2014 to 2015 was mainly due to lower prices on liquids and increased depreciation and net impairment losses.

The average daily production of liquids and gas was 1,235 mboe, 1,232 mboe and 1,184 mboe per day in 2016, 2015 and 2014, respectively.

The average daily total production level was maintained from 2015 to 2016 by high operational performance, new fields on stream and new wells from existing fields.

The average daily total production of liquids and gas increased by 4% from 2014 to 2015, mainly due to ramp up of new fields, increased sales gas and good operational performance, partly offset by expected natural decline and divestments.

Over time, the volumes lifted and sold will equal entitlement production, but may be higher or lower in any period due to differences between the capacities and timing of the vessels lifting the volumes and the actual entitlement production during the period.

Income statement under IFRS	For the year ended 31 December
(in USD million)	2016	2015	2014	16-15 change	15-14 change

Revenues	13,036	17,170	27,914	(24%)	(38%)
Net income from equity accounted investments	(78)	3	11	N/A	(70%)
Other income	119	166	1,002	(28%)	(83%)

Total revenues and other income	13,077	17,339	28,926	(25%)	(40%)

Operating expenses and selling, general and administrative expenses	(2,547)	(3,223)	(4,034)	(21%)	(20%)
Depreciation, amortisation and net impairment losses	(5,698)	(6,379)	(6,301)	(11%)	1%
Exploration expenses	(383)	(576)	(838)	(34%)	(31%)

Net operating income	4,451	7,161	17,753	(38%)	(60%)

Total revenues and other income were USD 13,077 million in 2016, USD 17,339 million in 2015 and USD 28,926 million in 2014.

The 24% decrease in revenues from 2015 to 2016 was mainly due to reduced liquids and gas prices. The 38% decrease in revenues from 2014 to 2015 was mainly due to reduced liquids prices and exchange rate development (NOK/USD). In addition, in 2015 a re-assessed valuation estimate of earn-out derivatives resulted in an unrealised fair value loss on derivatives and impacted revenues negatively.

62 Statoil, Annual Report on Form 20-F 2016

Other income in 2016 was impacted by gain from sale of Edvard Grieg of USD 114 million. Other income in 2015 was impacted by gain from the sale of certain ownership interests on the NCS to Repsol of USD 142 million. Other income in 2014 was impacted by gain from the sale of certain ownership interests on the NCS to Wintershall of USD 861 million.

Operating expenses and selling, general and administrative expenses were USD 2,547 million in 2016, compared to USD 3,223 million in 2015 and USD 4,034 million in 2014. In 2016, expenses decreased compared to 2015 mainly due to cost improvements and exchange rate development (NOK/USD). In 2015, expenses decreased compared to 2014 mainly due to exchange rate development (NOK/USD), cost improvements and reduced turnaround activity. This was partly offset by gain related to changes in pension scheme in 2014 and ramp up of new fields during 2015.

Depreciation, amortisation and net impairment losses were USD 5,698 million in 2016, compared to USD 6,379 million in 2015 and USD 6,301 million in 2014. The decrease of 11% from 2015 to 2016 was mainly due to reduced net impairments, exchange rate development (NOK/USD) and increased reserves, partly offset by ramp up of new fields in 2016. The increase from 2014 to 2015 was mainly due to net impairments of USD 1,074 million in 2015 and ramp-up of new fields in 2015, offset by exchange rate development (NOK/USD).

Exploration expenses were USD 383 million in 2016, compared to USD 576 million in 2015 and USD 838 million in 2014. The reduction from 2015 to 2016 was mainly due to lower drilling activity and more expensive wells being drilled in 2015, partially offset by a lower portion of current exploration expenditures being capitalised. The reduction in exploration expenses from 2014 to 2015 was mainly due to lower drilling activity, a lower portion of previously capitalised exploration expenditures being expensed in 2015 and idle rig costs in 2014.

DPI profit and loss analysis

Net operating income in 2016 was negative USD 4,352 million, compared to negative USD 8,729 million in 2015 and negative USD 2,703 million in 2014. The positive development from 2015 to 2016 was caused primarily by less impairment losses, and also by lower operating expenses. The negative development from 2014 to 2015 was caused primarily by lower realised liquids and gas prices and more impairment losses.

The average daily equity liquids and gas production (see section 5.6 Terms and abbreviations) was 743 mboe per day in 2016, compared to 739 mboe per day in 2015 and 744 mboe per day in 2014. The increase of 0.5% from 2015 to 2016 was driven primarily by the effect of the ramp-up of fields, mainly in Ireland, Algeria, and the US. The increase was partly offset by the divestment of Shah Deniz (Azerbaijan), natural decline primarily at mature fields in Angola as well as some operational challenges in 2016. The decrease of 0.7% from 2014 to 2015 was driven primarily by the effect of the divestment of Shah Deniz and a portion of Marcellus (US), and natural decline, primarily at mature fields in Angola. The decrease was partly offset by the ramp-up of fields in Angola and the US. Divestment of Shah Deniz occurred in both 2014 and 2015.

The average daily entitlement liquids and gas production (see section 5.6 Terms and abbreviations) was 592 mboe per day in 2016, compared to 580 mboe per day in 2015, and 546 mboe per day in 2014. Entitlement production in 2016 was up by 2% due to the increased equity production as described above and a relatively lower effect from production sharing agreements (PSA effect), mainly driven by the decrease in prices. The increase from 2014 to 2015 was driven by lower PSA effect. The PSA effect was 109 mboe, 116 mboe and 157 mboe per day in 2016, 2015 and 2014, respectively.

Over time, the volumes lifted and sold will equal our entitlement production, but they may be higher or lower in any period due to differences between the capacity and timing of the vessels lifting our volumes and the actual entitlement production during the period. See section 5.6 Terms and abbreviations for more information.

Income statement under IFRS	For the year ended 31 December
(in USD million)	2016	2015	2014	16-15 change	15-14 change

Revenues	6,623	7,135	12,823	(7%)	(44%)
Net income from equity accounted investments	(100)	(91)	(113)	(10%)	20%
Other income	134	1,156	951	(88%)	22%

Total revenues and other income	6,657	8,200	13,661	(19%)	(40%)

Purchases [net of inventory]	(7)	(10)	(2)	(28%)	>100%
Operating expenses and selling, general and administrative expenses	(2,923)	(3,391)	(3,654)	(14%)	(7%)
Depreciation, amortisation and net impairment losses	(5,510)	(10,231)	(8,885)	(46%)	15%
Exploration expenses	(2,569)	(3,296)	(3,824)	(22%)	(14%)

Net operating income	(4,352)	(8,729)	(2,703)	50%	>(100%)

Statoil, Annual Report on Form 20-F 2016 63

DPI generated total revenues and other income of USD 6,657 million in 2016 compared to USD 8,200 million in 2015 and USD 13,661 million in 2014.

Revenues in 2016 were negatively impacted by lower realised liquids and gas prices, partly offset by lower provisions relating to commercial disputes in 2016 compared to 2015. The decrease from 2014 to 2015 was mainly caused by lower realised liquids and gas prices, partly offset by an increase in lifted volumes. In addition, higher provisions relating to commercial disputes in 2015 compared to 2014 negatively impacted revenues. For information related to the disputes see note 23 Other commitments and contingencies to the Consolidated financial statements.

Other income was positively impacted by gains from sales of assets of USD 1,156 million in 2015 and USD 961 million in 2014, related primarily to the sale of ownership interest in the Shah Deniz project and the South Caucasus Pipeline.

As a result of the factors explained above, total revenues and other income decreased by 19% in 2016. In 2015, total revenues and other income decreased by 40%.

Operating expenses and selling, general and administrative expenses were USD 2,923 million in 2016, compared to USD 3,391 million in 2015 and USD 3,654 million in 2014. The 14% decrease from 2015 to 2016 was mainly due to lower operating and maintenance costs for various fields, in addition to lower diluent expenses. The decreases were partially offset by operating and transportation costs for the new fields coming on stream. The 7% decrease from 2014 to 2015 was mainly due to reduced operations and maintenance costs, lower royalties caused by lower prices, and portfolio changes. Production ramp-up and start-up of new fields partially offset the decrease.

Depreciation, amortisation and net impairment losses were USD 5,510 million in 2016, compared to USD 10,231 million in 2015 and USD 8,885 million in 2014. The 46% decrease was primarily caused by lower net impairment losses in 2016 compared to 2015. Net impairment losses amounted to USD 541 million in 2016, and resulted mainly from reduced long-term price assumptions with the largest effect being on the unconventional onshore assets in North America. In addition, depreciations decreased due to higher reserves estimates. The decreases were partially offset by start-up and ramp-up of production from new fields.

The 15% increase from 2014 to 2015 was primarily caused by net impairment losses of USD 5,416 million in 2015, mainly related to unconventional onshore assets in North America and certain conventional upstream assets. The impairment losses resulted primarily from reduced short-term forward prices in combination with reduced long-term oil price forecasts. In addition, depreciation increased due to higher production from start-up and ramp-up on various fields. The increases were partly offset by effect on depreciations from net impairments in 2014 and 2015 and reduced depreciations from higher reserves estimates.

Exploration expenses were USD 2,569 million in 2016, compared to USD 3,296 million in 2015 and USD 3,824 million in 2014. The 22% reduction from 2015 to 2016 was primarily due to lower impairments, lower drilling activity and lower well costs in 2016. Higher portion of wells capitalised in previous periods being expensed this year and a lower capitalisation rate in 2016 partially offset the decrease. The reduction from 2014 to 2015 was mainly due to lower drilling activity partly offset by increased impairments of oil and gas prospects in the Gulf of Mexico.

MMP profit and loss analysis

Net operating income was USD 623 million, USD 2,931 million and USD 2,608 million in 2016, 2015 and 2014, respectively. 2016 net operating income was positively impacted by solid liquids trading results as in 2015. The decrease of USD 2,308 million from 2015 to 2016 was mainly due to lower fair value of certain derivatives of USD 713 million as a result of increased forward curve. In addition, refining and gas marketing margins were reduced and production from processing plants lower than in 2015.

The increase of USD 324 million from 2014 to 2015 was mainly due to higher refining margins and solid liquids trading results and net reversal of impairment charges of USD 421 million. These increases were partially offset by the impact by Sonatrach Arbitration Settlement of USD 463 million in Statoil’s favour in 2014.

Total natural gas sales volumes were 52.9 bcm in 2016, 52.6 bcm in 2015 and 51.2 bcm in 2014. The 0.5% increase in total gas volumes sold from 2015 to 2016 was related to higher entitlement production on the NCS, partially offset by lower entitlement production internationally. The 3% increase in total gas volumes sold from 2014 to 2015 was related to higher entitlement production on the NCS in addition to higher third party volumes in Europe, partially offset by lower entitlement production internationally and lower third party volumes in the US. The chart does not include any volumes sold on behalf of the Norwegian State's direct financial interest (SDFI).

64 Statoil, Annual Report on Form 20-F 2016

In 2016, the average invoiced natural gas sales price in Europe was USD 5.17 per MMBtu compared to USD 7.08 per MMBtu in 2015, a decrease of 27%. Abundant gas supply in the first three quarters together with a mild winter had a negative influence on the prices. For the fourth quarter the market situation tightened and prices increased. LNG price has continued its downward trend, and only had a marginal positive effect on the European gas price in 2016. The average invoiced natural gas sales price in Europe was approximately 26% lower in 2015 than in 2014, mainly due to higher share of gas indexation in the gas contract portfolio.

In 2016, the average invoiced natural gas sales price in North Americas was USD 2.12 per MMBtu compared to USD 2.62 per MMBtu in 2015, a decrease of 19% due to significantly warmer weather first quarter 2016 than in 2015, and an abundant gas supply in the second quarter. In the third and fourth quarter prices rose due to cooler weather in New York and Toronto. The average invoiced natural gas sales price in North Americas was approximately 40% lower in 2015 than in 2014, mainly due to high market prices in first quarter 2014 as a result of exceptionally cold weather in North East combined with long term pipeline capacity agreements enabling access to premium markets in Toronto and Manhattan.

All of Statoil's gas produced on the NCS is sold by MMP, purchased from DPN at the fields’ lifting point at a market-based internal price with deduction for the cost of bringing gas from the field to market and a marketing fee element. Our average internal purchase price for gas was USD 3.42 per MMBtu in 2016, a decrease of 34% compared to USD 5.17 per MMBtu in 2015.

Average crude, condensate and NGL sales were 2.2 mmbbl per day in 2016 of which approximately 1.01 mmbbl were sales of our equity volumes, 0.80 mmbbl sales of third-party volumes and 0.40 mmbbl sales of volumes purchased from SDFI. Our average sales volumes were 2.3 and 2.2 mmbbl per day in 2015 and 2014. The average daily third-party volumes sold were 0.79 and 0.83 mmbbl in 2015 and 2014.

Statoil, Annual Report on Form 20-F 2016 65

MMPs refining margins were considerably lower the first three quarters 2016 compared to 2015, and results were impacted by lower production from the refineries. The average refining margin was at the same level in fourth quarter 2015 and 2016. Statoil's refining reference margin was 4.8 USD/bbl in 2016, compared to 8.0 USD/bbl in 2015, a decrease of 40%. The refining reference margin was 4.7 USD/bbl in 2014.

Income statement under IFRS	For the year ended 31 December
(in USD million)	2016	2015	2014	16-15 change	15-14 change

Revenues	44,847	57,873	94,483	(23%)	(39%)
Net income from equity accounted investments	61	55	73	12%	(25%)
Other income	72	178	615	(60%)	(71%)

Total revenues and other income	44,979	58,106	95,171	(23%)	(39%)

Purchases [net of inventory]	(39,696)	(50,547)	(86,689)	(21%)	(42%)
Operating expenses and selling, general and administrative expenses	(4,439)	(4,664)	(5,287)	(5%)	(12%)
Depreciation, amortisation and net impairment losses	(221)	37	(583)	>(100%)	>(100%)

Net operating income	623	2,931	2,608	(79%)	12%

Total revenues and other income were USD 44,979 million in 2016, compared to USD 58,106 million in 2015 and USD 95,171 million in 2014.

The decrease in revenues from 2015 to 2016 was mainly due to decrease in crude and gas prices. The average crude price in USD declined by approximately 17% in 2016 compared to 2015. Revenues in 2016 were negatively impacted by loss from derivatives mainly related to hedges of physical positions due to significant increase in the forward curve in the oil and gas market.

The decrease in revenues from 2014 to 2015 was mainly due to decrease in crude and gas prices, partially offset by higher volumes for crude, other oil products and gas sold. The average crude price in USD declined by approximately 47% in 2015 compared to 2014. Revenues in 2015 were positively impacted by gains from derivatives, mainly due to significant drop in the forward curve in the oil and gas market.

Other income in 2016 was positively impacted by gain on sale of assets of USD 72 million. In 2015, other income was positively impacted by gain on sale of assets of USD 178 million.

66 Statoil, Annual Report on Form 20-F 2016

As a result of the factors explained above, total revenues and other income decreased by 23% and 39% in 2016 and 2015, respectively.

Purchases [net of inventory] were USD 39,696 million in 2016, compared to USD 50,547 million in 2015 and USD 86,689 million in 2014. The decrease from 2015 to 2016 was mainly due to decrease in crude and gas prices. The decrease from 2014 to 2015 was mainly due to decrease in gas and crude prices and lower volumes of crude, other oil products and gas sold.

Operating expenses and selling, general and administrative expenses were USD 4,439 million in 2016, compared to USD 4,664 million in 2015 and USD 5,287 million in 2014. The decrease from 2015 to 2016 was mainly due to lower transportation cost and the ongoing cost reduction initiatives in 2016.

The decrease from 2014 to 2015 was mainly due to the ongoing cost reduction initiatives and a positive USD/NOK currency effect added to the decrease of USD 622 million.

Depreciation, amortisation and net impairment losses amounted to a loss of USD 221 million in 2016, compared to an income of USD 37 million in 2015 and a loss of USD 583 million in 2014. The increase in depreciation, amortisation and net impairment losses from 2015 to 2016 was mainly caused by lower reversal of impairments in 2016 compared to 2015. Net reversal of impairments in 2016 was mainly related to a refinery asset, impacted by expected lower cost base in the future cash flows. The decrease in depreciation, amortisation and net impairment losses from 2014 to 2015 was mainly caused by net reversal of impairment charges of USD 421 million in 2015 triggered by increased refinery margins and operational improvement.

Other operations

The Other reporting segment includes activities within New Energy Solutions; Global Strategy and Business Development; Technology, Projects and Drilling; and Corporate staffs and support functions.

In 2016, the Other reporting segment recorded a net operating loss of USD 423 million compared to a net operating loss of USD 129 million in 2015 and a net operating loss of USD 199 million in 2014.

Statoil, Annual Report on Form 20-F 2016 67

2.9 LIQUIDITY AND CAPITAL RESOURCES

Review of cash flows

Statoil`s cash flows in 2016 reflect a solid cash flow in a low price environment.

CONSOLIDATED STATEMENT OF CASH FLOWS
		Full year
(in USD million)	Note	2016	2015	2014

Income before tax		(178)	55	17,898

Depreciation, amortisation and net impairment losses	10, 11	11,550	16,715	15,925
Exploration expenditures written off	11	1,800	2,164	2,097
(Gains) losses on foreign currency transactions and balances		(137)	1,166	883
(Gains) losses on sales of assets and businesses	4	(110)	(1,716)	(1,998)
(Increase) decrease in other items related to operating activities		1,076	558	(1,671)
(Increase) decrease in net derivative financial instruments	25	1,307	1,551	254
Interest received		280	363	341
Interest paid		(548)	(443)	(551)

Cash flows provided by operating activities before taxes paid and working capital items		15,040	20,414	33,178

Taxes paid		(4,386)	(8,078)	(15,308)

(Increase) decrease in working capital		(1,620)	1,292	2,335

Cash flows provided by operating activities		9,034	13,628	20,205

Additions through business combinations	4	0	(398)	0
Capital expenditures and investments		(12,191)	(15,518)	(19,497)
(Increase) decrease in financial investments		877	(2,813)	(1,919)
(Increase) decrease in other non-current items		107	(22)	128
Proceeds from sale of assets and businesses	4	761	4,249	3,514

Cash flows used in investing activities		(10,446)	(14,501)	(17,775)

New finance debt	18	1,322	4,272	3,010
Repayment of finance debt		(1,072)	(1,464)	(1,537)
Dividend paid	17	(1,876)	(2,836)	(5,499)
Net current finance debt and other		(333)	(701)	(2)

Cash flows provided by (used in) financing activities		(1,959)	(729)	(4,028)

Net increase (decrease) in cash and cash equivalents		(3,371)	(1,602)	(1,598)

Effect of exchange rate changes on cash and cash equivalents		(152)	(871)	(1,329)
Cash and cash equivalents at the beginning of the period (net of overdraft)	16	8,613	11,085	14,013

Cash and cash equivalents at the end of the period (net of overdraft)	16	5,090	8,613	11,085

68 Statoil, Annual Report on Form 20-F 2016

Cash flows provided by operations

The most significant drivers of cash flows provided by operations were 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 reduced by USD 4,594 million compared to the full year 2015. The decrease was mainly due to reduced liquids and gas prices, partially offset by lower taxes paid.

Cash flows provided by operating activities were USD 13,628 million in 2015 compared to USD 20,205 million in 2014, which is a decrease of USD 6,577 million driven by a significant reduction in both liquids and gas prices. The decrease was partially offset by positive changes in working capital and lower taxes paid in 2015 compared to 2014.

Cash flows used in investing activities

Cash flows used in investing were reduced by USD 4,055 million compared to the full year 2015. The decrease was due to significantly lower capital expenditures, lower financial investments and reduced proceeds from sale of assets.

Cash flows used in investing activities were USD 14,501 million in 2015 compared to USD 17,775 million in 2014, a decrease of USD 3,274 million mainly due to reduced capital expenditures. The proceeds from sale of assets in 2015 of USD 4,249 million were mainly related to the divestment of the remaining interests in the Shah Deniz field and the South Caucasus pipeline, sale of office buildings, sale of interest in the Marcellus onshore play, sale of interests in Trans Adriatic pipeline AG and the sale of interests in licenses on the NCS.

Cash flows provided by (used in) financing activities

Cash flows used in financing activities increased by USD 1,230 million compared to the full year 2015. The change is mainly due to reduced cash flow from finance debt, partially offset by reduced cash dividend due to the scrip dividend.

Cash flows used in financing activities were USD 729 million in 2015 and were mainly related to payments of dividends USD 2,836 million and repayments of debt USD 1,464 million, partially offset by issuance of new debt of USD 4,272 million. Cash flows used in financing activities were USD 4,028 million in 2014 and were mainly related to payments of dividends and repayments of debt, partly offset by issuance of new debt in November 2014 of USD 3,010 million.

Financial assets and debt

Statoil's financial position is strong although its net debt to capital employed ratio before adjustments at year end increased from 25.6% in 2015 to 34.4% in 2016. See section 5.2 for non-GAAP measures for net debt ratio. Net interest-bearing debt increased from USD 13.9 billion to USD 18.4 billion. During 2016 Statoil's total equity decreased from USD 40.3 billion to USD 35.1billion, mainly due to impairments recognised in 2016 and dividend paid. Cash flows provided by operating activities were reduced in 2016 mainly due to lower prices. Cash flows used in investing activities reduced in 2016. Statoil has paid out four quarterly dividends in 2016. For the fourth quarter of 2016 the board of directors will propose to the annual general meeting (AGM) to maintain a dividend of USD 0.2201 per share and to maintain the scrip dividend program initiated from the fourth quarter 2015. For details, see note 17 Shareholders equity and dividends to the Consolidated financial statements.

Statoil believes that, given its current liquidity reserves, including committed credit facilities of USD 5.0 billion and its access to various capital markets, Statoil has sufficient funds available to meet its liquidity needs, including working capital.

Funding needs arise as a result of Statoil’s general business activities. Statoil generally seeks to establish financing at the corporate (top company) level. Project financing may also be used in cases involving joint ventures with other companies. Statoil aims to have 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 a wide range of banking services.

Moody's and Standard & Poor's (S&P) provide credit ratings on Statoil. Statoil’s current long-term ratings are A+ and Aa3 from S&P and Moody’s, respectively. The rating from S&P was revised from AA- credit watch negative to A+ with a stable outlook on 22 February 2016 while the rating from Moody’s was revised from Aa2 on review for downgrade to Aa3 with stable outlook on 21 March 2016. Both rating agency revisions were triggered by the low commodity price environment, and similar downgrades were seen across the sector around that time. The short-term ratings are P-1 from Moody's and A-1 from S&P. In order to maintain financial flexibility going forward, Statoil intend to keep key financial ratios at levels consistent with our objective of maintaining Statoil's long-term credit rating at least within the single A category on a stand-alone basis.

The management of financial assets and liabilities takes into consideration funding sources, the maturity profile of non-current debt, interest rate risk, currency risk and available liquid assets. Statoil’s borrowings are denominated in various currencies and normally swapped into USD. In addition, interest rate derivatives, primarily interest rate swaps, are used to manage the interest rate risk of our long-term debt portfolio. The Group's Capital Markets unit manages the funding and liquidity activities at Group level.

Statoil, Annual Report on Form 20-F 2016 69

Statoil has diversified its 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 2016, approximately 7% of Statoil’s liquid assets were held in USD-denominated assets, 21% in NOK, 58% in EUR, 5% in DKK and 9% in SEK, before the effect of currency swaps and forward contracts. Approximately 56% of Statoil’s liquid assets were held in treasury bills and commercial paper, 42% in time deposits, 1% in money market funds and 1% at in bank deposits. As of 31 December 2016, approximately 4.7% of Statoil’s liquid assets were classified as restricted cash (including collateral deposits).

Statoil’s general policy is to keep a liquidity reserve in the form of cash and cash equivalents or other current financial investments in Statoil’s balance sheet, as well as committed, unused credit facilities and credit lines in order to ensure that Statoil has sufficient financial resources to meet short-term requirements.

Long-term funding is raised when a need is identified for such financing based on Statoil’s business activities, cash flows and required financial flexibility or when market conditions are considered to be favourable.

The Group's borrowing needs are usually covered through the issuance of short-, medium- and long-term securities, including utilisation of a US Commercial Paper Programme (programme limit USD 5.0 billion) and a Shelf Registration Statement (unlimited) filed with the Securities and Exchange Commission (SEC) in the USA as well as through issues under a Euro Medium-Term Note (EMTN) Programme (updated 28 October 2016 with a limit of EUR 20.0 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 Statoil’s borrowings is in USD.

During 2016, Statoil issued bonds with 10 and 20 year maturities for a total amount of EUR 1.2 billion (USD 1.3 billion). All the bonds are unconditionally guaranteed by Statoil Petroleum AS. For more information, see note 18 Finance debt to the Consolidated financial statements.

Statoil issued new debt securities in 2015 equivalent to USD 4.3 billion and in 2014 equivalent to USD 3.0 billion.

Financial indicators

Financial indicators		For the year ended 31 December
(in USD million)		2016	2015	2014

Gross interest-bearing financial liabilities¹⁾		31,673	32,291	31,154
Net interest-bearing liabilities before adjustments		18,372	13,852	12,004
Net debt to capital employed ratio²⁾		34.4%	25.6%	19.0%
Net debt to capital employed ratio adjusted³⁾		35.6%	26.8%	20.0%
Cash and cash equivalents		5,090	8,623	11,182
Current financial investments		8,211	9,817	7,968
ROACE⁴⁾		(8.0%)	2.7%	11.3%
Ratio of earnings to fixed charges⁵⁾		0.9	1.0	7.0

1)	Defined as non-current and current finance debt.
2)	As calculated according to IFRS. Net debt to capital employed ratio is the net debt divided by capital employed. Net debt is interest-bearing debt less cash and cash equivalents and current financial investments. Capital employed is net debt, shareholders' equity and minority interest.
3)	In order to calculate the net debt to capital employed ratio adjusted, Statoil makes adjustments to capital employed as it would be reported under IFRS. Restricted funds held as financial investments in Statoil Forsikting AS and Collateral deposits has been added to the net debt whilst the SDFI part of the financial lease in the Snøhvit vessel has been taken out of the net debt. See section 5.2 Net debt to capital employed ratio for a reconciliation of capital employed and a description of why Statoil considers this measure to be useful.
4)	ROACE is equal to net income adjusted for financial items after tax, divided by average capital employed over the last 12 months. See section 5.2 Return on average capital employed (ROACE) for a reconciliation of ROACE and a description of why Statoil considers this measure to be useful.
5)	Based on IFRS. For the purpose of these ratios, earnings consist of the income before (i) tax, (ii) minority interest, (iii) amortisation of capitalised interest and (iv) fixed charges (which have been adjusted for capitalised interest) and after adjustment for unremitted earnings from equity accounted entities. Fixed charges consist of interest (including capitalised interest) and estimated interest within operating leases.

Gross interest-bearing debt

Gross interest-bearing debt was USD 31.7 billion, USD 32.3 billion and USD 31.2 billion at 31 December 2016, 2015 and 2014, respectively. The USD 0.6 billion net decrease from 2015 to 2016 was due to a decrease in non-current finance debt of USD 2.0 billion, offset by an increase in current finance debt of USD 1.4 billion. The USD 1.1 billion increase from 2014 to 2015 was due to an increase in non-current finance debt of USD 2.4 billion offset by a decrease in current finance debt of USD 1.3 billion. Our weighted average annual interest rate was 3.41%, 3.39% and 3.78% at 31 December 2016, 2015 and 2014, respectively. Statoil’s weighted

70 Statoil, Annual Report on Form 20-F 2016

average maturity on finance debt was nine years at 31 December 2016, nine years at 31 December 2015 and nine years at 31 December 2014.

Net interest-bearing debt

Net interest-bearing debt before adjustments were USD 18.4 billion, USD 13.9 billion and USD 12.0 billion at 31 December 2016, 2015 and 2014, respectively. The increase of USD 4.5 billion from 2015 to 2016 was mainly related to a decrease in cash and cash equivalents of USD 3.5 billion, a decrease of current financial investments of USD 1.6 billion offset by a USD 0.6 billion decrease in gross interest-bearing debt. Negative cash flow in 2016 is the main reason. The increase of USD1.8 billion from 2014 to 2015 was related to an increase in gross interest-bearing debt of USD 1.1 billion offset and a decrease in cash and cash equivalents and current financial investments of USD 0.7 billion.

The net debt to capital employed ratio

The net debt to capital employed ratio before adjustments was 34.4%, 25.6% and 19.0% in 2016, 2015 and 2014 respectively.

The net debt to capital employed ratio adjusted (non-GAAP financial measure, see footnote three above) was 35.6%, 26.8% and 20.0% in 2016, 2015, and 2014, respectively.

The 8.8 percentage points increase in net debt to capital employed ratio before adjustments from 2015 to 2016 was related to the increase in net interest-bearing debt adjusted of USD 4.5 billion in combination with a decrease in capital employed adjusted of USD 0.7 billion. The 6.6 percentage points increase in net debt to capital employed ratio before adjustments from 2014 to 2015 was related to an increase in net interest-bearing debt adjusted of USD 1.8 billion in combination with a decrease in capital employed adjusted of USD 9.1 billion.

The 8.8 percentage points increase in net debt to capital employed ratio adjusted from 2015 to 2016 was related to the increase in net interest-bearing debt adjusted of USD 4.6 billion in combination with a decrease in capital employed adjusted of USD 0.6 billion. The 6.8 percentage points increase in net debt to capital employed ratio adjusted from 2014 to 2015 was related to an increase in net interest-bearing debt adjusted of USD 1.9 billion in combination with a decrease in capital employed adjusted of USD 9.1 billion.

Cash, cash equivalents and current financial investments

Cash and cash equivalents were USD 5.1 billion, USD 8.6 billion and USD 11.2 billion at 31 December 2016, 2015 and 2014 respectively. See note 16 Cash and cash equivalents to the Consolidated financial statements for information concerning restricted cash. Current financial investments, which are part of Statoil’s liquidity management, amounted to USD 8.2 billion, USD 9.8 billion and USD 8.0 billion at 31 December 2016, 2015 and 2014, respectively.

Investments

In 2016, capital expenditures, defined as additions to property, plant and equipment (including capitalised financial leases), capitalised exploration expenditures, intangible assets, long-term share investments and investments in equity accounted companies, amounted to USD 14.1 billion, of which USD 10.1 billion were organic capital expenditures (excluding acquisitions, capital leases and other investments with significant different cash flow pattern). Among items excluded from the organic capital expenditure in 2016 were investment in ownership in Lundin Petroleum AB, acquisition of a 66% operated interest in the offshore licence BM-S-8 in Brazil and acquisition of a 50% stake in the Arkona offshore wind farm in Germany.

In 2015, capital expenditures were USD 15.5 billion, of which organic capital expenditures amounted to USD 14.7 billion.

In Norway, a substantial proportion of our 2017 capital expenditures will be spent on ongoing development projects such as Johan Sverdrup, Gina Krog and Aasta Hansteen, in addition to various extensions, modifications and improvements on currently producing fields like Gullfaks, Oseberg and Troll.

Internationally, we currently estimate that a substantial proportion of our 2017 capital expenditure will be spent on the following ongoing and planned development projects: Mariner in UK, Peregrino in Brazil, Stampede and onshore activity in the US.

In the area of renewable energy, a substantial proportion of our 2017 capital expenditure is expected to be spent on the following offshore wind projects: Arkona in Germany and Hywind in the UK.

Statoil finances its capital expenditures both internally and externally. For more information, see Financial assets and debt earlier in this section.

As illustrated in Principal contractual obligations later in this section, Statoil have committed to certain investments in the future. The further into the future, the more flexibility we will have to revise expenditure. This flexibility is partly dependent on the expenditure our partners in joint ventures agree to commit to. A large part of the capital expenditure for 2017 is committed.

Statoil, Annual Report on Form 20-F 2016 71

Statoil may alter the amount, timing or segmental or project allocation of our capital expenditures in anticipation of or as a result of a number of factors outside our control.

Impact of reduced prices

Our results are affected by the development in the price of raw materials and services that are necessary for the development and operation of oil and gas producing assets.

Cost development in the prices of goods, raw materials and services that are necessary for the development and operation of oil and gas producing assets can vary considerably over time and between each market segment.

Prices in supplier markets have been reduced and in several supplier market segments Statoil has achieved reduced rates compared to the 2014/2015 level. Such savings have been achieved both in new and renegotiated contracts.

See the analysis of profit and loss in section 2.8 Operating and financial performance as well section 2.1 Group Outlook.

Principal contractual obligations

The table summarises our principal obligations and includes contractual obligations, but excludes derivatives and other hedging instruments as well as asset retirement obligations, as these obligations for the most part are expected to lead to cash disbursements more than five years in the future. Obligations payable by Statoil to unconsolidated equity affiliates are included gross in the table. Where Statoil includes both an ownership interest and the transport capacity cost for a pipeline in the consolidated accounts, the amounts in the table include the transport commitments that exceed Statoil's ownership share. See Disclosures about market risk in section 2.10 Risk review for more information.

72 Statoil, Annual Report on Form 20-F 2016

		As at 31 December 2016
Contractual obligations		Payment due by period ¹⁾
(in USD million)		Less than 1 year	1-3 years	3-5 years	More than 5 years	Total

Undiscounted non-current finance debt		3,554	4,641	9,133	23,822	41,151
Minimum operating lease payments		1,993	2,693	1,657	2,306	8,649
Nominal minimum other long-term commitments²⁾		1,483	2,657	2,200	5,513	11,853

Total contractual obligations		7,030	9,992	12,990	31,642	61,653

1)	"Less than 1 year" represents 2016; "1-3 years" represents 2017 and 2018, "3-5 years" represents 2019 and 2020, while "More than 5 years" includes amounts for later periods.
2)	For further information see note 23 Other commitments and contingencies to the Consolidated financial statements.

Non-current finance debt in the table represents principal payment obligations. For information on interest commitments relating to long-term debt, reference is made to note 18 Finance debt and note 22 Leases to the Consolidated financial statements.

Statoil had contractual commitments of USD 6,889 million at 31 December 2016. The contractual commitments reflect Statoil's share and mainly comprise construction and acquisition of property, plant and equipment.

Statoil’s projected pension benefit obligation was USD 7,791 million, and the fair value of plan assets amounted to USD 5,250 million as of 31 December 2016. Company contributions are mainly related to employees in Norway. See note 19 Pensions to the Consolidated financial statements for more information.

Off balance sheet arrangements

Statoil is party to various agreements, such as operational leases and transportation and processing capacity contracts, that are not recognised in the balance sheet. For more information, see Principal contractual obligations in section 2.9 Liquidity and capital resources, and note 22 Leases to the Consolidated financial statements. Statoil is also party to certain guarantees, commitments and contingencies that, pursuant to IFRS, are not necessarily recognised in the balance sheet as liabilities. See note 23 Other commitments and contingencies to the Consolidated financial statements for more information.

Statoil, Annual Report on Form 20-F 2016 73

2.10 RISK REVIEW

Statoil’s overall risk management includes identifying, evaluating and managing risk in all its activities to ensure safe operations and to achieve Statoil’s corporate goals.

RISK FACTORS

Statoil is exposed to a number of risks that could affect its operational and financial performance. In this section, some of the key risk factors are addressed.

Risks related to our business

This section describes the most significant potential risks relating to Statoil’s business:

A prolonged period of low oil and/or natural gas prices would have a material adverse effect on Statoil

The prices of oil and natural gas have fluctuated greatly in response to changes in many factors. We have experienced a situation where oil and natural gas prices declined substantially compared to levels seen over the last few years. There are several reasons for this decline, but fundamental market forces beyond the control of Statoil or other similar market participants have impacted and can continue to impact oil and natural gas prices in the future. Recently, as a consequence of agreements within Opec and also between Opec and some non-Opec countries, oil prices have increased due to expectations of an earlier tightening of market balances. However, the uncertainty about future developments still prevails.

Generally, Statoil does not and will not have control over the factors that affect the prices of oil and natural gas. These factors include:

· economic and political developments in resource-producing regions

· global and regional supply and demand

· the ability of the Organisation of the Petroleum Exporting Countries (Opec) and/or other producing nations to influence global production levels and prices

· prices of alternative fuels that affect the prices realised under Statoil's long-term gas sales contracts

· government regulations and actions; including changes in energy and climate policies

· global economic conditions

· war or other international conflicts

· changes in population growth and consumer preferences

· the price and availability of new technology and

· weather conditions

It is impossible to predict future price movements for oil and/or natural gas with certainty. A prolonged period of low oil and natural gas prices will adversely affect Statoil's business, the results of operations, financial condition, liquidity and Statoil's ability to finance planned capital expenditure, including possible reductions in capital expenditures which could lead to reduced reserve replacement. In addition to the adverse effect on revenues, margins and profitability from any fall in oil and natural gas prices, a prolonged period of low prices or other indicators could, if deemed to have longer term impact, lead to further reviews for impairment of the group's oil and natural gas properties. Such reviews would reflect the management's view of long-term oil and natural gas prices and could result in a charge for impairment that could have a significant effect on the results of Statoil's operations in the period in which it occurs. Changes in management’s view on long-term oil and/or natural gas prices or further material reductions in oil, gas and/or product prices could have an adverse impact on the economic viability of projects that are planned or in development.

Statoil’s crude oil and natural gas reserves are only estimates and Statoil’s future production, revenues and expenditures with respect to its reserves may differ materially from these estimates. The reliability of proved reserve estimates depends on:

· the quality and quantity of Statoil’s geological, technical and economic data

· the production performance of Statoil’s reservoirs

· extensive engineering judgments and

· whether the prevailing tax rules and other government regulations, contracts and oil, gas and other prices will remain the same as on the date estimates are made

Proved reserves are calculated based on the U.S. Securities and Exchange Commission (SEC) requirements and may therefore differ substantially from Statoil’s view on expected reserves.

Many of the factors, assumptions and variables involved in estimating reserves are beyond Statoil’s control and may prove to be incorrect over time. The results of drilling, testing and production after the date of the estimates may require substantial upward or downward revisions in Statoil’s reserve data. The prices used for proved reserves are defined by the SEC and are calculated based on a 12 month un-weighted arithmetic average of the first-day-of-the-month price for each month during the reporting year, leading to a forward price strongly linked to last year’s price environment. Fluctuations in oil and gas prices will have a direct impact on Statoil’s proved reserves. For fields governed by production sharing agreements (PSAs), a lower price may lead to higher entitlement to the

74 Statoil, Annual Report on Form 20-F 2016

production and increased reserves for those fields. Adversely, a lower price environment may also lead to lower activity resulting in reduced reserves. For PSAs these two effects may to some degree offset each other. In addition a low price environment may result in earlier shutdown due to uneconomic production. This will affect both PSAs and fields with concession types of agreement.

Statoil is engaged in global exploration activities that involve a number of technical, commercial and country specific risks.

General risks are technical risks related to Statoil’s ability to conduct its seismic and drilling operations in a safe and efficient manner and to encounter commercially productive oil and gas reservoirs and commercial risks related to Statoil’s ability to secure access to new acreage in an uncertain global competitive and political environment and competent personnel to perform exploration activities and mature resources along the value-chain. Country specific risks are related to security threats and compliance with and understanding of local laws or license agreements. These risks may adversely affect Statoil’s current operations and financial results, and its long-term replacement of reserves.

If Statoil fails to acquire or discover and develop additional reserves, its reserves and production will decline materially from their current levels

Successful implementation of Statoil's group strategy for value growth is critically dependent on sustaining its long-term reserve replacement. If upstream resources are not progressed to proved reserves in a timely manner, Statoil’s reserve base and thereby future production will gradually decline and future revenue will be reduced.

Statoil's future production is highly dependent on its success in acquiring or finding and developing additional reserves adding value. If unsuccessful, future total proved reserves and production will decline.

If the low price environment continues for a substantial time, this may result in undeveloped acreage not being considered economically viable and consequently discovered resources not being matured to reserves. This may also lead to exploration areas not being explored for new resources and subsequently not being matured for development resulting in less future proved reserves.

In a number of resource-rich countries, national oil companies control a significant proportion of oil and gas reserves that remain to be developed. To the extent that national oil companies choose to develop their oil and gas resources without the participation of international oil companies, or if Statoil is unable to develop partnerships with national oil companies, its ability to find and acquire or develop additional reserves will be more limited.

Statoil is exposed to a wide range of health, safety and environmental risks that could result in significant losses.

Exploration, development, production, processing and transportation related to oil and natural gas, as well as development and operation of renewable energy production, can be hazardous. Technical integrity failures, operational failures, natural disasters or other occurrences can result in: loss of life, oil spills, gas leaks, loss of containment of hazardous materials, water contamination, blowouts, cratering, fires and equipment failure, among other things.

The risks associated with Statoil's activities are affected by the difficult geographies, climate zones and environmentally sensitive regions in which Statoil operates. All modes of transportation of hydrocarbons - including road, rail, sea or pipeline - are particularly susceptible to a loss of containment of hydrocarbons and other hazardous materials, and, given the high volumes involved, these could represent a significant risk to people and the environment. Offshore operations and transportation are subject to marine perils, including severe storms and other adverse weather conditions and vessel collisions. Onshore operations and transportation are subject to adverse weather conditions and accidents. Both onshore and offshore operations and transportation are subject to interruptions, restrictions or termination by government authorities based on safety, environmental or other considerations.

Policy and regulatory change due to rising climate change concerns, and the physical effects of climate change, could impact Statoil’s business and related costs

The transition to a low-carbon energy future poses fundamental strategic challenges for the oil and gas industry.

Statoil monitors and assesses risks related to climate change, whether political, regulatory, market or physical, including reputation impact.

Statoil expects and is preparing for policy and regulatory changes targeted at reducing greenhouse gas emissions. This could impact Statoil's financial outlook, whether directly through changes in taxation and regulation, or indirectly through changes in consumer behaviour.

There is continuing uncertainty over climate policy developments in various jurisdiction, and hence the long-term implications to costs and constraints. Statoil expects greenhouse gas emission costs to increase from current levels beyond 2020 and to have a wider geographical range than today.

Climate related policy changes may also reduce access to prospective geographical areas for exploration and production in the future.

Regulatory changes encouraging the development of low-carbon energy technologies such as renewable energy or other potentially disruptive technologies, could impact the demand for oil and gas. As an example, development of battery technologies could allow

Statoil, Annual Report on Form 20-F 2016 75

more intermittent renewables to be used in the power sector. This could impact Statoil's gas sales, particularly if subsidies of renewable energy in Europe were to increase.

Statoil has analysed the sensitivity of its project portfolio (equity production and expected production from accessed exploration acreage) against the assumptions regarding commodity and carbon prices in the International Energy Agency’s (IEA) energy scenarios, as laid out in their “World Economic Outlook 2016” report. The analysis demonstrated that the IEA’s “450 ppm scenario”, which is at large compatible with a global warming of maximum of two degrees Celsius with more than 50% probability, could have a positive impact of approximately 6% on Statoil’s net present value compared to Statoil’s internal planning assumptions as of December 2016. This assessment is based on Statoil’s and the IEA’s assumptions which may not be accurate and which are likely to develop over time as new information becomes available. Accordingly, there can be no assurance that the assessment, which is presented in Statoil ASA’s 2016 Sustainability report, is a reliable indicator of the actual impact of climate change on Statoil.

Changes in physical climate parameters could impact Statoil's operations, for example through restrained water availability, rising sea level, changes in sea currents and increasing frequency of extreme weather events.

Statoil is exposed to risks as a result of its hydraulic fracturing usage

Statoil's US operations use hydraulic fracturing which is subject to a range of applicable federal, state and local laws, including those discussed under the heading "Legal and Regulatory Risks". Fracturing is an important and common practice that is used to stimulate production of crude oil and/or natural gas from dense subsurface rock formations. Statoil's hydraulic fracturing and fluid handling operations are designed and operated to minimise the risk, if any, of subsurface migration of hydraulic fracturing fluids and spillage or mishandling of hydraulic fracturing fluids, however, a proven case of subsurface migration of hydraulic fracturing fluids or a case of spillage or mishandling of hydraulic fracturing fluids during these activities could potentially subject Statoil to civil and/or criminal liability and the possibility of substantial costs, including environmental remediation, depending on the circumstances of the underground migration, spillage, or mishandling, the nature and scope of the underground migration, spillage, or mishandling, and the applicable laws and regulations.

In addition, various states and local governments have implemented, or are considering, increased regulatory oversight of hydraulic fracturing through additional permit requirements, operational restrictions, disclosure requirements and temporary or permanent bans. New or further changes in laws and regulations imposing reporting obligations on, or otherwise banning or limiting, the hydraulic fracturing process could make it more difficult to complete oil and natural gas wells in shale formations, cause operational delays, increase costs of regulatory compliance or in exploration and production, which could adversely affect Statoil's US onshore business and the demand for fracturing services.

Statoil is exposed to security threats that could have a materially adverse effect on Statoil's results of operations and financial condition

Security threats such as acts of terrorism and cyber-attacks against Statoil's production and exploration facilities, offices, pipelines, means of transportation or computer systems or breaches of Statoil's security system, could result in losses. No assurances can be made that such attacks will not occur in the future and adversely impact its operations. Failure to manage the foregoing risks could result in injury or loss of life, damage to the environment, damage to or the destruction of wells and production facilities, pipelines and other property. Statoil could face, among other things, regulatory action, legal liability, damage to its reputation, a significant reduction in revenues, an increase in costs, a shutdown of operations and a loss of its investments in affected areas.

Statoil's crisis management systems may prove inadequate

Statoil has plans and capability to deal with crisis and emergencies at every level of its operations (ie; plant fires, terror, well instability etc). If Statoil does not respond or is perceived not to have responded in an appropriate manner to either an external or internal crisis, or if its plans to carry on or recover operations following a disruption or incident are not effected quickly enough, its business, operations and reputation could be severely affected. Inability to restore or replace critical capacity to an agreed level within an agreed time frame could prolong the impact of any disruption and could severely affect Statoil's business and operations.

Statoil encounters competition from other oil and gas companies in all areas of its operations

Statoil may experience increased competition from larger players with stronger financial resources and smaller ones with increased agility and flexibility. Gaining access to commercial resources via license acquisition, exploration, or development of existing assets is key to ensuring the long-term economic viability of the business and failure to address this could negatively impact future performance.

Technology is a key competitive advantage in Statoil's industry and our competition may be able to invest more in developing or acquiring intellectual property rights to technology that Statoil may require to remain competitive. Should Statoil's innovation and digitalisation lag behind the industry, its performance could be impeded.

Statoil's development projects and production activities involve many uncertainties and operating risks that can prevent Statoil from realising profits and cause substantial losses

Oil and gas projects may be curtailed, delayed or cancelled for many reasons, including equipment shortages or failures, natural hazards, unexpected drilling conditions or reservoir characteristics, irregularities in geological formations, accidents, mechanical and

76 Statoil, Annual Report on Form 20-F 2016

technical difficulties or challenges due to new technology. This is particularly relevant because of the physical environments in which some of Statoil’s projects are situated. Many of Statoil's development and production projects are located in deep waters or other harsh environments or have challenging field characteristics. In US onshore, low regional prices may cause certain areas to be unprofitable and the company may curtail production until prices recover. There is therefore a risk that prolonged low oil and gas prices, combined with the relatively high levels of tax and government take in several jurisdictions, could erode the profitability of some of Statoil’s projects.

Statoil faces challenges in achieving its strategic objective of successfully exploiting profitable growth opportunities

Statoil intends to continue to nurture attractive commercial opportunities in order to sustain future growth. This may involve acquisition of new businesses or properties to expand the existing portfolio or to move into new markets. This challenge will grow as global competition for access to new opportunities rises.

Statoil’s ability to increase this optionality depends on several factors; including the ability to:

· maintain and impart Statoil’s zero-harm safety culture

· identify suitable opportunities

· negotiate favourable terms

· develop new market opportunities or acquire properties or businesses in an agile and efficient way

· effectively integrate acquired properties or businesses into Statoil's operations

· arrange financing, if necessary and

· comply with legal regulations

Statoil anticipates significant investments and costs as it cultivates business opportunities in new and existing markets, and this process may incur or assume unanticipated liabilities, losses or costs associated with assets or businesses acquired. Failure by Statoil to successfully pursue and exploit new business opportunities could result in financial losses and inhibit growth. New projects may have different risk profiles than Statoil's existing portfolio. These and other effects of such acquisitions could result in Statoil having to revise its forecasts either or both with respect to unit production costs and production.

In addition, the pursuit of acquisitions or new business opportunities could divert financial and management resources away from Statoil's day-to-day operations to the integration of acquired operations or properties. Statoil may require additional debt or equity financing to undertake or consummate future acquisitions or projects, and such financing may not be available on terms satisfactory to Statoil, if at all, and it may, in the case of equity, be dilutive to Statoil's earnings per share.

The profitability of Statoil’s oil and gas production may be affected by limited transportation infrastructure when a field is in a remote location

Statoil's ability to exploit economically any discovered petroleum resources beyond its proved reserves will depend, among other factors, on the availability of the infrastructure required to transport oil and gas to potential buyers at a commercially acceptable price. Oil is transported by vessels, rail or pipelines to refineries, and natural gas is usually transported by pipeline or by vessels (for liquid natural gas) to processing plants and end users. Statoil may not be successful in its efforts to secure transportation and markets for all of its potential production.

Statoil is exposed to security threats on its information systems and digital infrastructure that could harm its assets and operations

Statoil’s security barriers are intended to protect its information systems and digital infrastructure from being compromised by unauthorised parties. Failure to maintain and develop these barriers may affect the confidentiality, integrity and availability of its information systems and digital infrastructure, including those critical to Statoil’s operations. Threats to Statoil’s information systems could result in significant financial damage to Statoil. Threats to Statoil’s industrial control systems are not limited by geography as Statoil’s digital infrastructure is accessible globally, and incidents in the industry in recent years have shown that parties who are able to circumvent barriers aimed at securing industrial control systems are capable and willing to perform attacks that destroy, disrupt or otherwise compromise operations. Such attacks could result in material losses or loss of life with consequent financial implications.

Some of Statoil's international interests are located in regions where political, social and economic instability could adversely impact Statoil’s business

Statoil has assets and operations located in diverse regions globally where potentially negative economic, social, and political developments could occur. These political risks and security threats require continuous monitoring. Adverse and hostile actions against Statoil's staff, its facilities, its transportation systems and its digital infrastructure (cybersecurity) may cause harm to people and disrupt Statoil's operations and further business opportunities in these or other regions, lead to a decline in production and otherwise adversely affect Statoil's business. This could have a materially adverse effect on Statoil's operations’ results and its financial condition.

Statoil's operations are subject to dynamic political and legal factors in the countries in which it operates

Statoil has assets in a number of countries with emerging or transitioning economies that, in part or in whole, lack well-functioning and reliable legal systems, where the enforcement of contractual rights is uncertain or where the governmental and regulatory framework is subject to unexpected change. Statoil's exploration and production activities in these countries are often undertaken together with national oil companies and are subject to a significant degree of state control. In recent years, governments and national oil

Statoil, Annual Report on Form 20-F 2016 77

companies in some regions have begun to exercise greater authority and to impose more stringent conditions on companies engaged in exploration and production activities. Intervention by governments in such countries can take a wide variety of forms, including:

· restrictions on exploration, production, imports and exports

· the awarding or denial of exploration and production interests

· the imposition of specific seismic and/or drilling obligations

· price and exchange controls

· tax or royalty increases, including retroactive claims

· nationalisation or expropriation of Statoil's assets

· unilateral cancellation or modification of Statoil's licence or contractual rights

· the renegotiation of contracts

· payment delays and

· currency exchange restrictions or currency devaluation

The likelihood of these occurrences and their overall effect on Statoil vary greatly from country to country and are hard to predict. If such risks materialise, they could cause Statoil to incur material costs and/or cause Statoil's production to decrease, potentially having a materially adverse effect on Statoil's operations or financial condition.

Statoil is exposed to potentially adverse changes in the tax regimes of each jurisdiction in which Statoil operates

Statoil has business operations in many countries around the world. Changes in the tax laws of the countries in which Statoil operates could have a material adverse effect on its liquidity and results of operations.

Statoil faces foreign exchange risks that could adversely affect the results of Statoil’s operations

Statoil's business faces foreign exchange risks and this is managed with USD as the base currency. Statoil has a large percentage of its revenues and cash receipts denominated in USD and sales of gas and refined products are mainly denominated in EUR and GBP. Further, Statoil pays a large portion of its income taxes, and a share of our operating expenses and capital expenditures, in NOK. The majority of Statoil's long term debt has USD exposure.

Statoil is exposed to risks relating to trading and supply activities

Statoil is engaged in substantial trading and commercial activities in the physical markets. Statoil also uses financial instruments such as futures, options, over-the-counter (OTC) forward contracts, market swaps and contracts for differences related to crude oil, petroleum products, natural gas and electricity in order to manage price volatility. Statoil also uses financial instruments to manage foreign exchange and interest rate risk. Trading activities involve elements of forecasting, and Statoil bears the risk of market movements, the risk of losses if prices develop contrary to expectations, and the risk of default by counterparties.

Non-compliance with anti-bribery, anti-corruption and other applicable laws, including failure to meet Statoil’s ethical requirements, exposes Statoil to legal liability and damage to its reputation, business and shareholder value

Statoil has activities in countries which present corruption risks and which may have weak legal institutions, lack of control and transparency. In addition, governments play a significant role in the oil and gas sector, through ownership of resources, participation, licensing and local content which leads to a high level of interaction with public officials. Statoil is, through its international activities, subject to anti-corruption and bribery laws in multiple jurisdictions, including the Norwegian Penal code, the US Foreign Corrupt Practices Act and the UK Bribery Act. A violation of any applicable anti-corruption and bribery laws could expose Statoil to investigations from multiple authorities, and any violations of laws may lead to criminal and/or civil liability with substantial fines. Incidents of non-compliance with applicable anti-corruption and bribery laws and regulations and the Statoil Code of Conduct could be damaging to Statoil's reputation, competitiveness and shareholder value.

Statoil’s insurance coverage may not provide adequate protection

Statoil maintains insurance coverage that includes coverage for physical damage to its oil and gas properties, third-party liability, workers' compensation and employers' liability, general liability, sudden pollution and other coverage. Statoil's insurance coverage includes deductibles that must be met prior to recovery. Statoil's external insurance is subject to caps, exclusions and limitations, and there is no assurance that such coverage will adequately protect Statoil against liability from all potential consequences and damages.

Statoil’s future performance depends on efficient operations and the ability to develop and deploy new technologies and new products

Our ability to remain efficient, to develop and adapt to new technology, to seek profitable renewable energy and other low-carbon energy solutions, are key success factors for future business. There is a possibility of Statoil not being able to define and implement the necessary changes due to the organisation’s capability, external competition or underestimated cost of implementing new technology. Any of these factors may have an adverse effect on Statoil’s future business goals.

Statoil may fail to secure the right level of workforce competence and capacity over the short and medium term

The uncertainty of the future of the oil industry in light of reduced oil and natural gas prices and climate policy changes, creates a risk in ensuring a robust workforce through industry cycles. The oil industry is a long term business and needs to take a long term perspective on workforce capacity and competence. Given the current extensive change agenda there is a risk that Statoil will fail to secure the right level of workforce competence and capacity.

78 Statoil, Annual Report on Form 20-F 2016

Statoil’s activities may be affected by international sanctions and trade restrictions

Statoil, like other major international energy companies, has a geographically diverse portfolio of reserves and operational sites, which may expose its business and financial affairs to political and economic risks, including operations in areas subject to international restrictions and sanctions.

Legislation and rules governing sanctions and trade restrictions are complex and constantly evolving. Moreover, changes in these laws and regulations can be unpredictable and happen swiftly. In addition, Statoil's business will constantly be subject to change. Accordingly, it should be understood that the below description does not reflect all parts of Statoil’s business where sanctions and trade restrictions are relevant, and that Statoil in the future could decide to take part in additional business activity where such laws and regulations are particularly relevant. While Statoil remains committed to doing business in compliance with all applicable sanctions and trade restrictions, there can be no assurance that no Statoil entity, officer, director, employee or agent is not in violation of such laws. Any such violation could result in substantial civil and/or criminal penalties and might materially adversely affect Statoil's business and results of operations or financial condition.

Statoil holds an interest in several different oil and gas projects in Russia both onshore and offshore. The majority of these projects result from a strategic cooperation with Rosneft Oil Company (Rosneft) initiated in 2012, some of these projects are located Arctic offshore and/or deepwater. In each of these projects, Rosneft holds the majority interest, while Statoil holds a minority interest. Sanctions imposed by Norway, the EU and the USA target, among others, Russia’s financial and energy sectors, including certain companies such as Rosneft and various affiliates, and specific activities related to oil exploration and production in the Arctic offshore area, and in deepwater or shale formation projects. Accordingly, aspects of the sanctions targeting Russia also affect Statoil’s business activity in the country. The continued progress of Statoil’s projects in Russia is, in part, dependent on various government authorisations and also the future development of sanctions and trade controls. Statoil continues to pursue its Russia business within the limitations of existing sanctions and trade controls. However, due to possible future developments there is no certainty that the projects can be progressed and concluded as initially planned.

Disclosure Pursuant to Section 13 (r) of the Exchange Act

Statoil is providing the following disclosure pursuant to Section 13(r) of the Exchange Act.

Statoil is a party to agreements with the National Iranian Oil Company (NIOC), namely, a Development Service Contract for South Pars Gas Phases 6, 7 & 8 (offshore part), an Exploration Service Contract for the Anaran Block and an Exploration Service Contract for the Khorramabad Block, which are located in Iran. Statoil's operational obligations under these agreements have terminated and the licenses have been abandoned. The cost recovery program for these contracts was completed in 2012, except for the recovery of tax and obligations to the Social Security Organisation (SSO). Since 2013, after closing Statoil’s office in Iran, Statoil's activity was focused on a final settlement with the Iranian tax and SSO authorities relating to the above mentioned agreements.

During 2016 Statoil paid the equivalent of USD 0.13 million in tax to Iranian authorities. Also during 2016 Statoil paid the equivalent of USD 153 in stamp duty to Iran Tax Organisation. All payments were made in local currency (Iranian Rials). The funds utilised for these purposes were held by Statoil in EN Bank (Iran). Additionally, NIOC, on behalf of Statoil, in 2016 paid a tax obligation of USD 2.47 million equivalent in Iranian Rial to the local tax authorities. The amount was settled towards recoverable costs from NIOC to Statoil.

Since 2009 Statoil has transparently and regularly provided information about its Iran related activity to the US State Department as well as to the Norwegian Ministry of Foreign Affairs. In a letter from the US State Department of 1 November 2010, Statoil was informed that the company was not considered to be a company of concern based on its previous Iran-related activities.

Statoil generated no net profit from the aforementioned 2016 activities. Payments of the above mentioned nature are expected to be made also in 2017, in relation to Statoil’s continued efforts to settle all remaining obligations related to its above mentioned historic activity in Iran.

Legal and regulatory risks

Compliance with health, safety and environmental laws and regulations that apply to Statoil's operations could materially increase its costs. The enactment of such laws and regulations in the future is uncertain.

Statoil incurs, and expects to continue to incur, substantial capital, operating, maintenance and remediation costs relating to compliance with increasingly complex laws and regulations for the protection of the environment and human health and safety, including:

Statoil, Annual Report on Form 20-F 2016 79

· higher price on greenhouse gas emissions

· costs of preventing, controlling, eliminating or reducing certain types of emissions to air and discharges to the sea

· remediaying of environmental contamination and adverse impacts caused by Statoil's activities

· compensation of cost related to persons and/or entities claiming damages as a result of Statoil's activities

Statoil`s activity is increasingly subject to statutory strict liability in respect of losses or damage suffered as a result of pollution caused by spills or discharges of petroleum from petroleum facilities.

Compliance with laws, regulations and obligations relating to climate change and other environmental regulations could result in substantial capital expenditure, reduced profitability as a result of changes in operating costs, and adverse effects on revenue generation and strategic growth opportunities. Statoil regularly assesses how changes in regulations, including introduction of stringent climate policies, may impact the oil price, the costs of developing new oil and gas assets, and the demand for oil and gas.

Statoil's operations in Norway are subject to emissions taxes as well as emissions allowances granted for Statoil's larger European operations under the EU Emissions Trading System. The agreed strengthening of the European Union's emission trading scheme may result in higher costs for installations at the NCS as the price of the EU ETS emissions allowances is expected to increase significantly towards 2030.

The Paris Agreement on climate change entered into force in November 2016. Norway, collectively with the European Union, intends to deliver 40% reductions in greenhouse gas emissions by 2030. The national targets are intended to be strengthened every five years. Additionally, Norway has set an ambition to achieve close to net zero emissions by 2050. The implications for the industry are not clear, however requirements to reduce emissions could result in increased costs.

Statoil's investments in North American onshore producing assets will be subject to evolving regulations that could affect these operations and their profitability (see also the risks related to hydraulic fracturing above). In the United States, the US Environmental Protection Agency (EPA) has taken steps to regulate greenhouse gas emissions under the Clean Air Act, including methane emissions from upstream oil and gas production. In 2016 the EPA finalized new source performance standards for methane emissions and began a process of information collection to inform further methane-related rulemaking. Statoil could incur higher operating costs in order to comply with any such new regulations and data gathering requirements.

Statoil is exposed to risk of supervision, review and sanctions for violations of regulatory laws at the supranational and national level. These include, among others, competition and antitrust laws and financial and trading.

Statoil's products are marketed and traded worldwide and therefore subject to competition and antitrust laws at the supranational and national level in multiple jurisdictions. Statoil is exposed to investigations from competition and antitrust authorities, and violations of the applicable laws and regulations may lead to substantial fines.

Statoil is also exposed to financial review from financial supervisory authorities such as the Norwegian Financial Supervisory Authority (FSA) and the US Securities and Exchange Commission (the SEC). Reviews performed by these authorities could result in changes to previous accounts and future accounting policies.

Statoil is listed on both the Oslo Børs and New York Stock Exchange (NYSE), and is registered with the SEC. Statoil is required to comply with the continuing obligations of these regulatory authorities, and violation of these obligations may result in imposition of fines or other sanctions.

The Norwegian Petroleum Supervisor (PSA) supervises all aspects of Statoil's operations, from exploration drilling through development and operation, to cessation and removal. Its regulatory authority covers the whole NCS as well as petroleum-related plants on land in Norway. Statoil is exposed to supervision from PSA, and as its business grows internationally other regulators, and such supervision could result in audit reports, orders and investigations.

The formation of a competitive internal gas market within the European Union (EU) and the general liberalisation of European gas markets could adversely affect Statoil's business.

The continuing liberalisation of EU gas markets following legislative instruments rolled out in 2011 and the implementation of these legislative instruments by member states, could affect Statoil's market position or result in a reduction in prices in Statoil's gas sales contracts. Statoil's exposure to hub gas prices has increased and correspondingly increased Statoil’s exposure to price volatility. Statoil continually monitors its contractual obligations and makes efforts to negotiate the most competitive pricing and other conditions available in the market.

The EU-wide quantity of carbon allowances issued each year under the Emission Trading Scheme (ETS) for greenhouse gas emission allowances began to decrease in a linear manner in 2013. The ETS can have a positive or negative impact on Statoil, depending on the price of carbon, which will consequently have an impact on the development of gas-fired power generation in the EU. Until now, the carbon price has been too low to replace coal with gas fired generation capacity. This effect has been worsened by heavy subsidising of renewables which has caused gas fired power plants to shut down. Current EU climate and energy policies do

80 Statoil, Annual Report on Form 20-F 2016

not address this problem, but there is a tendency towards more market based subsidies in the new guidelines on environment and energy aid.

Political and economic policies of the Norwegian State could affect Statoil’s business.

The Norwegian State plays an active role in the management of NCS hydrocarbon resources. In addition to its direct participation in petroleum activities through the State's direct financial interest (SDFI) and its indirect impact through legislation, such as tax and environmental laws and regulations, the Norwegian State, among other things, awards licences for exploration, production and transportation, approves exploration and development projects and applications for production rates for individual fields and may, if important public interests are at stake, also instruct Statoil and other oil companies to reduce petroleum production. Furthermore, in the production licences in which the SDFI holds an interest, the Norwegian State has the power to direct petroleum licences' actions in certain circumstances.

If the Norwegian State were to take additional action under its activities on the NCS or to change laws, regulations, policies or practices relating to the oil and gas industry, Statoil's NCS exploration, development and production activities and the results of its operations could be affected.

Risks related to state ownership

This section discusses some of the potential risks relating to Statoil’s business that could derive from the Norwegian State's majority ownership and from Statoil’s involvement in the SDFI.

The interests of Statoil’s majority shareholder, the Norwegian State, may not always be aligned with the interests of Statoil’s other shareholders, and this may affect Statoil’s decisions relating to the NCS

The Norwegian Parliament, known as the Storting, and the Norwegian State have resolved that the Norwegian State's shares in Statoil and the SDFI's interest in NCS licences must be managed in accordance with a coordinated ownership strategy for the Norwegian State's oil and gas interests. Under this strategy, the Norwegian State has required Statoil to continue to market the Norwegian State's oil and gas together with Statoil's own oil and gas as a single economic unit.

Pursuant to this coordinated ownership strategy, the Norwegian State requires Statoil, in its activities on the NCS, to take account of the Norwegian State's interests in all decisions that may affect the development and marketing of Statoil's own and the Norwegian State's oil and gas.

The Norwegian State directly held 67% of Statoil's ordinary shares as of 31 December 2016. Based on the Norwegian Public Limited Companies Act, the Norwegian State effectively has the power to influence the outcome of any vote of shareholders due to the percentage of Statoil's shares it owns, including amending its articles of association and electing all non-employee members of the corporate assembly. The employees are entitled to be represented by up to one-third of the members of the board of directors and one third of the corporate assembly.

The corporate assembly is responsible for electing Statoil's board of directors. It also makes recommendations to the general meeting concerning the board of directors' proposals relating to the company's annual accounts, balance sheet, allocation of profit and coverage of loss. The interests of the Norwegian State in deciding these and other matters and the factors it considers when casting its votes, especially under the coordinated ownership strategy for the SDFI and Statoil's shares held by the Norwegian State, could be different from the interests of Statoil's other shareholders.

If the Norwegian State's coordinated ownership strategy is not implemented and pursued in the future, then Statoil's mandate to continue to sell the Norwegian State's oil and gas together with its own oil and gas as a single economic unit is likely to be prejudiced. Loss of the mandate to sell the SDFI's oil and gas could have an adverse effect on Statoil's position in the markets in which it operates.

For further information about the mandate to sell the Norwegian State's oil and gas, see SDFI oil and gas marketing and sale in section 2.7 Corporate.

Risk management

Statoil’s overall risk management approach includes identifying, evaluating and managing risk in all its activities. In order to achieve optimal corporate solutions, Statoil bases its risk management on an enterprise-wide risk management approach. Statoil defines risk as a deviation from a specified reference value and the uncertainty associated with it. A positive deviation is defined as an upside risk, while a negative deviation is a downside risk. The reference value is most commonly a forecast, percentile or target. Statoil has an enterprise risk management (ERM) approach, which means that:

Statoil, Annual Report on Form 20-F 2016 81

· focus is on the value impact for Statoil

· risk is managed to make sure that Statoil’s operations are safe and in compliance with Statoil’s requirements and

· focus is on risk and reward at all levels in the organisation

Risk is managed in the business line and is an integral part of any manager’s responsibility. However, some risks are managed at corporate level. This includes oil and natural gas price risks, interest and currency risks, risk dimension in the strategy work, prioritisation processes and capital structure discussions.

Statoil’s corporate risk committee (CRC) is headed by the chief financial officer and its members include representatives of the principal business areas. It is an enterprise risk management advisory body that primarily advises the chief financial officer, but also the business areas' management on specific issues. The CRC assesses and advises on measures aimed at managing the overall risk to the group, and it proposes appropriate measures to adjust risk at the corporate level. The CRC is also involved in reviewing and developing Statoil’s risk policies. The committee meets regularly during the year to support Statoil’s risk management strategies, including hedging and trading strategies, as well as risk management methodologies. It regularly receives risk information that is relevant to it from Statoil’s corporate risk department.

· The following section describes how Statoil manages the market risks to which Statoil is exposed

Managing operational risk

Statoil manages risk in order to ensure safe operations and to achieve its corporate goals in compliance with its requirements

· All risks are related to Statoil's value chain, which denotes the value that is added in each step - from access, maturing, project execution and operation to market. In addition to the economic impact these risks could have on Statoil's cash flows, Statoil has a strong focus on avoiding HSE and integrity-related incidents (such as accidents, fraud and corruption). Most of the risks are managed by the principal business area line managers. Some operational risks are insurable and insured by Statoil’s captive insurance company operating in the Norwegian and international insurance markets

· Statoil’s risk management process is based on ISO31000 Risk management – principles and guidelines. The process provides a standardised framework and methodology for assessing and managing risk. A standardisation of the process across Statoil ASA and its subsidiaries allows for comparable risk levels and efficiency in decisions and it enables the organisation to create sustainable value while seeking to avoid incidents. The process seeks to ensure that risks are identified, analysed, evaluated and managed. Risk adjusting actions are subject to a cost benefit evaluation (except certain safety related risks which are subject to specific regulations)

Managing financial risk

The results of Statoil’s operations depend on a number of factors, most significantly those that affect the price it receives for the products

Statoil has developed policies aimed at managing the financial volatility inherent in some of the business exposures. In accordance with these policies, Statoil enters into various financial and commodity-based transactions (derivatives). While the policies and mandates are set at the company level, the business areas are responsible for marketing and trading commodities and for managing commodity-based price risks within mandates. Interest, liquidity, liability and credit risks are managed by the company's central finance department.

The factors that influence the results of Statoil’s operations include: the level of crude oil and natural gas prices, trends in the exchange rate between mainly the USD, EUR, GBP and NOK; Statoil’s oil and natural gas production volumes, which in turn depend on entitlement volumes under PSAs and available petroleum reserves, and Statoil’s own, as well as partners' expertise and cooperation in recovering oil and natural gas from those reserves; and changes in Statoil’s portfolio of assets due to acquisitions and disposals.

Statoil’s 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 Statoil operates, or possible or continued actions by members of the Organization of Petroleum Exporting Countries (OPEC) and/or other producing nations that affect price levels and volumes, refining margins, the cost of oilfield services, supplies and equipment, competition for exploration opportunities and operatorships, and deregulation of the natural gas markets, all of which may cause substantial changes to existing market structures and to the overall level and volatility of prices and price differentials.

The following table shows the yearly averages for quoted Brent Blend crude oil prices, natural gas average sales prices, refining reference margins and the USD/NOK exchange rates for 2016, 2015 and 2014.

Yearly average	2016	2015	2014

Average Brent oil price (USD/bbl)	43.7	52.4	98.9
Average invoiced gas prices - Europe (USD/mmbtu)	5.2	7.1	9.5
Refining reference margin (USD/bbl)	4.8	8.0	4.7
USD/NOK average daily exchange rate	8.4	8.1	6.3

82 Statoil, Annual Report on Form 20-F 2016

The illustration shows the indicative full-year effect on the financial result for 2017 given certain changes in the crude oil price, natural gas contract prices and the USD/NOK exchange rate. The estimated price sensitivity of Statoil’s financial results to each of the factors has been estimated based on the assumption that all other factors remain unchanged. The estimated indicative effects of the negative changes in these factors are not expected to be materially asymmetric to the effects shown in the illustration.

Significant downward adjustments of Statoil’s commodity price assumptions will result in impairment losses on certain producing and development assets in the portfolio. See note 10 Property, plant and equipment and note 11 Intangible assets to the Consolidated financial statements for sensitivity analysis related to impairment losses.

Statoil assesses oil and gas price hedging opportunities on a regular basis as a tool with regard to financial robustness and flexibility.

Fluctuating foreign exchange rates can have a significant impact on the operating results. Statoil’s revenues and cash flows are mainly denominated in or driven by USD, while a large portion of the operating expenses, capital expenditures and income taxes payable accrue in NOK. Statoil seeks 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. Statoil also engages in foreign currency management in order to cover the non-USD needs, which are primarily in NOK. In general, an increase in the value of USD in relation to NOK can be expected to increase Statoil’s reported earnings.

Historically, Statoil’s revenues have largely been generated by the production of oil and natural gas on the NCS. Norway imposes a 78% marginal tax rate on income from offshore oil and natural gas activities (a symmetrical tax system). For further information, see Taxation of Statoil in section 2.7 Corporate.

Statoil’s earnings volatility is moderated as a result of the significant proportion of its Norwegian offshore income that is subject to a 78% tax rate in profitable periods, and the significant tax assets generated by its Norwegian offshore operations in any loss-making periods. The basis for taxation is 3% of the dividend received, which is subject to the standard income tax rate (reduced from 25% in 2016 to 24% in 2017). Dividends received from Norwegian companies and from similar companies resident in the EEA for tax purposes, in which the recipient holds more than 90% of the shares and votes, are fully exempt from tax. Dividends from companies resident in the EEA that are not similar to Norwegian companies, companies in low-tax countries and portfolio investments outside the EEA will, under certain circumstances, be subject to the standard income tax rate (reduced from 25% in 2016 to 24% in 2016) based on the full amounts received.

Financial risk management

Statoil's business activities naturally expose the group to financial risk. The group's approach to risk management includes identifying, evaluating and managing risk in all activities using a top-down approach for the purpose of avoiding sub-optimisation and utilising correlations observed from a group perspective. Summing up the different market risks without including the correlations will

Statoil, Annual Report on Form 20-F 2016 83

overestimate Statoil’s total market risk. For this reason, Statoil utilises correlations between all of the most important market risks, such as oil and natural gas prices, product prices, currencies and interest rates, to assess the overall market risk. This approach also reduces the number of unnecessary transactions, which reduces transaction costs and avoids sub-optimisation.

In order to achieve the above effects, Statoil has centralised trading mandates (financial positions taken to achieve financial gains, in addition to established policies) so that all major/strategic transactions are coordinated through the CRC. Local trading mandates are therefore relatively small.

Statoil's activities expose the company to the following financial risks: market risks (including commodity price risk, interest rate risk and currency risk), liquidity risk and credit risk. For a discussion of financial risk management see note 5 Financial risk management in the Consolidated financial statements.

Disclosures about market risk

Statoil uses financial instruments to manage commodity price risks, interest rate risks, currency risks and liquidity risks. Significant amounts of assets and liabilities are accounted for as financial instruments.

See note 25 Financial instruments: fair value measurement and sensitivity analysis of market risk in the Consolidated financial statements, for details of the nature and extent of such positions, and for qualitative and quantitative disclosures of the risks associated with these instruments.

84 Statoil, Annual Report on Form 20-F 2016

2.11 SAFETY, SECURITY AND SUSTAINABILITY

Safety and security

Safety and security risks are particularly relevant for the oil and gas industry, because our core activities involve the risk of accidents and incidents. We work with flammable hydrocarbons at high pressure, often in harsh offshore environments and at height or depths. Oil spills are a major risk we need to handle in both our offshore and onshore oil and gas operations. To this end we have established a global oil spill response system, which includes close collaboration with industry peers and national and local communities.

We focus on identifying safety and security risks and having in place procedures and work processes to control them. Our objective is to be an industry leader in ensuring safe and secure operations that protect our people, the environment, the communities we work with and our assets.

For Statoil, 2016 was marked by two accidents with fatalities. A helicopter accident, in April, at Turøy in Norway in which 13 people were killed while travelling from the Gullfaks B platform in the North Sea. In May, one person was killed in an accident while working on the fabrication of a Statoil rig at the Samsung shipyard in Geoje, South Korea.

We also experienced a number of serious incidents in 2016, two of which had a major accident potential. At the Sture terminal (Norway) five people were exposed to H₂S gas (hydrogen sulphide) in October while working at a treatment facility for oily water inside the terminal area. All affected workers have since recovered after this incident. Statoil implemented immediate actions to avert this problem at all Statoil onshore plants where H₂S could cause a hazard.

Also in October, complications occurred during work to remove the production string from a well on the drilling rig Songa Endurance in the Troll field (Norway). There were no personal injuries, but drill mud containing gas was released. Procedures for handling well barriers have been strengthened.

All serious incidents are investigated in order to understand the causes and extract lessons learned to improve safety in the future. We use serious incident frequency (SIF) as a key indicator to monitor safety performance.

Our total serious incident frequency (SIF), including both actual and potential incidents, increased in 2016, with 0.8 incidents per million hours worked, compared to 0.6 in 2014 and 2015.

Total recordable injuries per million hours worked (TRIF) was 2.9 in 2016, compared to 2.7 in 2015.

The decline in our safety performance experienced in 2016 follows a decade of solid safety improvement.

Statoil has implemented a safety performance improvement programme to deal with this development. The main elements of the programme address risk management, safety guidance and practice, working safely with suppliers, safety leadership and engagement of the whole organisation.

In 2016, the total number of serious oil and gas leakages (with a leakage rate above 0.1 kg per second) was 18, down from 21 in 2015. Preventing oil and gas leakages is important to avoid of major accidents.

Statoil, Annual Report on Form 20-F 2016 85

Our performance over the past five years, related to oil spills, shows a significant reduction in the number of oil spills per year. From 2015 to 2016 there was a reduction in the number of oil spills from 172 to 148 spills. However, the total volume of oil spilt increased from 31 m³ in 2015 to 61 m³ in 2016. The largest oil spills in 2016 were in Norway. They included a 35 m³ oil spill from the Mongstad refinery, due to corrosion in a pipe and a 7 m³ oil spill from a leak in the export pipeline from Troll B.

Security is an important consideration for the energy industry. We assess security threats and risks on a continuous basis in order to achieve effective and proportionate security risk management. The terrorist attack against the Krechba plant in Algeria, in March, highlighted the security situation in North Africa. This was the single incident with the most significant impact for Statoil during 2016. In 2016 we continued our improvement programme in accordance with our road map to further strengthen our security culture and capabilities by 2020, focusing on areas such as competence and awareness, working with our suppliers and improving compliance.

Health and work environment

Statoil is committed to providing a healthy working environment for its employees. Systematic efforts are made to design and improve working conditions in order to prevent occupational injuries, work-related illness and sickness absence, due to both physical and psychosocial risk factors. A proactive psychosocial risk indicator is used to monitor health and work environment risk factors, in addition to the work related illness frequency indicator.

The most significant risk factors related to the work environment are noise, ergonomics, chemical risk as well as psychosocial conditions. In 2016, Statoil continued to fund research into exposure control for noise and chemicals, and research in to stroke treatment during evacuation from offshore facilities.

The sickness absence rate for Statoil ASA employees increased slightly from 4.1% in 2015 to 4.3% in 2016.

Climate change

Statoil supports the ambition set by the Paris Climate Agreement of December 2015 to limit the average global temperature rise to well below two degrees centigrade compared to pre-industrial levels by 2100. Our corporate ambition is to develop our business in support of the Paris Climate Agreement

Statoil’s approach to climate change as outlined in our climate roadmap focuses on:

· building a high value, low carbon oil and gas portfolio

· creating a material industrial position in new energy solutions

· accountability and collaboration.

Climate change is complex and requires global and cross sector cooperation. We are committed to working with our suppliers, customers, governments and peers to find innovative and commercially viable ways to reduce emissions across the oil and gas value chain. To spur technology development, for example, we continued through 2016 with our research and development (R&D) partnership with GE. In November 2016 we launched the USD 1 billion Climate Investments partnership with our global peers through the CEO-led Oil and Gas Climate Initiative (OGCI). And through our participation in the government-led Climate and Clean Air Coalition’s Oil and Gas Methane Partnership (OGMP) we continued our efforts to systematically address methane emissions and report on annual progress.

We work with governments and other organisations to support climate and energy policies that encourage fuel switching from coal to gas, growth in renewables, the deployment of carbon capture usage and storage (CCUS) and other low carbon solutions, and efficient production, distribution and use of energy globally. We have also teamed up with global peers through OGCI to help shape the industry’s climate response. Through the World Bank led Carbon Pricing Leadership Coalition and our membership of the International Emission Trading Association we continued our advocacy for a price on carbon during 2016. And through our membership in the OGCI and World Business Council for Sustainable Development (WBCSD) we expressed our continued support for the ambitions of the Paris climate agreement. Statoil is an endorser of the World Bank Global Gas Flaring Reduction Partnership and we have made a commitment to contribute to stopping routine flaring by 2030 through the World Bank Zero Routine Flaring by 2030 initiative.

The corporate executive committee and board of directors’ review climate change related business risks and opportunities, including market, regulatory and physical risk factors. We use tools such as internal carbon pricing, scenario planning and stress testing of projects against various oil and gas price assumptions. Statoil routinely tracks technology developments and changes in regulations, including the introduction of stringent climate policies, and assesses how these may impact the oil price, the costs of developing new oil and gas assets, and the demand for oil and gas.

Statoil initiated stress testing of our project portfolio against the International Energy Agency (IEA) and our own energy scenarios, in 2015, in response to a shareholder request. The stress test includes a range of price assumptions for oil, gas and carbon. Both Statoil’s and the IEA’s price assumptions may differ from actual and future oil, gas and carbon prices. As such, there can be no assurance that the analysis is a reliable indicator of the actual future impact of climate change on Statoil.

86 Statoil, Annual Report on Form 20-F 2016

Statoil’s efforts to reduce direct greenhouse gas emissions include improving energy efficiency; reducing methane emissions; eliminating routine flaring and scaling up carbon capture usage and storage (CCUS).

One of the most significant contributions to our emissions reductions in 2016 has been our efforts to reduce flaring at our Bakken (USA) asset. This contributed around 100 thousand tonnes to the total emission reductions. Energy efficiency improvements at our onshore facilities in Norway and the Kalundborg refinery in Denmark realised an additional 100 thousand tonnes in carbon dioxide (CO₂) reductions in 2016.

For our offshore operations in Norway we set a target in 2008 to achieve improved energy efficiency by 2020 equivalent to 800 thousand tonnes of CO₂ emissions (the so called Konkraft target). This was already achieved during 2015 through the implementation of energy efficiency projects. So we have raised the target to a total of 1.2 million tonnes of CO₂ emissions for the period 2008 to 2020.

The production from Statoil operated assets decreased from 1,073 million boe in 2015 to 1,030 million boe in 2016¹. The corresponding greenhouse gas emissions (so called Scope 1 emissions) decreased from 16.3 million tonnes CO₂ equivalents in 2015 to 15.4 million tonnes in 2016. Greenhouse gas emissions include carbon CO₂ and methane (CH₄), where CO₂ constitutes the largest part (14.8 million tonnes in 2016 compared to 15.4 tonnes in 2015). Methane (CH₄) emissions decreased from 36.3 thousand tonnes in 2015 to 24.2 thousand tonnes in 2016.

The decrease in CO₂ emissions in 2016, relative to 2015, was the result of emissions reductions efforts, reduced exploration activity and operational disruptions associated with turnarounds at our facilities on the Norwegian continental shelf and our onshore oil refining and gas processing facilities in Norway and Denmark. The 33% decrease in methane emissions in 2016, compared to 2015, was largely due to a change in methodology for the estimation of fugitive emissions for our Norwegian continental shelf assets, and updated fugitive emissions measurements for our oil refining and gas processing facilities.

In 2016, we introduced a 2030 carbon intensity target of 8 kg CO₂ per boe for our upstream exploration and production activities. This supplements the 2020 carbon intensity target of 9 kg of CO₂ per boe by 2020 established in 2015. These targets are based on production and emission forecasts and emission reduction targets for each business area. Our targets are subject to significant uncertainty because they relate to events and circumstances that will occur in the future. Changes in our asset portfolio and production can also affect the result for a particular year.

Upstream carbon intensity was established as a corporate-wide key performance indicator in 2016. It was included in the assessment of reward for the CEO. Statoil’s upstream carbon intensity in 2016 was 10 kg CO₂ per boe, less than 60% of the industry average of 17 kg as measured by the International Association of Oil and Gas Producers (Environmental Performance Indicators, 2015 data).

Statoil’s operations in Europe are subject to emissions allowances according to the EU Emissions Trading System (EU ETS). Statoil’s Norwegian operations are subject to both the Norwegian offshore CO₂ tax and EU ETS quotas. In 2016, Statoil paid some USD 496 million in CO₂ tax and quotas compared to USD 476 million in 2015.

¹ Climate and environmental performance data represent the total for Statoil operated assets (i.e. reflecting operational control rather than equity share), except for scope 3 emissions.

Statoil, Annual Report on Form 20-F 2016 87

Growth opportunities for Statoil within renewables and new energy solutions include both commercial investments and research and development (R&D). To date Statoil has invested USD 2.3 billion in offshore wind projects and is engaged in carbon capture usage and storage. In 2016 approximately 17% (USD 52.4 million) of Statoil’s spend on R&D efforts addressed energy efficiency, carbon capture and renewables.

Environmental impact and resource efficiency

Statoil is committed to using resources efficiently and responsible management of waste, emissions to air and impacts on ecosystems. This reduces the impact on the local environment and can also save costs.

Responsible water management is important for Statoil. Total fresh water consumption decreased from 14.5 million cubic metres in 2015 to 13.5 million cubic metres in 2016. The main contributor to this decrease in water consumption was the lower number of wells fracked, relative to 2015, in our US onshore shale and tight oil assets. We work actively to improve 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 39 thousand tonnes in 2016, down from 42 thousand tonnes in 2015. Sulphur oxide emissions were 1.8 thousand tonnes, down from 2.5 thousand tonnes in 2015. Total emissions of non-methane volatile organic compounds were 49 thousand tonnes in 2016, down from 60 thousand tonnes in 2015.

Statoil is concerned with valuing and protecting biodiversity and ecosystems and follows precautionary principles to minimise potential negative effects of the company’s activities. Statoil supports research programmes to increase knowledge about ecosystems and biodiversity and collaborates with industry peers to share knowledge and develop tools for biodiversity management. In addition, Statoil works with our suppliers to minimise invasive aquatic species and reduce risks pertaining to accidental spills related to shipping transportation.

During 2016 we saw a 42% rise in the volume of hazardous waste generated, from 309 thousand tonnes in 2015 to 438 thousand tonnes in 2016. The main contributor to this volume increase was drilling and well start-up activities, on the Norwegian continental shelf, at locations without treatment facilities for oil contaminated water. As such the untreated oil contaminated water was sent to shore for treatment.

A change was made, in 2016, to the definitions we use for reporting of hazardous waste recovery. Previously, treated oil contaminated water was not included in our categorisation of recovered hazardous waste. From 2016, treated oil contaminated water will be included in our hazardous waste recovery calculations. The rationale for this change is alignment with the way both our peers and the contractors handling our waste are reporting. It also serves to highlight the company’s efforts to treat hazardous waste. The impact on our waste recovery rate is significant, with a rise from 16% in 2015 to 84% for 2016.

For our US onshore operations drill cuttings and produced and flow-back water are exempt from hazardous waste regulations. Consequently, these exempt wastes are not included in the hazardous waste generation or recovery figures. For our US onshore operations in 2016 81 thousand tonnes of drill cuttings and solid waste were sent to landfill, and 4.3 million cubic meters of produced and flow back water was directed to deep well disposal.

In 2016 the volume of non-hazardous waste generated for all Statoil operated assets was 50 thousand tonnes, and the recovery rate was 56% in 2016 compared to 63% in 2015. Regular discharges of oil to water were 1.4 thousand tonnes in 2016, the same as for 2015.

Working with suppliers

Statoil is committed to using suppliers who operate in accordance with Statoil’s values and who maintain high standards of safety, security and sustainability. These aspects are incorporated in all phases of the procurement process. Potential suppliers must meet Statoil’s minimum requirements in order to qualify as a supplier, including those related to safety, security and sustainability.

Statoil expect our suppliers to comply with applicable laws, respect internationally recognised human rights and adhere to ethical standards which are consistent with our ethical requirements, when working for Statoil. Potential suppliers for contracts valued at more than USD 800 thousand are, in addition, required to sign Statoil’s Supplier Declaration, which establishes minimum requirements for ethics, anti-corruption, environment, health, safety, respect for human rights, and for further promoting these requirements among their own suppliers. Potential suppliers are also screened for integrity risk, in accordance with our procedures for integrity due diligence.

Human rights

Statoil seeks to conduct its business in a way that is consistent with the UN Guiding Principles on Business and Human Rights (the UN Guiding Principles), the ten UN Global Compact principles and the Voluntary Principles on Security and Human Rights. Statoil is committed to respecting internationally recognised human rights as laid out in the International Bill of Human Rights, the International Labour Organization's 1998 Declaration on Fundamental Rights and Principles at Work, and applicable standards of international humanitarian law.

Labour rights and working conditions for our workforce and suppliers, human rights of individuals in communities and human rights in security arrangements are the three broad focus areas for human rights for Statoil’s activities.

88 Statoil, Annual Report on Form 20-F 2016

Human rights aspects are integrated into relevant internal management processes, tools and training. On-going activities, business relationships and new business opportunities are assessed for potential human rights impacts and aspects, following a risk-based approach. In 2016, supplier screening and verification practices were strengthened.

In 2016 Statoil focused on strengthening its processes for managing human rights in our supply chain and on raising awareness through training. We strengthened our human rights risk screening and verification tools and conducted 65 supplier verifications across 21 countries in 2016. Over 800 employees attended classroom training about human rights in the supply chain.

During 2016 Statoil’s Human Rights Steering Committee (HRSC), responsible for overseeing the development and implementation of Statoil’s human rights policy, closely followed the ongoing implementation efforts and provided guidance on human rights related reporting requirements.

Statoil recognises that a company-wide commitment to respect human rights requires continuous training and awareness raising in order to embed good practices throughout the organisation. To this effect additional human rights training materials, including a human rights e-learning programme were developed in 2016. During 2016 over 3,000 staff and hired contractors have registered for the e-learning course.

The context of Statoil’s operations requires that security services are engaged to safeguard Statoil’s people and property. Particular focus is needed to ensure respect for human rights in security arrangements, in jurisdictions where security services are not well regulated or security personnel are not adequately trained. Statoil follows international standards of good practices in security and human rights. Statoil’s commitment

to the Voluntary Principles on Security and Human Rights is reflected in policies and procedures for risk assessment, deployment, training and follow-up of private and public security providers.

Transparency, ethics and anti-corruption

Transparency is a cornerstone of good governance. It is embodied in our corporate values. Transparency allows business to prosper in a predictable and competitive environment and enables society to hold governments and business accountable. Statoil supports and promotes effective, transparent and accountable management of wealth derived from the extractives industries.

Statoil supports and engages in global transparency initiatives through its membership in the Extractive Industries Transparency Initiative (EITI), the United Nations Global Compact Anti-Corruption Working Group and the World Economic Forum’s Partnering Against Corruption Initiative (PACI). Statoil was one of the first major oil and gas companies to voluntarily start disclosing payments to governments on a country-by-country basis. Our 2016 Payments to Governments report discloses payments per project for our extractive activities, in accordance with mandatory requirements in Norway.

Statoil believes that doing business in an ethical and transparent manner is a prerequisite for sustainable business. Statoil’s Code of Conduct (the Code) prohibits all forms of corruption, including facilitation payments. Statoil maintains a robust company-wide anti-corruption compliance programme to implement our zero-tolerance policy. A global network of compliance officers is integrated into our business activities to ensure the appropriate consideration is given to ethics and anti-corruption in Statoil’s business activities, regardless of where they take place.

The Code reflects Statoil’s values and the commitment to high ethical standards in business activities. It describes our requirements in areas such as anti-corruption, fair competition, human rights and a non-discriminatory working environment with equal opportunities. It applies to Statoil employees, board members and hired personnel.

Statoil seeks to work with others who share the company’s commitment to business integrity and who have codes of conduct consistent with Statoil’s Code. Before entering into a new business relationship, or extending an existing one, the relationship has to satisfy Statoil’s integrity due diligence requirements. Statoil have a process to develop in-depth knowledge of our suppliers, partners, and the markets in which we work. Our vetting process is risk-based, allowing us to target resources where we see potential concerns. In joint ventures and business partnerships that are not controlled by Statoil, Statoil encourages the adoption of ethics and anti-corruption policies and procedures that are consistent with the company’s standards.

All employees have to confirm annually that they understand and will comply with the Code. The purpose of this confirmation is to remind the individual about their duty to comply with Statoil’s values and ethical requirements. Disciplinary measures are in place for anyone working for Statoil who does not comply with the code. This may entail termination of their contract.

The Code requires reporting of possible violations of our ethical requirements or other unethical misconduct. Concerns can be reported through internal channels or through the publicly available Ethics Helpline, which allows for anonymous reporting. The number and types of cases from the helpline is reported quarterly to the board of directors. In 2016 we received 51 cases through the Ethics Helpline.

Other relevant reports

More information about Statoil's policies and approach taken to manage safety and sustainability performance is available on our corporate website. Information on our activities, plans and performance in 2016 is available in Statoil ASA’s 2016 Sustainability Report, which has been prepared with reference to the Global Reporting Initiative G4 Guidelines. This report is also available on our corporate website: www.statoil.com.

Statoil, Annual Report on Form 20-F 2016 89

2.12 OUR PEOPLE

In Statoil we work together to shape the future of energy in a partnership between the organisation and the individual. We all apply our skills and personal commitment to help Statoil towards achieving our vision.

Statoil aims to offer challenging and meaningful job opportunities that attract and retain the right people. Through our engagement, creativity and collaboration, we aim to build a better Statoil for tomorrow. We are committed to creating a caring and inspiring working environment, promoting diversity and equal opportunities for all employees.

At the same time, given the current commercial environment, the company continues to focus on efficiency. We are committed to doing this in a way that is respectful and considerate to those affected. In particular, employees are involved in initiatives to increase efficiency. Employees have demonstrated strong engagement in this process, which is also confirmed by the high employee engagement score of 4.6 (6 being the highest) in the 2016 Global People Survey (GPS).

Learning and development is at the core of Statoil. We encourage our employees to take responsibility for their own learning and development, continuously build new skills and share knowledge. Our corporate university is our platform for learning. It enables the company to build the capabilities needed to deliver on its strategy, continuously improve, and take the lead in developing leadership and technology. People@Statoil is our common process for people development, deployment, performance and reward. It is an integrated part of performance management and applies to all employees.

EMPLOYEES IN STATOIL

The Statoil group employs 20,539 employees. Of these, approximately 18,000 are employed in Norway and approximately 2,500 outside Norway.

	Number of employees			Women
Permanent employees and percentage of women in the Statoil group	2016	2015	2014	2016	2015	2014

Norway	18,034	18,977	19,670	30%	30%	30%
Rest of Europe	838	855	909	28%	29%	31%
Africa	78	98	117	36%	35%	34%
Asia	73	97	135	59%	36%	52%
North America	1,230	1,265	1,375	35%	35%	34%
South America	286	289	310	37%	38%	40%

Total	20,539	21,581	22,516	31%	30%	31%

Non-OECD	541	590	677	40%	40%	40%

Total workforce by region, employment type and new hires in the Statoil group in 2016

Geographical Region		Permanent employees	Consultants	Total Workforce¹⁾	Consultants (%)	Part time (%)	New hires

Norway		18,034	321	18,355	2%	3%	81
Rest of Europe		838	82	920	9%	2%	66
Africa		78	3	81	4%	NA	6
Asia		73	2	75	3%	NA	2
North America		1,230	94	1,324	7%	0%	89
South America		286	2	288	1%	2%	7

Total		20,539	504	21,043	2%	3%	251

Non-OECD		541	7	548	1%	NA	24

1)	Contractor 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 30,000 in 2016.

90 Statoil, Annual Report on Form 20-F 2016

Statoil works systematically to build a diverse workforce by attracting, recruiting, developing and retaining people of both genders and different nationalities and age groups across all types of positions. In 2016, 19% of employees and 23% 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 2016, 73% of new hires in Statoil were non-Norwegians and 34% were women.

Our annual intake of apprentices reflects our long-term commitment to the education and training of young technicians and operators in our industry. In 2016, we awarded 132 apprenticeships, of which 45 were to women. The total number of apprentices at year end was 271 (including 81 women).

In Statoil, the total turnover rate for 2016 was 3.6%. On 31 December 2016, the Statoil group employed 20,539 permanent employees and 3% of the workforce worked part-time. In the annual organisational and working environment survey, which continued to have a high response rate of 84%, our employees reported an overall satisfaction of 4.6, maintaining the high score from 2015.

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 contractor personnel, defined as third party service providers to our onshore and offshore operations, are not included in the table. These were roughly estimated to be around 30,000 in 2016. The information about people policies applies to Statoil ASA and its subsidiaries.

Equal opportunities

We are committed to building a workplace that promotes diversity and inclusion through its people processes and practices. The importance of diversity is stated explicitly in Statoil's values and Code of Conduct. Our goal is to create the same opportunities for everyone and do not tolerate discrimination or harassment of any kind in our workplace. In 2016, we continued to focus on strengthening women in leadership and professional positions and on building broad international experience in our workforce. The results from the Global People Survey for 2016 indicate that employees strongly agree that there is a zero tolerance for discrimination and harassment in Statoil. The scoring for the 2016 GPS was 5.1 (6 being the highest), maintaining the high score from 2015.

In 2016, the overall percentage of women in the company was 31%. The percentage of women in the board of directors is 50% (67% among the employee representatives and 43% among members elected by the shareholders). In the corporate executive committee, the female representation has increased from last year’s 18% to 27% in 2016. We continue to focus on increasing the number of female managers through our development programmes, and in 2016 the share of women in management was 29%, an increase of 1% from 2015. We are committed to maintaining the positive trend in 2017. We pay close attention to male-dominated positions and discipline areas, and in 2016 the proportion of female engineers remained stable at 27% in Statoil ASA.

We reward our people on the basis of their performance, giving equal emphasis to what we deliver and how we deliver. Our approach 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, which remained at an average of 98% for Statoil ASA, which represents the 85% of our workforce.

Unions and representatives

We respect our employees’ right to freedom of association and thereby their right to negotiate and cooperate through relevant representative bodies. The specific ways in which we involve our employees and/or their appropriate representatives in business and organisational issues may vary according to local laws and practices in specific geographical locations.

In Statoil ASA, 73% of the employees in the parent company are members of a trade union. Work councils and working environment committees are established where required by law or agreement.

In Norway, the formal basis for collaboration with labour unions is established in the Basic Agreements between the Confederation of Norwegian Enterprise (NHO) and the corresponding respective national labour confederations (unions). We have local collective wage agreements with five trade unions in Statoil ASA.

The European Works Council continues to be an important forum for collaboration between the company and our European employees.

Statoil promotes good employee and industrial relations practices through various networks and forums, including IndustriALL Global Union (IndustriAll) and the International Labour Organisation (ILO).

In 2016 we prolonged the temporary collaboration forum set up in 2015 with trade unions and safety delegates in Norway specifically to engage in the Organisational efficiency programme. Under a common framework, we have relied largely on the internal job market to find new employment opportunities and measures such as severance pay and early retirement.

Statoil, Annual Report on Form 20-F 2016 91

3 CORPORATE COVERNANCE

92 Statoil, Annual Report on Form 20-F 2016

3.1 INTRODUCTION

Statoil’s objective and principles

Statoil's objective is to create long-term value for its shareholders through the exploration for and production, transportation, refining and marketing of petroleum and petroleum-derived products and other forms of energy.

In pursuing its corporate objective, Statoil is committed to the highest standard of governance and to cultivating a values-based performance culture that rewards exemplary ethical practices, respect for the environment and personal and corporate integrity. Statoil believes that there is a link between high-quality governance and the creation of shareholder value.

The work of the board of directors is based on the existence of a clearly defined division of roles and responsibilities between the shareholders, the board of directors and the company's management.

Statoil’s governing structures and controls help to ensure that Statoil runs its business in a profitable manner for the benefit of shareholders, employees and other stakeholders in the societies in which Statoil operates.

The following principles underline Statoil’s approach to corporate governance:

· All shareholders will be treated equally

· Statoil will ensure that all shareholders have access to up-to-date, reliable and relevant information about its activities

· Statoil will have a board of directors that is independent (as defined by Norwegian Standards) of the group's management. The board focuses on preventing conflicts of interest between shareholders, the board of directors and the company's management

· The board of directors will base its work on the principles for good corporate governance applicable at all times

Corporate governance in Statoil is subject to regular review and discussion by the board of directors.

Articles of association

Statoil's current articles of association were adopted at the annual general meeting of shareholders on 14 May 2013, and last changed on 26 October 2016 following a share capital increase in connection to Statoil’s scrip dividend program.

Summary of Statoil’s articles of association:

Name of the company

The registered name is Statoil ASA. Statoil is a Norwegian public limited company.

Registered office

Statoil’s registered office is in Stavanger, Norway, registered with the Norwegian Register of Business Enterprises under number 923 609 016.

Objective of the company

The objective of Statoil is, either by itself or through participation in or together with other companies, to engage in the exploration, production, transportation, refining and marketing of petroleum and petroleum-derived products, and other forms of energy, as well as other business.

Share capital

Statoil’s share capital is NOK 8,112,623,528 divided into 3,245,049,411 ordinary shares.

Nominal value of shares

The nominal value of each ordinary share is NOK 2.50.

Board of directors

Statoil’s articles of association provide that the board of directors shall consist of nine to 11 directors. The board, including the chair and the deputy chair, shall be elected by the corporate assembly for a period of up to two years.

Corporate assembly

Statoil has a corporate assembly comprising 18 members who are normally elected for a term of two years. The general meeting elects 12 members with four deputy members, and six members with deputy members are elected by and from among the employees.

General meetings of shareholders

Statoil, Annual Report on Form 20-F 2016 93

Statoil’s annual general meeting is held no later than 30 June each year. The meeting will consider the annual report and accounts, including the distribution of any dividend, and any other matters required by law or the articles of association.

Documents relating to matters to be dealt with at general meetings do not need to be sent to all shareholders if the documents are accessible on Statoil’s website. A shareholder may nevertheless request that such documents be sent to him/her.

Shareholders may vote in writing, including through electronic communication, for a period before the general meeting. In order to practise advance voting, the board of directors must stipulate applicable guidelines. Statoil's board of directors adopted guidelines for such advance voting in March 2012, and these guidelines are described in the notices of the annual general meetings.

Marketing of petroleum on behalf of the Norwegian State

Statoil’s articles of association provide that Statoil is responsible for marketing and selling petroleum produced under the SDFI's shares in production licences on the Norwegian continental shelf as well as petroleum received by the Norwegian State paid as royalty together with its own production. Statoil’s general meeting adopted an instruction in respect of such marketing on 25 May 2001, as most recently amended by authorisation of the annual general meeting on 11 May 2016.

Nomination committee

The tasks of the nomination committee are to make recommendations to the general meeting regarding the election of and fees for shareholder-elected members and deputy members of the corporate assembly, to make recommendations to the corporate assembly regarding the election of and fees for shareholder-elected members of the board of directors, to make recommendations to the corporate assembly regarding the election of the chair and the deputy chair of the board and to make recommendations to the general meeting regarding the election of and fees for members of the nomination committee. The general meeting may adopt instructions for the nomination committee.

The articles of association are enclosed hereto as Exhibit 1, and are also available at www.statoil.com/articlesofassociation.

Code of Conduct

Ethics – Statoil’s approach

Statoil believes that responsible and ethical behaviour is a necessary condition for a sustainable business. Statoil’s Code of Conduct (the Code) is based on its values and reflects Statoil’s commitment to high ethical standards in all its activities.

Our Code of Conduct

The Code describes Statoil’s code of business practice and the requirements to expected behaviour in areas such as anti-corruption, fair competition, human rights and non-discrimination working environments with equal opportunities. The Code applies to Statoil’s board members, employees and hired personnel.

Statoil seeks to work with others who share its commitment to ethics and compliance, and Statoil manages its risks through in-depth knowledge of suppliers, business partners and markets. Statoil expects its suppliers and business partners to comply with applicable laws, respect internationally recognised human rights and adhere to ethical standards which are consistent with Statoil’s ethical requirements when working for or together with Statoil. In joint ventures and entities where Statoil does not have control, Statoil makes good faith efforts to encourage the adoption of ethics and anti-corruption policies and procedures that are consistent with its standards. Anyone working for Statoil who does not comply with the Code faces disciplinary action, up to and including summery dismissal or termination of their contract.

Training and Certifying the Code

Code of Conduct training and comprehensive trainings on specific issues, including anti-corruption and anti-trust, is carried out to explain how the Code applies and to describe the tools that Statoil has made available to address risk.

All Statoil employees have to annually confirm electronically that they understand and will comply with the Code (Code certification). The Code certification reminds the individuals of their duty to comply with Statoil’s values and ethical requirements and creates an environment with open dialog on ethical issues, both internally and externally.

Anti-corruption compliance programme

Statoil is against all forms of corruption including bribery, facilitation payments and trading in influence and has a company-wide anti-corruption compliance programme which implements its zero-tolerance policy. The programme includes mandatory procedures designed to comply with applicable laws and regulations and training on relevant issues such as gifts, hospitality and conflicts of interest. Compliance officers, who are responsible for ensuring that ethics and anti-corruption considerations are integrated into Statoil’s business activities, constitute an important part of the programme.

In 2016, Statoil introduced and rolled out an updated and more user-friendly Code of Conduct, which included new information on international trade restrictions and money laundering. Statoil continued to develop its implementation of the Code including focus on

94 Statoil, Annual Report on Form 20-F 2016

supplier monitoring and follow-up and integrating risk assessments more deeply into the business. Statoil also introduced a holistic approach to discussing various compliance and sustainability issues, and the links between the two, through workshops for internal and external stakeholders.

Speak Up

Statoil is committed to maintain an open dialog on ethical issues. The Code requires those who have a question or suspect misconduct to raise their concern either through internal channels or through Statoil’s external Ethics Helpline. Employees are encouraged to discuss their concerns with their supervisor. Statoil recognises that raising a concern is not always easy so there are several internal channels for taking concerns forward, including through human resources or the ethics and compliance function in the legal department. Concerns can also be expressed through the externally operated Ethics Helpline which is available 24/7, and allows for anonymous reporting and two-way communication through the use of a pin-code. Statoil has a non-retaliation policy for anyone who reports in good faith.

More information about Statoil’s policies and requirements related to the Code of Conduct is available on www.statoil.com/ethics.

Compliance with NYSE listing rules

Statoil's primary listing is on the Oslo Børs, but Statoil is also registered as a foreign private issuer with the US Securities and Exchange Commission and listed on the New York Stock Exchange.

American Depositary Shares represent the company's ordinary shares listed on the New York Stock Exchange (NYSE). While Statoil's corporate governance practices follow the requirements of Norwegian law, Statoil is also subject to the NYSE's listing rules.

As a foreign private issuer, Statoil is exempted from most of the NYSE corporate governance standards that domestic US companies must comply with. However, Statoil is required to disclose any significant ways in which its corporate governance practices differ from those applicable to domestic US companies under the NYSE rules. A statement of differences is set out below:

Corporate governance guidelines

The NYSE rules require domestic US companies to adopt and disclose corporate governance guidelines. Statoil's corporate governance principles are developed by the management and the board of directors, in accordance with the Norwegian Code of Practice for Corporate Governance and applicable law. Oversight of the board of directors and management is exercised by the corporate assembly.

Director independence

The NYSE rules require domestic US companies to have a majority of "independent directors". The NYSE definition of an "independent director" sets out five specific tests of independence and also requires an affirmative determination by the board of directors that the director has no material relationship with the company.

Pursuant to Norwegian company law, Statoil's board of directors consists of members elected by shareholders and employees. Statoil's board of directors has determined that, in its judgment, all of the shareholder-elected directors, except one, are independent. In making its determinations of independence, the board focuses inter alia on there not being any conflicts of interest between shareholders, the board of directors and the company's management. It does not strictly make its determination based on the NYSE's five specific tests, but take into consideration all relevant circumstances which may in the board’s view affect the directors’ independence. The directors elected from among Statoil's employees would not be considered independent under the NYSE rules because they are employees of Statoil. None of the employee-elected directors are an executive officer of the company.

For further information about the board of directors, see the section Board of directors.

Board committees

Pursuant to Norwegian company law, managing the company is the responsibility of the board of directors. Statoil has an audit committee, a safety, sustainability and ethics committee and a compensation and executive development committee. They are responsible for preparing certain matters for the board of directors. The audit committee and the compensation and executive development committee operate pursuant to charters that are broadly comparable to the form required by the NYSE rules. They report on a regular basis to, and are subject to, continuous oversight by the board of directors. For further information about the board’s sub-committees, see the section Board of directors.

Statoil complies with the NYSE rule regarding the obligation to have an audit committee that meets the requirements of Rule 10A-3 of the US Securities Exchange Act of 1934.

As required by Norwegian company legislation, the members of Statoil's audit committee include an employee-elected director. Statoil relies on the exemption provided for in Rule 10A-3(b)(1)(iv)(C) from the independence requirements of the US Securities Exchange Act of 1934 with respect to the employee-elected director. Statoil does not believe that its reliance on this exemption will materially

Statoil, Annual Report on Form 20-F 2016 95

adversely affect the ability of the audit committee to act independently or to satisfy the other requirements of Rule 10A-3 relating to audit committees. The other members of the audit committee meet the independence requirements under Rule 10A-3.

Among other things, the audit committee evaluates the qualifications and independence of the company's external auditor. However, in accordance with Norwegian law, the auditor is elected by the annual general meeting of the company's shareholders.

Statoil does not have a nominating/corporate governance sub-committee formed from its board of directors. Instead, the roles prescribed for a nominating/corporate governance committee under the NYSE rules are principally carried out by the corporate assembly and the nomination committee which is elected by the general meeting of shareholders. NYSE rules require the compensation committee of US companies to comprise independent directors under the NYSE rules, recommend senior management remuneration and make a determination on the independence of advisors when engaging them. Statoil, as foreign private issuer, is exempt from complying with these rules and is permitted to follow its home country regulations. Statoil considers all, but one, its compensation committee members to be independent (under Statoil’s framework which, as discussed above, is not identical to that of NYSE). Statoil's compensation committee makes recommendations to the board about management remuneration, including that of the CEO. The compensation committee assesses its own performance and has the authority to hire external advisors. The nomination committee, which is elected by the general meeting of shareholders, recommends to the corporate assembly the candidates and remuneration of the board of directors. Also, the nomination committee recommends to the general meeting of shareholders the candidates and remuneration of the corporate assembly and the nomination committee.

Shareholder approval of equity compensation plans

The NYSE rules require that, with limited exemptions, all equity compensation plans must be subject to a shareholder vote. Under Norwegian company law, although the issuance of shares and authority to buy back company shares must be approved by Statoil's annual general meeting of shareholders, the approval of equity compensation plans is normally reserved for the board of directors.

3.2 General meeting of shareholders

The general meeting of shareholders is Statoil’s supreme corporate body. It serves as a democratic and effective forum for interaction between the company’s shareholders, board of directors and management.

The next annual general meeting (AGM) is scheduled for 11 May 2017 in Stavanger, Norway, with simultaneous transmission by webcast through our website. The AGM is conducted in Norwegian, with simultaneous English translation during the webcast. At Statoil's AGM on 11 May 2016, 76.79% of the share capital was represented either by advance voting, in person or by proxy.

The main framework for convening and holding Statoil's AGM is as follows:

Pursuant to Statoil’s articles of association, the AGM must be held by the end of June each year. Notice of the meeting and documents relating to the AGM are published on Statoil's website and notice is sent to all shareholders with known addresses at least 21 days prior to the meeting. All shareholders who are registered in the Norwegian Central Securities Depository (VPS) will receive an invitation to the AGM. Other documents relating to Statoil's AGMs will be made available on Statoil's website. A shareholder may nevertheless request that documents that relate to matters to be dealt with at the AGM be sent to him/her.

Shareholders are entitled to have their proposals dealt with at the AGM if the proposal has been submitted in writing to the board of directors in sufficient time to enable it to be included in the notice of meeting, i.e. no later than 28 days before the meeting. Shareholders who are unable to attend may vote by proxy.

As described in the notice of the general meeting, shareholders may vote in writing, including through electronic communication, for a period before the general meeting.

The AGM is normally opened and chaired by the chair of the corporate assembly. If there is a dispute concerning individual matters and the chair of the corporate assembly belongs to one of the disputing parties, or is for some other reason not perceived as being impartial, another person will be appointed to chair the AGM. This is in order to ensure impartiality in relation to the matters to be considered. As Statoil has a large number of shareholders with a wide geographic distribution, Statoil offers shareholders the opportunity to follow the AGM by webcast.

The following matters are decided at the AGM:

· Approval of the board of directors' report, the financial statements and any dividend proposed by the board of directors and recommended by the corporate assembly

· Election of the shareholders' representatives to the corporate assembly and approval of the corporate assembly's fees

· Election of the nomination committee and approval of the nomination committee's fees

· Election of the external auditor and approval of the auditor's fee

· Any other matters listed in the notice convening the AGM

96 Statoil, Annual Report on Form 20-F 2016

All shares carry an equal right to vote at general meetings. Resolutions at general meetings are normally passed by simple majority. However, Norwegian company law requires a qualified majority for certain resolutions, including resolutions to waive preferential rights in connection with any share issue, approval of a merger or demerger, amendment of the articles of association or authorisation to increase or reduce the share capital. Such matters require the approval of at least two-thirds of the aggregate number of votes cast as well as two-thirds of the share capital represented at the general meeting.

If shares are registered by a nominee in the Norwegian Central Securities Depositary (VPS), cf. section 4-10 of the Norwegian Public Limited Liability Companies Act, and the beneficial shareholder wants to vote for their shares, the beneficial shareholder must re-register the shares in a separate VPS account in their own name prior to the general meeting. If the holder can prove that such steps have been taken and that the holder has a de facto shareholder interest in the company, the company will allow the shareholder to vote for the shares. Decisions regarding voting rights for shareholders and proxy holders are made by the person opening the meeting, whose decisions may be reversed by the general meeting by simple majority vote.

The minutes of the AGM are made available on Statoil’s website immediately after the AGM.

As regards to extraordinary general meetings (EGM), an EGM will be held in order to consider and decide a specific matter if demanded by the corporate assembly, the chair of the corporate assembly, the auditor or shareholders representing at least 5% of the share capital. The board must ensure that an EGM is held within a month of such demand being submitted.

In the following, certain types of resolutions by the general meeting of shareholders are outlined:

New share issues

If Statoil issues any new shares, including bonus shares, the articles of association must be amended. This requires the same majority as other amendments to the articles of association. In addition, under Norwegian law, the shareholders have a preferential right to subscribe for new shares issued by Statoil. The preferential right to subscribe for an issue may be waived by a resolution of a general meeting passed by the same percentage majority as required to approve amendments to the articles of association. The general meeting may, with a majority as described above, authorise the board of directors to issue new shares, and to waive the preferential rights of shareholders in connection with such share issues. Such authorisation may be effective for a maximum of two years, and the par value of the shares to be issued may not exceed 50% of the nominal share capital when the authorisation was granted.

The issuing of shares through the exercise of preferential rights to holders who are citizens or residents of the USA may require Statoil to file a registration statement in the USA under US securities laws. If Statoil decides not to file a registration statement, these holders may not be able to exercise their preferential rights.

Right of redemption and repurchase of shares

Statoil’s articles of association do not authorise the redemption of shares. In the absence of authorisation, the redemption of shares may nonetheless be decided upon by a general meeting of shareholders by a two-thirds majority on certain conditions. However, such share redemption would, for all practical purposes, depend on the consent of all shareholders whose shares are redeemed.

A Norwegian company may purchase its own shares if authorisation to do so has been granted by a general meeting with the approval of at least two-thirds of the aggregate number of votes cast as well as two-thirds of the share capital represented at the general meeting. The aggregate par value of such treasury shares held by the company must not exceed 10% of the company's share capital, and treasury shares may only be acquired if, according to the most recently adopted balance sheet, the company's distributable equity exceeds the consideration to be paid for the shares. Pursuant to Norwegian law, authorisation by the general meeting cannot be granted for a period exceeding 18 months.

Distribution of assets on liquidation

Under Norwegian law, a company may be wound up by a resolution of the company's shareholders at a general meeting passed by both a two-thirds majority of the aggregate votes cast and a two-thirds majority of the aggregate share capital represented at the general meeting. The shares are ranked equally in the event of a return on capital by the company upon winding up or otherwise.

3.3 Nomination committee

Pursuant to Statoil's articles of association, the nomination committee shall consist of four members who are shareholders or representatives of shareholders. The duties of the nomination committee are set forth in the articles of association, and the instructions for the committee are adopted by the general meeting of shareholders.

The duties of the nomination committee are to submit recommendations to:

Statoil, Annual Report on Form 20-F 2016 97

· the annual general meeting for the election of shareholder-elected members and deputy members of the corporate assembly, and the remuneration of members of the corporate assembly

· the annual general meeting for the election and remuneration of members of the nomination committee

· the corporate assembly for the election of shareholder-elected members of the board of directors and remuneration of the members of the board of directors and

· the corporate assembly for the election of the chair and deputy chair of the corporate assembly

The nomination committee would like to ensure that the shareholders’ views are taken into consideration when candidates to the governing bodies of Statoil ASA are proposed. The nomination committee invites in writing Statoil's largest shareholders to propose shareholder-elected candidates of the corporate assembly and the board of directors, as well as members of the nomination committee. The shareholders are also invited to provide input to the nomination committee in respect of the composition and competence of Statoil's governing bodies in light of Statoil's strategies and challenges going forward. The deadline for providing input is normally set to early January in order to secure that the response is taken into account in the upcoming nominations. In addition, all shareholders have an opportunity to submit proposals through an electronic mailbox as described on Statoil’s website. In the board nomination process, the board shares with the nomination committee the results from the annual, normally externally facilitated board evaluation with input from both management and the board. Separate meetings are held between the nomination committee and each board member, including employee-elected board members. The chair of the board and the chief executive officer are invited, without having the right to vote, to attend at least one meeting of the nomination committee before it makes its final recommendations. The committee regularly utilises external expertise in its work.

The members of the nomination committee are elected by the annual general meeting. The chair of the nomination committee and one other member are elected from among the shareholder-elected members of the corporate assembly. Members of the nomination committee are normally elected for a term of two years.

Personal deputy members for one or more of the nomination committee's members may be elected in accordance with the same criteria as described above. A deputy member normally only meets for the permanent member if the appointment of that member terminates before the term of office has expired.

Statoil's nomination committee consists of the following members as per 31 December 2016 and are elected for the period up to the annual general meeting in 2018:

· Tone Lunde Bakker (chair), Global head of cash management at Danske Bank (also chair of Statoil’s corporate assembly)

· Tom Rathke, Group executive vice president Wealth Management at DnB

· Elisabeth Berge, Secretary general, Norwegian Ministry of Petroleum and Energy (personal deputy for Elisabeth Berge is Bjørn Ståle Haavik, Director at the Norwegian Ministry of Petroleum and Energy)

· Jarle Roth, CEO of Arendals Fossekompani ASA (also a member of Statoil’s corporate assembly)

The board considers all members of the nomination committee to be independent of Statoil's management and board of directors. The general meeting decides the remuneration of the nomination committee.

The nomination committee held 15 ordinary meetings and four telephone meetings in 2016.

The instructions for the nomination committee are available at www.statoil.com/nominationcommittee.

3.4 Corporate assembly

Pursuant to the Norwegian Public Limited Liability Companies Act, companies with more than 200 employees must elect a corporate assembly unless otherwise agreed between the company and a majority of its employees.

In accordance with Statoil's articles of association, the corporate assembly normally consists of 18 members, 12 of whom (with four deputy members) are nominated by the nomination committee and elected by the annual general meeting. They represent a broad cross-section of the company's shareholders and stakeholders. Six members, with deputy members, and three observers are elected by and among our employees. Such employees are non-executive personnel. The corporate assembly elects its own chair and deputy chair from and among its members.

Members of the corporate assembly are normally elected for a term of two years. Members of the board of directors and management cannot be members of the corporate assembly, but they are entitled to attend and to speak at meetings of the corporate assembly unless the corporate assembly decides otherwise in individual cases. All members of the corporate assembly live in Norway. Members of the corporate assembly do not have service contracts with the company or its subsidiaries providing for benefits upon termination of office.

An overview of the members and observers of the corporate assembly as of 31 December 2016 follows below.

98 Statoil, Annual Report on Form 20-F 2016

Name	Occupation	Place of residence	Year of birth	Position	Family relations to corporate executive committee, board or corporate assembly members	Share ownership for members as of 31.12.2016	Share ownership for members as of 08.03.2017	First time elected	Expiration date of current term

Tone Lunde Bakker	Global head of cash management at Danske Bank	Oslo	1962	Chair, Shareholder-elected	No	0	0	2014	2018
Nils Bastiansen	Executive director of equities in Folketrygdfondet	Oslo	1960	Deputy chair, Shareholder-elected	No	0	0	2016	2018
Jarle Roth	CEO, Arendals Fossekompani ASA	Bærum	1960	Shareholder-elected	No	43	43	2016	2018
Greger Mannsverk	Managing director, Kimek AS	Kirkenes	1961	Shareholder-elected	No	0	0	2002	2018
Steinar Olsen	CEO, Jemso A/S	Stavanger	1949	Shareholder-elected	No	0	0	2007	2018
Kathrine Næss	Plant manager at the aluminium smelter at Alcoa Mosjøen	Mosjøen	1979	Shareholder-elected	No	0	0	2016	2018
Ingvald Strømmen	Dean at Norwegian University of Science and Technology (NTNU)	Ranheim	1950	Shareholder-elected	No	0	0	2006	2018
Rune Bjerke	President and CEO, DNB ASA	Oslo	1960	Shareholder-elected	No	0	0	2007	2018
Birgitte Ringstad Vartdal	CEO of the dry bulk shipping company Golden Ocean Group Ltd	Oslo	1977	Shareholder-elected	No	0	0	2016	2018
Siri Kalvig	Associate professor, University of Stavanger	Stavanger	1970	Shareholder-elected	No	0	0	2010	2018
Terje Venold	Independent advisor with various directorships	Bærum	1950	Shareholder-elected	No	519	519	2014	2018
Kjersti Kleven	Co-owner of John Kleven AS	Ulsteinvik	1967	Shareholder-elected	No	0	0	2014	2018
Brit Gunn Ersland	Union representative, Tekna. Prosj leder Res Tek	Bergen	1960	Employee-elected	No	2072	2270	2011	2017
Steinar Kåre Dale	Union representative, NITO, SR Analyst	Mongstad	1961	Employee-elected	No	3033	1931	2013	2017
Per Martin Labråten	Union representative, Industri Energi. Production technician	Brevik	1961	Employee-elected	No	983	1151	2007	2017
Anne K.S. Horneland	Union representative, Industri Energi	Hafrsfjord	1956	Employee-elected	No	5216	5498	2006	2017
Jan-Eirik Feste	Union representative, YS	Lindås	1952	Employee-elected	No	1251	1437	2008	2017
Hilde Møllerstad	Union representative, Tekna/NITO	Oslo	1966	Employee-elected	No	3338	3642	2013	2017
Per Helge Ødegård	Union representative, Lederne. Discipl resp operation process	Porsgrunn	1963	Employee-elected, observer	No	1181	1361	1994	2017
Dag-Rune Dale	Union representative, Industri Energi, Safety officer	Kollsnes	1963	Employee-elected, observer	No	3334	3555	2013	2017
Sun Lehmann	Union representative, Tekna. Advisor Data Management	Trondheim	1972	Employee-elected, observer	No	3608	3924	2015	2017
Total						24,578	25,331

Statoil, Annual Report on Form 20-F 2016 99

An election of shareholder-elected members of the corporate assembly was held at Statoil’s annual general meeting 11 May 2016. Effective as of 12 May 2016, Nils Bastiansen, Birgitte Ringstad Vartdal (former deputy member), Jarle Roth and Kathrine Næss were elected as new members of the corporate assembly, while Kjerstin Fyllingen, Håkon Volldal and Kari Skeidsvoll Moe were elected as new deputy members. Olaug Svarva (chair), Idar Kreutzer (deputy chair), Karin Aslaksen (member), Barbro Hætta (member), Arthur Sletteberg (deputy member) and Bassim Haj (deputy member) left the corporate assembly as of the same date. On 7 June 2016 the corporate assembly elected Tone Lunde Bakker as chair, and Nils Bastiansen as deputy chair, of the corporate assembly.

The duties of the corporate assembly are defined in section 6-37 of the Norwegian Public Limited Liability Companies Act. The corporate assembly elects the board of directors and the chair of the board and can vote separately on each nominated candidate. Its responsibilities also include overseeing the board and the CEO's management of the company, making decisions on investments of considerable magnitude in relation to the company's resources, and making decisions involving the rationalisation or reorganisation of operations that will entail major changes in or reallocation of the workforce.

Statoil's corporate assembly held four ordinary meetings in 2016, and visited Statoil’s operation center for logistics and emergency response in Bergen in connection with one of the meetings. The chair of the board participated at four meetings, and the CEO at three meetings (with the CFO acting on his behalf at one meeting). Other members of management were also present at the meetings.

The procedure for the work of the corporate assembly, as well as an updated overview of its members, is available at www.statoil.com/corporateassembly.

100 Statoil, Annual Report on Form 20-F 2016

3.5 Board of directors

Pursuant to Statoil's articles of association, the board of directors consists of between nine and 11 members elected by the corporate assembly. The chair of the board and the deputy chair of the board are also elected by the corporate assembly. At present, Statoil's board of directors consists of 10 members. As required by Norwegian company law, the company's employees are represented by three board members.

The employee-elected board members, but not the shareholder-elected board members, have four deputy members who attend board meetings in the event an employee-elected member of the board is unable to attend. The management is not represented on the board of directors. Members of the board are elected for a term of up to two years, normally for one year at a time. There are no board member service contracts that provide for benefits upon termination of office.

The board considers its composition to be diverse and competent with respect to the expertise, capacity and diversity appropriate to attend to the company's goals, main challenges, and the common interest of all shareholders. The board also deems its composition to be made up of individuals who are willing and able to work as a team, resulting in the board working effectively as a collegiate body. At least one board member qualifies as "audit committee financial expert", as defined in the US Securities and Exchange Commission requirements. Five board members are women and three board members are non-Norwegians resident outside of Norway.

Statoil's board of directors has determined that, in its judgment, all of the shareholder representatives on the board, except for Wenche Agerup, are considered independent. Under the NYSE rules, a director will not be considered independent if the director is, or was within the past three years, an executive officer of another company at which any of the listed company's current executive officers are, or were within the past three years, members of the compensation committee. Wenche Agerup was a member of Norsk Hydro ASA’s management team while Irene Rummelhoff, Executive Vice President of New Energy Solutions in Statoil, was member of the board’s compensation committee in Norsk Hydro. Agerup is therefore deemed as a non-independent board member until 31 December 2017.

The board held eight ordinary board meetings and two extraordinary meetings in 2016. Average attendance at these board meetings was 98,1%.

Further information about the members of the board and its sub-committees, including information about expertise, experience, other directorships, independence, share ownership and loans, is available below as well as on our website at www.statoil.com/board which is regularly updated.

Members of the board of directors as of 31 December 2016:

Øystein Løseth

Born: 1958

Position: Shareholder-elected chair of the board and chair of the board's compensation and executive committee.

Term of office: Member of the board of directors of Statoil ASA since 1 October 2014, and since 1 July 2015, also chair of the board and chair of the board’s compensation and executive development committee. Up for election in 2017.

Independent: Yes

Other directorships: Chair of the board of Eidsiva Energi AS and Hunton Fiber AS.

Number of shares in Statoil ASA as of 31 December 2016: 1,040

Loans from Statoil: None
Experience: In the period 2010 - 2014, Løseth was the CEO, and before that First Senior Executive Vice President since 2009, of Vattenfall AB. In the period 2003 – 2009, Løseth worked for NUON, a Dutch energy company, first as Division Managing Director, then as a Managing Director and the CEO, from 2006 and 2008 respectively. From 2002 to 2003, Løseth was the Head of Production,

Statoil, Annual Report on Form 20-F 2016 101

Business Development and R&D of Statkraft. In addition, he has other extensive management experience from Statkraft and Statoil, within strategy and business development among others.

Education: Løseth graduated as M.Sc. from the Norwegian University of Science and Technology and has a degree in Economics from BI Norwegian School of Management in Bergen.
Family relations: No family relations to other members of the board, members of the corporate executive committee or the corporate assembly.
Other matters: In 2016, Løseth participated in eight ordinary board meetings, two extraordinary board meetings, five meetings of the compensation and executive development committee and one meeting in the safety, sustainability and ethics committee. Løseth is a Norwegian citizen and resident in Norway.

Roy Franklin

Born: 1953

Position: Shareholder-elected deputy chair of the board, chair of the board’s safety, sustainability and ethics committee and member of the board’s audit committee.

Term of office: Board member and deputy chair of the board of Statoil ASA from 1 July 2015. Franklin was also previously a member of the board of StatoilHydro from October 2007 and Statoil from November 2009 until June 2013. Up for election in 2017.

Independent: Yes

Other directorships: Non-executive chair of the board of Cuadrilla Resources Holdings Limited, a privately held UK company focusing on unconventional energy sources. Board member of the Australian oil and gas company Santos Ltd, the private equity firm Kerogen Capital Ltd and the London-based international engineering company Amec Foster Wheeler.

Number of shares in Statoil ASA as of 31 December 2016: None

Loans from Statoil ASA: None

Experience: Franklin has broad experience from management positions in several countries, including positions with BP, Paladin Resources plc and Clyde Petroleum plc.

Education: Franklin has a Bachelor of Science in Geology from the University of Southampton, UK.

Family relations: No family relations to other members of the board, members of the corporate executive committee or the corporate assembly.

Other matters: In 2016, Franklin participated in eight ordinary board meetings, two extraordinary board meetings, five meetings of the audit committee and six meetings of the safety, sustainability and ethics committee. Franklin is a UK citizen and resident in UK.

Bjørn Tore Godal

Born: 1945

Position: Shareholder-elected member of the board, the board's compensation and executive development committee and the board's safety, sustainability and ethics committee.

102 Statoil, Annual Report on Form 20-F 2016

Term of office: Member of the board of Statoil ASA from 1 September 2010. Up for election in 2017.

Independent: Yes

Other directorships: Vice chair of the board of the Fridtjof Nansen Institute (FNI).

Number of shares in Statoil ASA as of 31 December 2016: None

Loans from Statoil ASA: None

Experience: Godal was a member of the Norwegian parliament for 15 years during the period 1986-2001. At various

times, he served as minister for trade and shipping, minister for defense, and minister of foreign affairs for a total of eight years between 1991 and 2001. From 2007-2010, Godal was special adviser for international energy and climate issues at the Norwegian Ministry of Foreign Affairs. From 2003-2007, Godal was Norway's ambassador to Germany and from 2002-2003 he was senior adviser at the department of political science at the University of Oslo. From 2014-2016, Godal lead a government-appointed committee responsible for the evaluation of the civil and military contribution from Norway in Afghanistan in the period 2001 - 2014.

Education: Godal has a bachelor of arts degree in political science, history and sociology from the University of Oslo.

Family relations: No family relations to other members of the board, members of the corporate executive committee or the corporate assembly.

Other matters: In 2016, Godal participated in eight ordinary board meetings, two extraordinary board meetings, five meetings of the compensation and executive development committee and three meetings of the safety, sustainability and ethics committee. Godal is a Norwegian citizen and resident in Norway.

Maria Johanna Oudeman

Born: 1958

Position: Shareholder-elected member of the board and member of the board’s compensation and executive development committee.

Term of office: Member of the board of Statoil ASA since 15 September 2012. Up for election in 2017.

Independent: Yes

Other directorships: Oudeman is a member of the boards of Solvay SA, Het Concertgebouw, Rijksmuseum and SHV Holdings.

Number of shares in Statoil ASA as of 31 December 2016: None

Loans from Statoil: None

Experience: Oudeman is the President of Utrecht University in the Netherlands, one of Europe's leading universities. From 2010 to 2013, Oudeman was a member of the Executive Committee of Akzo Nobel, responsible for HR and Organisational Development. Akzo Nobel is the world's largest paint and coatings company and major producer of specialty chemicals, with operations in more than 80 countries. Before joining Akzo Nobel, she was Executive Director Strip Products Division at Corus Group, now Tata Steel Europe. Oudeman has extensive experience as a line manager in the steel industry and considerable international business experience.

Education: Oudeman has a law degree from Rijksuniversiteit Groningen in the Netherlands and an MBA in business administration from the University of Rochester, New York, USA and Erasmus University, Rotterdam, the Netherlands.

Family relations: No family relations to other members of the board, members of the corporate executive committee or the corporate assembly.

Other matters: In 2016, Oudeman participated in eight ordinary board meetings, two extraordinary board meetings and four meetings of the compensation and executive development committee. Oudeman is a Dutch citizen and resident in the Netherlands.

Statoil, Annual Report on Form 20-F 2016 103

Rebekka Glasser Herlofsen

Born: 1970

Position: Shareholder-elected member of the board and the board's audit committee.

Term of office: Member of the board of Statoil ASA since 19 March 2015. Up for election in 2017.

Independent: Yes

Other directorships: Member of the board of directors of DNV Foundation, DNV Holding, DNV GL, and member of the committee for tax and capital in the Norwegian Shipowners’ Association.

Number of shares in Statoil ASA as of 31 December 2016: None

Loans from Statoil: None

Experience: Since 2012, Herlofsen has been the Chief Financial Officer in the shipping company Torvald Klaveness. She will during the first half of 2017 take on a new position as Chief Financial Officer in WWL ASA, an international shipping company under establishment. She has broad financial and strategic experience from several corporations and board directorships. Herlofsen’s professional career began in the Nordic Investment Bank, Enskilda Securities, where she worked with corporate finance from 1995 to 1999 in Oslo and London. During the next ten years Herlofsen worked in the Norwegian shipping company Bergesen d.y. ASA (later BW Group). During her period with Bergesen d.y. ASA/BW Group Herlofsen held leading positions within M&A, strategy and corporate planning and was part of the group management team.

Education: MSc in Economics and Business Administration (Siviløkonom) and Certified Financial Analyst Program (AFA), the Norwegian School of Economics (NHH). Breakthrough Program for Top Executives at IMD business school, Switzerland.

Family relations: No family relations to other members of the board, members of the corporate executive committee or the corporate assembly.

Other matters: In 2016, Herlofsen participated in eight ordinary board meetings, two extraordinary board meeting and six meetings of the audit committee. Herlofsen is a Norwegian citizen and resident in Norway.

Wenche Agerup

Born: 1964

Position: Shareholder-elected member of the board, the board’s compensation and executive development committee and the board's safety, sustainability and ethics committee.

Term of office: Member of the board of Statoil ASA since 21 August 2015. Up for election in 2017.

Independent: No.

Under the NYSE rules, a director will not be considered independent under the NYSE rules if the director is, or was within the past three years, an executive officer of another company at which any of the listed company's current executive officers are, or were within the past three years, members of the compensation committee. Agerup was a member of Norsk Hydro ASA’s management

104 Statoil, Annual Report on Form 20-F 2016

team while Irene Rummelhoff, Executive Vice President of New Energy Solutions in Statoil, was member of the board’s compensation committee in Norsk Hydro. Agerup is therefore deemed as a non-independent board member in Statoil until 31 December 2017.

Other directorships: Agerup is a member of the board of the seismic company TGS ASA and a member of Det Norske Veritas Council.

Number of shares in Statoil ASA as of 31 December 2016: 2,522
Loans from Statoil: None

Experience: Agerup is an Executive Vice President (Corporate Affairs) and General Counsel in Telenor ASA. Agerup was the Executive Vice President for Corporate Staffs and the General Counsel of Norsk Hydro ASA from 2010 to 31 December 2014. She has held various executive roles in Hydro since 1997, including within the company’s M&A-activities, the business area Alumina, Bauxite and Energy, as a plant manager at Hydro’s metal plant in Årdal and as a project director for a Joint Venture in Australia where Hydro cooperated with the Australian listed company UMC.

Education: MA in Law from the University of Oslo, Norway (1989) and a Master of Business Administration from Babson College, USA (1991).

Family relations: No family relations to other members of the board, members of the corporate executive committee or the corporate assembly.

Other matters: In 2016, Agerup participated in seven ordinary board meetings, two extraordinary board meetings, five meetings of the compensation and executive development committee and five meetings of the safety, sustainability and ethics committee. Agerup is a Norwegian citizen and resident in Norway.

Jeroen van der Veer

Born: 1947

Position: Shareholder-elected member of the board and chair of the board's audit committee.

Term of office: Member of the board of Statoil ASA since 18 March 2016. Up for election in 2017.

Independent: Yes

Other directorships: Van der Veer is the chair of the supervisory boards of ING Bank NV and Royal Philips Electronics, chair of the supervisory council of Technical University of Delft and Platform Betatechniek, chair of the advisory board of the Rotterdam Climate Initiative as well as a board member in Boskalis Westminster Groep NV and Het Concertbebouw.

Number of shares in Statoil ASA as of 31 December 2016: None

Loans from Statoil: None

Experience: Van der Veer was the Chief Executive Officer in the international oil and gas company Royal Dutch Shell Plc (Shell) in the period 2004 to 2009 when he retired. Van der Veer thereafter continued as a non-executive director on the board of Shell until 2013. He started to work for Shell in 1971 and has experience within all sectors of the business and has significant competence within corporate governance.

Education: Van der Veer has a degree in Mechanical Engineering (MSc) from Delft University of Technology, Netherlands and a degree in Economics (MSc) from Erasmus University, Rotterdam, Netherlands. Since 2005 he holds an honorary doctorate from the University of Port Harcourt, Nigeria.

Family relations: No family relations to other members of the board, members of the corporate executive committee or the corporate assembly.

Other matters: In 2016, van der Veer participated in six ordinary board meetings, one extraordinary board meetings and three meetings of the audit committee. Van der Veer is a Dutch citizen and resident in Netherlands.

Statoil, Annual Report on Form 20-F 2016 105

Lill-Heidi Bakkerud

Born: 1963

Position: Employee-elected member of the board and member of the board's safety, sustainability and ethics committee.

Term of office: Member of the board of Statoil ASA from 1998 to 2002, and again since 2004. Up for election in 2017.

Independent: No

Other directorships: Bakkerud is a member of the executive committee of the Industry Energy (IE) trade union and holds a number of offices as a result of this.

Number of shares in Statoil ASA as of 31 December 2016: 342
Loans from Statoil: None

Experience: Bakkerud has worked as a process technician at the petrochemical plant in Bamble and on the Gullfaks field in the North Sea. She is now a full-time employee representative as the leader of the union Industri Energi’s Statoil branch.

Education: Bakkerud has a craft certificate as a process/chemistry worker.

Family relations: No family relations to other members of the board, members of the corporate executive committee or the corporate assembly.

Other matters: In 2016, Bakkerud participated in eight ordinary board meetings, two extraordinary board meetings and five meetings of the safety, sustainability and ethics committee. Bakkerud is a Norwegian citizen and resident in Norway.

Ingrid Elisabeth di Valerio

Born: 1964

Position: Employee-elected member of the board and member of the board's audit committee.

Term of office: Member of board of directors of Statoil ASA from 1 July 2013. Up for election in 2017.

Independent: No

Other directorships: Board member of Tekna's central nomination committee.

Number of shares held in Statoil ASA as of 31 December 2016: 3,670

Loans from Statoil: None

Experience: Di Valerio has been employed by Statoil since 2005, and works within materials discipline for Technology, Projects & Drilling. Di Valerio was the union Tekna's main representative in Statoil from 2008 to 2013. She also sat on Tekna's central committee from 2005 to 2013.

Education: Chartered engineer (mathematics and physics) from the Norwegian University of Science and Technology in Trondheim (NTNU).

Familiy relations: No family relationships to other board members, members of the corporate executive committee or the corporate assembly.

Other matters: In 2016, di Valerio participated in eight ordinary board meetings, two extraordinary board meetings and six meetings of the audit committee. Di Valerio is a Norwegian citizen and resident in Norway.

106 Statoil, Annual Report on Form 20-F 2016

Stig Lægreid

Born: 1963

Position: Employee-elected member of the board and member of the board's safety, sustainability and ethics committee.

Term of office: Member of the board of directors of Statoil ASA from 1 July 2013. Up for election in 2017.

Independent: No

Other directorships: Member of The Norwegian society for Engineers and Technologists’ (NITO) negotiation committee for private sector.

Number of shares held in Statoil ASA as of 31 December 2016: 1,881

Loans from Statoil: None

Experience: Employed in ÅSV and Norsk Hydro since 1985. Mainly occupied as project engineer and constructor for production of primary metals until 2005 and from 2005 as weight estimator for platform design. He is now a full-time employee representative as the leader of the union NITO, Statoil.

Education: Bachelor degree, mechanical construction from OIH.

Family relations: No family relationships to other board members, members of the corporate executive committee or the corporate assembly.

Other matters: In 2016, Lægreid participated in eight ordinary board meetings, two extraordinary board meetings and six meetings of the safety, sustainability and ethics committee. Lægreid is a Norwegian citizen and resident in Norway.

The most recent changes to the composition of the board of directors were the election of Jeroen van der Veer as a new shareholder-elected board member effective as of 18 March 2016, as well as the resignation of shareholder-elected board member Jakob Stausholm effective as of 30 September 2016. Van der Veer replaced Stausholm as chair of the board’s audit committee as per 26 October 2016.

The work of the board of directors

The board is responsible for managing the Statoil group and for monitoring day-to-day management and the group's business activities. This means that the board is responsible for establishing control systems and for ensuring that Statoil operates in compliance with laws and regulations, with our values as stated in The Statoil Book, the Code of Conduct, as well as in accordance with the owners' expectations of good corporate governance. The board emphasises the safeguarding of the interests of all shareholders, but also the interests of Statoil's other stakeholders.

The board handles matters of major importance, or of an extraordinary nature, and may in addition require the management to refer any matter to it. An important task for the board is to appoint the chief executive officer (CEO) and stipulate his/her job instructions and terms and conditions of employment.

The board has adopted a generic annual plan for its work which is revised with regular intervals. Recurrent items on the board's annual plan are: security, safety and sustainability, corporate strategy, business plans, quarterly and annual results, annual reporting, ethics, management's monthly performance reporting, management compensation issues, CEO and top management leadership assessment and succession planning, project status review, people and organisation strategy and priorities, an annual enterprise risk management review, two yearly discussions of main risks and risk issues and an annual review of the board's governing documentation. In the beginning of each board meeting, the CEO meets separately with the board to discuss key matters in the company. At the end of all board meetings, the board has a closed session with only board members attending the discussions and evaluating the meeting.

The work of the board is based on rules of procedure that describe the board's responsibilities, duties and administrative procedures, and determines which cases are to be handled by the board. The rules of procedure also determines the handling of matters in which individual board members or a closely related party have a major personal or financial interest. The rules of procedure further describe the duties of the CEO and his/her duties vis-à-vis the board of directors. The board's rules of procedure are available on our website at www.statoil.com/board. In addition to the board of directors, the CEO, the CFO, the COO, the senior vice president for communication, the general counsel and the company secretary attend all board meetings. Other members of the executive committee and senior management attend board meetings by invitation in connection with specific matters.

Statoil, Annual Report on Form 20-F 2016 107

New members of the board are offered an induction program where meetings with key members of the management are arranged, an introduction to Statoil’s business is given and relevant information about the company and the board’s work is made available through the company’s web based board portal.

The board carries out an annual board evaluation, with input from various sources and as a main rule with external facilitation. The evaluation report is discussed in a board meeting and is made available to the nomination committee as input to the committee’s work.

The entire board, or part of it, regularly visits several Statoil locations in Norway and globally, and a longer board trip for all board members to an international location is made at least on a biennial basis. When visiting Statoil locations globally, the board emphasises the importance of improving its insight into, and knowledge about, safety and security in Statoil’s operations, Statoil's technical and commercial activities as well as the company's local organisations. In 2016, whole or parts of the board visited Statoil’s operations in Brazil, Tanzania, Russia and the United States.

Statoil's board has established three sub-committees: the audit committee; the compensation and executive development committee; and the safety, sustainability and ethics committee. The committees prepare items for consideration by the board and their authority is limited to making such recommendations. The committees consist entirely of board members and are answerable to the board alone for the performance of their duties. Minutes of the committee meetings are sent to the whole board, and the chair of each committee regularly informs the board at board meetings about the committee's work. The composition and work of the committees are further described below.

Audit committee

The board of directors elects at least three of its members to serve on the board of directors' audit committee and appoints one of them to act as chair. The employee-elected members of the board of directors may nominate one audit committee member.

At year-end 2016, the audit committee members were Jeroen van der Veer (chair), Roy Franklin, Rebekka Glasser Herlofsen and Ingrid di Valerio (employee-elected board member). Jakob Stausholm chaired the audit committee from September 2009 and until his resignation as board member 30 September 2016.

The audit committee is a sub-committee of the board of directors, and its objective is to act as a preparatory body in connection with the board's supervisory roles with respect to financial reporting and the effectiveness of the company's internal control system. It also attends to other tasks assigned to it in accordance with the instructions for the audit committee adopted by the board of directors. The audit committee is instructed to assist the board of directors in its supervising of matters such as:

· Approving the internal audit plan on behalf of the board of directors

· Monitoring the financial reporting process, including oil and gas reserves, fraudulent issues and reviewing the implementation of accounting principles and policies

· Monitoring the effectiveness of the company's internal control, internal audit and risk management systems

· Maintaining continuous contact with the external auditor regarding the annual and consolidated accounts

· Reviewing and monitoring the independence of the company's internal auditor and the independence of the external auditor, reference is made to the Norwegian Auditors Act chapter 4, and, in particular, whether services other than audits provided by the external auditor or the audit firm are a threat to the external auditor's independence

The audit committee supervises implementation of and compliance with the group's Code of Conduct in relation to financial reporting.

The internal audit function reports directly to the board of directors’ audit committee and to the chief executive officer.

Under Norwegian law, the external auditor is appointed by the shareholders at the annual general meeting based on a proposal from the corporate assembly. The audit committee issues a statement to the annual general meeting relating to the proposal.

The audit committee meets at least five times a year and both the board and the board’s audit committee hold meetings with the internal auditor and the external auditor on a regular basis without the company’s management being present.

The audit committee is also charged with reviewing the scope of the audit and the nature of any non-audit services provided by external auditors.

The audit committee is tasked with ensuring that the company has procedures in place for receiving and dealing with complaints received by the company regarding accounting, internal control or auditing matters, and procedures for the confidential and anonymous submission, via the group's ethics helpline, by company employees of concerns regarding accounting or auditing matters, as well as other matters regarded as being in breach of the group's Code of Conduct, a material violation of an applicable US federal or state securities law, a material breach of fiduciary duties or a similar material violation of any other US or Norwegian statutory provision. The audit committee is designated as the company's qualified legal compliance committee for the purposes of Part 205 in Title 17 of the U.S. Code of Federal Regulations.

108 Statoil, Annual Report on Form 20-F 2016

In the execution of its tasks, the audit committee may examine all activities and circumstances relating to the operations of the company. In this regard, the audit committee may request the chief executive officer or any other employee to grant it access to information, facilities and personnel and such assistance as it requests. The audit committee is authorised to carry out or instigate such investigations as it deems necessary in order to carry out its tasks and it may use the company's internal audit or investigation unit, the external auditor or other external advice and assistance. The costs of such work will be covered by the company.

The audit committee is only responsible to the board of directors for the execution of its tasks. The work of the audit committee in no way alters the responsibility of the board of directors and its individual members, and the board of directors retains full responsibility for the audit committee's tasks.

The audit committee held six meetings in 2016. There was 96% attendance at the committee's meetings.

The board of directors has decided that a member of the audit committee, Jeroen van der Veer, qualifies as an "audit committee financial expert", as defined in Item 16A of Form 20-F. The board of directors has also concluded that Jeroen van der Veer, Roy Franklin and Rebekka Glasser Herlofsen are independent within the meaning of Rule 10A-3 under the Securities Exchange Act.

The committee's mandate is available at www.statoil.com/auditcommittee.

Compensation and executive development committee

The compensation and executive development committee is a sub-committee of the board of directors that assists the board in matters relating to management compensation and leadership development. The main responsibilities of the compensation and executive development committee are:

(1) as a preparatory body for the board, to make recommendations to the board in all matters relating to principles and the framework for executive rewards, remuneration strategies and concepts, the CEO's contract and terms of employment, and leadership development, assessments and succession planning;

(2) to be informed about and advise the company's management in its work on Statoil's remuneration strategy for senior executive and in drawing up appropriate remuneration policies for senior executives; and

(3) to review Statoil's remuneration policies in order to safeguard the owners' long-term interests.

The committee consists of up to four board members. At year-end 2016, the committee members were Øystein Løseth (chair), Bjørn Tore Godal, Maria Johanna Oudeman and Wenche Agerup. All of the committee members are non-executive directors. All members, except for Wenche Agerup, are independent.

The committee held five meetings in 2016 and attendance was 95%.

For a more detailed description of the objective and duties of the compensation and executive development committee, please see the instructions for the committee available at www.statoil.com/compensationcommittee.

Safety, sustainability and ethics committee

The safety, sustainability and ethics committee is a sub-committee of the board of directors that assists the board in matters relating to safety, sustainability and ethics.

The safety, sustainability and ethics committee is chaired by Roy Franklin and the other members are Bjørn Tore Godal, Wenche Agerup, Stig Lægreid (employee-elected board member) and Lill-Heidi Bakkerud (employee-elected board member).

In its business activities, Statoil is committed to comply with applicable laws and regulations and to act in an ethical, environmental, safe and socially responsible manner. The committee has been established to support our commitment in this regard, and it assists the board of directors in its supervision of the company's safety, sustainability and ethics policies, systems and principles with the exception of aspects related to “financial matters”.

Establishing and maintaining a committee dedicated to safety, sustainability and ethics is intended to ensure that the board of directors has a strong focus on and knowledge of these complex, important and constantly evolving areas. The committee acts as a preparatory body for the board of directors and, among other things, monitors and assesses the effectiveness, development and implementation of policies, systems and principles in the areas of safety, sustainability and ethics, with the exception of aspects related to “financial matters”.

The committee held six meetings in 2016, and attendance was 83%.

Statoil, Annual Report on Form 20-F 2016 109

For a more detailed description of the objective, duties and composition of the committee, please see the instructions for the committee available at www.statoil.com/ssecommittee.

3.6 Management

The president and CEO has overall responsibility for day-to-day operations in Statoil and appoints the corporate executive committee (CEC). The president and CEO is responsible for developing Statoil's business strategy and presenting it to the board of directors for decision, for the execution of the business strategy and for cultivating a performance-driven, values-based culture.

Members of the CEC have a collective duty to safeguard and promote Statoil's corporate interests and to provide the president and CEO with the best possible basis for deciding the company's direction, making decisions and executing and following up business activities. In addition, each of the CEC members is head of a separate business area or staff function.

Members of Statoil's corporate executive committee as of 31 December 2016:

Eldar Sætre,
President and CEO

Eldar Sætre

Born: 1956

Position: President and chief executive officer of Statoil ASA since 15 October 2014.

External offices: Member of the board of Strømberg Gruppen AS and Trucknor AS.

Number of shares in Statoil ASA as of 31 December 2016: 47,882

Loans from Statoil: None
Experience: Sætre joined Statoil in 1980. Executive vice president and CFO from October 2003 until December 2010. Executive vice president for Marketing, Midstream and Processing (MMP) from 2011 until 2014.

Education: MA in business economics from the Norwegian School of Economics and Business Administration (NHH) in Bergen.

Family relations: No family relations to other members of the CEC, members of the board or the corporate assembly.

Other matters: Sætre is a Norwegian citizen and resident in Norway.

Hans Jakob Hegge,
Chief financial
officer (CFO)

Hans Jakob Hegge

Born: 1969
Position: Executive vice president and chief financial officer (CFO) of Statoil ASA since 1 August 2015.

External offices: None

Number of shares in Statoil ASA as of 31 December 2016: 28,190

Loans from Statoil: None

Experience: Hegge has held several managerial positions in Statoil, including senior vice president (SVP) for Operations North in Development and Production Norway (DPN) (2013-2015), SVP for Operations East (2011-2013) in DPN, SVP for Operational

110 Statoil, Annual Report on Form 20-F 2016

Development in DPN (2009-2011) and SVP for Global Business Services in Chief Financial Officer area (CFO) (2005-2009). From 1995 to 2004 he held various positions in DPN, Natural Gas business area and corporate functions in Statoil.

Education: Master of Science degree from the Norwegian School of Economics and Business Administration (NHH).

Family relations: No family relations to other members of the CEC, members of the board or the corporate assembly.
Other matters: Hegge is a Norwegian citizen and resident in Norway.

Jannicke Nilsson

Chief Operating Officer (COO)

Jannicke Nilsson

Born: 1965
Position: Executive vice president and chief operating officer (COO) of Statoil ASA since 1 December 2016.

External offices: Member of the board of Odfjell SE

Number of shares in Statoil ASA as of 31 December 2016: 35,049

Loans from Statoil: None

Experience: Jannicke Nilsson joined Statoil in 1999 and has held a number of central management positions within upstream operations Norway, including senior vice president for Technical Excellence in Technology, Projects & Drilling, senior vice president for Operations North Sea, vice president for modifications and project portfolio Bergen and platform manager at Oseberg South. In august 2013 she was appointed programme leader for Statoil technical efficiency programme (STEP), responsible for a project portfolio targeting yearly efficiency gains of 2.5 billion USD from 2016.

Education: MSc in cybernetics and process automation and a BSc in automation from the Rogaland Regional College/University of Stavanger.

Family relations: No family relations to other members of the CEC, members of the board or the corporate assembly.
Other matters: Nilsson is a Norwegian citizen and resident in Norway.

Lars Christian Bacher,
Executive vice president Development and Production International (DPI)

Lars Christian Bacher

Born: 1964
Position: Executive vice president of Statoil ASA since 1 September 2012.
External offices: None

Number of shares in Statoil ASA as of 31 December 2016: 24,896

Loans from Statoil ASA: None

Experience: Bacher joined Statoil in 1991 and has held a number of leading positions in Statoil, including that of platform manager on the Norne and Statfjord fields on the Norwegian continental shelf. He was in charge of the merger process involving the offshore installations of Norsk Hydro and Statoil. Bacher has also been senior vice president for Gullfaks operations and subsequently for the Tampen area. His most recent position, which he held from September 2009, was as senior vice president for Statoil's Canadian operations in Development & Production International (DPI).

Education: Master of science in chemical engineering from the Norwegian Institute of Technology (NTH). He also holds a business degree in Finance from the Norwegian School of Economics and Business Administration (NHH).

Family relations: No family relations to other members of the corporate executive committee, the board of directors or the corporate assembly.

Statoil, Annual Report on Form 20-F 2016 111

Other matters: Bacher is a Norwegian citizen and resident in Norway.

Torgrim Reitan,
Executive vice president Development and Production USA (DPUSA)

Torgrim Reitan

Born: 1969
Position: Executive vice president of Statoil ASA since 1 January 2011.

External offices: None

Number of shares in Statoil ASA as of 31 December 2016: 32,276

Loans from Statoil: None

Experience: From 1 January 2011 to 1 August 2015 Reitan held the position as executive vice president and chief financial officer of Statoil (CFO). He has held several managerial positions in Statoil, including senior vice president (SVP) in trading and operations in the Natural Gas business area (2009 - 2010), SVP in performance management and analysis (2007 - 2009) and SVP in performance management, tax and M&A (2005 - 2007). From 1995 to 2004, Reitan held various positions in the Natural Gas business area and corporate functions in Statoil.

Education: Master of science degree from the Norwegian School of Economics and Business Administration (Siviløkonom) (NHH).

Family relations: No family relations to other members of the CEC, members of the board or the corporate assembly.
Other matters: Reitan is a Norwegian citizen and resident in the United States.

John Knight,
Executive vice president
Global Strategy and Business
Development (GSB)

John Knight
Born: 1958

Position: Executive vice president of Statoil ASA since 1 January 2011.

External offices: Member on the advisory board of the Columbia University Center on Global Energy Policy in New York, and member of the advisory board of Lloyd’s Register. Chair of ONS18 Conference Committee in Stavanger, Norway.

Numbers of shares in Statoil ASA as of 31 December 2016: 103,808

Loans from Statoil ASA: None

Experience: Knight held several central managerial positions in International Operations in Statoil since 2002, mainly in business development. Between 1987 and 2002, Knight held various positions in energy investment banking. From 1977 to 1987, he qualified and worked as a barrister/lawyer, and was employed by Shell Petroleum in London during the period 1985-1987.

Education: Knight has first and post-graduate degrees in law from Cambridge University and the Inns of Court School of Law in London.

Family relations: No family relations to other members of the CEC, members of the board or the corporate assembly.

Other matters: Knight is a British citizen and resident in England.

Tim Dodson.
Executive vice president, Exploration (EXP)

112 Statoil, Annual Report on Form 20-F 2016

Tim Dodson
Born: 1959
Position: Executive vice president of Statoil ASA since 1 January 2011.

External offices: None
Number of shares in Statoil ASA as of 31 December 2016: 29,418

Loans from Statoil ASA: None

Experience: Dodson has worked in Statoil since 1985 and held central management positions in the company, including the positions of senior vice president for Global Exploration, Exploration & Production Norway and the Technology arena.

Education: Bachelor’s degree of science in geology and geography from the University of Keele.

Family relations: No family relations to other members of the CEC, members of the board or the corporate assembly.

Other matters: Dodson is a British citizen and resident in Norway.

Margareth Øvrum.
Executive vice president Technology, Projects and Drilling (TPD)

Margareth Øvrum

Born: 1958

Position: Executive vice president of Statoil ASA since September 2004.

External offices: Member of the board of Atlas Copco AB (Sweden) (until 26 April 2017), Alfa Laval (Sweden) and FMC Corporation (US).

Number of shares in Statoil ASA as of 31 December 2016: 49,227

Loans from Statoil: None

Experience: Øvrum has worked for Statoil since 1982 and has held central management positions in the company, including the position of executive vice president for health, safety and the environment and executive vice president for Technology & Projects. Øvrum was the company's first female platform manager, on the Gullfaks field. She was senior vice president for operations for Veslefrikk and vice president of operations support for the Norwegian continental shelf.

Education: Master's degree in engineering (sivilingeniør) from the Norwegian Institute of Technology (NTH) in Trondheim, specialising in technical physics.

Family relations: No family relations to other members of the CEC, members of the board or the corporate assembly.

Other matters: Øvrum is a Norwegian citizen and resident in Norway.

Arne Sigve Nylund,
Executive vice president Development and production Norway (DPN)

Statoil, Annual Report on Form 20-F 2016 113

Arne Sigve Nylund

Born: 1960

Position: Executive vice president of Statoil ASA since 1 January 2014.

External offices: Member of the board of directors of The Norwegian Oil & Gas Association (Norsk Olje & Gass).

Number of shares in Statoil ASA as of 31 December 2016: 11,312

Loans from Statoil: None

Experience: Employed by Mobil Exploration Inc. from 1983-1987. Since 1987, Nylund has held several central management positions in Statoil ASA.

Education: Mechanical engineer from Stavanger College of Engineering with further qualifications in operational technology from Rogaland Regional College/University of Stavanger (UiS). Business graduate of the Norwegian School of Business and Management (NHH).

Family relations: No family relations to other members of the CEC, members of the board or the corporate assembly.

Other matters: Nylund is a Norwegian citizen and is resident in Norway.

Jens Økland,

executive vice president Marketing, Midstream and Processing (MMP)

Jens Økland

Born: 1969

Position: Executive vice president of Statoil ASA since 1 June 2015.

External offices: None

Number of shares in Statoil ASA as of 31 December 2016: 13,937

Loans from Statoil ASA: None

Experience: Økland joined Statoil in 1994 and has mainly worked in the mid and downstream areas. Before becoming executive vice president of MMP, Økland worked as vice president of operations for the Åsgard area in Development and Production Norway. Previously Økland was senior vice president of Statoil’s natural gas portfolio and supply business in North America, marketing and developing infrastructure solutions for equity and non-equity production. Before heading up Statoil’s downstream gas division in North America, he had senior marketing and business development positions within natural gas in Europe mainly focusing on Germany, Statoil’s largest gas market.

Education: MSc in business from BI Norwegian Business School.

Family relations: No family relations to other members of the CEC, members of the board or the corporate assembly.

Other matters: Økland is a Norwegian citizen and resident in Norway.

Irene Rummelhoff,

executive vice president New Energy Solutions (NES)

114 Statoil, Annual Report on Form 20-F 2016

Irene Rummelhoff

Born: 1967

Position: Executive vice president of Statoil ASA since 1 June 2015.

External offices: Deputy chair of the board of directors of Norsk Hydro ASA.

Number of shares in Statoil ASA as of 31 December 2016: 21,556

Loans from Statoil ASA: None

Experience: Rummelhoff joined Statoil in 1991. She has held a number of management positions within international business development, exploration, and the downstream business in Statoil.

Education: Master’s degree in petroleum geosciences from the Norwegian Institute of Technology (NTH).

Family relations: No family relations to other members of the CEC, members of the board or the corporate assembly.

Other matters: Rummehoff is a Norwegian citizen and resident in Norway.

Statoil has granted loans to the Statoil-employed spouse of certain of the Executive Vice Presidents as part of its general loan arrangement for Statoil employees. Employees in salary grade 12 or higher may take out a car loan from Statoil in accordance with standardised provisions set by the company. The standard maximum car loan is limited to the cost of the car, including registration fees, but not exceeding NOK 300,000. Employees outside the collective labour area are entitled to a car loan up to NOK 575,000 (vice presidents and senior vice presidents) or NOK 475,000 (other positions). The car loan is interest-free, but the tax value, "interest advantage", must be reported as salary. Permanent employees in Statoil ASA may also apply for a consumer loan up to NOK 300.000. The interest rate on consumer loans is corresponding to the standard rate in effect at any time for “reasonable loans” from employer as decided by the Norwegian Ministry of Finance, i.e. the lowest rate an employer may offer without triggering taxation of the advantage for the employee.

Statoil, Annual Report on Form 20-F 2016 115

3.7 Compensation to governing bodies

Remuneration to the board of directors

The remuneration of the board and its sub-committees is decided by the corporate assembly, based on a recommendation from the nomination committee. The members have an annual, fixed remuneration, except for deputy members (only elected for employee-elected board members) who receive remuneration per meeting attended. Separate rates are set for the board's chair, deputy chair and other members, respectively. Separate rates are also adopted for the board's sub-committees, with similar differentiation between the chair and the other members of each committee. The employee-elected members of the board receive the same remuneration as the shareholder-elected members.

The board receives its remuneration by cash payment. Board members from outside Scandinavia and outside Europe, respectively, receive separate travel allowances for each meeting attended. The remuneration is not linked to the board members' performance, option programmes or similar. None of the shareholder-elected board members have a pension scheme or agreement concerning pay after termination of their office with the company. If shareholder-elected members of the board and/or companies they are associated with should take on specific assignments for Statoil in addition to their board membership, this will be disclosed to the full board.

In 2016, the total remuneration to the board, including fees for the board's three sub-committees, was NOK 6,524,119 (USD 776,803).

Detailed information about the individual remuneration to the members of the board of directors in 2016 is provided in the table below.

116 Statoil, Annual Report on Form 20-F 2016

Members of the board (figures in USD thousand except number of shares)	Total remuneration	Share ownership as of 31 December 2016

Øystein Løseth (chair of the board)	104	1,040
Roy Franklin (deputy chair of the board)	114	-
Jakob Stausholm¹⁾	52	n.a.
Wenche Agerup	65	2,522
Bjørn Tore Godal	65	-
Rebekka Glasser Herlofsen	61	-
Maria Johanna Oudeman	81	-
Jeroen van der Veer²⁾	61	-
Lill-Heidi Bakkerud	55	342
Stig Lægreid	55	1,881
Ingrid Elisabeth di Valerio	61	3,670

Total	777	9,455

1) Member until 30 September 2016 (resigned).
2) Member from 18 March 2016.

Remuneration to the corporate assembly

The remuneration of the corporate assembly is decided by the general meeting, based on a recommendation from the nomination committee. The members have an annual, fixed remuneration, except for deputy members who receive remuneration per meeting attended. Separate rates are set for the corporate assembly’s chair, deputy chair and other members, respectively. The employee-elected members of the corporate assembly receive the same remuneration as the shareholder-elected members. The corporate assembly receives its remuneration by cash payment.

In 2016, the total remuneration to the corporate assembly was NOK 1,065,682 (USD 126,875).

Remuneration to the corporate executive committee

In 2016, the aggregate remuneration to the corporate executive committee was NOK 71,414,699 (USD 8,503,083) (rounded figure). The board of directors’ complete declaration on remuneration of executive personnel follows below.

Statoil, Annual Report on Form 20-F 2016 117

Main elements - Statoil executive remuneration
Remuneration element	Objective	Award level	Performance criteria

Base salary	Attract and retain the right individuals providing competitive but not market-leading terms.	We offer base salary levels which are aligned with and differentiated according to the individual's responsibility and performance. The level is competitive in the markets in which we operate.	The base salary is normally subject to annual review based on an evaluation of the individual’s performance.; see “Annual Variable Pay" below
Cash compensation	The cash compensation is applied as a supplementing fixed remuneration element to be competitive in the market.	Reference is made to the remuneration table. Four of the executive vice presidents receive a cash compensation in lieu of pension accrual with reference to the section on pension and insurance scheme.	No performance criteria are linked to the cash compensation. The cash compensation is not included in the pensionable income.
Annual variable pay	Encourage a strong performance culture. Reward individuals for annual achievement of business objectives and goals relating to ‘how’ results are delivered.	Members of the corporate executive committee are entitled to annual variable pay ranging from 0 – 50% of their fixed remuneration. Target¹ value is 25%. The threshold principles and the company modifier are applied.	Achievement of annual performance goals (how and what to deliver), in order to create long-term and sustainable shareholder value. Assessment of goals defined on the individual’s performance contract including objectives related to selected KPI’s on the balanced scorecard constitute the basis for annual variable pay.
Long-term incentive (LTI)	Strengthen the alignment of top management and shareholder’s long term interests. Retention of key executives.	The LTI system is a monetary compensation calculated as a portion of the participant’s base salary. On behalf of the participant, the company acquires shares equivalent to the net annual grant amount. The shares are subject to a three-year lock-in period and then released for the participant’s disposal. The level of the annual LTI reward is in the range of 25-30%. The threshold principles are applied for the annual grant The company performance modifier is not applied for the LTI.in Statoil ASA	In Statoil ASA, LTI participation and grant level are reflective of the level and impact of the position and not directly linked to the incumbent’s performance.
Threshold	Financial threshold for payment of variable remuneration and award of LTI grant.	The threshold is based on Statoil group’s full-year adjusted earnings after tax ², requiring that a minimum level of earnings must be achieved for any payments to be made. This minimum level is USD 2 billion. Earnings between USD 2 and 3.3 will result in bonus payments reduced by 50%. Above USD 3.3 billion the threshold is fully achieved and variable pay payments are not affected.	Adjusted earnings after tax. Application of the threshold is subject to a discretionary assessment of the company’s overall performance.
Company performance modifier	Strengthen the alignment between variable remuneration and the company’s performance.	The company performance modifier determines the proportion of the bonus that will be paid, ranging from 50% to 150% The company performance modifier is subject to approval by the annual general meeting.	Company performance is assessed against two equally weighted measures: relative total shareholder return (TSR) and relative return on average capital employed (RoACE). Application of the modifier is subject to discretionary assessment based on the company’s overall performance.
Pension & insurance schemes	Provide competitive postemployment and other benefits.	The company offers a general occupational pension plan and insurance scheme aligned with local markets c.f. section on pension and insurance scheme	N/A
Employee share savings plan	Align and strengthen employee and shareholder’s interests and remunerate for long term commitment and value creation.	The share savings plan is offered to all employees in the group, provided no restrictions due to local legislation or business requirements. Participants are offered 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

² See calculation of Adjusted earnings after tax in section 5.2 Accounting standards and non-GAAP measures

118 Statoil, Annual Report on Form 20-F 2016

Pension and insurance schemes

Members of the corporate executive committee in Statoil ASA are covered by the company’s general occupational pension scheme which is a defined contribution scheme with a contribution level of 7% below 7,1 G and 22% above 7,1 G³. A defined benefit scheme is retained by a grandfathered group of employees. For new members of the corporate executive committee appointed after 13February 2015, a cap on pension contribution at 12 G is applied. In lieu of pension accrual above 12 G a cash compensation is provided.

Members of the corporate executive committee appointed before 13 February 2015, will maintain their pension contribution above 12 G based on obligations in previously established agreements.

The chief executive officer and three executive vice presidents have individual early retirement pension agreement with the company.

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.

Statoil has implemented a general cap on pensionable income at 12 G for all new hires into the company employed as of 1 September 2017.

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/defined benefit plan. Members of the corporate executive committee are covered by the general insurance schemes applicable within Statoil.

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.

Other benefits

The members of the corporate executive committee have benefits in kind such as company car and electronic communication. They are also eligible for participation in the share saving scheme as described above.

Performance management, assessment and results essential for variable pay

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

Performance is evaluated in two dimensions; “What” we deliver and “How” we deliver. “What” we deliver (business delivery) is defined through the company’s performance framework “Ambition to Action”, which addresses strategic objectives, key performance Indicators (KPIs) and actions across the five perspectives; Safety, Security and Sustainability, People and Leadership, Operations, Market and Results. Generally, Statoil believes in setting ambitious targets to inspire and drive strong performance.

Goals on “How” we deliver are based on our core values and leadership principles and address the behaviour required and expected in order to achieve our delivery goals.

³ G = The basic amount of the Norwegian Social security system

Statoil, Annual Report on Form 20-F 2016 119

Performance evaluation is holistic, involving both measurement and assessment. Since KPIs are indicators only, sound judgement and hindsight insights are applied. Significant changes in assumptions are taken into account, as well as target ambition levels, sustainability of delivered results and strategic contribution.

This balanced approach, which involves a broad set of goals defined in relation to both “What” and “How” 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.

In the performance contracts of the chief executive officer and chief financial officer, one of several targets is related to the company’s relative total shareholder return (TSR). The amount of the annual variable pay is decided based on an overall assessment of the performance of various targets including but not limited to the company's relative TSR.

120 Statoil, Annual Report on Form 20-F 2016

In 2016, 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		2016 assessment
Safety, security and sustainability	The strategic objectives and actions address safety, security and sustainability	Serious Incident Frequency (actual) of 0.29 was above target. Target on the number of oil and gas leakages was not met. CO2 intensity for the upstream portfolio was in line with target.
People and organisation	The strategic objectives and actions address high performing leaders and teams, and global and cost-effective capabilities	Employee engagement was above target, increasing from 2015 during a period of extensive organizational efficiency programmes. People development was in line with 2015, with strong focus on building competence and upholding learning activity throughout 2016 yielding positive results.
Operations	The strategic objectives and actions address reliable and cost-efficient operations, and value-driven technology development	Production exceeded target, despite an extensive maintenance programme. Relative unit production cost remained the lowest among industry peers. Production efficiency was slightly below target.
Market	The strategic objectives and actions address stakeholder trust, value chain optimisation and portfolio and project management	Capex was below target and external guiding level, due to increased efficiency and stricter prioritization. Cost efficiency for projects under development was above target, exceeding the industry average. Reserve replacement ratio was below the target of >1. Value creation from exploration was below target, mainly due to lower-than-expected discovered volumes.
Results	The strategic objectives and actions address shareholder return, financial robustness, value creation from exploration and cost & capital discipline	Relative Shareholder Return (TSR) improved and ended 3^rd in an industry peer group of 12. Relative ROACE for 2016 ended 9^th in an industry peer group of 12, falling as a result of exposure to upstream margins. The cash flow improvement programme delivered above target.

Board assessment of the chief executive officer’s performance

In its assessment of the chief executive officer’s performance, and consequently his annual pay for 2016, the board has put emphasis on the solid delivery on production, efficiency, and prioritization. CAPEX was below target and guiding, and relative TSR is first quartile. The number of oil and gas leakages was above target, while CO2 intensity for the upstream portfolio was in line with target. The actual SIF was above target (0.29 versus target of 0.18).

	⁺
	Fixed remuneration
Members of corporate executive committee (figures in USD thousand, except no. of shares)^{1), 2)}	Fixed pay³⁾	Cash allowance⁴⁾	LTI ⁵⁾	Annual variable pay⁶⁾	Taxable benefits	2016 Taxable compensation	Non-taxable benefits in kind	Estimated pension cost⁷⁾	Estimated present value of pension obligation⁸⁾	2015 Taxable compensation⁹⁾	Share ownership at 31 December 2016

Eldar Sætre¹³⁾	937	0	138	245	37	1,356	0	0	11,261	1,754	47,882
Margareth Øvrum	453	0	53	106	18	631	20	0	6,788	751	49,227
Timothy Dodson	440	0	51	67	15	573	39	141	4,746	673	29,418
Irene Rummelhoff	349	54	37	61	10	511	0	26	1,070	294	21,556
Jens Økland	347	58	40	53	12	509	0	22	785	329	13,937
Arne Sigve Nylund	398	0	49	80	18	546	0	112	4,047	690	11,312
Lars Christian Bacher	419	0	45	89	14	567	52	110	2,039	647	24,896
Hans Jakob Hegge	372	62	43	71	13	561	0	23	1,097	251	28,190
Jannicke Nilsson¹⁰⁾	32	5	2	0	0	40	0	3	1,032	NA	35,049
Anders Opedal¹¹⁾	338	57	40	78	2	514	0	23	1,030	456	15,910
Torgrim Reitan¹²⁾	611	0	49	87	137	884	0	115	1,947	744	32,276
John Knight¹³⁾	1,679	0	0	0	131	1,810	0	0	0	2,089	103,808

Statoil, Annual Report on Form 20-F 2016 121

1) All figures in the table are presented in USD based on average currency rates (2016: USD/NOK = 8.3987, USD/GBP = 1.3538. 2015: USD/NOK = 8,0739, USD/GBP = 1,5289). The figures are presented on accrual basis.

2) All CEC members receive their remuneration in Norwegian Kroner except John Knight who receives the remuneration in GBP.

3) Fixed pay consists of base salary, fixed remuneration element, holiday allowance and other administrative benefits.

4) Cash allowance in lieu of pension accrual above 12 G (the base amount in the national insurance scheme).

5) The fixed long-term incentive (LTI) element implies an obligation to invest the net amount in Statoil shares, including a lock-in period. The LTI element is presented the year it is granted for the members of the corporate executive committee employed by Statoil ASA.

6) Annual variable pay includes holiday allowance for corporate executive committee (CEC) members resident in Norway.

7) Estimated pension cost is calculated based on actuarial assumptions and pensionable salary (mainly base salary) at 31 December 2015 and is recognized as pension cost in the statement of income for 2016.

8) Estimated present value of pension obligation related to Eldar Sætre, Arne Sigve Nylund, Margareth Øvrum og Timothy Dodson are based on the estimated value of paid-up policies and rights letters from the Defined Benefit Pension Scheme. Estimated present value of pension obligation for the rest of the members of the corporate executive committee employed by Statoil ASA, is presented with value of paid-up policies and right letters from the Defined Benefit Pension Scheme and accrued pension assets from the Defined Contribution Pension Scheme.

9) Includes 2015 CEC members who are also CEC members in 2016.

10) Jannicke Nilsson was appointed executive vice president and chief operating officer (COO) from 1 December 2016.

11) Anders Opedal left the position as executive vice president and chief operating officer (COO) at 30 November 2016.

12) Compensation and benefit for Torgrim Reitan is according to Statoil’s international assignment terms.

13) Fixed pay for Eldar Sætre includes a fixed remuneration element of USD 238 thousand not included in pensionable salary. John Knight’s fixed pay includes a fixed remuneration element of USD 143 thousand that replaces his defined contribution pension plan and a fixed remuneration element of USD 724 thousand replacing his variable pay arrangements.

There are no loans from the company to members of the corporate executive committee.

122 Statoil, Annual Report on Form 20-F 2016

Company performance modifier

Introduction

Based on approval by the annual general meeting in 2016 a company performance modifier has been introduced to be applied in calculation of variable pay. The intention is to continue with the performance modifier in 2017. The relative total shareholder return is recommended as one of the criteria in the modifier. Thus, the case is submitted to the annual general meeting for approval, pursuant to the provisions in the Public Limited Companies Act § 5-6 third paragraph last sentence ref. § 6-16 a, first paragraph third sentence number 3.

Background

Statoil has implemented annual variable pay schemes (AVP) for members of the corporate executive committee. The schemes are described in section on remuneration concept for the corporate executive committee of this declaration. Other executives, managers and employees in defined professional positions are also eligible for individual variable pay according to the company’s guidelines.

The company performance modifier is implemented to strengthen the link between the company’s overall financial results and the individual variable pay. The governmental guidelines on executive remuneration also underline that “there shall be a clear connection between the variable salary and the performance of the company.”

Proposal

Based on this, the performance modifier will be continued in 2017. The company performance will be assessed against two equally weighted measures: relative total shareholder return (TSR) and relative return on average capital employed (RoACE). TSR and RoACE are currently also applied as performance indicators in the corporate performance management system.

The results of these two performance measures are compared to our peers and our relative position determined. A position of Q1 means that Statoil is amongst the top scoring quartile of peer companies. A position of Q4 means Statoil is in the bottom performing quartile. In years with strong deliveries on relative TSR and RoACE, the matrix will result in the variable pay being modified with a factor higher than one and, correspondingly, lower than one in weak years. The combination of ratings for both measures, will act as a ‘multiplier’ according to the guideline in the matrix displayed below.

By applying relative numbers, the effect of fluctuating oil price will be reduced. Within the framework of 50 - 150%, the matrix is a guideline and the multiplier (percentages) may be adjusted if oil or gas price effects or other occurrences outside the control of the company are deemed to cause disproportionate results in a given year.

Subject to approval by the 2017 general meeting, the company performance modifier will be continued in calculations of annual variable pay for members of the corporate executive committee in the earning year 2017 with subsequent impact on annual variable pay in 2018. The modifier will also be applied in other variable pay schemes below the corporate executive level. Further application of the company performance modifier will also be assessed and decided if deemed appropriate.

The annual variable pay for members of the corporate executive committee will be within a framework of 50% of the fixed remuneration irrespective of the result of the modifier. Any deviations from this framework for members of the corporate executive committee will be explained in the board’s annual declaration on remuneration and other employment terms for Statoil’s corporate executive committee.

Statoil, Annual Report on Form 20-F 2016 123

3.8 Share ownership

The number of Statoil shares owned by the members of the board of directors and the executive committee and/or owned by their close associates is shown below. Individually, each member of the board of directors and the corporate executive committee owned less than 1% of the outstanding Statoil shares.

124 Statoil, Annual Report on Form 20-F 2016

	As of 31 December	As of 8 March
Ownership of Statoil shares (including share ownership of «close associates»)	2016	2017

Members of the corporate executive committee
Eldar Sætre	47,882	48,629
Hans Jakob Hegge	28,190	29,111
Jannicke Nilsson	35,049	35,972
Lars Christian Bacher	24,896	20,895
Torgrim Reitan	32,276	33,133
John Knight	103,808	105,593
Tim Dodson	29,418	30,349
Margareth Øvrum	49,227	50,499
Arne Sigve Nylund	11,312	11,312
Jens Økland	13,937	14,462
Irene Rummelhoff	21,556	22,082

Members of the board of directors
Øystein Løseth	1,040	1,040
Roy Franklin	0	0
Bjørn Tore Godal	0	0
Jeroen van der Veer	0	0
Maria Johanna Oudeman	0	0
Rebekka Glasser Herlofsen	0	0
Wenche Agerup	2,522	2,522
Lill-Heidi Bakkerud	342	342
Ingrid Elisabeth di Valerio	3,670	3,949
Stig Lægreid	1,881	1,881

Individually, each member of the corporate assembly owned less than 1% of the outstanding Statoil shares as of 31 December 2016 and as of 8 March 2017. In aggregate, members of the corporate assembly owned a total of 24,578 shares as of 31 December 2016 and a total of 25,331 shares as of 8 March 2017. Information about the individual share ownership of the members of the corporate assembly is presented in the section 3.8 Corporate assembly, board of directors and management.

The voting rights of members of the board of directors, the corporate executive committee and the corporate assembly do not differ from those of ordinary shareholders.

3.9 External auditor

Our external registered public accounting firm (external auditor) is independent in relation to Statoil and is elected by the general meeting of shareholders. The external auditor's fee must be approved by the general meeting of shareholders.

Pursuant to the instructions for the board's audit committee approved by the board of directors, the audit committee is responsible for ensuring that the company is subject to an independent and effective external and internal audit. Every year, the external auditor presents a plan to the audit committee for the execution of the external auditor's work. The external auditor attends the meeting of the board of directors that deals with the preparation of the annual accounts.

The external auditor also participates in meetings of the audit committee. The audit committee considers all reports from the external auditor before they are considered by the board of directors. The audit committee meets at least five times a year and both the board and the board’s audit committee hold meetings with the internal auditor and the external auditor on a regular basis without the company’s management being present.

When evaluating the external auditor, emphasis is placed on the firm's qualifications, capacity, local and international availability and the size of the fee.

The audit committee evaluates and makes a recommendation to the board of directors, the corporate assembly and the general meeting of shareholders regarding the choice of external auditor. The committee is responsible for ensuring that the external auditor

Statoil, Annual Report on Form 20-F 2016 125

meets the requirements in Norway and in the countries where Statoil is listed. The external auditor is subject to the provisions of US securities legislation, which stipulates that a responsible partner may not lead the engagement for more than five consecutive years.

The audit committee's policies and procedures for pre-approval

In its instructions for the audit committee, the board of directors has delegated authority to the audit committee to pre-approve assignments to be performed by the external auditor. Within this pre-approval, the audit committee has issued further guidelines. The audit committee has issued guidelines for the management's pre-approval of assignments to be performed by the external auditor.

All audit-related and other services provided by the external auditor must be pre-approved by the audit committee. Provided that the types of services proposed are permissible under SEC guidelines, pre-approval is usually granted at a regular audit committee meeting. The chair of the audit committee has been authorised to pre-approve services that are in accordance with policies established by the audit committee that specify in detail the types of services that qualify. It is a condition that any services pre-approved in this manner are presented to the full audit committee at its next meeting. Some pre-approvals can therefore be granted by the chair of the audit committee if an urgent reply is deemed necessary.

Remuneration of the external auditor in 2014 – 2016

In the annual Consolidated financial statements and in the parent company's financial statements, the independent auditor's remuneration is split between the audit fee and the fee for audit-related and other services. The chair presents the breakdown between the audit fee and the fee for audit-related and other services to the annual general meeting of shareholders.

The following table sets out the aggregate fees related to professional services rendered by Statoil's principal accountant KPMG AS, for the fiscal year 2016, 2015 and 2014.

126 Statoil, Annual Report on Form 20-F 2016

Auditor's remuneration
	Full year
(in USD million, excluding VAT)	2016	2015	2014

Audit fee	6.5	6.1	7.1
Audit related fee	1.0	1.7	1.3
Tax fee	0.1	0.0	0.0
Other service fee	0.0	0.0	0.0

Total	7.5	7.9	8.4

All fees included in the table have been approved by the board's audit committee.

Audit fee is defined as the fee for standard audit work that must be performed every year in order to issue an opinion on Statoil's Consolidated financial statements, on Statoil's internal control over annual reporting and to issue reports on the statutory financial statements. It also includes other audit services, which are services that only the independent auditor can reasonably provide, such as the auditing of non-recurring transactions and the application of new accounting policies, audits of significant and newly implemented system controls and limited reviews of quarterly financial results.

Audit-related fees include other assurance and related services provided by auditors, but not limited to those that can only reasonably be provided by the external auditor who signs the audit report, that are reasonably related to the performance of the audit or review of the company's financial statements, such as acquisition due diligence, audits of pension and benefit plans, consultations concerning financial accounting and reporting standards.

Other services fees include services provided by the auditors within the framework of the Sarbanes-Oxley Act, i.e. certain agreed procedures.

In addition to the figures in the table above, the audit fees and audit-related fees relating to Statoil lated fees relating to Statoil-127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127127operated licences paid to KPMG for the years 2016, 2015 and 2014 amounted to USD 0.8 million, USD 0.9 million and USD 1.0 million, respectively.

3.10 Controls and procedures

This section describes controls and procedures relating to our financial reporting.

Evaluation of disclosure controls and procedures

The management, with the participation of our chief executive officer and chief financial officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(b) as of the end of the period covered by the Form 20-F. Based on that evaluation, the chief executive officer and chief financial officer have concluded that these disclosure controls and procedures are effective at a reasonable level of assurance.

In order to facilitate the evaluation, the disclosure committee reviews material disclosures made by Statoil for any errors, misstatements and omissions. The disclosure committee is chaired by the chief financial officer. It consists of the heads of investor relations, accounting and financial compliance, performance management and risk, tax and the general counsel and it may be supplemented by other internal and external personnel. The head of the internal audit is an observer at the committee's meetings.

In designing and evaluating our disclosure controls and procedures, our management, with the participation of the chief executive officer and chief financial officer, recognised that any controls and procedures, no matter how well designed and operated, can only provide reasonable assurance that the desired control objectives will be achieved, and that the management must necessarily exercise judgment when evaluating the cost-benefit aspects of possible controls and procedures. Because of the limitations inherent in all control systems, no evaluation of controls can provide absolute assurance that all control issues and any instances of fraud in the company have been detected.

The management's report on internal control over financial reporting

The management of Statoil ASA is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is a process designed, under the supervision of the chief executive officer and chief financial officer, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of Statoil's financial statements for external reporting purposes in accordance with International Financial Reporting Standards (IFRS) as adopted by the European Union (EU). The accounting policies applied by the group also comply with IFRS as issued by the International Accounting Standards Board (IASB).

Statoil, Annual Report on Form 20-F 2016 127

The management has assessed the effectiveness of internal control over financial reporting based on the Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this assessment, the management has concluded that Statoil's internal control over financial reporting as of 31 December 2016 was effective.

Statoil's internal control over financial reporting includes policies and procedures that pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets, provide reasonable assurance that transactions are recorded in the manner necessary to permit the preparation of financial statements in accordance with IFRS, and that receipts and expenditures are only carried out in accordance with the authorisation of the management and directors of Statoil; and provide reasonable assurance regarding the prevention or timely detection of any unauthorised acquisition, use or disposition of Statoil's assets that could have a material effect on our financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect all misstatements. Moreover, projections of any evaluation of the effectiveness of internal control to future periods are subject to a risk that controls may become inadequate because of changes in conditions and that the degree of compliance with the policies or procedures may deteriorate.

The effectiveness of internal control over financial reporting as of 31 December 2016 has been audited by KPMG AS, an independent registered public accounting firm that also audits the Consolidated financial statements included in this annual report. Their audit report on the internal control over financial reporting is included in section 4.1 Consolidated financial statements in this report.

No changes occurred in our internal control over financial reporting during the period that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

We continuously make improvement to our internal control environment.

128 Statoil, Annual Report on Form 20-F 2016

4.1 Statoil Consolidated financial statements

With effect from 1 January 2016 the financial statements are presented in US dollars (USD). Comparative data has been converted from Norwegian kroner (NOK) to USD accordingly. For more information concerning this see note 26 Change of presentation currency.

CONSOLIDATED STATEMENT OF INCOME
		Full year
(in USD million)	Note	2016	2015	2014

Revenues		45,688	57,900	96,708
Net income from equity accounted investments		(119)	(29)	(34)
Other income	4	304	1,770	2,590

Total revenues and other income	3	45,873	59,642	99,264

Purchases [net of inventory variation]		(21,505)	(26,254)	(47,980)
Operating expenses		(9,025)	(10,512)	(11,657)
Selling, general and administrative expenses		(762)	(921)	(1,159)
Depreciation, amortisation and net impairment losses	10, 11	(11,550)	(16,715)	(15,925)
Exploration expenses	11	(2,952)	(3,872)	(4,666)

Net operating income	3	80	1,366	17,878

Net financial items	8	(258)	(1,311)	20

Income before tax		(178)	55	17,898

Income tax	9	(2,724)	(5,225)	(14,011)

Net income		(2,902)	(5,169)	3,887

Attributable to equity holders of the company		(2,922)	(5,192)	3,871
Attributable to non-controlling interests		20	22	16

Basic earnings per share (in USD)		(0.91)	(1.63)	1.22
Diluted earnings per share (in USD)		(0.91)	(1.63)	1.21
Weighted average number of ordinary shares outstanding (in millions)		3,195	3,179	3,180
Weighted average number of ordinary shares outstanding, diluted (in millions)		3,207	3,189	3,189

Statoil, Annual Report on Form 20-F 2016 129

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
		Full year
(in USD million)	Note	2016	2015	2014

Net income		(2,902)	(5,169)	3,887

Actuarial gains (losses) on defined benefit pension plans	19	(503)	1,599	636
Income tax effect on income and expenses recognised in OCI		129	(461)	(56)
Items that will not be reclassified to the Consolidated statement of income		(374)	1,138	580

Currency translation adjustments		17	(3,976)	(5,167)
Items that may be subsequently reclassified to the Consolidated statement of income		17	(3,976)	(5,167)

Other comprehensive income		(357)	(2,838)	(4,587)

Total comprehensive income		(3,259)	(8,007)	(701)

Attributable to the equity holders of the company		(3,279)	(8,030)	(717)
Attributable to non-controlling interests		20	22	16

130 Statoil, Annual Report on Form 20-F 2016

CONSOLIDATED BALANCE SHEET
		At 31 December
(in USD million)	Note	2016	2015	2014

ASSETS
Property, plant and equipment	10	59,556	62,006	75,619
Intangible assets	11	9,243	9,452	11,458
Equity accounted investments	12	2,245	824	1,127
Deferred tax assets	9	2,195	2,022	1,732
Pension assets	19	839	1,284	1,072
Derivative financial instruments	25	1,819	2,697	4,023
Financial investments	13	2,344	2,336	2,634
Prepayments and financial receivables	13	893	967	766

Total non-current assets		79,133	81,588	98,430

Inventories	14	3,227	2,502	3,193
Trade and other receivables	15	7,839	6,671	11,212
Derivative financial instruments	25	492	542	717
Financial investments	13	8,211	9,817	7,968
Cash and cash equivalents	16	5,090	8,623	11,182

Total current assets		24,859	28,154	34,272

Assets classified as held for sale	4	537	0	0

Total assets		104,530	109,742	132,702

EQUITY AND LIABILITIES
Shareholders’ equity		35,072	40,271	51,225
Non-controlling interests		27	36	57

Total equity	17	35,099	40,307	51,282

Finance debt	18, 22	27,999	29,965	27,593
Deferred tax liabilities	9	6,427	7,421	9,613
Pension liabilities	19	3,380	2,979	3,752
Provisions	20	13,406	12,422	15,766
Derivative financial instruments	25	1,420	1,285	611

Total non-current liabilities		52,633	54,073	57,335

Trade, other payables and provisions	21	9,666	9,333	13,545
Current tax payable		2,184	2,740	5,321
Finance debt	18	3,674	2,326	3,561
Dividends payable	17	712	700	770
Derivative financial instruments	25	508	264	887

Total current liabilities		16,744	15,363	24,085

Liabilities directly associated with the assets classified as held for sale	4	54	0	0

Total liabilities		69,431	69,436	81,420

Total equity and liabilities		104,530	109,743	132,702

Statoil, Annual Report on Form 20-F 2016 131

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
(in USD million)	Share capital	Additional paid-in capital	Retained earnings	Currency translation adjustments	Shareholders' equity	Non-controlling interests	Total equity

At 31 December 2013	1,139	5,741	47,690	3,863	58,432	81	58,513
Net income for the period			3,871		3,871	16	3,887
Other comprehensive income			580	(5,167)	(4,587)		(4,587)
Total comprehensive income							(701)
Dividends			(6,517)		(6,517)		(6,517)
Other equity transactions		(26)	54		27	(39)	(12)

At 31 December 2014	1,139	5,714	45,677	(1,305)	51,225	57	51,282

Net income for the period			(5,192)		(5,192)	22	(5,169)
Other comprehensive income			1,138	(3,976)	(2,838)		(2,838)
Total comprehensive income							(8,007)
Dividends			(2,930)		(2,930)		(2,930)
Other equity transactions		6	(0)		6	(43)	(38)

At 31 December 2015	1,139	5,720	38,693	(5,281)	40,271	36	40,307

Net income for the period			(2,922)		(2,922)	20	(2,902)
Other comprehensive income			(374)	17	(357)		(357)
Total comprehensive income							(3,259)
Dividends	17	887	(2,824)		(1,920)		(1,920)
Other equity transactions		1	0		2	(30)	(28)

At 31 December 2016	1,156	6,607	32,573	(5,264)¹⁾	35,072	27	35,099

1) Balance of currency translation adjustments includes a loss of USD 321 million directly associated with assets classified as held for sale. See note 4 Acquisitions and disposals for information on transaction.

Refer to note 17 Shareholders’ equity and dividends.

132 Statoil, Annual Report on Form 20-F 2016

CONSOLIDATED STATEMENT OF CASH FLOWS
		Full year
(in USD million)	Note	2016	2015	2014

Income before tax		(178)	55	17,898

Depreciation, amortisation and net impairment losses	10, 11	11,550	16,715	15,925
Exploration expenditures written off	11	1,800	2,164	2,097
(Gains) losses on foreign currency transactions and balances		(137)	1,166	883
(Gains) losses on sales of assets and businesses	4	(110)	(1,716)	(1,998)
(Increase) decrease in other items related to operating activities		1,076	558	(1,671)
(Increase) decrease in net derivative financial instruments	25	1,307	1,551	254
Interest received		280	363	341
Interest paid		(548)	(443)	(551)

Cash flows provided by operating activities before taxes paid and working capital items		15,040	20,414	33,178

Taxes paid		(4,386)	(8,078)	(15,308)

(Increase) decrease in working capital		(1,620)	1,292	2,335

Cash flows provided by operating activities		9,034	13,628	20,205

Additions through business combinations	4	0	(398)	0
Capital expenditures and investments		(12,191)	(15,518)	(19,497)
(Increase) decrease in financial investments		877	(2,813)	(1,919)
(Increase) decrease in other non-current items		107	(22)	128
Proceeds from sale of assets and businesses	4	761	4,249	3,514

Cash flows used in investing activities		(10,446)	(14,501)	(17,775)

New finance debt	18	1,322	4,272	3,010
Repayment of finance debt		(1,072)	(1,464)	(1,537)
Dividend paid	17	(1,876)	(2,836)	(5,499)
Net current finance debt and other		(333)	(701)	(2)

Cash flows provided by (used in) financing activities		(1,959)	(729)	(4,028)

Net increase (decrease) in cash and cash equivalents		(3,371)	(1,602)	(1,598)

Effect of exchange rate changes on cash and cash equivalents		(152)	(871)	(1,329)
Cash and cash equivalents at the beginning of the period (net of overdraft)	16	8,613	11,085	14,013

Cash and cash equivalents at the end of the period (net of overdraft)	16	5,090	8,613	11,085

Cash and cash equivalents include bank overdrafts of nil at 31 December 2016 (2015: USD 10 million; 2014: USD 97 million).

Interest paid in cash flows provided by operating activities is excluding capitalised interest of USD 355 million at 31 December 2016, USD 392 million at
31 December 2015 and USD 250 million at 31 December 2014. Capitalised interest is included in Capital expenditures and investments in cash flows used in investing activities.

Statoil, Annual Report on Form 20-F 2016 133

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 Børs (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 2016 were authorised for issue in accordance with a resolution of the board of directors on 9 March 2017.

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), effective at 31 December 2016.

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
IFRS 15, effective from 1 January 2018, covers the recognition of revenue in the financial statements and related disclosure. IFRS 15 will replace IAS 18 Revenue.

IFRS 15 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 for the amounts that reflect the consideration to which Statoil expects to be entitled in exchange for those goods and services.

The impact of adopting IFRS 15 will principally impact the Marketing, Midstream and Processing segment (MMP), which accounts for the majority of Statoil’s petroleum sales to customers, and which is responsible for the marketing and sale of the State’s direct financial interest’s (SDFI’s) petroleum volumes.

IFRS 15 requires adoption either on a retrospective basis or on the basis of the cumulative effect on retained earnings. Statoil has not yet determined its implementation method for the standard, but at this stage in the evaluations, does not expect either implementation method to affect the Consolidated statement of income, balance sheet or statement of cash flows materially.

Statoil will adopt IFRS 15 on 1 January 2018.

134 Statoil, Annual Report on Form 20-F 2016

The most significant accounting matters with regards to the implementation of IFRS 15 in Statoil, as well as their expected impact, can be summarised as follows.

Marketing and sale of the Norwegian State’s share of crude oil and natural gas production from the Norwegian continental shelf (NCS) and related agent/principal evaluations; in evaluating these sales, Statoil has considered whether it acts as the principal in the transactions under IFRS 15, i.e. whether it controls the State’s volumes prior to onwards sales to third party customers. Statoil’s sales of the State’s natural gas volumes are performed for the Norwegian State’s account and risk, and although Statoil has been granted the ability to direct the use of the volumes, all the benefits from the sales of these volumes flow to the State. On that basis, Statoil is not considered the principal in the sale of the SDFI’s natural gas volumes. In the sales of the State-originated crude oil, Statoil also directs the use of the volumes. However, although certain benefits from these sales subsequently flow to the State, Statoil purchases the crude oil volumes from the State and obtains substantially all the remaining benefits. Statoil therefore is considered the principal in the crude oil sales. The accounting for Statoil’s sale of the SDFI’s natural gas and crude oil under IFRS 15 will consequently not lead to material changes compared to the current practice under IAS 18, as separately described in this note disclosure.

Transport of goods sold; in certain sales of goods such as crude oil or natural gas, Statoil provides transport services after control of the good has been transferred to the customer. Following implementation of IFRS 15, in most such instances this transport will be considered a service that is completed over time and is distinct from the good sold, and therefore will be recognised separately. The impact on the Consolidated financial statements from the resulting timing differences in the reflection of revenues from contracts with customers is currently not expected to be material.

Accounting for taxes paid in kind under the terms of profit sharing agreements (PSAs); in certain countries, taxes are paid in kind and the volumes are subsequently sold according to the terms of the PSA and applicable tax regulations. As the sale of the volumes is not performed directly by Statoil, evaluation is still ongoing as to whether the sales proceeds qualify as revenue from contracts with customers under IFRS 15. Irrespective of the conclusion reached, the in-kind tax payments and related sales of volumes will continue to be accounted for gross in the Statement of income, classified as tax expense in accordance with IAS 12 Income taxes and as a form of revenue, respectively.

IFRS 9 Financial Instruments
IFRS 9, 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.

IFRS 9 will principally impact Statoil’s financing and liquidity management activities, as well as the MMP segment, which reflects the majority of Statoil’s trade receivables and commodity-based financial instruments.

Portions of Statoil’s cash equivalents and current financial investments tied to liquidity management, which under IAS 39 are classified as held for trading and reflected at fair value through profit and loss, will under IFRS 9 be classified and measured at amortised cost, based on an evaluation of the contractual terms and the business model applied. The investment portfolio of Statoil’s captive insurance company will continue to be classified and measured at fair value through profit and loss under IFRS 9.

The impact on the Consolidated statement of income of commodity-based derivative financial instruments, which due to their connection with sales and revenue risk management currently are classified under revenues, is expected to be reflected in an appropriate section within total revenues and other income upon the implementation of IFRS 9. No decisions have yet been made related to whether, and if so, on which elements, hedge accounting will be applied.

IFRS 9’s transition provisions partially require retrospective adoption, and partially prospective adoption. IFRS 9 implementation issues are currently not expected to have a material impact on the Consolidated balance sheet, statement of income and statement of cash flows.

Statoil will adopt IFRS 9 on 1 January, 2018.

IFRS 16 Leases
IFRS 16, effective from 1 January 2019, covers the recognition of leases and related disclosure in the financial statements, and will replace IAS 17 Leases. In the financial statement of lessees, the new standard requires recognition of all contracts that qualify under its definition of a lease as right-of-use assets and lease liabilities in the balance sheet, while lease payments are to be reflected as interest expense and reduction of lease liabilities. The right-of-use assets are to be depreciated in accordance with IAS 16 Property, Plant and Equipment over the shorter of each contract’s term and the assets’ useful life.

The standard consequently implies a significant change in lessees’ accounting for leases currently defined as operating leases under IAS 17, both with regard to impact on the balance sheet and the statement of income. IFRS 16 defines a lease as a contract that conveys the right to control the use of an identified asset for a period of time in exchange for consideration. While this definition is not dissimilar to that of IAS 17, it would have required further evaluation of each contract to determine whether all leases included in Note 22 Leases of these financial statements, or contracts currently not defined as leases, would qualify as leases under the new standard.

The standard introduces new requirements both as regards establishing the term of a lease and the related discounted cash flows that determine the amount of a lease liability to be recognised. The standard requires adoption either on a full retrospective basis, or retrospectively with the cumulative effect of initially recognising the standard as an adjustment to retained earnings at the date of initial application, and if so with a number of practical expedients in

Statoil, Annual Report on Form 20-F 2016 135

transitioning existing leases at the time of initial application. Statoil is in the process of evaluating the impact of IFRS 16, and has not yet determined the expected impact of the standard on the Consolidated financial statements.

Implementation of IFRS 16 will affect all Statoil’s segments.

Statoil will adopt IFRS 16 on 1 January 2019 and currently expects to apply the modified retrospective method in implementing the standard.

Other amendments to standards

The amendments to IFRS 10 Consolidated Financial Statements and IAS 28 Investments in Associates and Joint Ventures, effective from a future date to be determined by the IASB, 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 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 has not determined an adoption date for the amendments.

The disclosure initiative amendments to IAS 7 Statement of Cash Flows, effective from 1 January 2017, establish certain additional requirements for disclosure of changes in financing liabilities. Statoil has implemented 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.

Change in the Statoil group’s presentation currency

On 1 January 2016 Statoil changed its presentation currency from Norwegian kroner (NOK) to US dollars (USD), mainly in order to better reflect the underlying USD exposure of Statoil’s business activities and to align with industry practice. As the change in presentation currency represents a policy change, comparative figures have been re-presented in USD to reflect the change. All currency translation adjustments have been set to zero as of 1 January 2006, which was the date of Statoil’s transition to IFRS. Translation adjustments and cumulative translation adjustments have been presented as if Statoil had used USD as the presentation currency from that date. For further details and re-presented consolidated financial information for prior periods, reference is made to Note 26 Change of presentation currency in these Consolidated financial statements.

Basis of consolidation

The Consolidated financial statements include the accounts of Statoil ASA and its subsidiaries and include Statoil’s interest in jointly controlled and equity accounted investments.

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

A joint arrangement is present where Statoil holds a long-term interest which is jointly controlled by Statoil and one or more other venturers under a contractual arrangement in which 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.

136 Statoil, Annual Report on Form 20-F 2016

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 also accounted for using the equity method.

Under the equity method, the investment is carried on the balance sheet at cost plus post-acquisition changes in Statoil’s share of net assets of the entity, less distribution received and less any impairment in value of the investment. Goodwill may arise as the surplus of the cost of investment over Statoil’s share of the net fair value of the identifiable assets and liabilities of the joint venture or associate. Such goodwill is recorded within the corresponding investment.

The Consolidated statement of income reflects Statoil’s share of the results after tax of an equity-accounted entity, adjusted to account for depreciation, amortization and any impairment of the equity-accounted entity’s assets based on their fair values at the date of acquisition. Where material differences in accounting policies arise, adjustments are made to the financial statements of equity-accounted entities in order to bring the accounting policies used into line with Statoil’s. Material unrealised gains on transactions between Statoil and its equity-accounted entities are eliminated to the extent of Statoil’s interest in each equity-accounted entity. Unrealised losses are also eliminated unless the transaction provides evidence of an impairment of the asset transferred. Statoil assesses investments in equity-accounted entities for impairment whenever events or changes in circumstances indicate that the carrying value may not be recoverable.

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 estimate-based 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, the balance sheet and the cash flows of each entity are translated from the functional currency into the presentation currency, USD. The assets and liabilities of entities whose functional currencies are other than USD, are translated into USD 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). The cumulative amount of such translation differences relating to an entity and previously recognised in OCI, is reclassified to the Consolidated statement of income and reflected as a part of the gain or loss on disposal of that entity.

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.

Statoil, Annual Report on Form 20-F 2016 137

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 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. These sales 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. Uplift benefit on the NCS is recognised when the deduction is included in the current year tax return and impacts taxes payable.

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 substantively 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, expected currency rate movements and similar facts and circumstances.

Oil and gas exploration, evaluation 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, or there is any other indicator of a potential impairment. Exploration wells that discover potentially economic quantities of oil and natural gas remain capitalised as intangible assets during the evaluation phase of the find. This evaluation is normally finalised within one year after well completion. If, following the evaluation, the exploratory well has not found potentially commercial quantities of hydrocarbons, the previously capitalised

costs are evaluated for derecognition or tested for impairment. Geological and geophysical costs and other exploration and evaluation 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 occurs 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) 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.

138 Statoil, Annual Report on Form 20-F 2016

Consideration from the sale of an undeveloped part of an onshore asset reduces the carrying amount of the asset. The part of the consideration that exceeds the carrying amount of the asset, if any, is reflected in the Consolidated statement of income under other 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, exploration costs transferred from intangible assets and, for qualifying assets, borrowing costs. Property, plant and equipment include costs relating to expenditures incurred under the terms of 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 measurable with sufficient reliability.

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 production 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, when designed for significantly larger volumes than the reserves from already developed and producing wells, are depreciated using the unit of production method based on proved reserves expected to be recovered from the area during the concession or contract period. Depreciation of production wells uses the unit of production method based on proved developed reserves, and capitalised acquisition costs of proved properties are depreciated using the unit of production method based on total proved reserves. In the rare circumstances where the use of proved reserves fails to provide an appropriate basis reflecting the pattern in which the asset’s future economic benefits are expected to be consumed, a more appropriate reserve estimate is used. 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.

Assets classified as held for sale

Non-current assets are classified separately as held for sale in the balance sheet when their carrying amount will be recovered through a sale transaction

rather than through continuing use. This condition is met only when the sale is highly probable, the asset is available for immediate sale in its present

condition, and management is committed to the sale, which should be expected to qualify for recognition as a completed sale within one year from the date

of classification. Liabilities directly associated with the assets classified as held for sale, and expected to be included as part of the sale transaction, are

correspondingly also classified separately. Once classified as held for sale, property, plant and equipment and intangible assets are not subject to

depreciation or amortisation. The net assets and liabilities of a disposal group classified as held for sale are measured at the lower of their carrying amount

and fair value less costs to sell.

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.

Statoil, Annual Report on Form 20-F 2016 139

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 other than goodwill

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. 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. Fair value less cost of disposal is determined based on comparable recent arm’s length market transactions, or based on Statoil’s estimate of the price that would be received for the asset in an orderly transaction between market participants. Value in use 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 forecasts. Statoil uses an approach of regular updates of assumptions and economic conditions in establishing the long-term forecasts which are reviewed by corporate management and updated at least annually. For assets and CGUs with an expected useful life or timeline for production of expected reserves extending beyond 5 years, the forecasts reflect expected production volumes for oil and natural gas, and 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

140 Statoil, Annual Report on Form 20-F 2016

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 firm plans for future drilling in the licence.

An assessment is made at each reporting date as to whether there is any indication that previously recognised impairment losses may no longer be relevant or may have decreased. If such an indication exists, the recoverable amount is estimated. A previously recognised impairment loss is reversed only if there has been a change in the estimates used to determine the asset’s recoverable amount since the last impairment loss was recognised. If that is the case, the carrying amount of the asset is increased to its recoverable amount. That increased amount cannot exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognised for the asset in prior years.

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 certain long-term natural gas sales agreements.

Statoil, Annual Report on Form 20-F 2016 141

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. A portion of the contributions are provided for as notional contributions, for which the liability increases with a promised notional return, set equal to the actual return of assets invested through the ordinary defined contribution plan. 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 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.

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 opening present value of the benefit obligation and opening present value of the plan assets, adjusted for material changes 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 estimated interest income and actual return is recognised in the Consolidated statement of comprehensive income.

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.

Notional contribution plans, reported in the parent company Statoil ASA, are recognised as pension liabilities with the actual value of the notional contributions and promised return at reporting date. Notional contributions and changes in fair value of notional assets are recognised in the statement of income as periodic pension cost.

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.

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 operations are deemed to have indefinite lives, and in consequence, no ARO has been recognised for their plants.

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. When a decrease in the ARO provision related to a producing asset exceeds the carrying amount of the asset, the excess is recognised as a reduction of depreciation, amortisation and net

142 Statoil, Annual Report on Form 20-F 2016

impairment losses in the Consolidated statement of income. When an asset has reached the end of its useful life, all subsequent changes to the ARO provision are recognised as they occur in operating expenses in the Consolidated statement of income. 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 on-going 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

Statoil, Annual Report on Form 20-F 2016 143

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.

The key assumptions used will bear the risk of change based on the inherent volatile nature of macro-economic factors such as future commodity prices or discount rate and uncertainty in asset specific factors such as reserve estimates and operational decisions impacting the production profile or activity levels for our oil and natural gas properties. When estimating the recoverable amount, the single most likely future cash flows, the point estimate, is the primary method applied to reflect uncertainties in timing and amount inherent in the assumptions used in the estimated future cash flows. For assumptions in which the expected probability distributions or outcome are expected to be significantly skewed the use of decision trees or simulation is applied.

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 firm 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 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. 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. The costs of these decommissioning and removal activities require revisions due to changes in current regulations and technology while considering 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.

144 Statoil, Annual Report on Form 20-F 2016

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 proper application of at times very complex sets of rules, the recognition of 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 USA (DPUSA), Development and Production International (DPI), Marketing, Midstream and Processing (MMP), New Energy Solutions (NES) and Other.

The development and production operating segments are responsible for the commercial development of the oil and gas portfolios within their respective geographical areas: DPN on the Norwegian continental shelf, DPUSA including offshore and onshore activities in the USA and Mexico, and DPI worldwide outside of DPN and DPUSA.

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 MMP 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.

The NES segment is responsible for wind parks, carbon capture and storage as well as other renewable energy and low-carbon energy solutions.

Statoil reports its business through reporting segments which correspond to the operating segments, except for the operating segments DPI and DPUSA 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, the methods of distribution and regulatory environment. The operating segment NES is reported in the segment Other due to its immateriality.

The Other reporting segment includes activities within New Energy Solutions, Global Strategy and Business Development, Technology, Projects and Drilling and Corporate Staffs and Services.

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

Segment data for the years ended 31 December 2016, 2015 and 2014 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 equity accounted investments are excluding movements due to changes in asset retirement obligations.

Statoil, Annual Report on Form 20-F 2016 145

(in USD million)	Development and Production Norway	Development and Production International	Marketing, Midstream and Processing	Other	Eliminations	Total

Full year 2016
Revenues third party and other income	184	884	44,883	41	0	45,993
Revenues inter-segment	12,971	5,873	35	1	(18,880)	(0)
Net income (loss) from equity accounted investments	(78)	(100)	61	(3)	0	(119)

Total revenues and other income	13,077	6,657	44,979	39	(18,880)	45,873

Purchases [net of inventory variation]	1	(7)	(39,696)	(0)	18,198	(21,505)
Operating and SG&A expenses	(2,547)	(2,923)	(4,439)	(340)	463	(9,787)
Depreciation, amortisation and net impairment losses	(5,698)	(5,510)	(221)	(121)	0	(11,550)
Exploration expenses	(383)	(2,569)	0	0	0	(2,952)

Net operating income	4,451	(4,352)	623	(423)	(219)	80

Additions to PP&E, intangibles and equity accounted investments	6,785	6,397	492	451	0	14,125

Balance sheet information
Equity accounted investments	1,133	365	129	618	0	2,245
Non-current segment assets	27,816	36,181	4,450	352	0	68,799
Non-current assets, not allocated to segments						8,090

Total non-current assets						79,133

(in USD million)	Development and Production Norway	Development and Production International	Marketing, Midstream and Processing	Other	Eliminations	Total

Full year 2015
Revenues third party and other income	(123)	1,576	57,868	349	0	59,671
Revenues inter-segment	17,459	6,715	183	1	(24,357)	(0)
Net income (loss) from equity accounted investments	3	(91)	55	4	0	(29)

Total revenues and other income	17,339	8,200	58,106	354	(24,357)	59,642

Purchases [net of inventory variation]	(0)	(10)	(50,547)	(0)	24,303	(26,254)
Operating and SG&A expenses	(3,223)	(3,391)	(4,664)	(342)	187	(11,433)
Depreciation, amortisation and net impairment losses	(6,379)	(10,231)	37	(142)	(0)	(16,715)
Exploration expenses	(576)	(3,296)	(0)	0	0	(3,872)

Net operating income	7,161	(8,729)	2,931	(129)	133	1,366

Additions to PP&E, intangibles and equity accounted investments	6,293	8,119	900	273	0	15,584

Balance sheet information
Equity accounted investments	5	333	214	272	0	824
Non-current segment assets	27,706	37,475	5,588	690	0	71,458
Non-current assets, not allocated to segments						9,305

Total non-current assets						81,588

146 Statoil, Annual Report on Form 20-F 2016

(in USD million)	Development and Production Norway	Development and Production International	Marketing, Midstream and Processing	Other	Eliminations	Total

Full year 2014
Revenues third party and other income	1,347	3,017	94,812	122	0	99,299
Revenues inter-segment	27,568	10,757	286	1	(38,612)	0
Net income (loss) from equity accounted investments	11	(113)	73	(5)	0	(34)

Total revenues and other income	28,926	13,661	95,171	118	(38,612)	99,264

Purchases [net of inventory variation]	(0)	(2)	(86,689)	0	38,711	(47,980)
Operating and SG&A expenses	(4,034)	(3,654)	(5,287)	(161)	321	(12,815)
Depreciation, amortisation and net impairment losses	(6,301)	(8,885)	(583)	(156)	0	(15,925)
Exploration expenses	(838)	(3,824)	(4)	0	0	(4,666)

Net operating income	17,753	(2,703)	2,608	(199)	420	17,878

Additions to PP&E, intangibles and equity accounted investments	8,817	9,750	1,225	132	0	19,924

Balance sheet information
Equity accounted investments	32	640	434	20	0	1,127
Non-current segment assets	35,243	44,912	6,234	688	0	87,077
Non-current assets, not allocated to segments						10,226

Total non-current assets						98,430

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

See note 10 Property, plant and equipment for information on impairment losses that affected the different segments.

See note 11 Intangible assets for information on impairment losses that affected the different segments.

See note 23 Other commitments, contingent liabilities and contingent assets for information on contingencies that have influenced the 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 78% and the USA constitutes 14%.

Statoil, Annual Report on Form 20-F 2016 147

Non-current assets by country
	At 31 December
(in USD million)	2016	2015	2014

Norway	31,484	31,487	38,966
USA	18,223	20,531	24,605
Brazil	5,308	3,474	3,974
Angola	3,884	5,350	6,903
UK	3,108	2,882	2,650
Canada	1,494	2,270	2,366
Algeria	1,344	1,435	1,593
Azerbaijan	1,326	1,416	3,181
Other countries	4,873	3,436	3,965

Total non-current assets¹⁾	71,043	72,282	88,204

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

Revenues by product type
(in USD million)	2016	2015	2014

Crude oil	24,307	27,806	51,803
Natural gas	9,202	12,390	15,732
Refined products	8,142	10,761	16,782
Natural gas liquids	4,036	5,482	9,506
Other	1	1,461	2,885

Total revenues	45,688	57,900	96,708

4 Acquisitions and disposals

2016

Acquisition of shares in Lundin Petroleum AB (Lundin) and sale of interests in the Edvard Grieg field

In January 2016 Statoil acquired 11.93% of the issued share capital and votes in Lundin Petroleum AB for a total purchase price of SEK 4.6 billion (USD 541 million). The shares were accounted for as a non-current financial investment at fair value with changes in fair value presented in the line item net gains (losses) from available for sale financial assets in the Consolidated statement of comprehensive income up until the transaction in June 2016.

In June 2016 Statoil closed an agreement with Lundin to divest its entire 15% interest in the Edvard Grieg field, a 9% interest in the Edvard Grieg Oil pipeline and a 6% interest in the Utsira High Gas pipeline for an increased ownership share in Lundin. In addition to the divested interests, a cash consideration of SEK 544 million (USD 64 million) was paid to Lundin. Following the completion of the transaction Statoil owns 68.4 million shares of Lundin, corresponding to 20.1% of the outstanding shares and votes. Statoil recognised a total net gain of USD 120 million related to the divestment presented in the line item other income in the Consolidated statement of income. In the segment reporting, the gain was recognised in the Development and Production Norway (DPN) segment (USD 114 million) and in the Marketing, Midstream and Processing (MMP) segment (USD 5 million). The transaction was tax exempt under the Norwegian petroleum tax legislation.

Following the increase in ownership interest on 30 June 2016, Statoil obtained significant influence over Lundin, and accounted for the investment as an associate under the equity method. Statoil performed a purchase price allocation to determine the net identifiable assets and liabilities of Lundin. Excess values were allocated mainly to Lundin`s exploration and production licences on the Norwegian continental shelf. The investment in Lundin was included in the Consolidated balance sheet within line item equity accounted investments with a book value of USD 1,199 million as per 30 June 2016. The Lundin investment is reported as part of the DPN segment. For summarized financial information relating investment in Lundin Petroleum AB, see note 12 Associated Companies.

Following the change in accounting classification, Statoil recognised a gain of USD 127 million representing the cumulative gain on its initial 11.93% shareholding being reclassified from the line item net gains (losses) from available for sale financial assets in the Consolidated statement of comprehensive income, to the net financial items line item in the Consolidated statement of income.

148 Statoil, Annual Report on Form 20-F 2016

Sale of interest in Marcellus operated onshore play

In July 2016 Statoil closed an agreement to divest its operated properties in the US state of West Virginia to EQT Corporation for USD 407 million in cash. The transaction was reported as part of Development and Production International (DPI) segment and had an immaterial effect on the Consolidated statement of income recognized in the third quarter of 2016.

Acquisition of operated interest in Brazil

In November 2016 Statoil closed an agreement with Petróleo Brasileiro S.A. (“Petrobras”) to acquire a 66% operated interest in the Brazilian offshore licence BM-S-8 in the Santos basin for the maximum cash consideration of USD 2,500 million. A cash consideration of USD 1,250 million was paid on the closing date. The payment of the remaining consideration is subject to certain conditions being met, and was reflected at fair value at the transaction date. The value of the acquired exploration assets has been recognised in the DPI segment, resulting in an increase in intangible assets of USD 2,271 million.

Sale of interest Kai Kos Dehseh
In December 2016 Statoil signed an agreement with Athabasca Oil Corporation to divest the 100% owned Kai Kos Dehseh (KKD) oil sands projects covering the producing Leismer plant and the undeveloped Corner project, along with a number of midstream contracts associated with Leismer’s production. The total consideration consists of a cash consideration of CAD 435 million (USD 323 million), 100 million common shares in Athabasca Oil Corporation (slightly under 20% ownership share) and a series of contingent payments, capped at CAD 250 million (USD 186 million), based on development of oil price and production over the next four years. Both the shares and the contingent consideration will be measured at fair value on the closing date. As of 31 December 2016 the KKD related assets and associated liabilities were presented as held for sale in the Consolidated balance sheet. Upon entering into the agreement, Statoil impaired the assets by USD 412 million. This impairment is partly reflected as depreciation, amortisation and net impairment losses and partly as exploration expense in the Consolidated statement of income. In addition, as a consequence of the transaction, a separate onerous contract provision of USD 50 million, mainly related to vacant office spaces, has been recognised as selling, general and administration expenses. Accumulated foreign exchange losses, currently recognised in other comprehensive income, will be reflected in the Consolidated Statement of Income at the closing date. The transaction was closed 31 January 2017, and will be reflected in the DPI segment in the first quarter 2017.

2015

Sale of interests in the Marcellus onshore play

In January 2015 Statoil reduced its average working interest in the non-operated southern Marcellus onshore play from 29% to 23% through a divestment to Southwestern Energy. Proceeds from the sale were USD 365 million, recognized in the DPI segment with no gain.

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

In April 2015 Statoil sold its remaining 15.5% interest in the Shah Deniz project and the South Caucasus Pipeline to Petronas with a total gain of USD 1,182 million, recognised in the DPI and the MMP segments. Total proceeds from the sale were USD 2,688 million.

Sale of buildings

In 2015 Statoil sold the shares in Forusbeen 50 AS, Strandveien 4 AS and Arkitekt Ebbelsvei 10 AS with a gain of USD 211 million, recognised in the Other segment. Proceeds from the sale were USD 486 million. At the same time Statoil entered into 15 year operating lease agreements for the buildings.

Sale of interests in the Trans Adriatic Pipeline AG

In December 2015 Statoil sold its 20% interest in Trans Adriatic Pipeline AG to Snam SpA, with a gain of USD 139 million, recognised in the MMP segment. Total proceeds from the sale were USD 227 million.

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

In December 2015 Statoil sold a 15% interest in the Gudrun field on the Norwegian continental shelf (NCS) to Repsol, recognizing a total gain of USD 142 million in the DPN segment. Proceeds from the sale were USD 216 million. Simultaneously Statoil acquired an additional 13% interest in the Eagle Ford formation with the same party. The acquisition was accounted for as a business combination using the acquisition method in the DPI and MMP segments with the fair value of net identifiable assets of USD 277 million and USD 121 million, respectively as of 30 December 2015. No goodwill was recognised.

2014

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

In March 2014 and May 2014 Statoil sold a 3.33% and a 6.67% working interests, in the Shah Deniz project and the South Caucasus Pipeline, to BP and SOCAR respectively, with a total gain of USD 942 million, presented in the DPI and the MMP segments. Proceeds from the sale were USD 1,383 million.

Kai Kos Dehseh oil sands swap agreement

In May 2014 Statoil and its partner PTTEP swapped the two parties' respective interests in the Kai Kos Dehseh oil sands project in Alberta, Canada. Subsequent to the closing, Statoil continues as 100% owner of the Leismer and Corner projects. The transaction has been recognised in the DPI segment resulting in an increase in property, plant and equipment of USD 769 million, including a transfer from intangible assets of USD 301 million, and with no impact on the Consolidated statement of income.

Sale of interests in licences on the Norwegian continental shelf

In December 2014 Statoil sold certain ownership interests in licences on the NCS to Wintershall with a gain of USD 861 million, recognised in the DPN segment. Proceeds from the sale were USD 1,250 million.

Statoil, Annual Report on Form 20-F 2016 149

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 assessing and managing risk

in all activities using a holistic risk 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.

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.

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

Statoil’s most important long term commodity risk (oil and natural gas) is related to future market prices as Statoil´s risk policy is to be exposed to both upside and downside price movements. To manage short-term commodity risk, Statoil 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. Statoil’s bilateral gas sales portfolio is exposed to various price indices and uses derivatives to manage the net gas sales exposure towards a diversified combination of long and short dated gas price markers.

The term of crude oil and refined oil products derivatives are usually less than one year, and they 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. The term of natural gas and electricity derivatives is usually three years or less, and they are mainly OTC physical forwards and options, NASDAQ OMX Oslo forwards and futures traded on the NYMEX and ICE.

Currency risk

Statoil's cash flows from operating activities deriving from oil and gas sales, operating expenses and capital expenditures are mainly in USD, but taxes,

dividends to shareholders on the Oslo Børs, a share of our operating expenses and capital expenditures are in NOK. Accordingly, Statoil's currency management is primarily linked to mitigate currency risk related to payments in NOK. This means that Statoil regularly purchases NOK, primarily spot, but also 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, EUR and GBP). Bonds are normally 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 fixed/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 ensure that Statoil has sufficient funds available at all times to cover its financial obligations.

The main cash outflows are the quarterly dividend payments and Norwegian petroleum tax payments paid six times per year. If the cash flow forecasts indicate that the liquid assets will fall below target levels, new long-term funding will be considered.

150 Statoil, Annual Report on Form 20-F 2016

Short-term funding needs will normally be covered by the USD 5.0 billion US Commercial Papers Programme (CP) which is backed by a revolving credit

facility of USD 5.0 billion, supported by 21 core banks, maturing in 2021. The facility supports secure access to funding, supported by the best available short-term rating. As at 31 December 2016 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 liabilities have 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.

	At 31 December
(in USD million)	2016	2015

Due within 1 year	12,766	11,909
Due between 1 and 2 years	4,913	8,361
Due between 3 and 4 years	9,891	9,861
Due between 5 and 10 years	10,884	10,645
Due after 10 years	13,278	13,113

Total specified	51,732	53,889

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.

Prior to entering into transactions with new counterparties, Statoil's credit policy requires all counterparties to be formally identified and assigned internal credit ratings as well as exposure limits. The internal credit ratings reflect Statoil's assessment of the counterparties' credit risk and are based on a quantitative and qualitative analysis of recent financial statements and other relevant business information including general market and industry information. All counterparties are re-assessed regularly.

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.

Statoil has pre-defined limits for the absolute credit risk level allowed at any given time on Statoil's portfolio 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.

Statoil, Annual Report on Form 20-F 2016 151

The following table contains the carrying amount of Statoil's financial receivables and derivative financial instruments split by Statoil's assessment of the counterparty's credit risk. Trade and other receivables include 4% overdue receivables for 30 days and more. The overdue receivables are mainly joint venture receivables pending the settlement of disputed working interest items payable from Statoil’s working interest partners within its US unconventional activities. Provisions have been made for expected losses. Only non-exchange traded instruments are included in derivative financial instruments.

(in USD million)	Non-current financial receivables	Trade and other receivables	Non-current derivative financial instruments	Current derivative financial instruments

At 31 December 2016
Investment grade, rated A or above	234	1,682	754	412
Other investment grade	264	4,090	1,064	75
Non-investment grade or not rated	210	1,302	0	4

Total financial asset	707	7,074	1,819	491

At 31 December 2015
Investment grade, rated A or above	0	1,653	1,346	230
Other investment grade	377	3,126	1,350	278
Non-investment grade or not rated	277	1,055	0	34

Total financial asset	655	5,834	2,697	542

At 31 December 2016, USD 571 million of cash was held as collateral to mitigate a portion of Statoil's credit exposure. At 31 December 2015, USD 1,161 million 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 2016, USD 817 million presented as liabilities do not meet the criteria for offsetting. At 31 December 2015, USD 794 million was not offset. The collateral received and the amounts not offset from derivative financial instrument liabilities, reduce 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. Trade and other receivables subject to similar master netting agreements USD 364 million have been offset as of 31 December 2016, and respectively USD 341 million as of 31 December 2015.

6 Remuneration

	Full year
(in USD million, except average number of employees)	2016	2015	2014

Salaries¹⁾	2,576	2,791	3,698
Pension costs	650	846	544
Payroll tax	394	419	548
Other compensations and social costs	276	312	376

Total payroll costs	3,895	4,369	5,166

Average number of employees²⁾	21,300	22,300	23,300

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

2) Part time employees amount to 3%, 3% and 2% for the years 2016, 2015 and 2014 respectively.

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

152 Statoil, Annual Report on Form 20-F 2016

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 USD thousand)¹⁾	2016	2015	2014

Current employee benefits	9,270	11,436	11,624
Post-employment benefits	574	799	2,064
Other non-current benefits	19	15	0
Share-based payment benefits	102	167	175

Total	9,966	12,418	13,863

1) All figures in the table are presented on accrual basis.

At 31 December 2016, 2015 and 2014 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 following the year of purchase, 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 USD 61 million, USD 77 million and USD 94 million related to the 2016, 2015 and 2014 programs, respectively. For the 2017 program (granted in 2016) the estimated compensation expense is USD 62 million. At 31 December 2016 the amount of compensation cost yet to be expensed throughout the vesting period is USD 138 million.

7 Other expenses

Auditor's remuneration
	Full year
(in USD million, excluding VAT)	2016	2015	2014

Audit fee	6.5	6.1	7.1
Audit related fee	1.0	1.7	1.3
Tax fee	0.1	0.0	0.0
Other service fee	0.0	0.0	0.0

Total	7.5	7.9	8.4

In addition to the figures in the table above, the audit fees and audit related fees related to Statoil operated licences amount to USD 0.8 million, USD 0.9 million and USD 1.0 million for 2016, 2015 and 2014, respectively.

Research and development expenditures

Research and development (R&D) expenditures were USD 298 million, USD 344 million and USD 476 million in 2016, 2015 and 2014, respectively. R&D expenditures are partly financed by partners of Statoil operated licenses. Statoil's share of the expenditures has been recognised as expense in the Consolidated statement of income.

Statoil, Annual Report on Form 20-F 2016 153

8 Financial items

	Full year
(in USD million)	2016	2015	2014

Foreign exchange gains (losses) derivative financial instruments	353	548	(198)
Other foreign exchange gains (losses)	(473)	(793)	(109)

Net foreign exchange gains (losses)	(120)	(245)	(307)

Dividends received	46	42	42
Gains (losses) financial investments	(0)	47	176
Interest income financial investments	63	76	111
Interest income non-current financial receivables	22	23	19
Interest income current financial assets and other financial items	305	208	281

Interest income and other financial items	436	396	628

Gains (losses) derivative financial instruments	470	(491)	904

Interest expense bonds and bank loans and net interest on related derivatives	(830)	(707)	(684)
Interest expense finance lease liabilities	(26)	(27)	(47)
Capitalised borrowing costs	355	392	250
Accretion expense asset retirement obligations	(420)	(481)	(597)
Interest expense current financial liabilities and other finance expense	(122)	(147)	(127)

Interest and other finance expenses	(1,043)	(971)	(1,205)

Net financial items	(258)	(1,311)	20

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 USD 1,018 million, USD 1,041 million and USD 1,079 million from the financial liabilities at amortised cost category. This was partly offset by net interest on related derivatives from the held for trading category, USD 188 million, USD 334 million and USD 395 million for 2016, 2015 and 2014, respectively.

The line item gains (losses) derivative financial instruments primarily includes fair value gain from the held for trading category of USD 454 million, a loss of USD 492 million and a gain of USD 897 million for 2016, 2015 and 2014, respectively.

Foreign exchange gains (losses) derivative financial instruments include fair value changes of currency derivatives related to liquidity and currency risk.

The line item foreign exchange gains (losses) includes a net foreign exchange loss of USD 205 million, a loss of USD 1,208 million and a loss of USD 2,120 million from the held for trading category for 2016, 2015 and 2014, respectively.

154 Statoil, Annual Report on Form 20-F 2016

9 Income taxes

Significant components of income tax expense
	Full year
(in USD million)	2016	2015	2014

Current income tax expense in respect of current year	(3,869)	(6,488)	(14,299)
Prior period adjustments	(158)	(91)	307

Current income tax expense	(4,027)	(6,579)	(13,993)

Origination and reversal of temporary differences	1,372	1,519	29
Change in tax regulations	(50)	(90)	(19)
Prior period adjustments	(20)	(74)	(29)

Deferred tax expense	1,302	1,355	(19)

Income tax expense	(2,724)	(5,225)	(14,011)

During the normal course of its business, Statoil files tax returns in many different tax regimes. There may be differing interpretation of applicable tax laws and regulations regarding some of the matters in the tax returns. In certain cases it may take several years to complete the discussions with the relevant tax authorities or to reach a resolution of the tax positions through litigations. Statoil has provided for probable income tax related assets and liabilities based on best estimates reflecting consistent interpretations of the applicable laws and regulations.

Reconciliation of statutory tax rate to effective tax rate
	Full year
(in USD million)	2016	2015	2014

Income before tax	(178)	55	17,898

Calculated income tax at statutory rate¹⁾	676	1,078	(5,139)
Calculated Norwegian Petroleum tax²⁾	(2,250)	(4,145)	(9,960)
Tax effect uplift²⁾	812	847	980
Tax effect of permanent differences regarding divestments	153	468	911
Tax effect of permanent differences caused by functional currency different from tax currency	(356)	719	762
Tax effect of other permanent differences	(48)	(2)	(298)
Change in unrecognised deferred tax assets	(1,625)	(3,557)	(1,299)
Change in tax regulations	(50)	(90)	(19)
Prior period adjustments	(177)	(165)	278
Other items including currency effects	141	(376)	(228)

Income tax expense	(2,724)	(5,225)	(14,011)

Effective tax rate	>(100%)	>100%	78.3%

1) The weighted average of statutory tax rates was positive 379.8% in 2016, negative 1,950.2% in 2015 and positive 28.7% in 2014. The high tax rate in 2016, the negative rate in 2015 and the change in average statutory tax rates from 2015 to 2016 is mainly caused by earnings composition between tax regimes with lower statutory tax rates and tax regimes with higher statutory tax rates. In both years there are positive income in tax regimes with relatively lower tax rates and losses, including impairments and provisions, in tax regimes with relatively higher tax rates. The decrease from 2014 to 2015 was mainly caused by losses, impairments and provisions in entities with higher than average statutory tax rates.

2) When computing the petroleum tax of 53% (54% from 2017) on income from the Norwegian continental shelf, an additional tax-free allowance, or uplift, is granted at a rate of 5.5% per year (5.4% per year from 2017 for new investments) on the basis of the original capitalised cost of offshore production installations. For investments made prior to 5 May 2013, the rate is 7.5% per year. Transitional rules apply to investments from 5 May 2013 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 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 2016 and 2015, unrecognised uplift credits amounted to USD 2,121 million and USD 2,333 million, respectively.

Statoil, Annual Report on Form 20-F 2016 155

Deferred tax assets and liabilities comprise
(in USD million)	Tax losses carried forward	Property, plant and equipment and Intangible assets	Asset removal obligation	Pensions	Derivatives	Other	Total

Deferred tax at 31 December 2016
Deferred tax assets	4,283	233	7,078	743	138	849	13,323
Deferred tax liabilities	0	(16,797)	0	0	(270)	(488)	(17,555)

Net asset (liability) at 31 December 2016	4,283	(16,564)	7,078	743	(132)	361	(4,231)

Deferred tax at 31 December 2015
Deferred tax assets	4,743	185	6,980	578	7	797	13,291
Deferred tax liabilities	(0)	(16,731)	0	(0)	(928)	(1,032)	(18,691)

Net asset (liability) at 31 December 2015	4,743	(16,545)	6,980	578	(920)	(235)	(5,399)

Changes in net deferred tax liability during the year were as follows:
(in USD million)	2016	2015	2014

Net deferred tax liability at 1 January	5,399	7,881	10,317
Charged (credited) to the Consolidated statement of income	(1,302)	(1,355)	19
Other comprehensive income	(129)	461	56
Translation differences and other	264	(1,588)	(2,510)

Net deferred tax liability at 31 December	4,231	5,399	7,881

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 USD million)	2016	2015

Deferred tax assets	2,195	2,022
Deferred tax liabilities	6,427	7,421

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 2016 and 2015 the deferred tax assets of USD 2,195 million and USD 2,022 million, respectively, were primarily recognised in Norway, Angola, Brasil and the UK.

Unrecognised deferred tax assets
	At 31 December
	2016		2015
(in USD million)	Basis	Tax	Basis	Tax

Deductible temporary differences	3,431	1,360	2,448	1,010
Tax losses carried forward	17,440	6,557	14,329	5,297

Total	20,871	7,917	16,776	6,307

Approximately 9% of the unrecognised carry forward tax losses can be carried forward indefinitely. The majority of the remaining part of the unrecognised tax losses expire after 2027. 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.

156 Statoil, Annual Report on Form 20-F 2016

At year end 2016 unrecognised deferred tax assets in the US and Angola represents USD 5,655 million and USD 800 million of the total unrecognised deferred tax assets of USD 7,917 million. Similar amounts for 2015 were USD 4,461 million in the US and USD 643 million in Angola of a total of USD 6,307 million.

10 Property, plant and equipment

(in USD million)	Machinery, equipment and transportation equipment, including vessels	Production plants and oil and gas assets	Refining and manufacturing plants	Buildings and land	Assets under development	Total

Cost at 31 December 2015	3,466	133,269	7,459	928	20,284	165,406
Additions and transfers	62	11,960	776	70	(2,148)	10,720
Disposals at cost¹⁾	(98)	(1,857)	(48)	(130)	(445)	(2,577)
Assets reclassified to held for sale (HFS)	(7)	(2,169)	0	(12)	(51)	(2,239)
Effect of changes in foreign exchange	(30)	1,546	75	2	(325)	1,268

Cost at 31 December 2016	3,394	142,750	8,262	859	17,315	172,579

Accumulated depreciation and impairment losses at 31 December 2015	(2,826)	(90,762)	(5,386)	(468)	(3,958)	(103,400)
Depreciation	(137)	(9,657)	(411)	(31)	0	(10,235)
Impairment losses	(0)	(1,672)	(240)	(12)	(969)	(2,893)
Reversal of impairment losses	0	1,186	371	0	35	1,592
Transfers	71	(2,013)	(79)	(0)	1,789	(232)
Accumulated depreciation and impairment disposed assets¹⁾	91	1,231	44	57	14	1,437
Accumulated depreciation and impairment assets classified as HFS	6	1,757	0	8	22	1,794
Effect of changes in foreign exchange	28	(1,042)	(71)	1	(1)	(1,086)

Accumulated depreciation and impairment losses at 31 December 2016	(2,767)	(100,971)	(5,772)	(446)	(3,068)	(113,023)

Carrying amount at 31 December 2016	626	41,779	2,490	413	14,247	59,556

Estimated useful lives (years)	3-20	UoP²⁾	15 - 20	20 - 33

Statoil, Annual Report on Form 20-F 2016 157

(in USD million)	Machinery, equipment and transportation equipment, including vessels	Production plants and oil and gas assets	Refining and manufacturing plants	Buildings and land	Assets under development	Total

Cost at 31 December 2014	3,508	139,578	8,691	1,358	22,162	175,297
Additions and transfers	52	9,895	598	78	1,292	11,914
Disposals at cost	(20)	(1,657)	(1,052)	(437)	(1,197)	(4,362)
Effect of changes in foreign exchange	(74)	(14,547)	(779)	(70)	(1,973)	(17,443)

Cost at 31 December 2015	3,466	133,269	7,459	928	20,284	165,406

Accumulated depreciation and impairment losses at 31 December 2014	(2,708)	(88,344)	(6,490)	(641)	(1,494)	(99,677)
Depreciation	(173)	(10,162)	(266)	(48)	0	(10,650)
Impairment losses and transfers	0	(3,419)	(67)	0	(2,661)	(6,147)
Reversal of impairment losses	0	108	483	6	22	620
Accumulated depreciation and impairment disposed assets	2	830	324	190	(0)	1,347
Effect of changes in foreign exchange	53	10,224	629	25	175	11,107

Accumulated depreciation and impairment losses at 31 December 2015	(2,826)	(90,762)	(5,386)	(468)	(3,958)	(103,400)

Carrying amount at 31 December 2015	641	42,507	2,073	460	16,326	62,006

Estimated useful lives (years)	3-20	UoP²⁾	15 - 20	20 - 33

1) Includes USD 445 million related to change in the classification of Statoil’s investment in joint operation (pro-rata line by line consolidation)/full consolidation to joint venture (equity method), mainly related to Dudgeon Offshore Wind Ltd (USD 341 million).

2) Depreciation according to unit of production method (UoP), see note 2 Significant accounting policies.

The carrying amount of assets transferred to Property, plant and equipment from Intangible assets in 2016 and 2015 amounted to USD 692 million and USD 332 million, respectively.

Impairments

(in USD million)	Property, plant and equipment	Intangible assets³⁾	Total

At 31 December 2016
Producing and development assets¹⁾	1,301	590	1,890
Acquisition costs related to oil and gas prospects²⁾	0	403	403

Total net impairment losses recognised	1,301	992	2,293

At 31 December 2015
Producing and development assets¹⁾	5,526	1,263	6,788
Goodwill¹⁾	0	539	539
Acquisition costs related to oil and gas prospects²⁾	0	688	688

Total net impairment losses recognised	5,526	2,490	8,015

1) Producing and development assets and goodwill are subject to impairment assessment under IAS 36. The total net impairment losses recognised under IAS 36 in 2016 and 2015 amount to USD 1,890 million and USD 7,327 million, respectively, including impairment of acquisition costs - oil and gas prospects (intangible assets).

2) Acquisition costs related to exploration activities, subject to impairment assessment under the successful efforts method (IFRS 6).

3) See note 11 Intangible assets.

158 Statoil, Annual Report on Form 20-F 2016

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 6.0% real after tax (2015: 6.5%). 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.

		2016		2015
(in USD million)	Impairment method	Carrying amount after impairment ¹⁾	Net impairment loss	Carrying amount after impairment ¹⁾	Net impairment loss

At 31 December
Development and Production Norway	VIU	3,115	760	1,427	454
	FVLCOD	1,401	69	2,010	620
North America - unconventional	VIU	3,887	945	5,733	3,119
	FVLCOD	483	412	1,240	539
North America Conventional offshore Gulf of Mexico	VIU	4,459	141	3,699	2,210
	FVLCOD	0	0	0	0
North Africa	VIU	0	104	490	130
	FVLCOD	0	0	0	0
Sub - Saharan Africa	VIU	772	(137)	903	169
	FVLCOD	0	0	0	0
Europe and Asia	VIU	1,124	(330)	1,018	511
	FVLCOD	0	0	0	0
Marketing, Midstream and Processing	VIU	1,046	(74)	1,005	(425)
	FVLCOD	0	0	0	0



Total		16,286	1,890	17,525	7,327

1) Carrying amount relates to assets impaired/reversed.

During 2016 net impairment losses of USD 1,890 million were recognised on producing and development assets mainly due to downward revision of long-term commodity price assumptions. For 2015 the net impairment losses recognised were USD 7,327 million primarily due to declining commodity prices.

Development and Production Norway (DPN)

In the DPN segment net impairment losses of USD 829 million were recognised in 2016, which were mainly related to conventional offshore assets in the development phase. The net impairment losses were triggered by reduction in commodity price assumptions. In 2015 impairment losses of USD 1,074 million were recognised.

Development and Production International (DPI)

In the DPI segment net impairment losses of USD 1,130 million were recognised in 2016 of which USD 1,357 million, including a reversal of USD 571 million, related to unconventional onshore assets in North America. The loss includes impairment of Kai Kos Dehseh, classified as held for sale as of 31 December 2016. In addition, impairment reversals of USD 780 million and impairment losses of USD 553 million were recognised in relation to conventional assets. Net impairment losses of USD 541 million were recognised as Depreciation, amortisation and net impairment losses and net impairment losses of USD 590 million related to signature bonuses and acquisition costs recognised as Exploration expenses. In 2015 impairment losses of USD 6,678 million were recognised.

The net impairment losses were mainly a result from reduced long term commodity price assumptions partly offset by increased short term prices, operational performance improvements and cost reductions.

Marketing, Midstream and Processing (MMP)

The MMP segment recognised a net impairment reversal of USD 74 million mainly related to a refinery. The reversal of impairment was triggered by increased refinery margins and operational and commercial improvements. In 2015 net reversal of USD 425 million were recognised.

The recoverable amount of assets tested for impairment was mainly based on Value in Use (VIU) estimates on the basis of internal forecasts on costs, production profiles and commodity prices. In fourth quarter, the downward revision of the long term price forecast constituted the most important impairment indicator. Business plan updates including improved production profiles, more efficient operations and lower costs in addition to increased short

Statoil, Annual Report on Form 20-F 2016 159

term commodity prices partially offsets the effect of lower long term prices. Short term commodity prices (2017 – 2019) are forecasted by using observable forward prices for 2017 and a linear projection towards the 2020 internal forecast. In 2015 the observable forward prices were used for the first three years.

Recoverable amount for assets measured at Fair Value Less Cost of Disposal (FVLCOD) have partially been established through comparisons with observed market transactions and bids, and partially through internally prepared net present value estimates using assumed market participant assumptions.

The price assumptions used for impairment calculations were as follows (prices used in 2015 impairment calculations for the respective years are indicated in brackets):

Year (Prices in real terms)	2017		2020		2025		2030

Brent Blend – USD/bbl	55	(45)	75	(83)	78	(92)	80	(100)
NBP - USD/mmbtu	6.0	(4.9)	6.0	(8.0)	8.0	(9.0)	8.0	(9.2)
Henry Hub – USD/mmbtu	3.4	(2.7)	4.0	(4.2)	4.0	(4.4)	4.0	(4.6)

Sensitivities

Commodity prices have historically been volatile. Significant further downward adjustments of Statoil’s commodity price assumptions would result in impairment losses on certain producing and development assets in Statoil’s portfolio. If a further decline in commodity price forecasts over the lifetime of the assets were 20%, considered to represent a reasonably likely change, the impairment amount to be recognised could illustratively be in the region of USD 8 billion before tax effects. This illustrative impairment sensitivity assumes no changes to input factors other than prices; however, a price reduction of 20% is likely to result in changes in business plans as well as other factors used when estimating an asset’s recoverable amount. Changes in such input factors would likely significantly reduce the actual impairment amount compared to the illustrative sensitivity above. Changes that could be expected would include a reduction in the cost level in the oil and gas industry as well as offsetting currency effects, both of which have historically occurred following significant changes in commodity prices. The illustrative sensitivity is therefore not considered to represent a best estimate of an expected impairment impact, nor an estimated impact on revenues or operating income in such a scenario. A significant and prolonged reduction in oil and gas prices would also result in mitigating actions by Statoil and its license partners, as a reduction of oil and gas prices would impact drilling plans and production profiles for new and existing assets. Quantifying such impacts is considered impracticable, as it requires detailed technical, geological and economical evaluations based on hypothetical scenarios and not based on existing business or development plans.

11 Intangible assets

(in USD million)	Exploration expenses	Acquisition costs - oil and gas prospects	Goodwill	Other	Total

Cost at 31 December 2015	3,701	5,207	1,565	402	10,875
Additions	246	2,477	0	(8)	2,715
Disposals at cost	(0)	(311)	0	(42)	(353)
Transfers	(298)	(392)	0	(2)	(692)
Assets reclassified to held for sale	(19)	(78)	0	0	(97)
Expensed exploration expenditures previously capitalised	(808)	(992)	0	0	(1,800)
Effect of changes in foreign exchange	33	(3)	5	(4)	31

Cost at 31 December 2016	2,856	5,907	1,570	346	10,679

Accumulated depreciation and impairment losses at 31 December 2015			(1,242)	(182)	(1,423)
Amortisation and impairments for the year			0	(13)	(13)
Amortisation and impairment losses disposed intangible assets			0	(2)	(2)
Effect of changes in foreign exchange			0	2	2

Accumulated depreciation and impairment losses at 31 December 2016			(1,242)	(195)	(1,437)

Carrying amount at 31 December 2016	2,856	5,907	328	151	9,243

160 Statoil, Annual Report on Form 20-F 2016

(in USD million)	Exploration expenses	Acquisition costs - oil and gas prospects	Goodwill	Other	Total

Cost at 31 December 2014	3,075	7,183	1,632	454	12,345
Additions	1,188	546	0	(18)	1,716
Disposals at cost	(61)	(293)	(9)	(24)	(387)
Transfers	(82)	(250)	0	(0)	(332)
Expensed exploration expenditures previously capitalised	(213)	(1,951)	0	0	(2,164)
Effect of changes in foreign exchange	(206)	(29)	(58)	(9)	(303)

Cost at 31 December 2015	3,701	5,207	1,565	402	10,875

Accumulated depreciation and impairment losses at 31 December 2014			(702)	(183)	(885)
Amortisation and impairments for the year			(539)	(2)	(541)
Effect of changes in foreign exchange			0	2	2

Accumulated depreciation and impairment losses at 31 December 2015			(1,242)	(182)	(1,423)

Carrying amount at 31 December 2015	3,701	5,207	323	220	9,452

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 2016, intangible assets were impacted by impairments of acquisition costs related to exploration activities of USD 403 million primarily as a result from dry wells and uncommercial discoveries in Gulf of Mexico, South America and Angola. Additionally, Statoil recognised impairments of signature bonuses and acquisition costs totalling USD 590 million.

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 10 Property, plant and equipment for more information on the basis for impairment assessments.

The table below shows the aging of capitalised exploration expenditures.
(in USD million)	2016	2015

Less than one year	311	1,448
Between one and five years	2,216	1,923
More than five years	329	331

Total	2,856	3,701

The table below shows the components of the exploration expenses.
	Full year
(in USD million)	2016	2015	2014

Exploration expenditures	1,437	2,860	3,730
Expensed exploration expenditures previously capitalised	1,800	2,164	2,097
Capitalised exploration	(285)	(1,151)	(1,161)

Exploration expenses	2,952	3,872	4,666

Statoil, Annual Report on Form 20-F 2016 161

12 Equity accounted investments

		(in USD million)
		2016		2015
	Ownership	Book value	Profit share	Book value	Profit share

Lundin Petroleum AB	20.1%	1,121	(78)	-	-
Other equity accounted investments		1,124	(41)	824	(29)

Total		2,245	(119)	824	(29)

Voting rights corresponds to ownership.

Summary financial information of equity accounted investments

The following table provides summarised financial information relating to Lundin Petroleum AB. This information is presented on a 20.1% basis and also reflects adjustments made by Statoil to Lundin Petroleum AB’s own results in applying the equity method of accounting. Statoil adjusts Lundin Petroleum AB’s results for depreciation of excess values determined in the purchase price allocation at the date of acquisition. Where there are significant differences in accounting policies, adjustments are made to bring the accounting policies applied in line with Statoil’s. These adjustments have decreased the reported net income for 2016, as shown in the table below, compared with the equivalent amount reported by Lundin Petroleum AB.

	Lundin Petroleum AB
(in USD million)		2016

At 31 December
Current assets		69
Non-Current assets		3,069
Current liabilities		(70)
Non-Current liabilities		(1,947)
Net assets		1,121
Year ended 31 December
Gross revenues¹⁾		135
Income before tax¹⁾		(83)
Net income¹⁾		(78)

Capital expenditures¹⁾		589

1) For the period 30 June to 31 December 2016.

Statoil has not received dividends from Lundin Petroleum AB for 2016.

Statoil’s quoted market value as per 31.12.2016 was USD 1.496 billion.

162 Statoil, Annual Report on Form 20-F 2016

13 Financial investments and non-current prepayments

Non-current financial investments
	At 31 December
(in USD million)	2016	2015

Bonds	1,362	1,412
Listed equity securities	731	715
Non-listed equity securities	251	209

Financial investments	2,344	2,336

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 USD million)	2016	2015

Financial receivables interest bearing	707	764
Prepayments and other non-interest bearing receivables	185	203

Prepayments and financial receivables	893	967

Financial receivables interest bearing primarily relate to project financing of equity accounted companies and loans to employees.

Current financial investments
	At 31 December
(in USD million)	2016	2015

Time deposits	3,242	2,166
Interest bearing securities	4,995	7,650

Financial investments	8,211	9,817

At 31 December 2016 current financial investments include USD 818.3 million 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 2015 was USD 677.2 million.

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

14 Inventories

	At 31 December
(in USD million)	2016	2015

Crude oil	1,966	1,210
Petroleum products	744	580
Natural gas	160	294
Other	358	419

Inventories	3,227	2,502

Higher inventory level of crude oil at 31 December is mainly related to higher prices and in-transit volumes. Other inventory consists of 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 USD 74 million and USD 439 million in 2016 and 2015, respectively.

Statoil, Annual Report on Form 20-F 2016 163

15 Trade and other receivables

	At 31 December
(in USD million)	2016	2015

Trade receivables	5,504	4,464
Current financial receivables	862	736
Joint venture receivables	592	574
Equity accounted investments and other related party receivables	116	60

Total financial trade and other receivables	7,074	5,834
Non-financial trade and other receivables	765	837

Trade and other receivables	7,839	6,671

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 USD million)	2016	2015

Cash at bank available	596	1,047
Time deposits	1,660	1,494
Money market funds	65	450
Interest bearing securities	2,234	5,091
Restricted cash, including margin deposits	535	540

Cash and cash equivalents	5,090	8,623

Restricted cash at 31 December 2016 and 2015 includes collateral deposits related to trading activities of USD 398 million and USD 411 million, 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 and dividends

At 31 December 2016, Statoil's share capital of NOK 8,112,623,527.50 (USD 1,155,993,270) comprised 3,245,049,411 shares at a nominal value of NOK 2.50. Share capital at 31 December 2015 was NOK 7,971,617,757.50 (USD 1,138,981,520) 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 per share were USD 0.2201 for the first three quarters of 2016. The board of directors will propose to the annual general meeting to maintain a dividend of USD 0.2201 per ordinary share for the fourth quarter, and continue the scrip programme giving shareholders the option to receive the dividend for the fourth quarter in cash or newly issued shares in Statoil at 5% discount.

As part of Statoil's scrip dividend program, approved by Statoil’s general assembly in May 2016, eligible shareholders can elect to receive their dividend in the form of new ordinary Statoil shares or in cash. For ADR (American Depository Receipts) holders, dividend can be received in the form of ADSs (American Depository Shares) or in cash. The subscription price for the dividend shares will have a discount compared to the volume-weighted average price on OSE of the last two trading days of the subscription period for each quarter. For the fourth quarter of 2015 and for the first, second and third quarter of 2016 the discount has been set at 5%.

During 2016 dividend for the third and for the fourth quarter of 2015 and dividend for the first and second quarter of 2016 were settled. Dividend declared but not yet settled, is presented as dividends payable in the Consolidated balance sheet, regardless of whether the dividend is expected to be paid in cash or by issuance of new shares. The Consolidated statement of changes in equity shows declared dividend in the period (retained earnings), offset by

164 Statoil, Annual Report on Form 20-F 2016

scrip dividend settled during the period (share capital and additional paid-in-capital). Dividend declared in 2016 relate to the fourth quarter of 2015 and to the first three quarters of 2016.

	At 31 December
(in USD million)	2016	2015

Dividends declared	2,824	2,930
US dollar per share or ADS	0.8804	0.9173 ¹⁾

Dividends paid in cash	1,876	2,836
US dollar per share or ADS	0.8804	0.9034
Norwegian kroner per share	7.3364	7.2000

Scrip dividends	904	-
Number of shares issued (millions)	56.4	-

Sum dividends settled	2,780	2,836

1) Dividend for the fourth quarter 2014 and for the first quarter 2015 declared in NOK and translated to USD at currency rate on declaration date.

During 2016 a total of 4,011,860 treasury shares were purchased for USD 62 million and 3,882,153 treasury shares were allocated to employees participating in the share saving plan. In 2015 a total of 4,057,902 treasury shares were purchased for USD 69 million and 3,203,968 treasury shares were allocated to employees participating in the share saving plan. At 31 December 2016 Statoil had 11,138,890 treasury shares and at 31 December 2015 11,009,183 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).

	At 31 December
(in USD million)	2016	2015

Net interest-bearing debt adjusted (ND)	19,389	14,748
Capital employed adjusted (CE)	54,490	55,055

Net debt to capital employed adjusted (ND/CE)	35.6%	26.8%

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 (amounting to USD 1,216 million and USD 1,111 million for 2016 and 2015, respectively) and balances related to the SDFI (amounting to USD 199 million and USD 214 million for 2016 and 2015, respectively) CE is defined as Statoil's total equity (including non-controlling interests) and ND.

Statoil, Annual Report on Form 20-F 2016 165

Non-current finance debt
Finance debt measured at amortised cost
	Weighted average interest rates in %¹⁾		Carrying amount in USD millions at 31 December		Fair value in USD millions at 31 December²⁾
	2016	2015	2016	2015	2016	2015

Unsecured bonds
United States Dollar (USD)	3.54	3.51	19,712	20,768	20,681	21,630
Euro (EUR)	2.10	2.28	8,211	7,201	8,884	7,495
Great Britain Pound (GBP)	6.08	6.08	1,693	2,040	2,475	2,698
Norwegian kroner (NOK)	4.18	4.18	348	341	386	378

Total			29,964	30,350	32,427	32,201

Unsecured loans
Japanese yen (JPY)	4.30	4.30	85	83	88	89

Secured bank loans
Norwegian kroner (NOK)	-	3.11	-	52	-	52

Finance lease liabilities			507	580	526	575

Total			592	715	614	716

Total finance debt			30,556	31,065	33,041	32,918
Less current portion			2,557	1,100	2,584	1,100

Non-current finance debt			27,999	29,965	30,457	31,818

1) 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.

2) 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 non-current financial liabilities. The credit premium used is based on indicative pricing from external financial institutions.

Unsecured bonds amounting to USD 19,712 million are denominated in USD and unsecured bonds amounting to USD 7,420 million are swapped into USD. Four bonds denominated in EUR amounting to USD 2,832 million 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.

In 2016 Statoil issued the following bonds:
Issuance date	Amount in EUR billion	Interest rate in %	Maturity date

9 November 2016	0.60	0.750	November 2026
9 November 2016	0.60	1.625	November 2036

Out of Statoil's total outstanding unsecured bond portfolio, 47 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 USD 29,616 million at the 31 December 2016 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.

166 Statoil, Annual Report on Form 20-F 2016

Non-current finance debt maturity profile
	At 31 December
(in USD million)	2016	2015

Year 2 and 3	6,478	6,234
Year 4 and 5	3,798	4,881
After 5 years	17,723	18,850

Total repayment of non-current finance debt	27,999	29,965

Weighted average maturity (years)	9	9
Weighted average annual interest rate (%)	3.41	3.39

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

Current finance debt
	At 31 December
(in USD million)	2016	2015

Collateral liabilities	571	1,161
Non-current finance debt due within one year	2,557	1,100
Other including bank overdraft	545	66

Total current finance debt	3,674	2,326

Weighted average interest rate (%)	1.61	1.90

Collateral liabilities and other current liabilities relate mainly to cash received as security for a portion of Statoil's credit exposure and outstanding amounts on US Commercial paper (CP) programme. At 31 December USD 500 million were issued on the CP programme. Corresponding at 31 December 2015 there were no outstanding amounts.

19 Pensions

The main pension plans for Statoil ASA and its most significant subsidiaries are defined contribution plans, in which the pension costs are recognised in the Consolidated statement of income in line with payments of annual pension premiums. The pension contribution plans in Statoil ASA also includes certain unfunded elements (notional contribution plans), for which the annual notional contributions are recognised as pension liabilities. These notional pension liabilities are regulated equal to the return on asset within the main contribution plan. See note 2 Significant accounting policies for more information about the accounting treatment of the notional contribution plans reported in Statoil ASA.

In addition, Statoil ASA has a closed defined benefit plan for employees which in 2015 had less than 15 years of future service before their regular retirement age, and for employees in certain subsidiaries. Statoil's defined benefit plans 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. The Norwegian companies in the group are subject to, and complies with, the requirements of the Norwegian Mandatory Company Pensions Act.

The defined benefit plans in Norway are managed and financed through 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 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 is a member of a Norwegian national agreement-based early retirement plan (“AFP”), and the premium 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 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 is recognised as a defined benefit obligation.

The present values of the defined benefit obligation, except for the notional contribution plan, 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 2016 the discount rate for the defined benefit plans in Norway was established on the basis of seven years' mortgage covered bonds interest

Statoil, Annual Report on Form 20-F 2016 167

rate extrapolated on a yield curve which matches the duration of Statoil's payment portfolio for earned benefits, which was calculated to be 17.4 years at the end of 2016. 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 not material and as such not disclosed separately. The pension costs in Statoil ASA are partly re-charged to license partners.

Net pension cost

(in USD million)	2016	2015	2014

Current service cost	238	378	751
Interest cost	192	191	496
Interest (income) on plan asset	(148)	(145)	(409)
Past service cost	2	-	(1)
Losses (gains) from curtailment, settlement or plan amendment	109	250	(298)
Actuarial (gains) losses related to termination benefits	59	(1)	(27)
Notional contributions	50	36	-

Defined benefit plans	503	709	512


Defined contribution plans	148	135	32

Total net pension cost	650	844	544

New entrants for the early retirement plans have been included as a settlement cost. The total impact in 2016 was USD 123 million and USD 173 million in 2015.

168 Statoil, Annual Report on Form 20-F 2016

(in USD million)	2016	2015

Defined benefit obligations (DBO)
Defined benefit obligations at 1 January	6,822	8,745
Current service cost	239	378
Interest cost	192	191
Actuarial (gains) losses - Financial assumptions	879	(703)
Actuarial (gains) losses - Experience	(282)	(369)
Benefits paid	(235)	(233)
Losses (gains) from curtailment, settlement or plan amendment¹⁾	171	253
Paid-up policies	(131)	(143)
Foreign currency translation	87	(1,332)
Changes in notional contribution liability	50	34

Defined benefit obligations at 31 December	7,791	6,822

Fair value of plan assets
Fair value of plan assets at 1 January	5,127	6,066
Interest income	148	145
Return on plan assets (excluding interest income)	76	69
Company contributions	22	35
Benefits paid	(80)	(70)
Paid-up policies and personal insurance	(92)	(208)
Foreign currency translation	50	(911)

Fair value of plan assets at 31 December	5,250	5,127

Net pension liability at 31 December	(2,541)	(1,695)

Represented by:
Asset recognised as non-current pension assets (funded plan)	839	1,284
Liability recognised as non-current pension liabilities (unfunded plans)	(3,380)	(2,979)

DBO specified by funded and unfunded pension plans	7,791	6,822

Funded	4,423	3,849
Unfunded	3,368	2,974

Actual return on assets	131	207

The actuarial losses from changes in financial assumptions mainly relate to increased pension liabilities due to reduced interest rates and a higher expected rate of pension increase. For 2015 Statoil recognised a gain from an opposite movement of these assumptions.

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

(in USD million)	2016	2015	2014

Net actuarial (losses) gains recognised in OCI during the year	(482)	1,139	24
Actuarial (losses) gains related to currency effects on net obligation and foreign exchange translation	(21)	460	611
Tax effects of actuarial (losses) gains recognised in OCI	129	(461)	(56)

Recognised directly in OCI during the year net of tax	(374)	1,138	580

Cumulative actuarial (losses) gains recognised directly in OCI net of tax	(1,188)	(814)	(1,952)

Statoil, Annual Report on Form 20-F 2016 169

Actuarial assumptions
	Assumptions used to determine benefit costs in %		Assumptions used to determine benefit obligations in %

	2016	2015	2016	2015

Discount rate	2.75	2.50	2.50	2.75
Rate of compensation increase	2.25	2.25	2.25	2.25
Expected rate of pension increase	1.00	1.50	1.75	1.00
Expected increase of social security base amount (G-amount)	2.25	2.25	2.25	2.25

Weighted-average duration of the defined benefit obligation			17.4	17.1

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 2016 and 2015 was 0.4% and 0.1% for employees between 50-59 years and 60-67 years, respectively.

For population in Norway, the mortality table K2013, issued by The Financial Supervisory Authority of Norway, is used as the best mortality estimate.

Disability tables for plans in Norway developed by the actuary were implemented in 2013 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 2016.

	Discount rate		Expected rate of compensation increase		Expected rate of pension increase		Mortality assumption
(in USD million)	0.50%	-0.50%	0.50%	-0.50%	0.50%	-0.50%	+ 1 year	- 1 year

Changes in:
Defined benefit obligation at 31 December 2016	(605)	689	129	(121)	599	(542)	371	(384)
Service cost 2017	(24)	28	6	(6)	24	(22)	9	(10)

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.

170 Statoil, Annual Report on Form 20-F 2016

Pension assets

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

Real estate properties owned by Statoil Pension amounted to USD 402 million and USD 386 million of total pension assets at 31 December 2016 and 2015, respectively, and are rented to Statoil companies.

The table below presents the portfolio weighting as approved by the board of Statoil Pension for 2016. The portfolio weight during a year will depend on the risk capacity.

Pension assets on investments classes			Target portfolio weight
(in %)	2016	2015	Target portfolio weight

Equity securities	39.0	38.3	31 - 43
Bonds	41.1	40.3	36 - 48
Money market instruments	13.9	14.9	0 - 29
Real estate	5.4	5.0	5 - 10
Other assets	0.6	1.5

Total	100.0	100.0

In 2016 98% of the equity securities, 30% of bonds and 71% of money market instruments had quoted market prices in an active market (level 1). In 2015 100% of the equity securities, 38% of bonds and 100% of money market instruments had quoted market prices in an active market. 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 2017.

20 Provisions

(in USD million)	Asset retirement obligations	Claims and litigations	Other provisions	Total

Non-current portion at 31 December 2015	10,632	1,116	675	12,422
Long term interest bearing provisions at 31 December 2015 reported as finance debt	-	-	27	27
Current portion at 31 December 2015 reported as trade and other payables	150	1,009	388	1,547

Provisions at 31 December 2015	10,782	2,124	1,090	13,997

New or increased provisions	660	256	2,046	2,962
Decrease in the estimates	(1,168)	(21)	(583)	(1,772)
Amounts charged against provisions	(221)	(3)	(195)	(420)
Effects of change in the discount rate	426	-	28	455
Reduction due to divestments	(41)	-	(0)	(41)
Accretion expenses	398	-	-	398
Reclassification and transfer	(44)	-	(0)	(45)
Currency translation	107	(0)	24	131

Provisions at 31 December 2016	10,899	2,356	2,409	15,664

Current portion at 31 December 2016 reported as trade and other payables	188	1,147	922	2,258
Non-current portion at 31 December 2016	10,711	1,209	1,487	13,406

Statoil, Annual Report on Form 20-F 2016 171

Expected timing of cash outflows
(in USD million)	Asset retirement obligations	Other provisions, including claims and litigations	Total

2017 - 2021	1,233	4,340	5,574
2022 - 2026	1,849	78	1,927
2027 - 2031	1,760	27	1,788
2032 - 2036	3,306	21	3,328
Thereafter	2,751	298	3,048

At 31 December 2016	10,899	4,765	15,664

The claims and litigations category mainly relates to expected payments on unresolved claims. The timing and amounts of potential settlements in respect of these 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.

The other provisions category relates to expected payments on onerous contracts, cancellation fees and other. In 2016 Statoil recognised a provision amounting to USD 1 billion of which USD 0.3 billion is current portion for a contingent consideration related to the BM-S-8 acquisition in Brazil. For further information, see note 4 Acquisitions and dispositions.

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

21 Trade, other payables and provisions

	At 31 December
(in USD million)	2016	2015

Trade payables	2,358	2,052
Non-trade payables and accrued expenses	1,623	2,323
Joint venture payables	2,632	2,590
Equity accounted investments and other related party payables	620	622

Total financial trade and other payables	7,233	7,587
Current portion of provisions and other non-financial payables	2,433	1,746

Trade, other payables and provisions	9,666	9,333

Included in current portion of provisions and other non-financial payables are certain provisions that are further described in note 20 Provisions and 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 equity accounted investments and other related parties, see note 24 Related parties.

172 Statoil, Annual Report on Form 20-F 2016

22 Leases

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

In 2016, net rental expenditures were USD 2,569 million (USD 3,439 million in 2015 and USD 3,637 million in 2014) consisting of minimum lease payments of USD 3,113 million (USD 4,046 million in 2015 and USD 4,505 million in 2014) reduced with sublease payments received of USD 558 million (USD 608 million in 2015 and USD 870 million in 2014). Net rental expenditures in 2016 include rig cancellation payments of USD 115 million. No material contingent rent payments have been expensed in 2016, 2015 or 2014.

The information in the table below shows future minimum lease payments due and receivable under non-cancellable operating leases at 31 December 2016:

	Operating leases
(in USD million)	Rigs	Vessels	Land and buildings	Other	Total	Sublease	Net total

2017	1,099	592	143	158	1,993	(135)	1,857
2018	807	462	132	114	1,514	(100)	1,414
2019	624	336	126	94	1,179	(99)	1,080
2020	459	281	124	70	934	(97)	837
2021	324	223	123	52	723	(66)	657
2022-2026	572	396	591	91	1,650	(76)	1,574
2027-2031	-	105	408	29	542	-	542
Thereafter	-	-	100	15	114	-	114

Total future minimum lease payments	3,885	2,395	1,746	624	8,649	(573)	8,076

Statoil had certain operating lease contracts for drilling rigs at 31 December 2016. The remaining significant contracts' terms range from one month to eight years. 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 2016 includes three crude tankers. The contract's estimated nominal amount was approximately USD 650 million at year end 2016, and it is included in the category vessels in the table above.

The category land and buildings includes future minimum lease payments to related parties of USD 474 million regarding the lease of one office building located in Bergen and owned by Statoil`s pension fund (“Statoil Pension”). These operating lease commitments extend to the year 2034. USD 367 million of the total is payable after 2020.

Statoil had finance lease liabilities of USD 507 million at 31 December 2016. The nominal minimum lease payments related to these finance leases amount to USD 667 million. Property, plant and equipment includes USD 484 million for finance leases that have been capitalised at year end (USD 768 million in 2015), mainly presented in the category machinery, equipment and transportation equipment, including vessels in note 11 Property, plant and equipment.

Certain contracts contain renewal options. The execution of such options will depend on future market development and business needs at the time when such options are to be exercised.

23 Other commitments, contingent liabilities and contingent assets

Contractual commitments

As a condition for being awarded oil and gas exploration and production licenses, participants may be committed to drill a certain number of wells. At the end of 2016, Statoil was committed to participate in 42 wells, with an average ownership interest of approximately 39%. Statoil's share of estimated expenditures to drill these wells amounts to USD 777 million. Additional wells that Statoil may become committed to participating in depending on future discoveries in certain licenses are not included in these numbers.

Statoil, Annual Report on Form 20-F 2016 173

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 Statoil's ownership share).

Nominal minimum other long-term commitments at 31 December 2016:

(in USD million)

2017	1,483
2018	1,395
2019	1,262
2020	1,179
2021	1,021
Thereafter	5,513

Total	11,853

Long term commitments related to contracts in the process of being terminated, and for which the termination fee has been provided for in the accounts, are not included in the above table.

Guarantees

Statoil has guaranteed for its proportionate portion of an associate’s long term bank debt, amounting to USD 160 million. The book value of the guarantee is immaterial.

Contingent liabilities and contingent assets

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 2014. 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 2016, the exposure for Statoil at year end 2016 is estimated to USD 1,808 million, 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.

Through its ownership in OML 128 in Nigeria, Statoil is party to an ownership interest redetermination process for the Agbami field. In October 2015, Statoil received the Expert’s final ruling which implies a reduction of 5.17 percentage points in Statoil’s equity interest in the field. Statoil had previously initiated arbitration proceedings to set aside interim decisions made by the Expert, but this was declined by the arbitration tribunal in its November 2015 judgment. Statoil has initiated proceedings before the Federal High Court in Lagos to set aside the arbitration award. In October 2016 Statoil also initiated a new arbitration to set aside the Expert’s final ruling. Currently Statoil has two distinct, but connected, legal processes ongoing related to the Agbami redetermination. As of 31 December 2016, Statoil has recognised a provision of USD 1,104 million net of tax, which reflects a reduction of 5.17 percentage points in Statoil’s equity interest in the Agbami field. The provision is reflected within Provisions in the Consolidated balance sheet.

Some 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 USD 374 million for gas delivered prior to year end 2016. 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.

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. The Contractor initiated arbitration in the matter in accordance with the terms of the PSC. In 2015 the Arbitral Tribunal ruled in favour of Contractor’s interpretation of the PSC on the main points. The Contractor is currently proceeding to enforce the favourable decision by the means available in the Nigerian legal system, while NNPC on its hand has initiated litigation concerning certain objections to the arbitration award. The Nigerian Federal Inland Revenue Service is also contesting the legality of the arbitration process as far as resolving tax related disputes goes, and in March 2017 the arbitration award was set aside by the Nigerian Federal High Court (FHC) based on the dispute having a tax nature and therefore being non-arbitrable. The Contractor will challenge this ruling in the Court of Appeal. The FHC’s ruling will not impact Statoil’s

174 Statoil, Annual Report on Form 20-F 2016

2016 financial statements, as Statoil’s stake in the dispute at year end mainly relates to oil volumes previously lifted by NNPC contrary to the PSC terms. NNPC has continued overlifting contrary to the arbitration award.

Brazilian tax authorities have issued an updated tax assessment for 2011 for Statoil’s Brazilian subsidiary which was party to Statoil’s divestment of 40% of the Peregrino field to Sinochem at that time. The assessment disputes Statoil’s allocation of the sale proceeds between entities and assets involved, resulting in a significantly higher assessed taxable gain and related taxes payable in Brazil. Statoil disagrees with the assessment, and has provided an initial response to this effect. The process of formal communication with the Brazilian tax authorities, as well as any subsequent litigation that may become necessary, may take several years. No taxes will become payable until the matter has been finally settled. Statoil is of the view that all applicable tax regulations have been applied in the case and that the group has a strong position. No amounts have consequently been provided for in the accounts.

On 26 September 2016, the Norwegian Ministry of Finance (MoF) denied Statoil’s appeal related to a 2014 order from the Financial Supervisory Authority of Norway to change the timing of a Cove Point related onerous contract provision to a financial period prior to the first quarter of 2013, in which Statoil originally reflected the provision. Statoil has decided not to pursue the matter further, as it does not impact any comparative financial periods presented in the annual Consolidated financial statements of 2016. Further reference is made to Note 23 Other commitments, contingent liabilities and contingent assets of Statoil’s 2015 Financial Statements.

On 6 July 2016, the Norwegian tax authorities issued a deviation notice for the years 2012 to 2014 related to the internal pricing on certain transactions between Statoil Coordination Centre (SCC) in Belgium and Norwegian entities in the Statoil group. The main issue relates to SCC`s capital structure and its compliance with the arm’s length principle. Statoil is of the view that arm’s length pricing has been applied in these cases and that the group has a strong position, and no amounts have consequently been provided for in the accounts.

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 2016 the Norwegian State had an ownership interest in Statoil of 67.0% (excluding Folketrygdfondet, the Norwegian national insurance fund, of 3.2%). 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 USD 5,848 million, USD 7,431 million and USD 13,718 million in 2016, 2015 and 2014, respectively. Total purchases of natural gas regarding the Tjeldbergodden methanol plant from the Norwegian State amounted to USD 44 million, USD 68 million and USD 73 million in 2016, 2015 and 2014, respectively. These purchases of oil and natural gas are recorded in Statoil ASA. 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 transactions are presented net. For further information please see note 2 Significant accounting policies. The most significant items included in the line item equity accounted investments 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 Statoil enters into contracts such as pipeline transport, gas storage and processing of petroleum products, with companies 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. Gassled and certain other infrastructure assets are operated by Gassco AS, which is an entity under common control by the Norwegian Ministry of Petroleum and Energy. Gassco’s activities are performed on behalf of and for the risk and reward of pipeline and terminal owners, and capacity payments flow through Gassco to the respective owners. Statoil payments that flowed through Gassco in this respect amounted to USD 1,167 million, USD 1,105 million and USD 1,476 million in 2016, 2015 and 2014, respectively. These payments are recorded in Statoil ASA. In addition, Statoil ASA process in its own name, but for the Norwegian State’s account and risk, the Norwegian State’s share of the Gassco costs. These transactions are presented net.

On 30 June 2016, Statoil increased its ownership interest in Lundin Petroleum AB (Lundin) to 20.1% of the outstanding shares and votes. Since 30 June, total purchase of oil and related products from Lundin amounted to USD 155 million. The purchase of oil and related products is recorded in Statoil ASA. For more information concerning the Lundin acquisition, see note 4 Acquisitions and disposals.

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

Statoil, Annual Report on Form 20-F 2016 175

Related party transactions with management are presented in note 6 Remuneration. Management remuneration for 2016 is presented in note 4 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 USD million)	Note	Loans and receivables	Available for sale	Held for trading	Fair value option	Non-financial assets	Total carrying amount

At 31 December 2016
Assets
Non-current derivative financial instruments		-	-	1,819	-	-	1,819
Non-current financial investments	13	-	207	-	2,137	-	2,344
Prepayments and financial receivables	13	707	-	-	-	185	893

Trade and other receivables	15	7,074	-	-	-	765	7,839
Current derivative financial instruments		-	-	492	-	-	492
Current financial investments	13	3,217	-	4,176	818	-	8,211
Cash and cash equivalents	16	2,791	-	2,299	-	-	5,090

Total		13,789	207	8,785	2,955	950	26,687


				Fair value through profit or loss
(in USD million)	Note	Loans and receivables	Available for sale	Held for trading	Fair value option	Non-financial assets	Total carrying amount

At 31 December 2015
Assets
Non-current derivative financial instruments		-	-	2,697	-	-	2,697
Non-current financial investments	13	-	209	-	2,127	-	2,336
Prepayments and financial receivables	13	655	-	-	-	313	967

Trade and other receivables	15	5,834	-	-	-	837	6,671
Current derivative financial instruments		-	-	542	-	-	542
Current financial investments	13	2,166	1	6,973	677	-	9,817
Cash and cash equivalents	16	3,081	-	5,541	-	-	8,623

Total		11,736	210	15,753	2,804	1,150	31,652

176 Statoil, Annual Report on Form 20-F 2016

(in USD million)	Note	Amortised cost	Fair value through profit or loss	Non-financial liabilities	Total carrying amount

At 31 December 2016
Liabilities
Non-current finance debt	18	27,999	-	-	27,999
Non-current derivative financial instruments		-	1,420	-	1,420

Trade and other payables	21	7,233	-	2,433	9,666
Current finance debt	18	3,674	-	-	3,674
Dividend payable		712	-	-	712
Current derivative financial instruments		-	508	-	508

Total		39,618	1,928	2,433	43,979


(in USD million)	Note	Amortised cost	Fair value through profit or loss	Non-financial liabilities	Total carrying amount

At 31 December 2015
Liabilities
Non-current finance debt	18	29,965	-	-	29,965
Non-current derivative financial instruments		-	1,285	-	1,285

Trade and other payables	21	7,587	-	1,746	9,333
Current finance debt	18	2,326	-	-	2,326
Dividend payable		700	-	-	700
Current derivative financial instruments		-	264	-	264

Total		40,578	1,549	1,746	43,873

Fair value hierarchy

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

(in USD million)	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 2016
Level 1	1,095	-	516	-	-	-	-	1,611
Level 2	1,042	970	4,479	426	2,299	(1,414)	(503)	7,299
Level 3	207	848	-	66	-	(6)	(4)	1,110

Total fair value	2,344	1,819	4,994	492	2,299	(1,420)	(508)	10,019

At 31 December 2015
Level 1	1,194	-	542	-	-	-	-	1,737
Level 2	932	1,756	7,109	491	5,541	(1,226)	(264)	14,340
Level 3	209	941	-	50	-	(59)	-	1,141

Total fair value	2,336	2,697	7,651	542	5,541	(1,285)	(264)	17,218

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.

Statoil, Annual Report on Form 20-F 2016 177

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. 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 USD 97 million at end of 2016 and decreased by USD 526 million at end of 2015 and impacted the Consolidated statement of income with corresponding amounts.

The reconciliation of the changes in fair value during 2016 and 2015 for financial instruments classified in the third level in the hierarchy are presented in the following table.

(in USD million)	Non-current financial investments	Non-current derivative financial instruments - assets	Current derivative financial instruments - assets	Non-current derivative financial instruments liabilities	Current derivative financial instruments - liabilities	Total amount

Full year 2016
Opening balance	209	941	50	(59)	-	1,141
Total gains and losses recognised in statement of income	-	(98)	66	49	-	17
Purchases	2	-	-	-	-	2
Settlement	(5)	(17)	(53)	-	-	(75)
Transfer to current portion	-	(1)	1	4	(4)	-
Foreign currency translation differences	1	23	1	-	-	25

Closing balance	207	848	66	(6)	(4)	1,110

Full year 2015
Opening balance	189	1,707	87	-	-	1,983
Total gains and losses recognised in statement of income	(2)	(442)	54	(59)	-	(449)
Purchases	28	-	-	-	-	28
Settlement	-	(110)	(79)	-	-	(190)
Foreign currency translation differences	(5)	(214)	(11)	-	-	(231)

Closing balance	209	941	50	(59)	-	1,141

During 2016 the financial instruments within level 3 have had a net decrease in the fair value of USD 31 million. The USD 44 million recognised in the Consolidated statement of income during 2016 are impacted by a reduction of USD 13 million related to changes in fair value of certain earn-out agreements. Related to the same earn-out agreements, USD 69 million included in the opening balance for 2016 has been fully realised as the underlying volumes have been delivered during 2016 and the amount is presented as settled in the above table.

Substantially all gains and losses recognised in the Consolidated statement of income during 2016 are related to assets held at the end of 2016.

Sensitivity analysis of market risk

Commodity price risk

The table below contains the 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 consist of both exchange traded and non-exchange traded 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 2016 and 2015 at 30% are assumed to represent a reasonably likely change based on the duration of the derivatives.

178 Statoil, Annual Report on Form 20-F 2016

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.

Commodity price sensitivity	2016		2015
(in USD million)	- 30%	+ 30%	- 30%	+ 30%

At 31 December
Crude oil and refined products net gains (losses)	395	(390)	110	(66)
Natural gas and electricity net gains (losses)	810	(809)	249	(248)

Currency risk

The following currency risk sensitivity has been calculated by assuming an 12% reasonably possible change in the main foreign exchange rates that Statoil is exposed to. At the end of 2015 a change of 11% in the foreign exchange rates were viewed as reasonably possible changes. An increase in the foreign exchange rates 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. For further information related to the currency risk and how Statoil manages these risks, see note 5 Financial risk management.

Currency risk sensitivity	2016		2015
(in million)	- 12%	+ 12%	- 11%	+ 11%

At 31 December
USD net gains (losses)	79	(79)	247	(247)
NOK net gains (losses)	31	(31)	(185)	185

Interest rate risk

The following interest rate risk sensitivity has been calculated by assuming a change of 0.8 percentage points as reasonably possible changes in the interest rates at the end of 2016. At the end of 2015 a change of 0.9 percentage points in the interest rates was 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. For further information related to the interest risks and how Statoil manages these risks, see note 5 Financial risk management.

Interest risk sensitivity	2016		2015
(in USD million)	- 0.8 percentage points	+ 0.8 percentage points	- 0.9 percentage points	+ 0.9 percentage points

At 31 December
Interest rate net gains (losses)	897	(897)	1,217	(1,217)

Statoil, Annual Report on Form 20-F 2016 179

26 Change of presentation currency

On 1 January 2016 Statoil changed its presentation currency from Norwegian kroner (NOK) to US dollars (USD). The change was made mainly in order to better reflect the underlying USD exposure of Statoil’s business activities and to align with industry practice.

The change in presentation currency has been accounted for as a policy change, and comparative figures have been re-presented to USD, to reflect the change in presentation currency. There are no policy changes other than the change in presentation currency.

The different components of assets and liabilities in USD correspond to the amount published in NOK translated at the USD/NOK closing rate applicable at the end of each reporting period. The same relates to the equity as a whole. As such, the change in presentation currency will not impact the valuation of assets, liabilities, equity or any ratios between these components, such as debt to equity ratios. Income statements are translated at quarterly average rate.

All currency translation adjustments have been set to zero as of 1 January 2006, which was the date of Statoil’s transition to IFRS. Translation adjustments and cumulative translation adjustments have been presented as if Statoil had used USD as the presentation currency from that date.

The recalculation of currency translation adjustments in USD has an impact on the distribution of shareholders’ equity for comparable periods, between currency translation adjustments and other components of equity. Together with changes in net income arising from the change in presentation currency, these effects are presented as re-presentations in the table below.

EFFECT OF CHANGES IN REPORTED EQUITY

	Historical Consolidated financial statements in NOK billion	Historical Consolidated financial statements in USD million¹⁾	Re-presentation in USD million	Consolidated financial statements in USD million
31 December 2015	Historical Consolidated financial statements in NOK billion		Re-presentation in USD million	Consolidated financial statements in USD million

Share capital	8.0	905	234	1,139
Additional paid-in capital	40.1	4,552	1,168	5,720
Retained earnings	215.1	24,417	14,276	38,693
Currency translation adjustments	91.6	10,398	(15,679)	(5,281)
Non-controlling interests	0.3	34	2	36

Total equity	355.1	40,307	0	40,307

1) Translated at exchange rate USD/NOK 8,8090 as of 31 December 2015.

	Historical Consolidated financial statements in NOK billion	Historical Consolidated financial statements in USD million¹⁾	Re-presentation in USD million	Consolidated financial statements in USD million
31 December 2014	Historical Consolidated financial statements in NOK billion		Re-presentation in USD million	Consolidated financial statements in USD million

Share capital	8.0	1,072	67	1,139
Additional paid-in capital	40.2	5,408	306	5,714
Retained earnings	268.4	36,097	9,580	45,677
Currency translation adjustments	64.3	8,650	(9,955)	(1,305)
Non-controlling interests	0.4	54	3	57

Total equity	381.2	51,282	0	51,282

1) Translated at exchange rate USD/NOK 7,4332 as of 31 December 2014.

180 Statoil, Annual Report on Form 20-F 2016

The Consolidated statement of income, Consolidated statement of other comprehensive income, Consolidated statement of changes in equity and Consolidated statement of cash flows have been re-presented to reflect the currency rates of transactions in foreign currencies at the date of the transactions.

Upon disposal of a foreign operation accumulated currency translation adjustments arising from currency movements between the Group’s presentation currency and the functional currency of the foreign operation are reclassified from equity to profit or loss and included as part of the gain or loss from the disposal, presented as other income. When changing the Group’s presentation currency from NOK to USD, the gains or losses from such disposals have been changed to reflect accumulated currency gains or losses being calculated based on USD being the presentation currency rather than NOK. These effects are presented as re-presentations in the table below, and represent the only re-measurements following the change in presentation currency to USD.

EFFECT OF CHANGES IN REPORTED NET INCOME

	Historical Consolidated financial statements in NOK billion	Historical Consolidated financial statements in USD million¹⁾	Re-presentation in USD million	Consolidated financial statements in USD million
Net income	Historical Consolidated financial statements in NOK billion		Re-presentation in USD million	Consolidated financial statements in USD million

Full year 2015	(37)	(4,684)	(485)	(5,169)

Full year 2014	22	3,831	56	3,887

1) Translated at average exchange rates for the quarters.

The disposal with most significant effect on the net income of the Group is the disposal of Statoil’s interests in Shah Deniz, presented within the DPI segment in the second quarter 2015, for which the gain presented in NOK included NOK 3.2 billion arising from reclassification of accumulated translation differences. As the disposed foreign operation had USD as functional currency, there are no accumulated translation differences when presented in USD for this transaction.

The Statement of cash flow has been re-presented to reflect the changes described above and based on the currency rates applicable at the transaction dates of relevant transactions. The re-presentation impacts the classification between the different lines in the statement of cash flow, between currency translation adjustments and other components of cash flow.

27 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 2016 that would result in a significant change in the estimated proved reserves or other figures reported as of that date.

The disputed equity determination at Agbami will potentially alter Statoil's equity share in this field. The effect on the proved reserves will be included once the redetermination is finalised and the effect is known.The effect of the farm out of the oil sands projects will be included in 2017, after the closing date of the transaction, and will reduce the proved reserves at year end 2017 by an immaterial volume related to the Leismer field.

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, Annual Report on Form 20-F 2016 181

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 2016, 7% of total proved reserves were related to such agreements (13% of total oil, condensate and natural gas liquids (NGL) reserves and 2% of total gas reserves). This compares with 9% and 12% of total proved reserves for 2015 and 2014, respectively. Net entitlement oil and gas production from fields with such agreements was 96 million boe during 2016 (104 million boe for 2015 and 95 million boe for 2014). 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. The proved reserves at year end 2016 have been determined based on a Brent blend price equivalent of USD 42.82/bbl, compared to USD 54.17/bbl and USD 101.27/bbl for 2015 and 2014 respectively. The volume weighted average gas price for proved reserves at year end 2016 was USD 4.50MMBtu. The comparable gas price used to determine gas reserves at year end 2015 and 2014 was USD 5.76MMBtu and USD 8.01MMBtu. The volume weighted average NGL price for proved reserves at year end 2016 was USD 24.85/boe. The corresponding NGL price used to determine NGL reserves at year end 2015 and 2014 was USD 30.56/boe and USD 57.03/boe. The decrease in commodity prices affects the profitable reserves to be recovered from accumulations resulting in reduced reserves marginally. The negative revisions due to price are in general a result of earlier economic cut-off. For fields with a production-sharing type of agreement this is to some degree offset by higher entitlement to the reserves. These changes are all included in the revision category in the tables below, giving a net reduction of Statoil’s proved reserves at year end.

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 utilizes 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 76% of total proved reserves at 31 December 2016 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 2013 through 2016, and the changes therein.

The reason for the most significant changes to our proved reserves at year end 2016 were:

· Positive revisions due to better performance of producing fields, maturing of improved recovery projects, and reduced uncertainty due to further drilling and production experience. This added a total of 409 million boe in 2016. A significant part of these positive revisions are related to large, producing fields offshore Norway where production is declining less than previously assumed for the proved reserves due to continuous improvement activities.

· Proved reserves from new discoveries have also been added through the sanctioning of new field development projects in 2016, Svale Nord Trestakk and Utgard in Norway and Julia in US. The new projects added a total of 66 million boe. New discoveries with proved reserves booked in 2016 are all expected to start production within a period of five years.

• Further drilling in the Bakken, Marcellus and Eagle Ford onshore plays in the US increased the proved reserves in 2016, and some of these additions are presented as extensions. Extension of proved area on existing field added a total of 112 million boe of new proved reserves in 2016. Together with proved reserves from new fields this adds a total of 179 million boe of proved reserves from Extensions and discoveries.

· The net effect of purchase and sale increased the reserves by 39 million boe in 2016.

· Production during 2016 reduced proved reserves by 673 million boe.

Changes to the proved reserves in 2016 are also described in some detail in section 2.8 Operating and financial performance by each geographical area. Development of the proved reserves are described in section 2.8 Operating and financial performance, Development of reserves.

182 Statoil, Annual Report on Form 20-F 2016

	Consolidated companies					Equity accounted				Total
	Norway	Eurasia excluding Norway	Africa	Americas	Subtotal	Norway	Eurasia excluding Norway	Americas	Subtotal	Total
Net proved oil and condensate reserves in million barrels oil equivalent
At 31 December 2013	918	227	271	399	1,815	-	-	63	63	1,877

Revisions and improved recovery	143	10	85	(4)	235	-	-	(3)	(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)	(4)	(306)

At 31 December 2014	886	196	296	508	1,887	-	-	55	55	1,942

Revisions and improved recovery	71	(68)	57	(54)	5	-	-	(5)	(5)	0
Extensions and discoveries	437	-	-	74	511	-	-	-	-	511
Purchase of reserves-in-place	-	-	-	4	4	-	-	-	-	4
Sales of reserves-in-place	(4)	(38)	-	(1)	(43)	-	-	-	-	(43)
Production	(174)	(13)	(75)	(57)	(319)	-	-	(4)	(4)	(324)

At 31 December 2015	1,216	76	278	474	2,045	-	-	46	46	2,091

Revisions and improved recovery	111	6	16	17	149	-	-	(12)	(12)	137
Extensions and discoveries	29	-	-	49	78	-	-	-	-	78
Purchase of reserves-in-place	-	-	-	-	-	60	0	-	60	60
Sales of reserves-in-place	(14)	-	-	-	(14)	-	-	-	-	(14)
Production	(169)	(12)	(72)	(60)	(313)	(2)	(0)	(4)	(6)	(320)

At 31 December 2016	1,174	71	221	480	1,945	58	-	30	88	2,033

Statoil, Annual Report on Form 20-F 2016 183

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	Norway	Eurasia excluding Norway	Americas	Subtotal	Total
Net proved NGL reserves in million barrels oil equivalent
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

Revisions and improved recovery	7	-	3	(20)	(10)	-	-	-	-	(10)
Extensions and discoveries	11	-	-	16	27	-	-	-	-	27
Purchase of reserves-in-place	-	-	-	4	4	-	-	-	-	4
Sales of reserves-in-place	(1)	-	-	(5)	(5)	-	-	-	-	(5)
Production	(44)	-	(3)	(7)	(54)	-	-	-	-	(54)

At 31 December 2015	291	-	15	57	364	-	-	-	-	364

Revisions and improved recovery	37	-	3	6	46	-	-	-	-	46
Extensions and discoveries	5	-	-	13	18	-	-	-	-	18
Purchase of reserves-in-place	-	-	-	-	-	2	-	-	2	2
Sales of reserves-in-place	(0)	-	-	-	(0)	-	-	-	-	(0)
Production	(46)	-	(2)	(9)	(58)	(0)	-	-	(0)	(58)

At 31 December 2016	287	-	16	67	370	2	-	-	2	372

184 Statoil, Annual Report on Form 20-F 2016

	Consolidated companies					Equity accounted				Total
	Norway	Eurasia excluding Norway	Africa	Americas	Subtotal	Norway	Eurasia excluding Norway	Americas	Subtotal	Total
Net proved gas reserves in billion standard cubic feet
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

Revisions and improved recovery	385	(18)	129	(676)	(180)	-	-	-	-	(180)
Extensions and discoveries	179	-	-	318	497	-	-	-	-	497
Purchase of reserves-in-place	-	-	-	31	31	-	-	-	-	31
Sales of reserves-in-place	(10)	(991)	-	(42)	(1,043)	-	-	-	-	(1,043)
Production	(1,306)	(16)	(63)	(215)	(1,600)	-	-	-	-	(1,600)

At 31 December 2015	12,942	193	366	1,123	14,624	-	-	-	-	14,624

Revisions and improved recovery	1,160	29	(25)	102	1,265	-	-	-	-	1,265
Extensions and discoveries	78	-	-	384	462	-	-	-	-	462
Purchase of reserves-in-place	-	-	-	-	-	16	0	-	16	16
Sales of reserves-in-place	(5)	-	-	(65)	(70)	-	-	-	-	(70)
Production	(1,338)	(34)	(60)	(227)	(1,659)	(1)	(0)	-	(2)	(1,661)

At 31 December 2016	12,836	188	280	1,318	14,623	15	-	-	15	14,637

Statoil, Annual Report on Form 20-F 2016 185

	Consolidated companies					Equity accounted				Total
	Norway	Eurasia excluding Norway	Africa	Americas	Subtotal	Norway	Eurasia excluding Norway	Americas	Subtotal	Total
Net proved reserves in million barrels oil equivalent
At 31 December 2013	3,916	569	346	705	5,537	-	-	63	63	5,600

Revisions and improved recovery	219	16	87	36	359	-	-	(3)	(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)	(4)	(635)

At 31 December 2014	3,644	413	364	882	5,304	-	-	55	55	5,359

Revisions and improved recovery	146	(72)	83	(194)	(37)	-	-	(5)	(5)	(42)
Extensions and discoveries	480	-	-	146	627	-	-	-	-	627
Purchase of reserves-in-place	-	-	-	13	13	-	-	-	-	13
Sales of reserves-in-place	(6)	(215)	-	(13)	(235)	-	-	-	-	(235)
Production	(450)	(16)	(88)	(103)	(658)	-	-	(4)	(4)	(662)

At 31 December 2015	3,814	111	358	731	5,014	-	-	46	46	5,060

Revisions and improved recovery	355	11	14	41	421	-	-	(12)	(12)	409
Extensions and discoveries	48	-	-	130	179	-	-	-	-	179
Purchase of reserves-in-place	-	-	-	-	-	65	0	-	65	65
Sales of reserves-in-place	(15)	-	-	(11)	(27)	-	-	-	-	(27)
Production	(454)	(18)	(85)	(110)	(666)	(3)	(0)	(4)	(7)	(673)

At 31 December 2016	3,748	104	287	782	4,921	62	-	30	92	5,013

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

186 Statoil, Annual Report on Form 20-F 2016

	Consolidated companies					Equity accounted				Total
	Norway	Eurasia excluding Norway	Africa	Americas	Subtotal	Norway	Eurasia excluding Norway	Americas	Subtotal	Total
Net proved oil and condensate reserves in million barrels oil equivalent
At 31 December 2013
Developed	548	63	197	212	1,020	-	-	32	32	1,052
Undeveloped	370	164	74	187	795	-	-	30	30	826
At 31 December 2014
Developed	559	63	243	267	1,133	-	-	24	24	1,156
Undeveloped	327	133	52	242	754	-	-	32	32	786
At 31 December 2015
Developed	505	48	248	282	1,083	-	-	21	21	1,104
Undeveloped	711	29	30	192	962	-	-	25	25	987
At 31 December 2016
Developed	536	43	200	303	1,082	7	-	16	23	1,105
Undeveloped	638	28	22	176	863	51	-	13	65	928
Net proved NGL reserves in million barrels oil equivalent
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
At 31 December 2015
Developed	235	-	9	45	290	-	-	-	-	290
Undeveloped	56	-	6	12	74	-	-	-	-	74
At 31 December 2016
Developed	213	-	10	53	276	1	-	-	1	277
Undeveloped	74	-	6	14	94	1	-	-	1	95
Net proved gas reserves in billion standard cubic feet
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
At 31 December 2015
Developed	10,664	32	206	999	11,901	-	-	-	-	11,901
Undeveloped	2,278	161	160	124	2,723	-	-	-	-	2,723
At 31 December 2016
Developed	9,219	188	171	1,002	10,580	4	-	-	4	10,584
Undeveloped	3,617	-	110	316	4,043	11	-	-	11	4,054
Net proved oil, condensate, NGL and gas reserves in million barrels oil equivalent
At 31 December 2013
Developed	2,898	146	244	392	3,679	-	-	32	32	3,711
Undeveloped	1,018	423	103	314	1,858	-	-	30	30	1,888
At 31 December 2014
Developed	2,818	119	287	477	3,701	-	-	24	24	3,725
Undeveloped	826	295	78	405	1,603	-	-	32	32	1,635
At 31 December 2015
Developed	2,641	53	294	505	3,494	-	-	21	21	3,515
Undeveloped	1,173	57	64	226	1,521	-	-	25	25	1,546
At 31 December 2016
Developed	2,392	76	240	535	3,244	8	-	16	24	3,268
Undeveloped	1,357	28	47	246	1,678	54	-	13	68	1,746

Statoil, Annual Report on Form 20-F 2016 187

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 producing activities
Consolidated companies
	At 31 December
(in USD million)	2016	2015	2014

Unproved properties	13,563	13,341	13,121
Proved properties, wells, plants and other equipment	159,284	150,653	158,586

Total capitalised cost	172,847	163,994	171,707
Accumulated depreciation, impairment and amortisation	(109,160)	(99,118)	(92,451)

Net capitalised cost	63,687	64,876	79,256

Net capitalised cost related to equity accounted investments as of 31 December 2016 was USD 2,000 million, USD 1,000 million in 2015 and USD 1,147 million in 2014. The increase is mainly related to the investment in Lundin Petroleum AB as described in note 12. 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
(in USD million)	Norway	Eurasia excluding Norway	Africa	Americas	Total

Full year 2016
Exploration expenditures	495	155	197	590	1,437
Development costs	5,245	661	780	2,118	8,804
Acquired proved properties	6	0	0	3	9
Acquired unproved properties	57	58	0	2,362	2,477

Total	5,803	874	977	5,073	12,727

Full year 2015
Exploration expenditures	796	213	381	1,469	2,859
Development costs	5,863	1,420	1,315	3,600	12,198
Acquired proved properties	0	0	0	79	79
Acquired unproved properties	6	77	88	375	546

Total	6,665	1,710	1,784	5,523	15,682

Full year 2014
Exploration expenditures	1,117	291	1,244	1,075	3,727
Development costs	8,354	2,140	2,107	3,389	15,990
Acquired proved properties	0	0	0	778	778
Acquired unproved properties	0	3	(3)	355	355

Total	9,471	2,434	3,348	5,596	20,849

Expenditures incurred in development activities related to equity accounted investments was USD 1,370 million in 2016, USD 46 million in 2015 and USD 255 million in 2014. The increase is mainly related to the investment in Lundin Petroleum AB, USD 1,199 million, as described in note 12.

188 Statoil, Annual Report on Form 20-F 2016

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. Production cost is based on operating expenses related to production of oil and gas. From the operating expenses certain expenses such as; transportation costs, accruals for over/underlift position, royalty payments and diluent costs are excluded. These expenses and mainly upstream business administration are included as other expenses in the tables below. Other revenues mainly consist of gains and losses from sales of oil and gas interests and gains and losses from commodity based derivatives within the upstream segments.

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
(in USD million)	Norway	Eurasia excluding Norway	Africa	Americas	Total

Full year 2016
Sales	57	161	305	226	749
Transfers	12,962	494	2,803	2,466	18,725
Other revenues	136	30	6	266	438

Total revenues	13,155	685	3,114	2,958	19,912

Exploration expenses	(383)	(274)	(284)	(2,011)	(2,952)
Production costs	(2,129)	(148)	(629)	(663)	(3,569)
Depreciation, amortisation and net impairment losses	(5,698)	(130)	(2,181)	(3,199)	(11,208)
Other expenses	(417)	(81)	(89)	(1,321)	(1,908)

Total costs	(8,627)	(633)	(3,183)	(7,194)	(19,637)

Results of operations before tax	4,528	52	(69)	(4,236)	275
Tax expense	(2,760)	272	(123)	(25)	(2,636)

Results of operations	1,768	324	(192)	(4,261)	(2,361)

Net income from equity accounted investments	(78)	(86)	0	(14)	(178)

Statoil, Annual Report on Form 20-F 2016 189

Consolidated companies
(in USD million)	Norway	Eurasia excluding Norway	Africa	Americas	Total

Full year 2015
Sales	50	257	(41)	198	464
Transfers	17,429	480	3,454	2,764	24,127
Other revenues	(143)	1,169	3	7	1,036

Total revenues	17,336	1,906	3,416	2,969	25,627

Exploration expenses	(576)	(190)	(630)	(2,476)	(3,872)
Production costs	(2,629)	(160)	(671)	(794)	(4,254)
Depreciation, amortisation and net impairment losses	(6,379)	(799)	(2,487)	(6,946)	(16,611)
Other expenses	(594)	(165)	(237)	(1,374)	(2,370)

Total costs	(10,178)	(1,314)	(4,025)	(11,590)	(27,107)

Results of operations before tax	7,157	593	(609)	(8,622)	(1,481)
Tax expense	(4,824)	238	(717)	(21)	(5,324)

Results of operations	2,333	831	(1,326)	(8,643)	(6,805)

Net income from equity accounted investments	3	32	0	(123)	(88)

190 Statoil, Annual Report on Form 20-F 2016

Consolidated companies
(in USD million)	Norway	Eurasia excluding Norway	Africa	Americas	Total

Full year 2014
Sales	286	688	818	615	2,407
Transfers	27,478	978	5,214	4,564	38,234
Other revenues	1,151	932	117	(152)	2,048

Total revenues	28,915	2,598	6,149	5,027	42,689

Exploration expenses	(838)	(397)	(1,349)	(2,078)	(4,662)
Production costs	(3,555)	(225)	(719)	(856)	(5,355)
Depreciation, amortisation and net impairment losses	(6,301)	(744)	(2,221)	(5,921)	(15,187)
Other expenses	(479)	(170)	33	(1,718)	(2,334)

Total costs	(11,173)	(1,536)	(4,256)	(10,573)	(27,538)

Results of operations before tax	17,742	1,062	1,893	(5,546)	15,151
Tax expense	(11,512)	(70)	(1,278)	(64)	(12,924)

Results of operations	6,230	992	615	(5,610)	2,227

Net income from equity accounted investments	11	132	0	(246)	(103)

Average production cost in USD per boe based on entitlement volumes (consolidated)	Norway	Eurasia excluding Norway	Africa	Americas	Total

2016	5	8	7	6	5
2015	6	10	8	8	6
2014	8	10	10	8	8

Production cost per boe is calculated as the production costs in the result of operations table, divided by the produced entitlement volumes (mboe) for the corresponding period.

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.

Statoil, Annual Report on Form 20-F 2016 191

(in USD million)	Norway	Eurasia excluding Norway	Africa	Americas	Total
At 31 December 2016
Consolidated companies
Future net cash inflows	120,355	4,032	10,644	20,034	155,065
Future development costs	(14,572)	(927)	(733)	(3,559)	(19,791)
Future production costs	(45,357)	(2,101)	(4,909)	(11,701)	(64,069)
Future income tax expenses	(36,268)	(127)	(1,492)	(1,355)	(39,243)
Future net cash flows	24,158	876	3,510	3,418	31,962
10% annual discount for estimated timing of cash flows	(8,729)	(241)	(646)	(1,255)	(10,870)
Standardised measure of discounted future net cash flows	15,429	635	2,864	2,164	21,092

Equity accounted investments
Standardised measure of discounted future net cash flows	279	-	-	127	406

Total standardised measure of discounted future net cash flows including equity accounted investments	15,708	635	2,864	2,290	21,498


(in USD million)	Norway	Eurasia excluding Norway	Africa	Americas	Total
At 31 December 2015
Consolidated companies
Future net cash inflows	160,277	5,455	17,073	23,595	206,399
Future development costs	(19,409)	(1,345)	(1,330)	(5,157)	(27,242)
Future production costs	(54,911)	(2,765)	(6,832)	(12,762)	(77,271)
Future income tax expenses	(56,680)	(118)	(3,149)	(800)	(60,747)
Future net cash flows	29,276	1,226	5,762	4,875	41,139
10% annual discount for estimated timing of cash flows	(12,011)	(406)	(1,386)	(1,969)	(15,773)
Standardised measure of discounted future net cash flows	17,264	820	4,375	2,906	25,366

Equity accounted investments
Standardised measure of discounted future net cash flows	-	-	-	140	140

Total standardised measure of discounted future net cash flows including equity accounted investments	17,264	820	4,375	3,047	25,506


(in USD million)	Norway	Eurasia excluding Norway	Africa	Americas	Total
At 31 December 2014
Consolidated companies
Future net cash inflows	234,404	32,474	34,114	51,585	352,577
Future development costs	(26,643)	(9,571)	(1,961)	(8,262)	(46,437)
Future production costs	(70,229)	(14,622)	(9,310)	(22,785)	(116,946)
Future income tax expenses	(96,896)	(1,287)	(7,764)	(5,432)	(111,378)
Future net cash flows	40,636	6,995	15,079	15,107	77,816
10% annual discount for estimated timing of cash flows	(15,925)	(4,438)	(4,494)	(6,688)	(31,546)
Standardised measure of discounted future net cash flows	24,711	2,556	10,584	8,419	46,270

Equity accounted investments
Standardised measure of discounted future net cash flows	-	-	-	806	806

Total standardised measure of discounted future net cash flows including equity accounted investments	24,711	2,556	10,584	9,225	47,076

192 Statoil, Annual Report on Form 20-F 2016

Changes in the standardised measure of discounted future net cash flows from proved reserves
(in USD million)	2016	2015	2014

Consolidated companies
Standardised measure at beginning of year	25,366	46,270	47,448
Net change in sales and transfer prices and in production (lifting) costs related to future production	(21,148)	(71,817)	(20,157)
Changes in estimated future development costs	(16)	6,739	(3,838)
Sales and transfers of oil and gas produced during the period, net of production cost	(16,824)	(20,803)	(36,904)
Net change due to extensions, discoveries, and improved recovery	1,099	3,745	3,685
Net change due to purchases and sales of minerals in place	(566)	(1,026)	(4,181)
Net change due to revisions in quantity estimates	8,163	7,491	19,340
Previously estimated development costs incurred during the period	7,998	10,474	15,811
Accretion of discount	5,949	11,335	12,691
Net change in income taxes	11,070	32,958	12,374

Total change in the standardised measure during the year	(4,274)	(20,904)	(1,178)

Standardised measure at end of year	21,092	25,366	46,270

Equity accounted investments
Standardised measure at end of year	406	140	806

Standardised measure at end of year including equity accounted investments	21,498	25,506	47,076

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.

The standardized measure at the beginning of the year represents the discounted net present value after deductions of both future development costs, production costs and taxes. The ‘Net change in sales and transfer prices and in production (lifting) costs related to future production’ is, on the other hand, related to the future net cash flows at 31 December 2015. The proved reserves at 31 December 2015 were multiplied by the actual change in price, and change in unit of production costs, to arrive at the net effect of changes in price and production costs. Development costs and taxes are reflected in the line items ‘Change in estimated future development costs’ and ‘Net change in income taxes’ and are not included in the ‘Net change in sales and transfer prices and in production (lifting) costs related to future production’.

28 Subsequent events

See note 17 Equity and dividend for proposed dividend for the fourth quarter 2016.

Statoil, Annual Report on Form 20-F 2016 193

29 Condensed consolidated financial information related to guaranteed debt securities

Statoil Petroleum AS, a 100% owned subsidiary of Statoil ASA, is the co-obligor of certain existing debt securities of Statoil ASA that are registered under the US Securities Act of 1933 ("US registered debt securities"). As co-obligor, Statoil Petroleum AS fully, unconditionally and irrevocably assumes and agrees to perform, jointly and severally with Statoil ASA, the payment and covenant obligations for these US registered debt securities. In addition, Statoil ASA is also the co-obligor of a US registered debt security of Statoil Petroleum AS. As co-obligor, Statoil ASA fully, unconditionally and irrevocably assumes and agrees to perform, jointly and severally with Statoil Petroleum AS, the payment and covenant obligations of that security. In the future, Statoil ASA may from time to time issue future US registered debt securities for which Statoil Petroleum AS will be the co-obligor or guarantor.

The following financial information on a condensed consolidated basis provides financial information about Statoil ASA, as issuer and co-obligor, Statoil Petroleum AS, as co-obligor and guarantor, and all other subsidiaries as required by SEC Rule 3-10 of Regulation S-X. The condensed consolidated information is prepared in accordance with Statoil's IFRS accounting policies as described in note 2 Significant accounting policies, except that investments in subsidiaries and jointly controlled entities are accounted for using the equity method as required by Rule 3-10.

The following is condensed consolidated financial information for the full year 2016, 2015 and 2014, and as of 31 December 2016 and 2015.

CONDENSED CONSOLIDATED STATEMENT OF INCOME AND OTHER COMPREHENSIVE INCOME
	Statoil ASA	Statoil Petroleum AS	Non-guarantor subsidiaries	Consolidation adjustments	The Statoil group
Full year 2016 (in USD million)	Statoil ASA	Statoil Petroleum AS	Non-guarantor subsidiaries	Consolidation adjustments	The Statoil group

Revenues and other income	31,580	15,405	15,472	(16,464)	45,993
Net income from equity accounted companies	(2,726)	(3,987)	26	6,567	(119)

Total revenues and other income	28,854	11,418	15,498	(9,898)	45,873

Total operating expenses	(31,784)	(10,989)	(19,364)	16,344	(45,793)

Net operating income	(2,930)	429	(3,865)	6,446	80

Net financial items	728	(560)	(115)	(311)	(258)

Income before tax	(2,202)	(131)	(3,980)	6,135	(178)

Income tax	(407)	(2,392)	97	(23)	(2,724)

Net income	(2,608)	(2,523)	(3,884)	6,113	(2,902)

Other comprehensive income	(671)	153	(280)	441	(357)

Total comprehensive income	(3,279)	(2,370)	(4,163)	6,553	(3,259)

194 Statoil, Annual Report on Form 20-F 2016

CONDENSED CONSOLIDATED STATEMENT OF INCOME AND OTHER COMPREHENSIVE INCOME
	Statoil ASA	Statoil Petroleum AS	Non-guarantor subsidiaries	Consolidation adjustments	The Statoil group
Full year 2015 (in USD million)	Statoil ASA	Statoil Petroleum AS	Non-guarantor subsidiaries	Consolidation adjustments	The Statoil group

Revenues and other income	39,289	20,583	20,248	(20,448)	59,671
Net income from equity accounted companies	(4,686)	(8,350)	(42)	13,050	(29)

Total revenues and other income	34,603	12,232	20,205	(7,399)	59,642

Total operating expenses	(39,372)	(12,561)	(26,907)	20,566	(58,276)

Net operating income	(4,769)	(329)	(6,702)	13,167	1,366

Net financial items	(2,771)	(106)	139	1,427	(1,311)

Income before tax	(7,541)	(435)	(6,563)	14,594	55

Income tax	925	(5,301)	(840)	(9)	(5,225)

Net income	(6,616)	(5,736)	(7,402)	14,585	(5,169)

Other comprehensive income	(1,414)	(1,771)	(1,405)	1,751	(2,838)

Total comprehensive income	(8,030)	(7,507)	(8,807)	16,336	(8,007)

CONDENSED CONSOLIDATED STATEMENT OF INCOME AND OTHER COMPREHENSIVE INCOME
	Statoil ASA	Statoil Petroleum AS	Non-guarantor subsidiaries	Consolidation adjustments	The Statoil group
Full year 2014 (in USD million)	Statoil ASA	Statoil Petroleum AS	Non-guarantor subsidiaries	Consolidation adjustments	The Statoil group

Revenues and other income	65,647	33,454	34,189	(33,991)	99,299
Net income from equity accounted companies	3,812	(4,794)	(41)	989	(34)

Total revenues and other income	69,458	28,660	34,148	(33,002)	99,264

Total operating expenses	(66,668)	(14,120)	(35,114)	34,516	(81,386)

Net operating income	2,791	14,540	(966)	1,514	17,878

Net financial items	(1,841)	(28)	(51)	1,940	20

Income before tax	950	14,512	(1,017)	3,453	17,898

Income tax	981	(13,007)	(1,802)	(184)	(14,011)

Net income	1,931	1,505	(2,819)	3,269	3,887

Other comprehensive income	(2,648)	(2,384)	(1,385)	1,829	(4,587)

Total comprehensive income	(717)	(879)	(4,204)	5,099	(701)

Statoil, Annual Report on Form 20-F 2016 195

CONDENSED CONSOLIDATED BALANCE SHEET
	Statoil ASA	Statoil Petroleum AS	Non-guarantor subsidiaries	Consolidation adjustments	The Statoil group
At 31 December 2016 (in USD million)	Statoil ASA	Statoil Petroleum AS	Non-guarantor subsidiaries	Consolidation adjustments	The Statoil group

ASSETS
Property, plant, equipment and intangible assets	576	29,944	38,310	(31)	68,799
Equity accounted companies	40,294	18,089	1,013	(57,151)	2,245
Other non-current assets	3,212	945	3,933	0	8,090
Non-current receivables from subsidiaries	23,644	(0)	26	(23,670)	0

Total non-current assets	67,725	48,979	43,281	(80,852)	79,133

Current receivables from subsidiaries	4,305	2,141	12,879	(19,325)	0
Other current assets	14,716	924	4,769	(639)	19,769
Cash and cash equivalents	4,274	46	770	0	5,090

Total current assets	23,295	3,111	18,418	(19,964)	24,859

Assets classified as held for sale	0	0	537	0	537

Total assets	91,021	52,089	62,236	(100,816)	104,530

EQUITY AND LIABILITIES
Total equity	35,072	17,974	39,510	(57,457)	35,099

Non-current liabilities to subsidiaries	17	12,848	10,806	(23,670)	0
Other non-current liabilities	33,065	13,812	5,953	(198)	52,633

Total non-current liabilities	33,082	26,660	16,759	(23,868)	52,633

Other current liabilities	7,757	4,419	4,735	(166)	16,744
Current liabilities to subsidiaries	15,109	3,037	1,179	(19,325)	0

Total current liabilities	22,866	7,456	5,913	(19,492)	16,744

Liabilities directly associated with the assets classified as held for sale	0	0	54	0	54

Total liabilities	55,948	34,116	22,727	(43,359)	69,431

Total equity and liabilities	91,021	52,089	62,236	(100,816)	104,530

196 Statoil, Annual Report on Form 20-F 2016

CONDENSED CONSOLIDATED BALANCE SHEET
	Statoil ASA	Statoil Petroleum AS	Non-guarantor subsidiaries	Consolidation adjustments	The Statoil group
At 31 December 2015 (in USD million)	Statoil ASA	Statoil Petroleum AS	Non-guarantor subsidiaries	Consolidation adjustments	The Statoil group

ASSETS
Property, plant, equipment and intangible assets	636	29,653	41,205	(36)	71,458
Equity accounted companies	53,643	20,547	434	(73,800)	824
Other non-current assets	4,357	1,014	3,937	(3)	9,305
Non-current receivables from subsidiaries	13,976	(0)	24	(13,999)	0

Total non-current assets	72,612	51,214	45,600	(87,839)	81,588

Current receivables from subsidiaries	1,239	2,319	13,631	(17,189)	(0)
Other current assets	14,847	1,006	4,118	(440)	19,532
Cash and cash equivalents	7,471	87	1,066	0	8,623

Total current assets	23,557	3,412	18,815	(17,629)	28,154

Total assets	96,169	54,626	64,415	(105,468)	109,742

EQUITY AND LIABILITIES
Total equity	40,271	20,895	52,607	(73,466)	40,307

Non-current liabilities to subsidiaries	15	13,726	259	(13,999)	0
Other non-current liabilities	34,415	14,363	5,432	(138)	54,073

Total non-current liabilities	34,430	28,089	5,691	(14,137)	54,073

Other current liabilities	5,954	4,377	5,707	(675)	15,363
Current liabilities to subsidiaries	15,514	1,265	410	(17,189)	0

Total current liabilities	21,468	5,643	6,117	(17,865)	15,363

Total liabilities	55,899	33,731	11,808	(32,002)	69,436

Total equity and liabilities	96,169	54,626	64,415	(105,468)	109,743

Statoil, Annual Report on Form 20-F 2016 197

CONDENSED CONSOLIDATED CASH FLOW STATEMENT
	Statoil ASA	Statoil Petroleum AS	Non-guarantor subsidiaries	Consolidation adjustments	The Statoil group
Full year 2016 (in USD million)	Statoil ASA	Statoil Petroleum AS	Non-guarantor subsidiaries	Consolidation adjustments	The Statoil group

Cash flows provided by (used in) operating activities	3,330	7,262	1,561	(3,119)	9,034
Cash flows provided by (used in) investing activities	(3,138)	(6,785)	(5,393)	4,869	(10,447)
Cash flows provided by (used in) financing activities	(3,308)	(516)	3,616	(1,750)	(1,958)

Net increase (decrease) in cash and cash equivalents	(3,116)	(39)	(216)	0	(3,371)

Effect of exchange rate changes on cash and cash equivalents	(81)	(2)	(69)	0	(152)
Cash and cash equivalents at the beginning of the period (net of overdraft)	7,471	87	1,056	0	8,614

Cash and cash equivalents at the end of the period (net of overdraft)	4,274	46	770	0	5,090


	Statoil ASA	Statoil Petroleum AS	Non-guarantor subsidiaries	Consolidation adjustments	The Statoil group
Full year 2015 (in USD million)	Statoil ASA	Statoil Petroleum AS	Non-guarantor subsidiaries	Consolidation adjustments	The Statoil group

Cash flows provided by (used in) operating activities	2,883	8,348	4,567	(2,170)	13,628
Cash flows provided by (used in) investing activities	(5,694)	(17,219)	(5,630)	14,042	(14,501)
Cash flows provided by (used in) financing activities	1,333	8,986	824	(11,872)	(729)

Net increase (decrease) in cash and cash equivalents	(1,478)	115	(239)	0	(1,602)

Effect of exchange rate changes on cash and cash equivalents	(677)	(106)	(88)	0	(871)
Cash and cash equivalents at the beginning of the period (net of overdraft)	9,625	78	1,382	0	11,085

Cash and cash equivalents at the end of the period (net of overdraft)	7,470	87	1,055	0	8,612


	Statoil ASA	Statoil Petroleum AS	Non-guarantor subsidiaries	Consolidation adjustments	The Statoil group
Full year 2014 (in USD million)	Statoil ASA	Statoil Petroleum AS	Non-guarantor subsidiaries	Consolidation adjustments	The Statoil group

Cash flows provided by (used in) operating activities	2,666	11,966	8,927	(3,354)	20,205
Cash flows provided by (used in) investing activities	(2,528)	(9,872)	(8,500)	3,125	(17,775)
Cash flows provided by (used in) financing activities	(1,852)	(2,015)	(390)	229	(4,028)

Net increase (decrease) in cash and cash equivalents	(1,714)	79	37	0	(1,598)

Effect of exchange rate changes on cash and cash equivalents	(1,309)	(1)	(19)	0	(1,329)
Cash and cash equivalents at the beginning of the period (net of overdraft)	12,648	(2)	1,367	0	14,013

Cash and cash equivalents at the end of the period (net of overdraft)	9,625	76	1,385	0	11,086

Report of Independent Registered Public Accounting Firm

To the board of directors and shareholders of Statoil ASA

We have audited the accompanying Consolidated balance sheets of Statoil ASA and subsidiaries as of 31 December 2016 and 2015, and the related Consolidated statements of income, comprehensive income, changes in equity, and cash flows for each of the years in the three-year period ended 31 December 2016. These Consolidated financial statements are the responsibility of the Statoil ASA's management. Our responsibility is to express an opinion on these Consolidated financial statements based on our audits.

198 Statoil, Annual Report on Form 20-F 2016

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the Consolidated financial statements referred to above present fairly, in all material respects, the financial position of Statoil ASA and subsidiaries as of 31 December 2016 and 2015, and the results of their operations and their cash flows for each of the years in the three-year period ended 31 December 2016, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board and International Financial Reporting Standards as adopted by the European Union.

As discussed in Note 26 to the Consolidated financial statements, Statoil ASA has elected to change its presentation currency from Norwegian Kroner to US Dollar. In addition to the information included in Note 26, Statoil ASA has also included a US Dollar Consolidated balance sheet as of 31 December 2014.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Statoil ASA’s internal control over financial reporting as of 31 December 2016, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated 9 March 2017 expressed an unqualified opinion on the effectiveness of the Statoil ASA’s internal control over financial reporting.

Statoil, Annual Report on Form 20-F 2016 199

/s/ KPMG AS

Oslo, Norway

9 March 2017

200 Statoil, Annual Report on Form 20-F 2016

Report of KPMG on Statoil’s internal control over financial reporting

Report of Independent Registered Public Accounting Firm

To the board of directors and shareholders of Statoil ASA

We have audited Statoil ASA’s internal control over financial reporting as of 31 December 2016, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Statoil ASA’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying The management's report on internal control over financial reporting. Our responsibility is to express an opinion on Statoil ASA’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Statoil ASA maintained, in all material respects, effective internal control over financial reporting as of 31 December 2016, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Consolidated balance sheets of Statoil ASA and subsidiaries as of 31 December 2016 and 2015, and the related Consolidated statements of income, comprehensive income, changes in equity, and cash flows for each of the years in the three-year period ended 31 December 2016, and our report dated 9 March 2017 expressed an unqualified opinion on those Consolidated financial statements.

Statoil, Annual Report on Form 20-F 2016 201

/s/ KPMG AS

Oslo, Norway

9 March 2017

202 Statoil, Annual Report on Form 20-F 2016

5.1 SHAREHOLDER INFORMATION

Statoil is the largest company listed on the Oslo Børs where it trades under the ticker code STL. Statoil is also listed on the New York Stock Exchange under the ticker code STO, trading in the form of American Depositary Shares (ADS).

Statoil's shares have been listed on the Oslo Børs since our initial public offering on 18 June 2001. The ADSs traded on the New York Stock Exchange are evidenced by American Depositary Receipts (ADR), and each ADS represents one ordinary share.

Statoil Share	2016	2015	2014	2013	2012

Shareprice STL (low) (NOK)	97.90	116.30	120.00	123.00	133.80
Shareprice STL (average) (NOK)	133.50	137.59	166.41	136.72	146.97
Shareprice STL (high) (NOK)	159.80	160.80	194.80	147.70	162.40
Shareprice STL (year-end) (NOK)	158.40	123.70	131.20	147.00	139.00
Shareprice STO (low) (USD)	11.38	13.42	15.82	20.14	22.15
Shareprice STO (average) (USD)	15.92	17.11	26.52	23.32	25.29
Shareprice STO (high) (USD)	18.51	21.31	31.91	27.00	28.92
Shareprice STO (year-end) (USD)	18.24	13.96	17.61	24.13	25.04

STL Market value year-end (NOK billion)	514	394	418	469	443
STL Daily turnover (million shares)	4.7	5.1	3.7	3.0	4.3

Ordinary shares outstanding, year-end	3,245,049,411	3,188,647,103	3,188,647,103	3,188,647,103	3,188,647,103

As of 31 December 2016, Statoil represented 23.24% of the total value of all companies registered on the Oslo Børs, with a market value of NOK 514 billion. Total shareholder return (dividend reinvested) for 2016 is 35.4%.

The graph shows the development of the Statoil share price compared to the oil price and the Oslo Børs Benchmark Index (OSEBX). The turnover of shares is a measure of traded volumes. On average, 4.62 million Statoil shares were traded on the Oslo Børs every day in 2016 compared to 5.1 million shares in 2015. In 2016, Statoil shares accounted for 15% of the total market value traded throughout the year which is equal to 2015.

Statoil, Annual Report on Form 20-F 2016 203

Statoil ASA has one class of shares, and each share confers one vote at the general meeting. Statoil ASA had 3,245,049,411 ordinary shares outstanding at year end. As of 31 December 2016, Statoil had 91,128 shareholders registered in the Norwegian Central Securities Depository (VPS), down from 91,774 shareholders at 31 December 2015.

Share prices

These are the reported high and low quotations at market closing for the ordinary shares on the Oslo Børs and New York Stock Exchange for the periods indicated. They are derived from the Oslo Børs Daily Official List, and the highest and lowest sales prices of the ADSs as reported on the New York Stock Exchange composite tape.

204 Statoil, Annual Report on Form 20-F 2016

	NOK per ordinary share		USD per ADS
Share price	High	Low	High	Low

Year ended 31 December
2012	162.40	133.80	28.92	22.15
2013	147.70	123.00	27.00	20.14
2014	194.80	120.00	31.91	15.82
2015	160.80	116.30	21.31	13.42
2016	159.80	97.90	18.51	11.38

Quarter ended
Monday, March 31, 2015	149.80	125.80	19.62	16.25
Monday, June 30, 2015	160.80	140.10	21.31	17.59
Wednesday, September 30, 2015	141.40	116.30	17.56	13.85
Thursday, December 31, 2015	145.60	118.70	17.74	13.42
Thursday, March 31, 2016	135.50	97.90	16.01	11.38
Thursday, June 30, 2016	144.80	122.40	17.68	14.66
Friday, September 30, 2016	149.80	124.00	17.74	15.07
Friday, December 30, 2016	159.80	129.30	18.51	15.86
Up until March 8, 2017	162.90	97.90	19.21	11.38

Month of
September 2016	135.00	124.00	16.80	15.07
October 2016	140.70	133.90	17.30	16.24
November 2016	146.40	129.30	17.40	15.86
December 2016	159.80	147.30	18.51	18.51
January 2017	162.90	153.40	19.21	18.47
February 2017	156.50	147.10	18.81	17.41
Up until March 8, 2017	162.90	122.40	19.21	14.66

Dividend policy and dividends

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

Statoil’s board approves first, second and third quarter interim dividends, based on an authorisation from the annual general meeting (AGM), while the AGM approves the fourth quarter dividend and implicitly the total annual dividend based on a proposal from the board. It is Statoil’s intention to pay quarterly dividends, although when deciding the interim dividends and recommending the total annual dividend level, the board will take into consideration expected cash flow, capital expenditure plans, financing requirements and appropriate financial flexibility.

In addition to cash dividend, Statoil might buy back shares as part of total distribution of capital to the shareholders. The shareholders at the AGM may vote to reduce, but may not increase, the fourth quarter dividend proposed by the board of directors. Statoil announces dividend payments in connection with quarterly results. Payment of quarterly dividends is expected to take place within six months after the announcement of each quarterly dividend.

The board of directors proposes to the AGM a dividend of USD 0.2201 per share for the fourth quarter 2016 and to continue with the two-year scrip dividend programme which started from fourth quarter 2015. The scrip programme will give shareholders the option to receive quarterly dividends in cash or in newly issued shares in Statoil at a 5% discount for the fourth quarter 2016. On 11 May 2016, Statoil and the Norwegian state entered into a two-year agreement whereby the Norwegian state shall use the part of its quarterly dividend to subscribe for the number of shares that is required to maintain its ownership of 67%. Any part of the Dividend not used as settlement for dividend shares by the Norwegian state shall be paid in cash. For further information about dividends and our scrip dividend programme see Statoil.com.

The following table shows the cash dividend amounts to all shareholders since 2011 on a per share basis and in aggregate.

Statoil, Annual Report on Form 20-F 2016 205

		Ordinary dividend per share								Ordinary dividend per share
Fiscal year	Curr.	Q1	Curr.	Q2	Curr.	Q3	Curr.	Q4	Curr.	Ordinary dividend per share

2012									NOK	6.7500
2013									NOK	7.0000
2014	NOK	1.8000	NOK	1.8000	NOK	1.8000	NOK	1.8000	NOK	7.2000
2015	NOK	1.8000	NOK	0.0000	NOK	0.0000	NOK	0.0000	NOK	1.8000
2015	USD	0.0000	USD	0.2201	USD	0.2201	USD	0.2201	USD	0.6603
2016	USD	0.2201	USD	0.2201	USD	0.2201	USD	0.2201	USD	0.8804

The proposed fourth quarter 2016 dividend will be considered at the annual general meeting 11 May 2017. The Statoil share will be traded ex dividend 12 May 2017 and the dividend will be disbursed around late June 2017. For US ADR holders, the ex-dividend date will be 11 May 2017 and expected payment and allocation of new dividend shares for ADR holders will be in June 2017.

Dividends in NOK per share will be calculated and communicated four business days after record date for shareholders at Oslo Børs. The NOK dividend will be based on average USD/NOK fixing rates from Norges Bank in the period plus/minus three business days from record date, in total seven business dates.

Share repurchase

For the period 2013-2016, the board of directors was authorised by the annual general meeting of Statoil to repurchase Statoil shares in the market for subsequent annulment. Statoil has not undertaken any share repurchase based on this authorisation.

It is Statoil’s intention to renew this authorisation at the annual general meeting in May 2017.

206 Statoil, Annual Report on Form 20-F 2016

Shares purchased by issuer

Shares are acquired in the market for transfer to employees under the share savings scheme in accordance with the limits set by the board of directors. No shares were repurchased in the market for the purpose of subsequent annulment in 2016.

Statoil's share savings plan

Since 2004, Statoil has had a share savings plan for employees of the company. The purpose of this plan is to strengthen the business culture and encourage loyalty through employees becoming part-owners of the company.

Through regular salary deductions, employees can invest up to 5% of their base salary in Statoil shares. In addition, the company contributes 20% of the total share investment made by employees in Norway, up to a maximum of NOK 1,500 per year (approximately USD 170). This company contribution is a tax-free employee benefit under current Norwegian tax legislation. After a lock-in period of two calendar years, one extra share will be awarded for each share purchased. Under current Norwegian tax legislation, the share award is a taxable employee benefit, with a value equal to the value of the shares and taxed at the time of the award.

The board of directors is authorized to acquire Statoil shares in the market on behalf of the company. The authorization is valid until the next annual general meeting, but not beyond 30 June 2017. This authorisation replaces the previous authorisation to acquire Statoil's own shares for implementation of the share savings plan granted by the annual general meeting 19 May 2015. It is Statoil’s intention to renew this authorisation at the annual general meeting. Statoil intends to use share buybacks more actively going forward, based on balance sheet strength considerations.

Period in which shares were repurchased		Number of shares repurchased	Average price per share in NOK	Total number of shares purchased as part of programme	Maximum number of shares that may yet be purchased under the programme authorisation

Jan-16		878,834	102.6997	5,821,999	8,178,001
Feb-16		745,858	117.5826	6,567,857	7,432,143
Mar-16		700,095	127.9825	7,267,952	6,732,048
Apr-16		682,975	130.5009	7,950,927	6,049,073
May-16		657,216	135.2827	8,608,143	5,391,857
Jun-16		665,179	133.1370	665,179	13,334,821
Jul-16		589,151	149.4623	1,254,330	12,745,670
Aug-16		653,493	134.1070	1,907,823	12,092,177
Sep-16		703,884	124.1965	2,611,707	11,388,293
Oct-16		627,062	138.7885	3,238,769	10,761,231
Nov-16		631,197	137.8332	3,869,966	10,130,034
Dec-16		567,259	153.3690	4,437,225	9,562,775
Jan-17		520,716	162,6375	4,957,941	9,042,059
Feb-17		577,674	147.8341	5,535,615	8,464,385

TOTAL		9,200,593 ¹⁾	144.3980 ²⁾

1)	All shares repurchased have been purchased in the open market and pursuant to the authorisation mentioned above.
2)	Weighted average price per share.

Statoil, Annual Report on Form 20-F 2016 207

Statoil ADR programme fees

Fees and charges payable by a holder of ADSs.

As depositary from 31 January 2013, Deutsche Bank Trust Company Americas collects its fees for the delivery and surrender of ADSs directly from investors depositing shares or surrendering ADSs for the purpose of withdrawal, or from intermediaries acting for them. The depositary collects fees from investors by deducting the fees from the amounts distributed or by selling a portion of distributable property to pay the fees. The depositary may refuse to provide fee-attracting services until its fees for those services are paid.

The charges of the depositary payable by investors are as follows:

Persons depositing or withdrawing shares must pay:	For:

USD 5.00 (or less) per 100 ADSs (or portion of 100 ADSs)	• Issuance of ADSs, including issuances resulting from a distribution of shares or rights or other property
	• Cancellation of ADSs for the purpose of withdrawal, including if the deposit agreement terminates

USD 0.02(or less) per ADS, subject to the company's consent	• Any cash distribution to ADS registered holders

USD 0.05 (or less) per ADS, subject to the company's consent	• For the operation and maintenance costs in administering the ADR programme

A fee equivalent to the fee that would be payable if securities distributed to you had been shares and the shares had been deposited for issuance of ADSs	• Distribution of securities distributed to holders of deposited securities which are distributed by the Depositary to ADS registered holders

Registration or transfer fees	• Transfer and registration of shares on our share register to or from the name of the Depositary or its agent when you deposit or withdraw shares

Expenses of the Depositary	• Cable, telex and facsimile transmissions (as provided in the deposit agreement)
	• Converting foreign currency to USD

Taxes and other governmental charges the Depositary or the custodian have to pay on any ADS or share underlying an ADS, for example, stock transfer taxes, stamp duty or withholding taxes	• As necessary

Any charges incurred by the Depositary or its agents for servicing the deposited securities	• As necessary

Reimbursements and payments made and fee waivers granted by the depositary

The depositary has agreed to reimburse certain company expenses related to the company's ADR programme and incurred by the company in connection with the programme. In the year ended 31 December 2016, the depositary reimbursed approximately USD 1.29 million to the company in relation to certain expenses including investor relations expenses, expenses related to the maintenance of the ADR programme, legal counsel fees, printing and ADR certificates.

The depositary has also agreed to waive fees for costs associated with the administration of the ADR programme, and it has paid certain expenses directly to third parties on behalf of the company. The expenses paid to third parties include expenses relating to reporting services, access charges to its online platform, re-registration costs borne by the custodian and costs in relation to printing and mailing AGM materials. For the year ended 31 December 2016, the depositary paid expenses of approximately USD 214,814 directly to third parties.

208 Statoil, Annual Report on Form 20-F 2016

TAXATION

This section describes the material Norwegian tax consequences that apply to shareholders resident in Norway and to non-resident shareholders in connection with the acquisition, ownership and disposal of shares and American Depositary Shares (ADS). The term “shareholder” refers to both holders of shares and holders of ADSs, unless otherwise explicitly stated.

Norwegian tax matters

The outline does not provide a complete description of all tax regulations that might be relevant (i.e. for investors to whom special regulations may be applicable), and is based on current law and practice. Shareholders should consult their professional tax adviser for advice about individual tax consequences.

Taxation of dividends

Corporate shareholders (i.e. limited liability companies and similar entities) residing in Norway for tax purposes are generally subject to tax in Norway on dividends received from Norwegian companies. The basis for taxation is 3% of the dividends received, which is subject to the standard income tax rate. The standard income tax rate has been reduced from 25% in 2016 to 24% in 2017.

Individual shareholders resident in Norway for tax purposes are subject to the standard income tax rate (reduced from 25% in 2016 to 24% in 2017) in Norway for dividend income exceeding a basic tax free allowance. However, in 2017 dividend income exceeding the basic tax free allowance is grossed up with a factor of 1.24 before included in the ordinary taxable income, resulting in an effective tax rate of 29.76% (24% x 1.24). The tax free allowance is computed for each individual share or ADS and corresponds as a rule to the cost price of that share or ADS multiplied by an annual risk-free interest rate. Any part of the calculated allowance for one year that exceeds the dividend distributed for the share or ADS ("unused allowance") may be carried forward and set off against future dividends received for (or gains upon the realisation of, see below) the same share or ADS. Any unused allowance will also be added to the basis for computation of the allowance for the same share or ADS the following year.

Non-resident shareholders are as a rule subject to withholding tax at a rate of 25% on dividends distributed by Norwegian companies. It is the responsibility of the distributing company to deduct the withholding tax when dividends are paid to non-resident shareholders. This withholding tax does not apply to corporate shareholders in the EEA area that document that they are genuinely established and carry on genuine economic business activity within the EEA area, provided that Norway is entitled to receive information from the state of residence pursuant to a tax treaty or other international treaty. If no such treaty exists with the state of residence, the shareholder may instead present confirmation issued by the tax authorities of the state of residence verifying the documentation. Individual shareholders resident for tax purposes in the EEA area may apply to the Norwegian tax authorities for a refund if the tax withheld by the distributing company exceeds the tax that would have been levied on individual shareholders resident in Norway.

The withholding rate of 25% is often reduced in tax treaties between Norway and other countries. The reduced withholding rate will generally only apply to dividends paid on shares held by shareholders who are able to properly demonstrate that they are the beneficial owner and entitled to the benefits of the tax treaty.

For holders of shares and ADSs deposited with Deutsche Bank Trust Company Americas (Deutsche Bank), documentation establishing that the holder is eligible for the benefits under the tax treaty with Norway, may be provided to Deutsche Bank. Deutsche Bank has been granted permission by the Norwegian tax authorities to receive dividends from us for redistribution to a beneficial owner of shares and ADSs at the applicable treaty withholding rate.

Dividends paid to shareholders (either directly or through a depositary) who have not provided the relevant documentation to the relevant party that they are eligible for the reduced rate, will be subject to withholding tax of 25%. The beneficial owners will in this case have to apply to the Central Office - Foreign Tax Affairs for a refund of the excess amount of tax withheld.

Corporate shareholders that carry on business activities in Norway, and whose shares or ADSs are effectively connected with such activities are not subject to withholding tax. For such shareholders, 3% of the received dividends are subject to the standard income tax rate (reduced from 25% in 2016 to 24% in 2017).

Taxation on the realisation of shares and ADSs

Corporate shareholders resident in Norway for tax purposes are not subject to tax in Norway on gains derived from the sale, redemption or other disposal of shares or ADSs in Norwegian companies. Capital losses are not deductible.

Individual shareholders residing in Norway for tax purposes are subject to tax in Norway on the sale, redemption or other disposal of shares or ADSs. Gains or losses in connection with such realisation are included in the individual's ordinary taxable income in the year of disposal, which is subject to the standard income tax rate, being reduced from 25% in 2016 to 24% in 2017. However, in 2017 the taxable gain or deductible loss is grossed up with a factor of 1.24 before included in the ordinary taxable income, resulting in an effective tax rate of 29.76% (24% x 1.24).

The taxable gain or deductible loss (before gross up) is calculated as the sales price adjusted for transaction expenses minus the taxable basis. A shareholder's tax basis is normally equal to the acquisition cost of the shares or ADSs. Any unused allowance pertaining to a share may be

Statoil, Annual Report on Form 20-F 2016 209

deducted from a taxable gain on the same share or ADS, but may not lead to or increase a deductible loss. Furthermore, any unused allowance may not be set off against gains from the realisation of the other shares or ADSs.

If the shareholder disposes of shares or ADSs acquired at different times, the shares or ADSs that were first acquired will be deemed to be first sold (the "FIFO" principle) when calculating gain or loss for tax purposes.

From 2017, individual shareholders may hold listed shares in companies resident within EEA through a stock savings account. If the conditions for the stock savings account are met, taxable gain or loss on shares owned through the stock savings account will be payable when deposits are withdrawn from the account whereas loss on shares will be deductible when the account is terminated. Dividends are not comprised by the stock savings account scheme and will thus be taxed pursuant to the ordinary rules described above.

A corporate shareholder or an individual shareholder who ceases to be tax resident in Norway due to domestic law or tax treaty provisions may, in certain circumstances, become subject to Norwegian exit taxation on capital gains related to shares or ADSs.

Shareholders not residing in Norway are generally not subject to tax in Norway on capital gains, and losses are not deductible on the sale, redemption or other disposal of shares or ADSs in Norwegian companies, unless the shareholder carries on business activities in Norway and such shares or ADSs are or have been effectively connected with such activities.

Wealth tax

The shares or ADSs are included in the basis for the computation of wealth tax imposed on individuals resident in Norway for tax purposes. Norwegian limited companies and certain similar entities are not subject to wealth tax. The current marginal wealth tax rate is 0.85% of the value assessed. The assessment value of listed shares (including ADSs) is 90% of the listed value of such shares or ADSs on 1 January in the assessment year.

Non-resident shareholders are not subject to wealth tax in Norway for shares and ADSs in Norwegian limited companies unless the shareholder is an individual and the shareholding is effectively connected with the individual's business activities in Norway.

Inheritance tax and gift tax

No inheritance or gift tax is imposed in Norway.

Transfer tax

No transfer tax is imposed in Norway in connection with the sale or purchase of shares or ADSs.

United States tax matters

This section describes the material United States federal income tax consequences for US holders (as defined below) of owning shares or ADSs. It only applies to you if you hold your shares or ADSs as capital assets for tax purposes and are not a member of a special class of holders subject to special rules, including dealers in securities, insurance companies, partnerships, persons liable for the alternative minimum tax, persons that actually or constructively own 10% of the voting stock of Statoil, persons that hold shares or ADSs as part of a straddle or a hedging or conversion transaction, or persons whose functional currency is not USD.

This section is based on the Internal Revenue Code of 1986, as amended, its legislative history, existing and proposed regulations, published rulings and court decisions, and the Convention between the United States of America and the Kingdom of Norway for the Avoidance of Double Taxation and the Prevention of Fiscal Evasion with Respect to Taxes on Income and Property (the ''Treaty''). These laws are subject to change, possibly on a retroactive basis. In addition, this section is based in part upon the representations of the depositary and the assumption that each obligation in the deposit agreement and any related agreement will be performed in accordance with its terms. For United States federal income tax purposes, if you hold ADRs evidencing ADSs, you will generally be treated as the owner of the ordinary shares represented by those ADRs. Exchanges of shares for ADRs and ADRs for shares will not generally be subject to United States federal income tax.

A ''US holder'' is a beneficial owner of shares or ADSs that is: (i) a citizen or resident of the United States; (ii) a United States domestic corporation; (iii) an estate whose income is subject to United States federal income tax regardless of its source; or (iv) a trust if a United States court can exercise primary supervision over the trust's administration and one or more United States persons are authorised to control all substantial decisions of the trust.

You should consult your own tax adviser regarding the United States federal, state and local and Norwegian and other tax consequences of owning and disposing of shares and ADSs in your particular circumstances.

Taxation of dividends

The gross amount of any dividend (including any Norwegian tax withheld from the dividend payment) paid by Statoil out of its current or accumulated earnings and profits (as determined for United States federal income tax purposes) is taxable for you when you, in the case of shares, or the depositary, in the case of ADSs, receive the dividend, actually or constructively. If you are a non-corporate US holder, dividends paid to you will be eligible to be taxed at the preferential rates applicable to long-term capital gains as long as, in the year that you receive the dividend, the shares or ADSs are readily tradable on an established securities market in the United States or Statoil is eligible for benefits under the Treaty. To qualify for the preferential rates, you must hold the shares or ADSs for more than 60 days during the 121-day period beginning 60 days before

210 Statoil, Annual Report on Form 20-F 2016

the ex-dividend date and meet certain other requirements. The dividend will not be eligible for the dividends-received deduction generally allowed to United States corporations in respect of dividends received from other United States corporations.

The amount of the dividend distribution that you must include in your income as a US holder will be the value in USD of the payments made in NOK determined at the spot NOK/USD rate on the date the dividend distribution is includible in your income, regardless of whether or not the payment is in fact converted into USD. Distributions in excess of current and accumulated earnings and profits, as determined for United States federal income tax purposes, will be treated as a non-taxable return of capital to the extent of your tax basis in the shares or ADSs and, to the extent in excess of your tax basis, will be treated as capital gain.

Subject to certain limitations, the 15% Norwegian tax withheld in accordance with the Treaty and paid to Norway will be creditable or deductible against your United States federal income tax liability, unless a refund of the tax withheld is available to you under Norwegian law. Special rules apply when determining the foreign tax credit limitation with respect to dividends that are subject to the preferential rates. Dividends will be income from sources outside the United States and will generally, depending on your circumstances, be either ''passive'' or ''general'' income for purposes of computing the foreign tax credit allowable to you. Any gain or loss resulting from currency exchange rate fluctuations during the period from the date you include the dividend payment in income until the date you convert the payment into USD will generally be treated as US-source ordinary income or loss and will not be eligible for the special tax rate.

Taxation of capital gains

If you sell or otherwise dispose of your shares or ADSs, you will generally recognise a capital gain or loss for United States federal income tax purposes equal to the difference between the value in USD of the amount that you realise and your tax basis, determined in USD, in your shares or ADSs. A capital gain of a non-corporate US holder is generally taxed at preferential rates if the property is held for more than one year. The gain or loss will generally be income or loss from sources within the United States for foreign tax credit limitation purposes. If you receive any foreign currency on the sale of shares or ADSs, you may recognise ordinary income or loss from sources within the United States as a result of currency fluctuations between the date of the sale of the shares or ADSs and the date the sales proceeds are converted into USD. You should consult your own tax adviser regarding how to account for payments made or received in a currency other than USD.

PFIC rules

We believe that the shares and ADSs should not be treated as stock of a PFIC for United States federal income tax purposes, but this conclusion is a factual determination that is made annually and thus may be subject to change. If we were to be treated as a PFIC, a gain realised on the sale or other disposition of the shares or ADSs would in general not be treated as a capital gain. Instead, unless you elect to be taxed annually on a mark-to-market basis with respect to the shares or ADSs, you would be treated as if you had realised such gain and certain "excess distributions" ratably over your holding period for the shares or ADSs. Amounts allocated to the year in which the gain is realised or the “excess distribution” is received or to a taxable year before we were classified as a PFIC would be subject to tax at ordinary income tax rates, and amounts allocated to all other years would be taxed at the highest tax rate in effect for each such year to which the gain or distribution was allocated, together with an interest charge in respect of the tax attributable to each such year. With certain exceptions, your shares or ADSs will be treated as stock in a PFIC if we were a PFIC at any time during the period you held the shares or ADSs. Dividends that you receive from us will not be eligible for the preferential tax rates if we are treated as a PFIC with respect to you, either in the taxable year of the distribution or the preceding taxable year, but will instead be taxable at rates applicable to ordinary income.

Foreign Account Tax Compliance Withholding

A 30% withholding tax will be imposed on certain payments to certain non-US financial institutions that fail to comply with information reporting requirements or certification requirements in respect of their direct and indirect United States shareholders and/or United States accountholders. To avoid becoming subject to the 30% withholding tax on payments to them, we and other non-US financial institutions may be required to report information to the IRS regarding the holders of shares or ADSs and to withhold on a portion of payments under the shares or ADSs to certain holders that fail to comply with the relevant information reporting requirements (or hold shares or ADSs directly or indirectly through certain non-compliant intermediaries). However, such withholding will not apply to payments made before January 1, 2019. The rules for the implementation of this legislation have not yet been fully finalised, so it is impossible to determine at this time what impact, if any, this legislation will have on holders of the shares and ADSs.

Statoil, Annual Report on Form 20-F 2016 211

EXCHANGE RATES

The table below shows the high, low, average and end-of-period exchange rates for the Norwegian krone for USD 1.00 as announced by Norges Bank (Norway's central bank).

The average is computed using the quarterly average exchange rates announced by Norges Bank during the period indicated.

For the year ended 31 December	Low	High	Average	End of Period

2012	5.5349	6.1471	5.8172	5.5664
2013	5.4438	6.2154	5.8753	6.0837
2014	5.8611	7.6111	6.3011	7.4332
2015	7.3593	8.8090	8.0637	8.8090
2016	7.9766	8.9578	8.4014	8.6200

	Low	High

2016
September	8.0517	8.3483
October	7.9766	8.2810
November	8.1780	8.6138
December	8.3662	8.7277

2017
January	8.2641	8.6676
February	8.1953	8.3868
March (up to and including 8 March 2017)	8.4134	8.4798

On 8 March 2017, the exchange rate announced by the Norges Bank for the Norwegian krone was USD 1.00 = NOK 8.4798

Fluctuations in the exchange rate between the NOK and USD will affect the amounts in USD received by holders of American Depositary Shares (ADSs) on the conversion of dividends, if any, paid in Norwegian kroner on the ordinary shares, and they may affect the USD price of the ADSs on the New York Stock Exchange.

212 Statoil, Annual Report on Form 20-F 2016

MAJOR SHAREHOLDERS

The Norwegian State is the largest shareholder in Statoil, with a direct ownership interest of 67%. Its ownership interest is managed by the Norwegian Ministry of Petroleum and Energy.

Pursuant to the exchange ratio agreed in connection with the merger with Hydro's oil and gas activities, the State's ownership interest in the merged company was 62.5%, or 1,992,959,739 shares, on 1 October 2007. In accordance with the Norwegian parliament's decision of 2001 concerning a minimum state shareholding in Statoil of two-thirds, the Government built up the State's ownership interest in Statoil by buying shares in the market during the period from June 2008 to March 2009. In March 2009, the Government announced that the State's direct ownership interest had reached 67% and the Government's direct purchase of Statoil shares was completed.

As of 31 December 2016, the Norwegian State had a 67% direct ownership interest in Statoil and a 3.22% indirect interest through the National Insurance Fund (Folketrygdfondet), totaling 70.22%. Also, the Norwegian State has entered into an agreement where it commits for each quarterly dividend where a scrip option is offered to receive newly issued shares for a fraction of its shareholdings equal to the average participation among the other shareholders. This to ensure that the States ownership share is not impacted by the scrip programme.

Statoil has one class of shares, and each share confers one vote at the general meeting. The Norwegian State does not have any voting rights that differ from the rights of other ordinary shareholders. Pursuant to the Norwegian Public Limited Liability Companies Act, a majority of at least two-thirds of the votes cast as well as of the votes represented at a general meeting is required to amend our articles of association. As long as the Norwegian State owns more than one-third of our shares, it will be able to prevent any amendments to our articles of association. Since the Norwegian State, acting through the Norwegian Minister of Petroleum and Energy, has in excess of two-thirds of the shares in the company, it has sole power to amend our articles of association. In addition, as majority shareholder, the Norwegian State has the power to control any decision at general meetings of our shareholders that requires a majority vote, including the election of the majority of the corporate assembly, which has the power to elect our board of directors and approve the dividend proposed by the board of directors.

The Norwegian State endorses the principles set out in "The Norwegian Code of Practice for Corporate Governance", and it has stated that it expects companies in which the State has ownership interests to adhere to the code. The principle of ensuring equal treatment of different groups of shareholders is a key element in the State's own guidelines. In companies in which the State is a shareholder together with others, the State wishes to exercise the same rights and obligations as any other shareholder and not act in a manner that has a detrimental effect on the rights or financial interests of other shareholders. In addition to the principle of equal treatment of shareholders, emphasis is also placed on transparency in relation to the State's ownership and on the general meeting being the correct arena for owner decisions and formal

Statoil, Annual Report on Form 20-F 2016 213

resolutions.

214 Statoil, Annual Report on Form 20-F 2016

Shareholders at December 2016		Number of Shares	Ownership in %

1	Government of Norway	2,174,183,105	67.00%
2	Folketrygdfondet	104,403,441	3.22%
3	BlackRock Institutional Trust Company, N.A.	29,242,733	0.90%
4	Lazard Asset Management, L.L.C.	28,711,525	0.88%
5	SAFE Investment Company Limited	24,698,519	0.76%
6	INVESCO Asset Management Limited	22,281,500	0.69%
7	Fidelity Management & Research Company	21,301,248	0.68%
8	The Vanguard Group, Inc.	21,120,974	0.65%
9	State Street Global Advisors (US)	18,293,972	0.61%
10	Schroder Investment Management Ltd. (SIM)	19,493,851	0.60%
11	Storebrand Kapitalforvaltning AS	17,611,950	0.54%
12	KLP Forsikring	16,761,633	0.52%
13	DNB Asset Management AS	16,032,525	0.49%
14	UBS Asset Management (UK) Ltd.	12,890,335	0.40%
15	Fidelity Worldwide Investment (UK) Ltd.	11,731,543	0.36%
16	TIAA Global Asset Management	11,413,046	0.35%
17	Allianz Global Investors GmbH	11,397,417	0.35%
18	Epoch Investment Partners, Inc.	11,194,404	0.35%
19	Legal & General Investment Management Ltd.	10,152,188	0.31%
20	AXA Investment Managers UK Ltd.	9,304,532	0.29%

Source: Data collected by third party, authorized by Statoil, December 2016.

EXCHANGE CONTROLS AND LIMITATIONS

Under Norwegian foreign exchange controls currently in effect, transfers of capital to and from Norway are not subject to prior government approval. An exception applies to the physical transfer of payments in currency exceeding certain thresholds, which must be declared to the Norwegian custom authorities. This means that non-Norwegian resident shareholders may receive dividend payments without Norwegian exchange control consent as long as the payment is made through a licensed bank or other licensed payment institution.

There are no restrictions affecting the rights of non-Norwegian residents or foreign owners to hold or vote for our shares.

Statoil, Annual Report on Form 20-F 2016 215

5.2 ACCOUNTING STANDARDS (IFRS) AND non-GAAP MEASURES

Since 2007, Statoil has been preparing the Consolidated financial statements in accordance with International Financial Reporting Standards (IFRS) as adopted by the EU and as issued by the International Accounting Standards Board. The IFRS standards have been applied consistently to all periods presented in the Consolidated financial statements. See note 2 Significant accounting policies to the Consolidated financial statements for a discussion of key accounting estimates and judgements.

Non-GAAP MEASURES

Statoil is subject to SEC regulations regarding the use of "non-GAAP financial measures" in public disclosures. Non-GAAP financial measures are defined as numerical measures that either exclude or include amounts that are not excluded or included in the comparable measures calculated and presented in accordance with generally accepted accounting principles, which in Statoil’s case refers to IFRS. The following financial measures may be considered non-GAAP financial measures:

· Return on average capital employed (ROACE)

· Net debt to capital employed ratio before adjustments

· Net debt to capital employed ratio adjusted

· Adjusted earnings after tax

· Organic capital expenditures

For information regarding Organic capital expenditures, see Investments in section 2.9 Liquidity and capital resources.

Return on average capital employed (ROACE)

This measure provides useful information for both the group and investors about performance during the period under evaluation. Statoil uses ROACE to measure the return on capital employed, regardless of whether the financing is through equity or debt. The use of ROACE should not be viewed as an alternative to income before financial items, income taxes and minority interest, or to net income, which are measures calculated in accordance with GAAP or ratios based on these figures. Impacted by impairments, ROACE was negative 4.7% in 2016 compared to negative 8.9% in 2015 and 3.4% in 2014. The change from 2015 is mainly due to an increase in net income adjusted for financial items.

Calculation of numerator and denominator used in ROACE calculation		For the year ended 31 December
(in USD million, except percentages)		2016	2015	2014	16-15 change	15-14 change

Net income for the year		(2,902)	(5,169)	3,887
- Net financial items		(258)	(1,311)	20
- Tax on financial items		(75)	1,259	1,466
+ Accretion expense net after tax		21	(124)	(175)

Net income adjusted for financial Items after tax (A1)		(2,548)	(5,241)	2,226	51%	N/A

Capital employed before adjustments to net interest-bearing debt: ¹⁾
Year End 2016		53,471
Year End 2015		54,159	54,159
Year End 2014			63,311	63,311
Year End 2013				68,092

Sum of capital employed for two years (B1)		107,630	117,470	131,403

Calculated average capital employed:
Average capital employed before adjustments to net interest-bearing debt (B1/2)		53,815	58,735	65,702	(8%)	(11%)

Calculated ROACE:
Return on average capital employed (A1/(B1/2))		(4.7%)	(8.9%)	3.4%	47%	N/A

1)	Capital employed before adjustments for each year is reconciled in the table in section 5.2 Net debt to capital employed ratio.

216 Statoil, Annual Report on Form 20-F 2016

Net debt to capital employed ratio

In the Company's view, the calculated net debt to capital employed ratio gives a more complete picture of the Group's current debt situation than gross interest-bearing financial liabilities.

The calculation uses balance sheet items relating to gross interest bearing financial liabilities and adjusts for cash, cash equivalents and current financial investments. Certain adjustments are made, such as collateral deposits classified as cash and cash equivalents in the Consolidated balance sheet but considered non cash in the non-GAAP calculations. The financial investments held in Statoil Forsikring AS are excluded in the non-GAAP calculations as they are deemed restricted. These two adjustment are increasing the net debt and give a stricter definition of the net debt to capital employed ratio than the IFRS based definition. Similarly, certain net interest-bearing debts incurred from activities pursuant to the Owners Instruction from the Norwegian State are set off against receivables on the Norwegian State's direct financial interest (SDFI).

The net interest-bearing debt adjusted for these items is included in the average capital employed. The table below reconciles the net interest-bearing liabilities adjusted, capital employed and net debt to capital employed adjusted ratio with the most directly comparable financial measure or measures calculated in accordance with IFRS.

		For the year ended 31 December
Calculation of capital employed and net debt to capital employed ratio		2016	2015	2014
(in USD million, except percentages)

Shareholders' equity		35,072	40,271	51,225
Non-controlling interests (Minority interest)		27	36	57

Total equity (A)		35,099	40,307	51,282

Current bonds, bank loans, commercial papers and collateral liabilities		3,674	2,326	3,561
Bonds, bank loans and finance lease liabilities		27,999	29,965	27,593

Gross interest-bearing financial liabilities (B)		31,673	32,291	31,154

Cash and cash equivalents		5,090	8,623	11,182
Current financial investments		8,211	9,817	7,968

Cash and cash equivalents and current financial investments (C)		13,301	18,440	19,150

Net interest-bearing liabilities before adjustments (B1) (B-C)		18,372	13,852	12,004

Other interest-bearing elements¹⁾		1,216	1,111	1,081
Marketing instruction adjustment²⁾		(199)	(214)	(212)
Adjustment for project loan³⁾		0	0	(18)

Net interest-bearing liabilities adjusted (B2)		19,389	14,748	12,855

Calculation of capital employed:
Capital employed before adjustments to net interest-bearing liabilities (A+B1)		53,471	54,159	63,286
Capital employed adjusted (A+B2)		54,488	55,055	64,137

Calculated net debt to capital employed:
Net debt to capital employed before adjustments (B1/(A+B1)		34.4%	25.6%	19.0%
Net debt to capital employed adjusted (B2/(A+B2)		35.6%	26.8%	20.0%

1)	Other interest-bearing elements are cash and cash equivalents adjustments regarding collateral deposits classified as cash and cash equivalents in the Consolidated balance sheet but considered as non-cash in the non-GAAP calculations as well as financial investments in Statoil Forsikring AS classified as current financial investments.
2)	Marketing instruction adjustment is an adjustment to gross interest-bearing financial debt due to the SDFI part of the financial lease in the Snøhvit vessels that are included in Statoil's Consolidated balance sheet.
3)	Adjustment for project loan is adjustment to gross interest-bearing debt due to the BTC project loan structure.

Statoil, Annual Report on Form 20-F 2016 217

Adjusted earnings after tax

Adjusted earnings are based on net operating income and adjusts for certain items affecting the income for the period in order to separate out effects that management considers may not be well correlated to Statoil's underlying operational performance in the individual reporting period. Management considers adjusted earnings to be a supplemental measure to Statoil's IFRS measures that provides an indication of Statoil's underlying operational performance in the period and facilitates a better understanding of operational trends between the periods, and this metric is used in determining variable remuneration and awards of LTI grants to members of the corporate executive committee. Adjusted earnings adjusts for the following items:

· Certain gas contracts are, due to pricing or delivery conditions, deemed to contain embedded derivatives, required to be carried at fair value. Certain transactions related to historical divestments include contingent consideration, carried at fair value. The accounting impacts of changes in fair value of the aforementioned are excluded from adjusted earnings. In addition, adjustments are also made for changes in the unrealised fair value of derivatives related to some natural gas trading contracts. Due to the nature of these gas sales contracts, these are classified as financial derivatives to be measured at fair value at the balance sheet date. Unrealised gains and losses on these contracts reflect the value of the difference between current market gas prices and the actual prices to be realised under the gas sales contracts. Only realised gains and losses on these contracts are reflected in adjusted earnings. This presentation best reflects the underlying performance of the business as it replaces the effect of temporary timing differences associated with the re-measurements of the derivatives to fair value at the balance sheet date with actual realised gains and losses for the period

· Periodisation of inventory hedging effect: Commercial storage is hedged in the paper market. Commercial storage is accounted for by using the lower of cost and market price. If market prices increase above cost price, there will be a loss in the IFRS income statement since the derivatives always reflect changes in the market price. An adjustment is made to reflect the unrealised market value of the commercial storage. As a result, loss on derivatives is matched by a similar adjustment for the exposure being managed. If market prices decrease below cost price, the write-down and the derivative effect in the IFRS income statement will offset each other and no adjustment is made

· Over/underlift is accounted for using the sales method and therefore revenues are reflected in the period the product is sold rather than in the period it is produced. The over/underlift position depends on a number of factors related to our lifting programme and the way it corresponds to our entitlement share of production. The effect on income for the period is therefore adjusted, to show estimated revenues and associated costs based upon the production for the period which management believes reflects operational performance and increase comparability with peers

· Statoil holds operational storage which is not hedged in the paper market due to inventory strategies. Cost of goods sold is measured based on the FIFO (first-in, first-out) method, and includes realised gains or losses that arise due to changes in market prices. These gains or losses will fluctuate from one period to another and are not considered part of the underlying operations for the period

· Impairment and reversal of impairment are excluded from adjusted earnings since they affect the economics of an asset for the lifetime of that asset; not only the period in which it is impaired or the impairment is reversed. Impairment and reversal of impairment can impact both the exploration expenses and the depreciation, amortisation and impairment line items

· Gain or loss from sales is eliminated from the measure since the gain or loss does not give an indication of future performance or periodic performance; such a gain or loss is related to the cumulative value creation from the time the asset is acquired until it is sold

· Internal unrealised profit on inventories: Volumes derived from equity oil inventory will vary depending on several factors and inventory strategies, i.e. level of crude oil in inventory, equity oil used in the refining process and level of in-transit cargoes. Internal profit related to volumes sold between entities in the group, and still in inventory at period end, is eliminated according to IFRS (write down to production cost). The proportion of realised versus unrealised gain will fluctuate from one period to another due to inventory strategies and accordingly impact net operating income. This impact is not assessed to be a part of the underlying operational performance, and elimination of internal profit related to equity volumes is excluded in adjusted earnings

· Other items of income and expense are adjusted when the impacts on income in the period are not reflective of Statoil's underlying operational performance in the reporting period. Such items may be unusual or infrequent transactions but they may also include transactions that are significant which would not necessarily qualify as either unusual or infrequent. Other items can include transactions such as provisions related to reorganisation, early retirement, etc

The measure adjusted earnings after tax excludes net financial items and the associated tax effects on net financial items. It is based on adjusted earnings less the tax effects on all elements included in adjusted earnings (or calculated tax on operating income and on each of the adjusting items using an estimated marginal tax rate). In addition, tax effect related to tax exposure items not related to the individual reporting period is excluded from adjusted earnings after tax. Management considers adjusted earnings after tax, which reflects a normalised tax charge associated with its operational performance excluding the impact of financing, to be a supplemental measure to Statoil's net income. Certain net USD denominated financial positions are held by group companies that have a USD functional currency that is different from the currency in which the taxable income is measured. As currency exchange rates change between periods, the basis for measuring net financial items for IFRS will change disproportionally with taxable income which includes exchange gains and losses from translating the net USD denominated financial positions into the currency of the applicable tax return. Therefore, the effective tax rate may be significantly higher or lower than the statutory tax rate for any given period.

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

218 Statoil, Annual Report on Form 20-F 2016

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

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

Calculation of adjusted earnings after tax	For the year ended 31 December
(in USD million)	2016	2015

Net operating income	80	1,366

Total revenues and other income	1,020	(924)
Changes in fair value of derivatives	738	356
Periodisation of inventory hedging effect	360	(39)
Impairment from associated companies	25	153
Over-/underlift	232	(96)
Other adjustments	-	(53)
Gain/loss on sale of assets	(333)	(1,750)
Provisions	-	639
Eliminations	-	(133)

Purchases [net of inventory variation]	(9)	262
Operational storage effects	(228)	262
Eliminations	219	-

Operating and administrative expenses	617	843
Over-/underlift	(59)	236
Other adjustments	168	322
Gain/loss on sale of assets	86	-
Provisions	422	285

Depreciation, amortisation and impairment	1,300	5,990
Impairment	2,946	7,710
Reversal of impairment	(1,646)	(1,649)
Other adjustments	-	(72)

Exploration expenses	1,061	2,096
Impairment	1,141	2,265
Reversal of impairment	(149)	(312)
Other adjustments	41	24
Provisions	28	119

Sum of adjustments to net operating income	3,990	8,267

Adjusted earnings	4,070	9,633

Tax on adjusted earnings	(4,277)	(7,168)

Adjusted earnings after tax	(208)	2,465

Statoil, Annual Report on Form 20-F 2016 219

5.3 LEGAL PROCEEDINGS

Statoil is involved in a number of proceedings globally concerning matters arising in connection with the conduct of its business. No further update is provided on previously reported legal or arbitration proceedings which Statoil does not believe will, individually or in the aggregate, have a significant effect on Statoil’s financial position, profitability, results of operations or liquidity. See also note 9 Income taxes and note 23 Other commitments, contingent liabilities and contingent assets in Consolidated financial statements.

220 Statoil, Annual Report on Form 20-F 2016

5.6 Terms and ABBREVIATIONS

Organisational abbreviations

· ADS – American Depositary Share

· ADR – American Depositary Receipt

· ACG - Azeri-Chirag-GunashliX

· ACQ - Annual contract quantity

· AFP - Agreement-based early retirement plan

· AGM - Annual general meeting

· ÅTS - Åsgard transport system

· APA - Awards in pre-defined areas

· ARO - Asset retirement obligation

· BTC - Baku-Tbilisi-Ceyhan pipeline

· CCS - Carbon capture and storage

· CH4 - Methane

· CO2 - Carbon dioxide

· DKK - Danish Krone

· DPI - Development and Production International

· DPN - Development and Production Norway

· DPUSA - Development and Production USA

· DST - Drill Stem Test

· D&W - Drilling and Well

· EEA - European Economic Area

· EFTA - European Free Trade Association

· EMTN - Euro medium-term note

· EU - European Union

· EU ETS - EU Emissions Trading System

· EUR - Euro

· EXP - Exploration

· FPSO - Floating production, storage and offload vessel

· GAAP - Generally Accepted Accounting Principals

· GBP - British Pound

· GBS - Gravity-based structure

· GDP - Gross domestic product

· GHG - Greenhouse gas

· GSB - Global Strategy and Business Development

· HSE - Health, safety and environment

· HTHP - High-temperature/high pressure

· IASB - International Accounting Standards Board

· ICE - Intercontinental Exchange

· IEA - International Energy Agency

· IFRS - International Financial Reporting Standards

· IOR - Improved oil recovery

· LNG - Liquefied natural gas

· LPG - Liquefied petroleum gas

· MMP - Marketing, Midstream and Processing

· MPE - Norwegian Ministry of Petroleum and Energy

· MW - Mega watt

· NCS - Norwegian continental shelf

· NES – New Energy Solutions

· NIOC - National Iranian Oil Company

· NOK - Norwegian kroner

· NOx- Nitrogen oxide

· OECD - Organisation of Economic Co-Operation and Development

· OML - Oil mining lease

· OPEC - Organization of the Petroleum Exporting Countries

· OTC - Over-the-counter

· OTS - Oil trading and supply department

· P5+1 – UN Security Council`s five permanent members

· PDO - Plan for development and operation

· PDQ – Production drilling quarters

· PIO - Plan for installation and operation

· PRD - Project Development organisation

· PSA - Production sharing agreement

· PSC – Production sharing contract

Statoil, Annual Report on Form 20-F 2016 221

· PSR - Procurement and Supplier Relations

· RDI - Research, Development and Innovation

· R&D - Research and development

· ROACE - Return on average capital employed

· RRR - Reserve replacement ratio

· SAGD - Steam-assisted gravity drainage

· SCP - South Caucasus Pipeline System

· SDFI - Norwegian State's Direct Financial Interest

· SEC - Securities and Exchange Commission

· SEK - Swedish Krona

· SFR - Statoil Fuel & Retail

· SIF - Serious Incident Frequency

· TAP - Trans Adriatic Pipeline AG

· TEX - Technology Excellence

· TLP - Tension leg platform

· TPD - Technology, projects and drilling

· TRIF - Total recordable injuries per million hours worked

· TSP - Technical service provider

· UKCS - UK continental shelf

· USD - United States dollar

· WTG - Wind Turbine Generators

Metric abbreviations etc.

· bbl - barrel

· mbbl - thousand barrels

· mmbbl - million barrels

· boe - barrels of oil equivalent

· mboe - thousand barrels of oil equivalent

· mmboe - million barrels of oil equivalent

· mmcf - million cubic feet

· MMBtu - million british thermal units

· bcf - billion cubic feet

· tcf - trillion cubic feet

· scm - standard cubic metre

· mcm - thousand cubic metres

· mmcm - million cubic metres

· bcm - billion cubic metres

· mmtpa - million tonnes per annum

· km - kilometre

· ppm - part per million

· one billion - one thousand million

Equivalent measurements are based upon

· 1 barrel equals 0.134 tonnes of oil (33 degrees API)

· 1 barrel equals 42 US gallons

· 1 barrel equals 0.159 standard cubic metres

· 1 barrel of oil equivalent equals 1 barrel of crude oil

· 1 barrel of oil equivalent equals 159 standard cubic metres of natural gas

· 1 barrel of oil equivalent equals 5,612 cubic feet of natural gas

· 1 barrel of oil equivalent equals 0.0837 tonnes of NGLs

· 1 billion standard cubic metres of natural gas equals 1 million standard cubic metres of oil equivalent

· 1 cubic metre equals 35.3 cubic feet

· 1 kilometre equals 0.62 miles

· 1 square kilometre equals 0.39 square miles

· 1 square kilometre equals 247.105 acres

· 1 cubic metre of natural gas equals 1 standard cubic metre of natural gas

· 1,000 standard cubic meter gas equals 1 standard cubic meter oil equivalent

· 1,000 standard cubic metres of natural gas equals 6.29 boe

· 1 standard cubic foot equals 0.0283 standard cubic metres

· 1 standard cubic foot equals 1000 British thermal units (btu)

· 1 tonne of NGLs equals 1.9 standard cubic metres of oil equivalent

· 1 degree Celsius equals minus 32 plus five-ninths of the number of degrees Fahrenheit

Miscellaneous terms

· Appraisal well: A well drilled to establish the extent and the size of a discovery

222 Statoil, Annual Report on Form 20-F 2016

· Backwardation and contango are terms used in the crude oil market. Contango is a condition where forward prices exceed spot prices, so the forward curve is upward sloping. Backwardation is the opposite condition, where spot prices exceed forward prices, and the forward curve slopes downward

· Biofuel: A solid, liquid or gaseous fuel derived from relatively recently dead biological material and is distinguished from fossil fuels, which are derived from long dead biological material

· BOE (barrels of oil equivalent): A measure to quantify crude oil, natural gas liquids and natural gas amounts using the same basis. Natural gas volumes are converted to barrels on the basis of energy content

· Clastic reservoir systems: The integrated static and dynamic characteristics of a hydrocarbon reservoir formed by clastic rocks of a specific depositional sedimentary succession and its seal

· Condensates: The heavier natural gas components, such as pentane, hexane, iceptane and so forth, which are liquid under atmospheric pressure – also called natural gasoline or naphtha

· Crude oil, or oil: Includes condensate and natural gas liquids

· Development: The drilling, construction, and related activities following discovery that are necessary to begin production of crude oil and natural gas fields

· Downstream: The selling and distribution of products derived from upstream activities

· Equity and entitlement volumes of oil and gas: Equity volumes represent volumes produced under a production sharing agreement (PSA) that correspond to Statoil's percentage ownership in a particular field. Entitlement volumes, on the other hand, represent Statoil's share of the volumes distributed to the partners in the field, which are subject to deductions for, among other things, royalties and the host government's share of profit oil. Under the terms of a PSA, the amount of profit oil deducted from equity volumes will normally increase with the cumulative return on investment to the partners and/or production from the licence. The distinction between equity and entitlement is relevant to most PSA regimes, whereas it is not applicable in most concessionary regimes such as those in Norway, the UK, Canada and Brazil. The overview of equity production provides additional information for readers, as certain costs described in the profit and loss analysis were directly associated with equity volumes produced during the reported years

· Heavy oil: Crude oil with high viscosity (typically above 10 cp), and high specific gravity. The API classifies heavy oil as crudes with a gravity below 22.3° API. In addition to high viscosity and high specific gravity, heavy oils typically have low hydrogen-to-carbon ratios, high asphaltene, sulphur, nitrogen, and heavy-metal content, as well as higher acid numbers

· High grade: Relates to selectively harvesting goods, to cut the best and leave the rest. In reference to exploration and production this entails strict prioritisation and sequencing of drilling targets

· Hydro: A reference to the oil and energy activities of Norsk Hydro ASA, which merged with Statoil ASA

· IOR (improved oil recovery): Actual measures resulting in an increased oil recovery factor from a reservoir as compared with the expected value at a certain reference point in time. IOR comprises both of conventional and emerging technologies

· Liquids: Refers to oil, condensates and NGL

· LNG (liquefied natural gas): Lean gas - primarily methane - converted to liquid form through refrigeration to minus 163 degrees Celsius under atmospheric pressures

· LPG (liquefied petroleum gas): Consists primarily of propane and butane, which turn liquid under a pressure of six to seven atmospheres. LPG is shipped in special vessels

· Midstream: Processing, storage, and transport of crude oil, natural gas, natural gas liquids and sulphur

· Naphtha: inflammable oil obtained by the dry distillation of petroleum

· Natural gas: Petroleum that consists principally of light hydrocarbons. It can be divided into 1) lean gas, primarily methane but often containing some ethane and smaller quantities of heavier hydrocarbons (also called sales gas) and 2) wet gas, primarily ethane, propane and butane as well as smaller amounts of heavier hydrocarbons; partially liquid under atmospheric pressure

· NGL (natural gas liquids): Light hydrocarbons mainly consisting of ethane, propane and butane which are liquid under pressure at normal temperature

· Oil sands: A naturally occurring mixture of bitumen, water, sand, and clay. A heavy viscous form of crude oil

· Oil and gas value chains: Describes the value that is being added at each step from 1) exploring; 2) developing; 3) producing; 4) transportation and refining; and 5) marketing and distribution

· Organic capital expenditures: Capital expenditures excluding acquisitions, capital leases and other investments with significant different cash flow pattern

· Oslo Børs : Oslo stock exchange

· Peer group: Statoil’s peer group consists of Statoil, Shell, ExxonMobil, OMV, ConocoPhillips, BP, Marathon, Chevron, Total, Repsol, Anadarko and Eni

· Petroleum: A collective term for hydrocarbons, whether solid, liquid or gaseous. Hydrocarbons are compounds formed from the elements hydrogen (H) and carbon (C). The proportion of different compounds, from methane and ethane up to the heaviest components, in a petroleum find varies from discovery to discovery. If a reservoir primarily contains light hydrocarbons, it is described as a gas field. If heavier hydrocarbons predominate, it is described as an oil field. An oil field may feature free gas above the oil and contain a quantity of light hydrocarbons, also called associated gas

· Proved reserves: Reserves claimed to have a reasonable certainty (normally at least 90% confidence) of being recoverable under existing economic and political conditions, and using existing technology. They are the only type the US Securities and Exchange Commission allows oil companies to report

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

· Rig year: A measure of the number of equivalent rigs operating during a given period. It is calculated as the number of days rigs are operating divided by the number of days in the period

· Upstream: Includes the searching for potential underground or underwater oil and gas fields, drilling of exploratory wells, subsequent operating wells which bring the liquids and or natural gas to the surface

· VOC (volatile organic compounds): Organic chemical compounds that have high enough vapour pressures under normal conditions to significantly vaporise and enter the earth's atmosphere (e.g. gasses formed under loading and offloading of crude oil)

Statoil, Annual Report on Form 20-F 2016 223

5.7 Forward-looking statements

This Annual Report on Form 20-F contains certain forward-looking statements that involve risks and uncertainties, in particular in the sections "Business overview" and "Strategy and market overview". In some cases, we use words such as "aim", "ambition", "anticipate", "believe", "continue", "could", "estimate", "expect", "intend", "likely", "objective", "outlook", "may", "plan", "schedule", "seek", "should", "strategy", "target", "will", "goal" and similar expressions to identify forward-looking statements. All statements other than statements of historical fact, including, among others, statements regarding future financial position, results of operations and cash flows; future financial ratios and information; future financial or operational portfolio or performance; future market position and conditions; future credit rating; business strategy; growth strategy; sales, trading and market strategies; research and development initiatives and strategy; market outlook and future economic projections and assumptions; competitive position; projected regularity and performance levels; expectations related to our recent transactions and projects, such as the sale of interests in the Shah Deniz project and the South Caucasus Pipeline, interests in the Marcellus onshore play in the US, interests in Trans Adriatic Pipeline, interests in Gudrun and acquisition of interests in Eagle Ford in the US, the UK Mariner project, the Peregrino phase II project in Brazil, in addition to the Johan Sverdrup and Aasta Hansteen projects on the NCS, discoveries on the NCS and internationally; our ownership share in Gassled; completion and results of acquisitions, disposals and other contractual arrangements; reserve information; recovery factors and levels; future margins; projected returns; future levels or development of capacity, reserves or resources; future decline of mature fields; planned turnarounds and other maintenance; plans for cessation and decommissioning; oil and gas production forecasts and reporting; growth, expectations and development of production, projects, pipelines or resources; estimates related to production and development levels and dates; operational expectations, estimates, schedules and costs; exploration and development activities, plans and expectations; projections and expectations for upstream and downstream activities; expectations relating to licences; oil, gas, alternative fuel and energy prices and volatility; oil, gas, alternative fuel and energy supply and demand; renewable energy production, industry outlook and carbon capture and storage; organisational structure and policies; planned responses to climate change; technological innovation, implementation, position and expectations; future energy efficiency; projected operational costs or savings; our ability to create or improve value; future sources of financing; exploration and project development expenditure; our goal of safe and efficient operations; effectiveness of our internal policies and plans; our ability to manage our risk exposure; our liquidity levels and management; estimated or future liabilities, obligations or expenses; expected impact of currency and interest rate fluctuations; expectations related to contractual or financial counterparties; capital expenditure estimates and expectations; projected outcome, impact or timing of HSE regulations; HSE goals and objectives of management for future operations; expectations related to regulatory trends; impact of PSA effects; projected impact or timing of administrative or governmental rules, standards, decisions, standards or laws (including taxation laws); projected impact of legal claims against us; plans for capital distribution and amounts of dividends are forward-looking statements. You should not place undue reliance on these forward-looking statements. Our actual results could differ materially from those anticipated in the forward-looking statements for many reasons, including the risks described above in "Risk review", and in "Operational review", and elsewhere in this Annual Report on Form 20-F.

These forward-looking statements reflect current views about future events and are, by their nature, subject to significant risks and uncertainties because they relate to events and depend on circumstances that will occur in the future. There are a number of factors that could cause actual results and developments to differ materially from those expressed or implied by these forward-looking statements, including levels of industry product supply, demand and pricing; exchange rate and interest rate fluctuations; the political and economic policies of Norway and other oil-producing countries; EU directives; general economic conditions; political and social stability and economic growth in relevant areas of the world; Euro-zone uncertainty; global political events and actions, including war, terrorism and sanctions; security breaches, including breaches of our digital infrastructure (cybersecurity); changes or uncertainty in or non-compliance with laws and governmental regulations; the timing of bringing new fields on stream; an inability to exploit growth opportunities; material differences from reserves estimates; unsuccessful drilling; an inability to find and develop reserves; ineffectiveness of crisis management systems; adverse changes in tax regimes; the development and use of new technology, particularly in the renewable energy sector; geological or technical difficulties; operational problems; operator error; inadequate insurance coverage; the lack of necessary transportation infrastructure when a field is in a remote location and other transportation problems; the actions of competitors; the actions of field partners; the actions of the Norwegian state as majority shareholder; counterparty defaults; natural disasters, adverse weather conditions, climate change, and other changes to business conditions; failure to meet our ethical and social standards; an inability to attract and retain personnel and other factors discussed elsewhere in this report.

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

224 Statoil, Annual Report on Form 20-F 2016

5.8 Signature page

The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorised the undersigned to sign this Annual Report on its behalf.

STATOIL ASA

(Registrant)

By: /s/Hans Jakob Hegge

Name: Hans Jakob Hegge

Title: Executive Vice President and Chief Financial Officer

Dated: 17 March 2017

Statoil, Annual Report on Form 20-F 2016 225

5.9 Exhibits

The following exhibits are filed as part of this Annual Report:

Exhibit no		Description

Exhibit 1		Articles of Association of Statoil ASA, as amended, effective from 26 October 2016 (English translation).
Exhibit 2.1		Form of Indenture among Statoil ASA (formerly known as StatoilHydro ASA), Statoil Petroleum AS (formerly known as Statoil Hydro Petroleum AS) and Deutsche Bank Trust Company Americas (incorporated by reference to Exhibit 4.1 of Statoil ASA’s and Statoil Petroleum AS’s Post‐Effective Amendment No. 1 to their Registration Statement on Form F‐3 (File No. 333‐143339) filed with the Commission on April 2, 2009).
Exhibit 2.2		Amended and Restated Agency Agreement, dated as of 5 February 2016, by and among Statoil ASA, as Issuer, Statoil Petroleum AS as Guarantor, the Bank of New York Mellon, as Agent and the Bank of New York Mellon (Luxembourg) S.A. as Paying Agent in respect of a €20,000,000 Euro Medium Term Note Programme.
Exhibit 2.3		Deed of Covenant, dated as of 5 February 2016, of Statoil ASA in respect of a €20,000,000 Euro Medium Term Notes Programme.
Exhibit 2.4		Deed of Guarantee, dated as of 5 February 2016, of Statoil Petroleum AS in respect of a €20,000,000 Euro Medium Term Notes Programme.
Exhibit 4(a)(i)		Technical Services Agreement between Gassco AS and Statoil Petroleum AS, dated November 24, 2010.
Exhibit 4(c)		Employment agreement with Eldar Sætre as of 4 February 2015.
Exhibit 7		Calculation of ratio of earnings to fixed charges.
Exhibit 8		Subsidiaries (see Significant subsidiaries included in section 2.7 Corporate in this Annual Report).
Exhibit 12.1		Rule 13a-14(a) Certification of Chief Executive Officer.
Exhibit 12.2		Rule 13a-14(a) Certification of Chief Financial Officer.
Exhibit 13.1		Rule 13a-14(b) Certification of Chief Executive Officer.¹⁾
Exhibit 13.2		Rule 13a-14(b) Certification of Chief Financial Officer.¹⁾
Exhibit 15(a)(i)		Consent of KPMG AS.
Exhibit 15(a)(ii)		Consent of DeGolyer and MacNaughton.
Exhibit 15(a)(iii)		Report of DeGolyer and MacNaughton.

1)	Furnished only.

The total amount of long term debt securities of Statoil ASA and its subsidiaries authorized under instruments other than those listed above does not exceed 10% of the total assets of Statoil ASA and its subsidiaries on a consolidated basis. The company agrees to furnish copies of any or all such instruments to the Commission upon request.

226 Statoil, Annual Report on Form 20-F 2016

5.10 Cross reference to Form 20-F

		Sections
Item 1.	Identity of Directors, Senior Management and Advisers	N/A
Item 2.	Offer Statistics and Expected Timetable	N/A
Item 3.	Key Information
	A. Selected Financial Data	Key Figures and Highlights
	B. Capitalisation and Indebtedness	N/A
	C. Reasons for the Offer and Use of Proceeds	N/A
	D. Risk Factors	2.10 (Risk review—Risk factors)
Item 4.	Information on the Company
	A. History and Development of the Company	Statoil at a Glance; 2.2 (Business Overview); 2.3 (DPN – Development and production Norway); 2.4 (DPI – Development and production international); 2.5 (MMP – Marketing, Midstream and processing); 2.6 (Other group); 2.9 (Liquidity and capital resources—Reviews of cash flows); 2.9 (Liquidity and Capital Resources—Investments); note 4 (Acquisitions and disposals) to Statoil’s Consolidated financial statements)
	B. Business Overview	2.1 (Strategy and market overview); 2.2 (Business overview); 2.3 (DPN – Development and production Norway); 2.4 (DPI – Development and production international); 2.5 (MMP – Marketing, midstream and processing); 2.6 (Other group); 2.7 (Corporate)
	C. Organisational Structure	2.2 (Business overview—Corporate structure); 2.2 (Business Overview—Segment reporting); 2.7 (Corporate—Subsidiaries and properties)
	D. Property, Plants and Equipment	2.3 (DPN – Development and production Norway); 2.4 (DPI – Development and production international); 2.5 (MMP – Marketing, midstream and processing); 2.7 (Corporate—Property, plant and equipment); 2.9 (Liquidity and Capital Resources—Investments); notes 10 (Property, plant and equipment) and 22 (Leases) to Statoil’s Consolidated financial statements
	Oil and Gas Disclosures	2.8 (Operating and financial performance—Proved oil and gas reserves); 2.8 (Operating and financial performance—Production volumes and pricing); Exhibit 15(a)(iii)
Item 4A.	Unresolved Staff Comments	None
Item 5.	Operating and Financial Review and Prospects
	A. Operating Results	2.8 (Operating and financial performance); 2.7 (Corporate—Applicable laws and regulations); 2.9 (Liquidity and capital resources—Impact of reduced prices); 2.10 (Risk review—Risk management—Managing operational risks); note 25 (Financial instruments: fair value measurement and sensitivity analysis of market risk) to Statoil’s Consolidated financial statements
	B. Liquidity and Capital Resources	2.9 (Liquidity and capital resources); 2.10 (Risk review—Risk management); notes 5 (Financial risk management), 15 (Trades and other receivables); 18 (Finance debt), 23 (Other commitments, contingent liabilities and contingent assets) and 25 (Financial instruments: fair value measurement and sensitivity analysis of market risk) to Statoil’s Consolidated financial statements
	C. Research and development, Patents and Licenses, etc.	2.2 (Business overview—Research and development); note 7 (Other expenses) to Statoil’s consolidated financial statements
	D. Trend Information	passim
	E. Off‐Balance Sheet Arrangements	2.9 (Liquidity and capital resources—Principal Contractual obligations); 2.9 (Liquidity and capital resources—Off balance sheet arrangements); notes 22 (Leases) and 23 (Other commitments, contingent liabilities and contingent assets) to Statoil’s Consolidated financial statements
	F. Tabular Disclosure of Contractual Obligations	2.9 (Liquidity and capital resources—Principal contractual obligations)
	G. Safe Harbor	5.7 (Forward-Looking Statements)
Item 6.	Directors, Senior Management and Employees
	A. Directors and Senior Management	3.5 (Board of directors); 3.6 (Management)
	B. Compensation	3.7 (Compensation to governing bodies)
	C. Board Practices	3.4 (Corporate assembly); 3.5 (Board of directors); 3.6 (Management)
	D. Employees	2.12 (Our people—Employees in Statoil); 2.12 (Our people—Unions and representatives)
	E. Share Ownership	3.8 (Share ownership); 5.1 (Shareholder information—Shares purchased by the issuer—Statoil’s share savings plan)
Item 7.	Major Shareholders and Related Party Transactions
	A. Major Shareholders	5.1 (Shareholder information—Major shareholders)
	B. Related Party Transactions	2.7 (Corporate—Related party transactions); note 24 (Related parties) to Statoil’s Consolidated financial statement
	C. Interests of Experts and Counsel	N/A
Item 8.	Financial Information
	A. Consolidated Statements and Other Financial Information	4.1 (Consolidated financial statements of Statoil); 5.3 (Legal proceedings)
	B. Significant Changes	note 28 (Subsequent events) to Statoil’s Consolidated financial statements)
Item 9.	The Offer and Listing
	A. Offer and Listing Details	5.1 (Shareholder information); 5.1 (Shareholder information—Share Prices)
	B. Plan of Distribution	N/A
	C. Markets	5.1 (Shareholder Information)
	D. Selling Shareholders	N/A
	E. Dilution	N/A
	F. Expenses of the Issue	N/A
Item 10.	Additional Information
	A. Share Capital	N/A
	B. Memorandum and Articles of Association	2.10 (Risk review—Risks related to state ownership); 3.1 (Introduction—Articles of association); 3.2 (General meeting of shareholders); 5.1 (Shareholder information); 5.1 (Shareholder Information—Major Shareholders) and note 17 (Shareholders’ Equity and dividends) to Statoil’s Consolidated financial statements
	C. Material Contracts	N/A
	D. Exchange Controls	5.1 (Shareholder information—Exchange controls and limitations
	E. Taxation	5.1 (Shareholder information—Taxation)
	F. Dividends and Paying Agents	N/A
	G. Statements by Experts	N/A
	H. Documents On Display	About this Report
	I. Subsidiary Information	N/A
Item 11.	Quantitative and Qualitative Disclosures About Market Risk	2.10 (Risk review—Risk management); notes 5 (Financial risk management) and 25 (Financial instruments; fair value measurement and sensitivity analysis of market risk) to Statoil’s Consolidated financial statements
Item 12.	Description of Securities Other than Equity Securities
	A. Debt Securities	N/A
	B. Warrants and Rights	N/A
	C. Other Securities	N/A
	D. American Depositary Shares	5.1 (Shareholder Information—Statoil ADR Programme Fees)
Item 13.	Defaults, Dividend Arrearages and Delinquencies	None
Item 14.	Material Modifications to the Rights of Security Holders and Use of	None
	Proceeds
Item 15.	Controls and Procedures	3.10 (Controls and Procedures);
Item 16A.	Audit Committee Financial Expert	3.5 (Board of Directors—Audit Committee)
Item 16B.	Code of Ethics	3.1 (Introduction—Code of Conduct)
Item 16C.	Principal Accountant Fees and Services	3.9 (External Auditor)
Item 16D.	Exemptions from the Listing Standards for Audit Committees	3.1 (Introduction—Compliance with NYSE listing rules)
Item 16E.	Purchases of Equity Securities by the Issuer and Affiliated Purchases	5.1 (Shareholder Information—Shares purchased by the Issuer)
Item 16F.	Changes in Registrant’s Certifying Accountant	N/A
Item 16G.	Corporate Governance	3.1 (Introduction—Compliance with NYSE listing rules)
Item 16H	Mine Safety Disclosure	None
Item 17.	Financial Statements	N/A
Item 18.	Financial Statements	4.1 (Financial statements of Statoil)

Statoil, Annual Report on Form 20-F 2016 227

228 Statoil, Annual Report on Form 20-F 2016

INTRODUCTION
Message from Chair of the board	3
Chief executive letter	5
Statoil at a glance	6
About the report	8

STRATEGIC REPORT
2.1 Strategy and market overview	9
2.2 Business overview	14
2.3 DPN - Development and Production Norway	19
2.4 DPI - Development and Production International	27
2.5 MMP - Marketing, Midstream and Processing	33
2.6 Other group	36
2.7 Corporate	39
2.8 Operating and financial performance	44
2.9 Liquidity and capital resources	69
2.10 Risk review	74
2.11 Safety, security and sustainability	85
2.12 Our people	90

CORPORATE GOVERNANCE
3.1 Introduction	93
3.2 General meeting of shareholders	96
3.3 Nomination committee	97
3.4 Corporate assembly	98
3.5 Board of directors	101
3.6 Management	111
3.7 Compensation to governing bodies	116
3.8 Share ownership	124
3.9 External auditor	125
3.10 Controls and procedures	127

FINANCIAL STATEMENTS AND SUPPLEMENTS
4.1 Statoil Consolidated financial statements	129

ADDITIONAL INFORMATION
5.1 Shareholder information	203
5.2 Accounting standards (IFRS) and Non-GAAP measures	216
5.3 Legal proceedings	220
5.6 Terms and abbreviations	221
5.7 Forward-looking statements	224
5.8 Signature page	225
5.9 Exhibits	226
5.10 Cross reference to Form 20-F	227

Dear shareholder,

Our shareholders

Our business areas

Key figures and highlights

About the report

2.1 Strategy and market overview

Statoil’s business environment

Market overview

Oil prices and refining margins

Natural gas prices

2.2 BUSINESS OVERVIEW

History

Activities

Our competitive position

SEGMENT REPORTING

2.3 DPN - DEVELOPMENT AND PRODUCTION NORWAY

Fields in production on the NCS

Main producing fields on the NCS

Statoil operated fields

Partner-operated fields

Exploration on the NCS

Fields under development on the NCS

Decommissioning on the NCS

2.4 DPI - DEVELOPMENT AND PRODUCTION INTERNATIONAL

DPI overview

International production

Americas

Africa

Eurasia

International exploration

Fields under development internationally

Americas

Africa

Eurasia United Kingdom

2.5 MMP - MARKETING, MIDSTREAM AND PROCESSING

Marketing and Trading

Marketing and trading of gas and LNG

Marketing and trading of liquids

Production plants

Terminals and storage

Pipelines

2.6 OTHER GROUP

Global Strategy and Business Development (GSB)

Corporate staffs and support functions

Technology, Projects and Drilling (TPD)

2.7 CORPORATE

APPLICABLE LAWS AND REGULATIONS

Gas sales and transportation from the NCS

The Norwegian State's participation

HSE regulation

Taxation of Statoil

SUBSIDIARIES AND PROPERTIES

Significant subsidiaries

Property, plant and equipment

Related party transactions

Insurance

2.8 OPERATING AND FINANCIAL PERFORMANCE

Development of reserves

Preparations of reserves estimates

Operational statistics

Delivery commitments

PRODUCTION VOLUMES AND PRICES

Entitlement production

Sales prices

Sales volumes

FINANCIAL REVIEW – GROUP PROFIT AND LOSS ANALYSIS

FINANCIAL REVIEW – SEGMENTS PERFORMANCE

DPN profit and loss analysis

DPI profit and loss analysis

MMP profit and loss analysis

Other operations

2.9 LIQUIDITY AND CAPITAL RESOURCES

Review of cash flows

Financial assets and debt

Investments

Impact of reduced prices

Principal contractual obligations

Off balance sheet arrangements

2.10 RISK REVIEW

RISK FACTORS

Main producing fields on
the NCS

Eurasia
United Kingdom