20-F 1 eqnr20f19.htm EQUINOR ANNUAL REPORT ON FORM 20-F 2019

2019 Annual Report on Form 20-F

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549

FORM 20-F

(Mark One)

☐ REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR 12(g) OF THE SECURITIES EXCHANGE ACT OF 1934
OR
x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2019
OR
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
OR
☐ SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Date of event requiring this shell company report
Commission file number 1-15200
Equinor ASA
(Exact Name of Registrant as Specified in Its Charter)
N/A
(Translation of Registrant’s Name Into English)
Norway
(Jurisdiction of Incorporation or Organization)
Forusbeen 50, N-4035, Stavanger, Norway
(Address of Principal Executive Offices) Lars Christian Bacher Chief Financial Officer Equinor ASA Forusbeen 50, N-4035 Stavanger, Norway Telephone No.: 011-47-5199-0000 Fax No.: 011-47-5199-0050
(Name, Telephone, E-mail and/or Facsimile number and Address of Company Contact Person)
Securities registered or to be registered pursuant to Section 12(b) of the Act:

Title of Each Class | Trading Symbol(s) | Name of Each Exchange On Which Registered
American Depositary Shares | EQNR | New York Stock Exchange
Ordinary shares, nominal value of NOK 2.50 each |  | New York Stock Exchange*

*Listed, not for trading, but only in connection with the registration of American Depositary Shares, pursuant to the requirements of the Securities and Exchange Commission

Securities registered or to be registered pursuant to Section 12(g) of the Act: None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None

Equinor, Annual Report on Form 20-F 2019 1

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.

Ordinary shares of NOK 2.50 each | 3,305,008,097

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

| x Yes ☐ No

If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.

| ☐ Yes x No

Note – Checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 from their obligations under those Sections.

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

| x Yes ☐ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files)

| x Yes ☐ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer x | Accelerated filer ☐ | Non-accelerated filer ☐ | Emerging growth company ☐

If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards† provided pursuant to Section 13(a) of the Exchange Act. ☐

† The term “new or revised financial accounting standard” refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012.

Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:

U.S. GAAP ☐ | International Financial Reporting Standards as issued by the International Accounting Standards Board x | Other ☐

If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow.

Item 17 ☐

Item 18 ☐

If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

| ☐ Yes x No

2 Equinor, Annual Report on Form 20-F 2019

We are Equinor

We are an international energy company committed to long-term value creation in a low carbon future inspired by its vision of shaping the future of energy.

Our values​ are

Open​

Collaborative​

Courageous ​

Caring

We energize the lives of 170 million people. Every day.

Equinor, Annual Report on Form 20-F 2019 3

Always safe, high value, low carbon

We continue to pursue our strategy of always safe, high value and low carbon through developing and maximising the value of our unique Norwegian continental shelf position, our international oil and gas business, our manufacturing and trading activities and our growing new energy business.

Below are some key figures related to 2019 presented.

#

4 Equinor, Annual Report on Form 20-F 2019

# 2019 highlights

#

#### January:

Awarded 29 exploration licences on the NCS

#### February:

Danske Commodities, a trading company for power and gas, becomes a wholly owned subsidiary of Equinor

#### March:

Record-breaking offshore lift completes the Johan Sverdrup field centre on the NCS

#### April:

Formal opening of Arkona Windfarm, offshore Germany, awarded seven exploration licences in offshore Argentina, final investment decision (FID) on Azeri-Central-East, Azerbaijan

#### May:

Increased share in Caesar Tonga to 46%, US Gulf of Mexico, Huldra removal on the NCS, approved PDO for Johan Sverdrup phase 2

#### June:

Awarded five exploration licences on the UKCS, operatorship of Wisting in the Barents Sea was transferred from OMV to Equinor

#### July:

Trestakk onstream on the NCS, Lundin-transaction increasing Equinor’s direct share in Johan Sverdrup, Winner in the New York state’s first large-scale competitive offshore wind solicitation.

#### August:

Start-up of the heavy oil field Mariner, UKCS

#### September:

Winning bid on Dogger Bank in the UK, launched USD 5 billion share buy-back programme, Statfjord field 40 years of production celebration, Utgard started productio n on the NCS and UKCS, Snefrid Nord onstream with record breaking 1,309 meters below sea-level

#### October:

Start-up of Johan Sverdrup on the NCS, F ID for Hywind Tampen floating offshore wind park to supply the Gullfaks and Snorre fields with renewable electric power.

#### November:

Announced divestment of Eagle Ford onshore asset in the US

#### December:

#### Increased position in Scatec Solar ASA to 15,2%, final investment decision on North Komsomolskoye, Russia

#

Equinor, Annual Report on Form 20-F 2019 5

# About the report

This document constitutes the Annual report on Form 20-F in accordance with the US Securities Exchange Act of 1934 applicable to foreign private issuers, for Equinor ASA for the year ended 31 December 2019. 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). The Annual report and Form 20-F are filed with the Norwegian Register of company accounts.

The Equinor annual report and Form 20-F may be downloaded from Equinor’s website at www.equinor.com/reports. References to this document or other documents on Equinor’s website are included as an aid to their location and are not incorporated by reference into this document. All SEC filings made available electronically by Equinor may be found at www.sec.gov.

Table of contents

INTRODUCTION |
About the report | 6
Message from the chair of the board | 9
Chief executive letter | 11
STRATEGIC REPORT |
2.1 Strategy and market overview | 13
2.2 Business overview | 20
2.3 Exploration & Production Norway (E&P Norway) | 28
2.4 Exploration & Production International (E&P International) | 37
2.5 Marketing, Midstream & Processing (MMP) | 47
2.6 Other group | 50
2.7 Corporate | 55
2.8 Operational performance | 63
2.9 Financial review | 82
2.10 Liquidity and capital resources | 91
2.11 Risk review | 97
2.12 Safety, security and sustainability | 110
2.13 Our people | 117
3. CORPORATE GOVERNANCE | 121
3.1 Introduction | 122
3.2 General meeting of shareholders | 125
3.3 Nomination committee | 126
3.4 Corporate assembly | 127
3.5 Board of directors | 130
3.6 Management | 140
3.7 Compensation to governing bodies | 147
3.8 Share ownership | 155
3.9 External auditor | 157
3.10 Risk management and internal control | 159
FINANCIAL STATEMENTS AND SUPPLEMENTS |
4.1 Consolidated financial statements of the Equinor group | 162
4.2 Supplementary oil and gas information (unaudited) | 240
ADDITIONAL INFORMATION |
5.1 Shareholder information | 253
5.2 Use and reconciliation of non-GAAP financial measures | 263
5.3 Legal proceedings | 268
5.6 Terms and abbreviations | 269
5.7 Forward-looking statements | 272
5.8 Signature page | 273
5.9 Exhibits | 274
5.10 Cross reference to Form 20-F | 275

6 Equinor, Annual Report on Form 20-F 2019

###

Equinor, Annual Report on Form 20-F 2019 7

###

| We believe the company is well prepared to deal with future market uncertainties, and has the competence, capacity and leadership capabilities necessary to create new business opportunities and long-term value for our shareholders. Jon Erik Reinhardsen

8 Equinor, Annual Report on Form 20-F 2019

Message from the chair of the board Dear fellow investors,
The biggest transition our modern-day energy systems have ever seen is underway, and Equinor is well positioned for the changes that need to take place. The board of directors believe Equinor can be a leading company in the energy transition, shaping a resilient and competitive portfolio while creating significant value for shareholders. Safety and security are on top of the board of directors agenda. The Board receives regular updates related to safety and security from the administration, and it is the first item on the agenda of every board meeting. Overall, we see many positive developments, but the company needs to further enhance its efforts related to serious incidents and personal injuries. Also during 2019, accidents have reminded us of the importance of a continued and strong focus on the safety of our people. Equinor continues to improve and demonstrate strong operational performance. High production and continued strong cost and capital discipline contributed to solid results, despite lower commodity prices. The net operating income was USD 9.30 billion compared to USD 20.1 billion in 2018. The company has a strong balance sheet and remains committed to competitive capital distribution. We delivered a 42% increase in capital distribution in 2019, including the effect of the share buy-back programme introduced in 2019. For the fourth quarter 2019 we propose to the AGM a quarterly dividend of USD 0.27 per share, an increase of 4%. The proposed increase is consistent with the dividend policy to grow the annual cash dividend in line with expected long-term underlying earnings. The company expects a strong equity production growth in 2020 of around 7% and a 3% annual average production growth from 2019 to 2026. New projects coming on stream in 2019 had an average breakeven oil price of around USD 30 per barrel. Equinor is also set for a value driven growth in renewables, developing as a global offshore wind major. In 2026 the production capacity is expected to be 4-6 GW[1] , which is around 10 times current capacity. | Equinor has taken new initiatives to prolong production at several offshore installations on the Norwegian Continental Shelf. The company is also further developing its international portfolio and strengthening its presences in core areas. The international portfolio is delivering high value and we expect production to increase by more than 3% annually for 2019 to 2026. The global challenge of climate change will dominate many debates in 2020 and the years ahead. Equinor`s joint statement with Climate Action 100+ from April 2019, forms the starting point for our investor dialogue in support of the goals of the Paris Agreement. In our updated climate roadmap, we recognise the need for significant changes in the energy markets, which means that also Equinor`s portfolio will have to change accordingly to remain competitive. We will produce less oil in a low carbon future, but value creation will still be high. Oil and gas production with low greenhouse gas emissions will be an even stronger competitive advantage for us. In addition, profitable growth in renewables gives significant new opportunities to create attractive returns. Our markets are volatile by nature, and the effects of the Covid-19 and the sharp drop in the oil price in March 2020, are strong reminders of this. For the board of directors, it is essential that Equinor maintains its position as a robust and resilient company. We believe the company is well prepared to deal with future market uncertainties, and has the competence, capacity and leadership capabilities necessary to create new business opportunities and long-term value for our shareholders. I would like to thank all employees for their dedication and commitment to Equinor and our shareholders for their continued investment. Jon Erik Reinhardsen Chair of the board

[1] Including our 15.2% equity in Scatec Solar ASA

Equinor, Annual Report on Form 20-F 2019 9

| We aim to strengthen our industry-leading position within carbon efficient operations and to grow profitably from a strong and competitive renewables business. The company is well positioned for long-term shareholder value creation and to be competitive also in a low-carbon future. Eldar Sætre

10 Equinor, Annual Report on Form 20-F 2019

Chief executive letter Dear fellow shareholder, ###
Equinor is committed to sustainability and recognize that the energy systems must go through profound changes to meet the goals of the Paris-agreement. We know that the world needs to reach net zero emissions as soon as possible and that we at the same time, must provide enough energy to meet a growing demand. Equinor is a leading company within our sector, driving towards a low-carbon future. As a broad energy company, we are strengthening our portfolio to underpin a competitive and resilient business model fit for long term value creation, and in line with the Paris Agreement. The safety and security of our people and integrity of our operations is our top priority. The frequency of personal injuries was down last year, while we did not see the same positive trend for our serious incident frequency. We need to continue our relentless efforts to avoid serious incidents and further reduce personal injuries. The serious work-related accident at the Heimdal platform in the North Sea last November, is a strong reminder of the importance of safety for our people. And the impact from the Hurricane Dorian at the South Riding Point terminal in the Bahamas illustrates the need for preparedness also towards a new type of incidents. In 2019, we delivered a solid result with adjusted earnings[2] of USD 13.5 billion and USD 4.93 billion after tax. Our net operating income was USD 9.30 billion in 2019, compared to USD 20.1 billion in 2018. The decrease was primarily driven by lower liquids and gas prices. The return on average capital employed was 9% and we delivered USD 13.5 billion in cash flow from operations after tax. This was combined with an increase in total capital distribution of more than 40%, reflecting a 13% step-up in cash dividend, the conclusion of the scrip programme as planned, as well as the introduction of our share buy-back programme. Last year, Equinor delivered high total equity production of 2,074 mboe per day and has a world-class project portfolio with an average break-even oil price below USD 35 per barrels. Six new projects came on stream in 2019, including the start-up of Johan Sverdrup. Organic capital expenditures amounted to USD 10 billion[3] for 2019. | We have a strong balance sheet and expect growth in long-term underlying earnings, driven by a high-quality portfolio, as well as a range of improvement efforts across our portfolio. At an assumed oil price of USD 65 per barrel we expect to increase our adjusted return on average capital employed to around 15% in 2023, and to deliver organic cash flow of around USD 30 billion in total, after tax and organic investments – from 2020 to 2023. Driven by the strong opportunity set of high-quality projects in front of us, we expect organic investments to be USD 10-11 billion on average in 2020 and 2021, and around USD 12 billion on average in the two following years. 2019 was also truly a game-changing year for our renewables business. We made the investment decision for Hywind Tampen in Norway and won the opportunities to develop Empire Wind offshore New York and Dogger Bank in the UK, the world’s largest offshore wind development. Projects under development will add 2.8 gigawatts of renewables electricity capacity to Equinor. In our updated climate roadmap, we have set new targets for both short, medium and long-term climate performance. We aim to strengthen our industry-leading position within carbon efficient operations and to grow profitably from a strong and competitive renewables business. The company is well positioned for long-term shareholder value creation and to be competitive also in a low-carbon future. Our results confirm that we are on track with our ambitions to increase returns, grow production and cash flow in the years to come. We know that our markets are volatile and that we always need to be prepared for unexpected events that could impact our business. The outbreak of the Covid-19 virus and the sharp drop in the oil price, are both examples of this. Thanks to strict cost discipline, strong commercial mindset and substantial improvement measures over several years, we are a more resilient company today with significant business flexibility to handle volatility. Eldar Sætre President and CEO Equinor ASA

[2] See section 5.2 for non-GAAP measures.

[3] IFRS capital expenditures for 2019 were USD 14,8 billion.

Equinor, Annual Report on Form 20-F 2019 11

# 2.1 # Strategy and market overview

Digital field worker, Kårstø, Norway.

## Equinor’s business environment

### Market overview

In 2019 the global economy grew at its weakest pace since the global financial crisis a decade ago. The global growth rate, estimated at 2.6%, reflects common challenges across countries as well as country-specific factors. Trade conflicts and uncertainty led to stagnation in trade, dragging down business sentiment and activity globally. Geopolitical tensions, Brexit and rising policy uncertainty have influenced investments and resulted in sluggish consumer demand and weaker industry production. Central banks have reacted to the weaker activity with loosened monetary policy that has averted a deeper slowdown.

The estimated growth rate for the US in 2019 is 2.3%. Business investment and the manufacturing sector represented significant drags on growth during the year, reflecting rising protectionism and elevated policy uncertainty. However, the private sector has shown resilience, supported by employment growth and persistently low interest rates. In China, uncertainty and escalating tariffs on export to the US had a negative effect on industry production and investment throughout the year. Estimated growth ended at 6.1% for 2019. It was a troublesome year for the Eurozone, with threats of increased tariffs on export to US and Brexit. Despite gaining some momentum towards year-end, the Eurozone growth rate for the year is estimated at 1.2%.

Looking ahead, early signs of stabilization in manufacturing activity and trade could persist and reinforce the link between the resilient consumer sector and improved business spending. In addition, the effects of monetary easing across economies in 2019 are expected to continue working their way through the global economy in 2020. However, downside risk remains significant, including the potential for further worsening in the US-China relations, rising geopolitical tensions, as well as the effects of Covid-19 virus, keeping the global economic growth forecast modest.

### Oil prices and refining margins

The average price for Dated Brent in 2019 was USD 64.3 per barrel, 10% lower than USD 71.1 per barrel in 2018. Prices were less volatile than in 2018, staying mostly within the USD 60-70 range, despite multiple disruptions both to supply and demand throughout the year. The Organization of the Petroleum Exporting Countries and its allies (Opec+) continued attempts to balance an oversupplied market amidst weaker oil demand growth impacted by the US-China trade conflict.

Even though in December 2018 the Opec+ group agreed to renew the supply cuts, 2019 started with an oversupplied market. Nonetheless, prices recovered from around USD 50 per barrel at the end of December 2018 to around USD 62 per barrel by the end

12 Equinor, Annual Report on Form 20-F 2019

of January 2019. The upward trend continued during the first quarter, supported by a new round of US sanctions on Venezuela and Iran, removing more supply from the market, on top of the agreed Opec+ cuts.

Dated Brent reached its highest in April and May at above USD 70 per barrel, driven by pressure on supply due to increased tensions in the Middle East, mainly in Saudi Arabia, following the US decision not to extend import waivers for Iranian oil.

However, subsequently prices weakened again, hovering around USD 64 per barrel in June and July. The extension of the Opec+ cuts and continuous threats in the Middle East, including tanker attacks in the strait of Hormuz, did not balance out the perceived impact of the increase in global supply and the negative impact of the US-China trade war on oil demand growth.

One of the major events in 2019 was the September attack on Saudi Arabian oil processing plants that decreased temporarily global supply by around 5% (~5 mmboe per day). However, after a one-day surge to USD 68.2 per barrel, prices stabilized at around USD 60 per barrel by end of September. This underlined the sentiment of oversupply and concerns mostly focused on signs of weaker demand growth.

Nevertheless, as the trade talks between US and China started to show positive signals, prices started to rally in November, also supported by many refineries coming out of maintenance. Dated Brent in November averaged USD 63.0 per barrel.

2019 ended on an upward trend, with average Dated Brent price at USD 67.0 per barrel in December. Faced with further oversupply in 2020, the Opec+ alliance decided to extend and increase the cut agreement at the meeting in Vienna early in December. As the date for the US-China trade deal was announced, and expected in January, the market welcomed 2020 with a fresh wave of optimism towards oil demand growth.

Recently, there has been price volatility, triggered, among other things by the changing dynamic among Opec+ members and the uncertainty regarding demand created by the Covid-19 pandemic.

Refinery margins

For a standard upgraded refinery in North-West Europe, margins were slightly stronger than in 2018. Margins were weak in the first two months of 2019, but then gradually rose to a peak in October before dropping towards year-end. One distinct feature in 2019 was the preparation for producing IMO 2020 fuel, the low-sulphur bunker fuel for ships to be sold from year-end. This led to strong margins for low-sulphur fuel oil components already from July, due to purchases for storage. That again gave unusually strong margins for low complex refineries that ran on light, low-sulphur crudes.

Margins for the high-sulphur HSFO bunker fuel fell slowly until early October, when they collapsed. That gave weak margins for refineries running heavy, high-sulphur crude oils and having a substantial yield of HSFO.

Margins for naphtha were weak through the year. Being the main feedstock for the petrochemical industry, it was hurt by a low demand for petrochemical products, ascribed to the US-China trade conflict. Gasoline margins were depressed by high US stock levels early in the year but were normal through summer. Diesel margins were normal and on par with 2018. A peak in October was due to purchase for storage by those who believed that marine diesel would become the IMO 2020 fuel. Refinery margins are calculated as the relevant product prices against physical dated Brent crude oil. However, product prices are generally traded and set against the Brent prices in the paper market at the ICE exchange. Strength in dated Brent vs. ICE therefore tends to depress refinery margins, and vice versa. Specific strength in dated Brent depressed margins in June and in the last one and a half month of the year.

### Natural gas prices

Gas prices – Europe

The National Balancing Point (NBP) in the UK started 2019 at
7.5 USD/MMBtu, down 8% from December 2018. Abundant LNG availability, high pipeline flows as well as mild weather contributed to a decreasing trend in European prices during the first quarter. In addition, winter storage inventories remained well above the five-year average. In late March, Asian LNG prices dropped below NBP at 5.2 USD/MMBtu, increasing the incentive for LNG to go to Europe rather than Asia. European prices continued to decline during the second quarter and reached 3.5 USD/MMBtu in June. Record high temperatures and start of the maintenance season provided some support to NBP during July, but in August prices fell again. Despite another round of maintenance on Norwegian assets in September, prices lacked support and remained below 3.5 USD/MMBtu. NBP recovered towards the end of the year due to colder weather and uncertainty related to the Russia-Ukraine transit agreement, closing the year at 4.2 USD/MMBtu.

Gas prices – North America

The Henry Hub price showed a downward trend during 2019, averaging 2.5 USD/MMBtu for the year, compared to
3.1 USD/MMBtu in 2018. High dry gas production, driven by the addition of pipeline capacity in the Northeast and Texas put downward pressure on the price. Storage levels rose above the five-year average for the first time in two years. Demand gains have not been able to keep pace with supply growth, despite more than 20 Bcm of new LNG capacity entering service in 2019, as well as record demand in Mexican pipeline exports and the gas-to-power sector.

Equinor, Annual Report on Form 20-F 2019 13

Global LNG prices

Asian LNG prices started the first quarter at 8.2 USD/MMBtu but fell steadily to 5.2 USD/MMBtu in March. Ample supply, as newly started LNG liquefaction trains ramped up to nameplate capacity, and lack of prompt demand have weighed on LNG prices. During the second and third quarters, the oversupply situation continued, forcing significant volumes of LNG into European storages. As a result, prices reached a low of
4.2 USD/MMBtu. In the fourth quarter, Asian LNG prices recovered with the start of the heating season. However, high nuclear availability in Japan and above-normal winter temperatures resulted in an average of 5.8 USD/MMBtu for the quarter, well below the fourth quarter average price of 9.9 USD/MMBtu in 2018.

European electricity and CO2 prices

Western European (United Kingdom, France, Germany, Belgium, Netherlands, Spain and Italy) electricity prices averaged
43.9 EUR/MWh in 2019, which was 20% lower than in 2018. While 2019 began strong with prices around 61 EUR/MWh for January, milder weather, a quick decrease in the underlying fuel prices, better nuclear availability and a further increase in renewable capacity drove the electricity prices down. The average price was already at around 42 EUR/MWh in March and trended down to end the year at an average of 38 EUR/MWh in December.

The European Union Emission Trading System (EU ETS) CO2 price continued its strength in 2019, at an average of
24.9 EUR/tonne. Prices peaked in July, with the highest closing price at 29.8 EUR/tonne. Throughout the year, the CO2 price suffered from volatility due to uncertainties surrounding Brexit and various energy policy announcements, such as the decision to phase out coal-fired power generation in Germany by 2038.

Although the high CO2 price put pressure on the power generation costs, the bearish conditions such as above average temperatures, low gas prices and growth in renewables, more than offset this pressure. Nevertheless, the high CO2 price helped to further accelerate the coal to gas switch in European power generation, consequently driving down CO2-emissions from the sector.

## Equinor’s corporate strategy

Equinor is an international energy company committed to long-term value creation in a low carbon future inspired by its vision of shaping the future of energy.

Equinor continues to pursue its strategy of always safe, high value and low carbon through developing and maximising the value of its unique Norwegian continental shelf position, its international oil and gas business, its manufacturing and trading activities and its growing new energy business.

The energy context is expected to remain volatile characterised by geopolitical shifts, challenges in liquids- and gas resource replenishments, market cyclicality, structural changes to costs and increasing momentum towards low carbon. Equinor expects volatility in energy prices. Equinor’s strategic response is focused on creating value by building a more resilient, diverse, and option-rich portfolio, delivered by an empowered organisation. To do so, Equinor will continue to concentrate its strategy realisation and development around the following areas:

· Norwegian continental shelf – transform the NCS to deliver sustainable value for decades

· International oil and gas – deepen core areas and develop growth options

· New energy solutions – value driven growth in renewables

· Midstream and marketing – secure premium market access and grow value creation through economic cycles

Equinor’s unique position at the Norwegian continental shelf has enabled the company to develop new technologies and scale them industrially. Equinor has today a strong set of industrial value drivers:

· Operational excellence

· World-class recovery

· Leading project deliveries

· Premium market access

· Digital leadership

In sum, these drivers strengthen the company’s competitiveness. Internationally, Equinor is increasingly taking the role of operator, allowing the company to leverage its industrial value drivers. Across its business, Equinor is targeting opportunities that play to its strength.

14 Equinor, Annual Report on Form 20-F 2019

Johan Sverdrup, NCS.

Equinor, Annual Report on Form 20-F 2019 15

Equinor is actively shaping its future portfolio guided by the following strategic principles:

· 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 economic cycles

· Capex flexibility – having sufficient flexibility in organic capital expenditure to be able to respond to market downturns and avoid value destructive measures as well as ability to always prioritise projects expected to deliver greater value.

· Capture value from cycles – ensuring the ability and capacity to act counter-cyclically to capture value through the cycles

· 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

To deliver on the strategy, Equinor has identified four key strategic enablers that will continue to support the business’s needs:

· Safe and secure operations: The safety and security of its people and the integrity of its operations is Equinor’s top priority. In 2019 several strategic improvement initiatives were carried out guided by the corporate wide project “Safety beyond 2020”. The goal has been to further strengthen culture and drive performance through embedding safety and security thinking and proactive behaviour at all organisational levels. Equinor has continued its efforts to reinforce the security culture and capability through implementation of the 2020 Security Roadmap, and an Information Technology Strategy which aims at protecting people and assets against digital threats.

· Technology and innovation: Equinor recognises technology and innovation as enablers for its strategy. Equinor’s technology strategy guides the company’s technology development and implementation activities, providing technologies to shape the future of energy. While Equinor conduct in-house R&D in areas that give us a competitive advantage, the majority of its activities are conducted in collaboration with partners to ensure that Equinor makes the best use of the external technology eco-system. Equinor continues to invest in digitalisation to unlock the value from its data. In 2019, USD 400 million (pre-tax) was delivered in cash flow impact from digital initiatives, which enabled a month earlier start-up of Johan Sverdrup by leveraging new digital solutions as well as increased uptime driven by Equinor’s integrated operations centre.

· Empowered people: Equinor promotes a culture of collaboration, innovation, and safety, guided by its values. A diverse and inclusive Equinor continues to recruit and develop employees to deliver on the future-fit portfolio ambition.

· Stakeholder engagement: Equinor engages with stakeholders to secure industrial legitimacy, its social contract, trust, and strategic support from stakeholders. This engagement extends to internal and external collaboration, partnerships, and other co-operation with suppliers, partners, governments, NGOs, and communities in which Equinor operates.

Equinor maintains its 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. Equinor believes a lower carbon footprint will make it more competitive in the future and sustainability is integrated in Equinor’s strategic work.

Equinor’s new climate roadmap presents a series of short-, mid- and long-term ambitions to reduce its own greenhouse gas emissions and to ensure a competitive and resilient business model in the energy transition, fit for long term value creation and in line with the Paris Agreement:

16 Equinor, Annual Report on Form 20-F 2019

Peregrino FPSO, Brazil.

Equinor aims to:

· reduce the net carbon intensity, from initial production to final consumption, of energy produced by at least 50% by 2050,

· grow renewable energy capacity tenfold by 2026, developing as a global offshore wind major, and

· strengthen its industry leading position on carbon efficient production, aiming to reach carbon neutral global operations by 2030.

Equinor expects to meet the net carbon intensity ambition primarily through significant growth in renewables and changes in the scale and composition of its oil and gas portfolio. In addition, operational efficiency and further development of new businesses such as carbon capture, utilisation and storage (CCUS) and hydrogen are expected to be important. Equinor may also use recognised offset mechanisms and natural sinks as a supplement. To reach carbon neutral global operations, the main priority will be to reduce GHG emissions from Equinor’s own operations. Remaining emissions are expected to be compensated either through quota trading systems, such as the European Union Emissions Trading System (EU ETS), or high-quality offset mechanisms. Further information can be found in section 2.12 Safety, security and sustainability.

Norwegian continental shelf – Transforming the NCS for continued high value creation and low carbon emissions for the coming decades

For more than 40 years, Equinor has explored, developed, and produced oil and gas from the NCS. It represents approximately 60% of Equinor’s equity production at 1.235 million boe per day in 2019. NCS cash generation capacity will continue to be substantial going forward, even at lower oil- and gas prices.

At the same time, Equinor aims to continue to improve the efficiency, reliability, carbon emissions, and lifespan of fields already in production. During 2019, Equinor updated the climate ambitions for Norway. Driven by a large remaining resource potential on the NCS, Equinor aims to reduce the absolute greenhouse gas emissions from its operated offshore installations and onshore plants in Norway with 40% by 2030, 70% by 2040, and towards near zero by 2050, compared to 2005. The 2030 ambition alone is expected to require investments of around NOK 20 billion Equinor share, in projects within energy efficiency, electrification, infrastructure consolidation, digitalization, and new value chains, such as CCS and Hydrogen.

Equinor has decided to create a new unit for its late life assets on the NCS. The purpose of the new unit is to realise the full potential of its late life fields, by realising additional subsurface potential, lean operations, cost efficient lifetime extensions, and decommissioning cost reductions.

Equinor continues to add highly profitable barrels through increased oil and gas recovery and Equinor is making progress towards the ambition of 60% oil recovery and 85% gas recovery for operated fields.

In July, Equinor agreed with Lundin Petroleum AB to divest a 16% shareholding in Lundin Petroleum for a direct interest of 2.6% in the Johan Sverdrup field and a cash consideration. In October, the Johan Sverdrup field came on stream, ahead of schedule and below cost, and with a world class ramp-up, the field is already producing more than 350 mboe per day (100%). In the next few years, Equinor aims to bring several large projects on stream including Johan Sverdrup phase 2, Troll phase 3, Johan Castberg, and Martin Linge, and the refurbished Njord, in addition to a large number of subsea tiebacks. Strong overall volume growth is expected towards a potential historically high production level in 2026. More information on assets in operations and projects under development in Norway is provided in section 2.3 E&P Norway – Exploration & Production Norway.

International oil and gas – Deepen core areas and develop growth options

Equinor has been growing its international portfolio for over 25 years. International oil and gas production represented approximately 40% of Equinor’s equity production at 0.839 million boe per day in 2019. In 2019, Equinor made significant progress in growing and de-risking its international oil and gas portfolio: successful start-ups of both Mariner and Utgard in the UK; high value license extensions in Angola Blocks 15 and 17; access to new acreage both onshore and offshore in Argentina, on the UK Continental shelf, offshore Canada, and in US GoM; ACE development sanction in Azerbaijan; investment decision on the first stage of the North Komsomolskoye full field development in Russia. Key projects in Equinor’s international project portfolio include Bay du Nord, Rosebank, Vito, Peregrino phase 2, Bacalhau (formerly Carcará), BM-C-33, North Komsomolskoye, North Platte, and Block 17 satellites in Angola.

In Argentina Equinor is building a broad energy company – onshore production in Vaca Muerta, 8 new oil & gas leases across various basins offshore, and within onshore wind and solar.

In the United States, Equinor high-graded its onshore portfolio through the divestment of Eagle Ford and increased its equity share in Caesar Tonga in the Gulf of Mexico. Equinor continues to focus on increasing and sustaining the profitability of existing portfolio. With drone technology, Equinor has significantly reduced methane emissions from onshore operations.

In Brazil, Equinor is sustaining and growing a competitive portfolio of high-quality assets in all development phases, including a promising exploration portfolio. The Bacalhau field FPSO concept is an example of project optimization, while reducing carbon emissions.

Equinor, Annual Report on Form 20-F 2019 17

Equinor is set up for growing with quality and expects its international business to grow steadily for a long time, with an organic cash flow contribution of USD 7 billion after tax and investments over the next 4 years at 65 USD per bbl. Equinor is focused on continuing to deliver improvements on cost, cashflow, and earnings to increase competitiveness across its international portfolio. Equinor aims at reducing carbon intensity across the operated international portfolio, to ambition level of <10kg CO2 per boe by 2025. More information on assets in operation and projects under development internationally is provided in section 2.4 E&P International – Exploration & Production International.

New energy solutions – Develop a high value renewable business

The renewable market is changing and growing at unprecedented pace, presenting opportunities for decades of growth. Equinor has a strong renewable portfolio in production and is leveraging its core competencies in managing complex oil and gas projects when growing in offshore wind. By 2026 Equinor expects to increase installed capacity from renewable projects to between 4 and 6 GW[4], Equinor share, mainly based on the current project portfolio. This is around 10 times higher than today’s capacity, implying an annual average growth rate of more than 30% in electricity production. Towards 2035, Equinor expects to increase installed renewables capacity further to between 12 and 16 GW, depending on availability of attractive project opportunities. Equinor expects to spend USD 0.5-1 billion in 2020-2021 and USD 2-3 billion in 2022-2023 (Annual gross capex before project financing, Equinor share, organic net capex 2022-2023 below USD 1.5 billion on average annually).

Becoming a global offshore wind major

The last year has been transformational for Equinor’s offshore wind portfolio. With the recent additions of Dogger Bank (UK) and Empire Wind (US), Equinor is on the path to becoming a global offshore wind major. Dogger Bank is expected to be the world’s largest offshore wind farm development with an installed capacity of 3.6GW and a total potential of more than 20GW - enough to supply one third of UK electricity demand. Empire Wind will provide renewable electricity to one of the busiest cities in the world: New York City. With a capacity of 816MW, it is expected to deliver power to the equivalent of one million homes.

Equinor has a decade of operating experience from floating offshore wind. Up to 80% of the world’s offshore wind potential will likely require floating solutions and Equinor is well positioned to industrialise floating wind. Equinor’s ambition is to bring floating wind towards commerciality by 2030.

Opportunities in onshore renewables

Equinor believes in diversifying its offshore wind business and pursuing additional growth options. Having a flexible portfolio gives Equinor the ability to provide power from numerous renewable energy sources including offshore wind, solar, and onshore wind. Over time Equinor expects to build profitable onshore positions in select power markets.

In December 2019, Equinor acquired 6.500.000 shares in Scatec Solar, corresponding to 5.2% of the shares and votes. Following the transaction Equinor owns a total of 18.965.400 shares of Scatec Solar, raising its total shareholding to 15.2% of the shares and votes. Equinor is present in two solar projects in South America (Brazil and Argentina). More information on new energy assets in operation and projects under development is provided in section 2.6 Other group.

Midstream and marketing – Secure premium market access and grow value creation through economic cycles

The main objective for Equinor’s Midstream, Marketing & Processing unit’s (MMP) mid- and downstream activities is to process and transport Equinor’s oil and gas production (including the Norwegian State’s petroleum) competitively to premium markets, realising maximum value. In addition, MMP is expanding its marketing of a growing electricity portfolio. Focus in 2019 has been on:

· Safe, secure, and efficient operations

· Securing flow assurance and premium market access for Equinor’s equity production and the Norwegian State’s direct financial interest volumes

· Building and maintaining resilience through asset backed trading, value chain positioning, and counter-cyclical actions

· Reducing carbon emissions and carbon intensity from its operations

· Optimising regional piped gas value chains and pursuing selective trading positions in liquefied natural gas (LNG)

· Renewing the contracted shipping portfolio with ships that are more efficient and have less emissions.

Since Equinor’s closing of the acquisition of Danske Commodities (DC) on 1 February 2019, Equinor and DC have realised several synergies, including positioning DC as Equinor’s route-to-market for renewables. In early fall, DC entered the American power market and building on this successful market entry, Equinor and DC are looking at entering additional power markets. More information on mid- and downstream activities is provided in section 2.5 MMP – Marketing, Midstream & Processing.

## G roup outlook

Equinor’s plans address the current business environment while continuing to invest in high-quality projects. Equinor continues to reiterate its efforts and commitment to deliver on its strategy.

[4] Including 15.2% equity in Scatec Solar ASA

18 Equinor, Annual Report on Form 20-F 2019

· Organic capital expenditures[5] are estimated at an annual average of USD 10-11 billion for 2020-2021 and around
USD 12 billion annual average for 2022-2023

· Equinor intends to continue to mature its large portfolio of exploration assets and estimates a total exploration activity level of around USD 1.4 billion for 2020, excluding signature bonuses and field development costs

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

· For the period 2019 – 2026, production growth[6] is expected to come from new projects resulting in around 3% CAGR (Compound Annual Growth Rate)

· Production6 for 2020 is estimated to be around 7% above 2019 level

· Scheduled maintenance activity is estimated to reduce the quarterly production by approximately 20 mboe per day in the first quarter of 2020. In total, maintenance is estimated to reduce equity production by around 45 mboe per day for the full year of 2020

· Renewable equity generation capacity in 2026 is expected to be between 4 and 6 GW (this includes 15.2% share of Scatec Solar ASA)

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. Deferral of production to create future value, gas off-take, timing of new capacity coming on stream, operational regularity, impact of Covid-19, activity level in the US onshore, as well as uncertainty around the closing of the announced transactions represent the most significant risks related to the foregoing production guidance. In particular, recently there has been considerable uncertainty created by the Covid-19 pandemic as well as the changing dynamics among Opec+ members. We are unable to predict the impact of these events. For further information, see section 5.7 Forward-looking statements.

[5] See section 5.2 for non-GAAP measures.

[6] The production guidance reflects our estimates of proved reserves calculated in accordance with US Securities and Exchange Commission (SEC) guidelines and additional production from other reserves not included in proved reserves estimates. The growth percentage is based on historical production numbers, adjusted for portfolio measures.

Equinor, Annual Report on Form 20-F 2019 19

# 2.2 # Business overview

# History in brief

18 September 1972

Equinor, formerly 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. At the time owned 100% by the Norwegian State, Equinor'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, Equinor’s operations were primarily focused on exploration, development and production of oil

and gas on the Norwegian continental shelf (NCS).

1979 – 1981

The Statfjord field was discovered in the North Sea

and commenced production. In 1981 Equinor was the first Norwegian company to be given operatorship

for a field, at Gullfaks in the North Sea.

1980s and 1990s

Equinor grew substantially through the development of the NCS (Statfjord, Gullfaks, Oseberg, Troll and others). Equinor 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 these decades, Equinor was also involved in manufacturing and marketing in Scandinavia and established a comprehensive network of service stations. This line of business was fully divested in 2012.

2001

Equinor was listed on the Oslo and New York stock exchanges and became a public limited company under the name Statoil ASA, now Equinor ASA, with a 67% majority stake owned by the Norwegian State.

2007 - 2018

Equinor’s ability to fully realise the potential of the NCS and grow internationally was strengthened through the merger with Norsk Hydro's oil and gas division on 1 October 2007. Equinor’s business grew as a result of substantial investments on the NCS and internationally. Equinor delivered the world’s longest multiphase pipelines on the Ormen Lange and Snøhvit gas fields, and the giant Ormen Lange development project was completed in 2007. Equinor also expanded into Algeria, Angola, Azerbaijan, Brazil, Nigeria, UK, and the US Gulf of Mexico, among others. Equinor’s US onshore operations represents its largest international production outside Norway, and with the Peregrino field, Equinor is the largest international operator in Brazil.

2018

Statoil ASA changed its name to Equinor ASA following approval of the name change by the company’s annual general meeting on 15 May 2018. The name supports the company’s strategy and development as a broad energy company in addition to reflecting Equinor’s evolution and identity as a company for the generations to come.

2019 and present

Equinor’s access to crude oil in the form of equity, governmental and third-party volumes makes Equinor a large seller of crude oil, and Equinor is the second-largest supplier of natural gas to the European market. Processing, refining, offshore wind and carbon capture and storage are also part of our operations.

In recent years, Equinor has utilised its expertise to design and manage operations in various environments to grow upstream activities outside the traditional area of offshore production. This includes the development of shale oil and gas projects.

As part of Equinor’s strategy, the company is investing actively in new energy, such as offshore wind, and solar energy, in order to expand energy production, strengthen energy security and combat climate change.

Equinor operates in more than 30 countries and as of 31 December 2019 employs 21,412 people worldwide.

Equinor’s registered office is at Forusbeen 50, 4035 Stavanger, Norway. The telephone number of its registered office is +47 51 99 00 00.

20 Equinor, Annual Report on Form 20-F 2019

## Equinor’s 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, Equinor competes with other integrated oil and gas companies.

Equinor continues to explore new business opportunities in offshore wind, solar, hydrogen and carbon capture, usage and storage (CCUS). Improvements in cost and technology for renewables have rapidly changed the landscape. Equinor is a player within the renewables business.

Equinor'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 and utilise new opportunities for digitalisation.

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

Equinor, Annual Report on Form 20-F 2019 21

Equinor’s value chain

# Corporate structure

Equinor is a broad international energy company, its value chain includes most phases from exploration of hydrocarbons through developing, production and manufacturing, marketing and trading, and a growing renewables business. Equinor’s operations are managed through eight business areas: Development & Production Norway (DPN), Development & Production International (DPI), Development & Production Brazil (DPB), Marketing, Midstream & Processing (MMP), New Energy Solutions (NES), Technology, Projects & Drilling (TPD), Exploration (EXP) and Global Strategy & Business Development (GSB). The business areas are aggregated into four reporting segments; E&P Norway, E&P International, MMP and Other. For more information, see Segment reporting later in this chapter.

On 28 April 2018, Equinor announced changes in its business area structure to strengthen its ability to deliver on Equinor’s always safe, high value and low carbon strategy as Equinor develops as a broad energy company. DPB was established as a separate business area representing a new core geographic area, holding promising offshore oil and gas basins with a significant resource base. Equinor’s US operations were integrated in DPI as US operations have been maturing over the last few years. Equinor is pursuing unconventional onshore business opportunities globally and sees synergies in having US onshore operations which are organised within DPI.

Development & Production Norway (DPN)

Managing Equinor’s upstream activities on the NCS, DPN explores for and extracts crude oil, natural gas and natural gas liquids in the North Sea, the Norwegian Sea and the Barents Sea. DPN aims to ensure safe and efficient operations and transform the NCS to deliver sustainable value for many decades. DPN is shaping the future of the NCS with a digital transformation and solutions to achieve a lower carbon footprint and high recovery rates.

Development & Production International (DPI)

DPI manages Equinor’s worldwide upstream activities in all countries outside Norway and Brazil. DPI operates across six continents covering offshore and onshore exploration and extraction of crude oil, natural gas and natural gas liquids; and implementing rigorous safety standards, technological innovations and environmental awareness. DPI's intent is to build and grow a competitive international portfolio - always safe, high value and low carbon.

Development & Production Brazil (DPB)

DPB manages the development and production of oil and gas resources in Brazil, which Equinor considers to be a core area for long-term growth. Equinor has a diverse portfolio in Brazil with activities in all development stages from exploration to production. Most of Brazil licences are in deep-water areas, some of them more than 2,900 metres deep. Equinor has been producing in Brazil since 2011 with the Peregrino field, in the Campos Basin. DPB intends to grow a competitive portfolio creating value by increasing capacity and increasing recovery from mature fields, while reducing emissions and focusing on safety as priority.

22 Equinor, Annual Report on Form 20-F 2019

Marketing, Midstream & Processing (MMP)

MMP works to maximise value creation in Equinor’s global midstream and downstream positions. MMP is responsible for global marketing and trading of crude, petroleum products, natural gas and electricity, including marketing of the Norwegian State’s natural gas and crude on the Norwegian continental shelf. MMP is also responsible for onshore plants and transportation in addition to the development of value chains to ensure flow assurance for Equinor’s upstream production and to maximise value creation.

New Energy Solutions (NES)

NES reflects Equinor’s long-term goal to complement Equinor’s oil and gas portfolio with profitable renewable energy and other low-carbon energy solutions. NES is responsible for wind farms and carbon capture and storage as well as other renewable energy and low-carbon energy solutions. NES aims to do this by combining Equinor’s oil and gas competence, project delivery capacities and ability to integrate technological solutions.

Technology, Projects & Drilling (TPD)

TPD is responsible for field development, well deliveries, technology development and procurement in Equinor. TPD aims to deliver safe, secure and efficient field development, including well construction, founded on world-class project execution and technology excellence. TPD utilises innovative technologies, digital solutions and carbon-efficient concepts to shape a competitive project portfolio at the forefront of the energy industry transformation. Sustainable value is being created together with suppliers through a simplified and standardised fit-for-purpose approach.

Exploration (EXP)

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

Global Strategy & Business Development (GSB)

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

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

As required by the SEC, Equinor prepares its disclosures about oil and gas reserves and certain other supplementary oil and gas disclosures based on geographic areas. Equinor’s geographical areas are defined by country and continent and consist of Norway, Eurasia excluding Norway, Africa, US and Americas excluding US. For more information, see section 4.2 Supplementary oil and gas information (unaudited) in the Financial statements and supplements chapter.

## Segment reporting

The business areas DPI and DPB are aggregated into the reporting segment Exploration & Production International (E&P International). The basis for this aggregation is similar economic characteristics, such as the assets’ long term and capital-intensive nature and exposure to volatile oil and gas commodity prices, the nature of products, service and production processes, the type and class of customers, the methods of distribution and regulatory environment. The reporting segments Exploration & Production Norway (E&P Norway) and MMP consists of the business areas DPN and MMP respectively. The business areas NES, GSB, TPD, EXP and corporate staffs and support functions are aggregated into the reporting segment “Other” due to the immateriality of these areas.

Most of the costs within the business areas GSB, TPD and EXP are allocated to the E&P International, E&P Norway and MMP reporting segments. Activities relating to the EXP business area are fully allocated to the relevant E&P reporting segments. Activities relating to the TPD, GSB business areas and corporate staffs and support functions are partly allocated to the relevant E&P and MMP reporting segments.

Internal transactions in oil and gas volumes occur between reporting segments before such volumes are sold in the market. Equinor has established a market-based transfer pricing methodology for the oil and natural gas intercompany sales and purchases that meets the requirements for applicable laws and regulations. For further information, see section 2.8 Operational performance under Production volumes and prices.

Equinor, Annual Report on Form 20-F 2019 23

Equinor eliminates intercompany sales when combining the results of reporting segments. Intercompany sales include transactions recorded in connection with oil and natural gas production in the E&P Norway and the E&P International reporting segments, and in connection with the sale, transportation or refining of oil and natural gas production in the MMP reporting segment. Certain types of transportation costs are reported in both the MMP and the E&P International segments.

The E&P Norway segment produces oil and natural gas which is sold internally to the MMP segment. A large share of the oil produced by the E&P International segment is also sold through the MMP segment. The remaining oil and gas from the E&P International segment is sold directly in the market. In 2019, the average transfer price for natural gas for E&P Norway was USD 4.46 per mmbtu. The average transfer price was USD 5.65 per mmbtu in 2018. For the oil sold from the E&P Norway reporting segment to the MMP reporting segment, the transfer price is the applicable market-reflective price minus a cost recovery rate.

24 Equinor, Annual Report on Form 20-F 2019

The following table shows certain financial information for the four reporting segments, including intercompany eliminations for the two-year period ending 31 December 2019.

For additional information, see note 3 Segments to the Consolidated financial statements.

Segment performance |  |
| For the year ended 31 December
(in USD million) | 2019 | 2018
Exploration & Production Norway |  |
Total revenues and other income | 18,832 | 22,475
Net operating income/(loss) | 9,631 | 14,406
Non-current segment assets1) | 33,795 | 30,762
Exploration & Production International |  |
Total revenues and other income | 10,325 | 12,399
Net operating income/(loss) | (800) | 3,802
Non-current segment assets1) | 37,558 | 38,672
Marketing, Midstream & Processing |  |
Total revenues and other income | 60,955 | 75,794
Net operating income/(loss) | 1,004 | 1,906
Non-current segment assets1) | 5,124 | 5,148
Other |  |
Total revenues and other income | 624 | 280
Net operating income/(loss) | 92 | (79)
Non-current segment assets1) | 4,214 | 353
Eliminations2) |  |
Total revenues and other income | (26,379) | (31,355)
Net operating income/(loss) | (629) | 103
Non-current segment assets1) | - | -
Equinor group |  |
Total revenues and other income | 64,357 | 79,593
Net operating income/(loss) | 9,299 | 20,137
Non-current segment assets1) | 80,691 | 74,934
1) | Equity accounted investments, deferred tax assets, pension assets and non-current financial assets are not allocated to segments. Right of use assets according to IFRS16 are included in Other segment from 2019.
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.

Equinor, Annual Report on Form 20-F 2019 25

The following tables show total revenues and other income by country.

2019 Total revenues and other income by country | Crude oil | Natural gas | Natural gas liquids | Refined products | Other | Total
(in USD million)
Norway | 25,106 | 9,525 | 4,674 | 6,334 | 611 | 46,250
US | 7,120 | 1,353 | 1,132 | 1,697 | 229 | 11,532
Denmark | 0 | 12 | 0 | 2,580 | 191 | 2,783
Brazil | 1,099 | 19 | 0 | 0 | 560 | 1,678
Other | 180 | 372 | 0 | 41 | 1,358 | 1,951
Total revenues and other income1) | 33,505 | 11,281 | 5,807 | 10,652 | 2,949 | 64,194
1) Excluding net income (loss) from equity accounted investments

2018 Total revenues and other income by country | Crude oil | Natural gas | Natural gas liquids | Refined products | Other | Total
(in USD million)
Norway | 30,221 | 11,953 | 5,969 | 8,299 | 1,971 | 58,412
US | 9,113 | 1,575 | 1,198 | 1,790 | 444 | 14,120
Denmark | 0 | 0 | 0 | 2,533 | 22 | 2,556
United Kingdom | 653 | 0 | 0 | 0 | 124 | 777
Other | 962 | 543 | 0 | 502 | 1,430 | 3,436
Total revenues and other income1) | 40,948 | 14,070 | 7,167 | 13,124 | 3,991 | 79,301
1) Excluding net income (loss) from equity accounted investments

## R esearch and development

Technology and innovation are identified as enablers to deliver on Equinor’s strategy. We continually research, develop and implement innovative technologies to create opportunities and enhance the value of Equinor’s current and future assets.

Our technology strategy sets the direction for technology development and implementation to meet Equinor’s ambitions. We prioritise and accelerate high-value technologies for broad implementation in existing and new value chains:

· Optimise production from existing and near field resources

· Low carbon solutions for oil and gas

· Discover and develop prolific basins and deep-water areas

· Unlock low recovery reservoirs

· Develop renewable energy opportunities

We utilise a range of tools for the development of new technologies:

· In-house research and development

· Cooperation with academia, research institutes and suppliers

· Project-related development as part of field development activities

· Direct investment in technology start-up companies through Equinor Technology Venture’s investment activities

· Invitation to open innovation challenges as part of Equinor Innovate

For additional information, see note 7 Other expenses to the Consolidated financial statements.

26 Equinor, Annual Report on Form 20-F 2019

Key figures |  |  |  |  |
(in USD million, unless stated otherwise) | For the year ended 31 December
2019 | 2018 | 2017 | 2016 | 2015
Financial information |  |  |  |  |
Total revenues and other income | 64,357 | 79,593 | 61,187 | 45,873 | 59,642
Operating expenses | (9,660) | (9,528) | (8,763) | (9,025) | (10,512)
Net operating income/(loss) | 9,299 | 20,137 | 13,771 | 80 | 1,366
Net income/(loss) | 1,851 | 7,538 | 4,598 | (2,902) | (5,169)
Non-current finance debt | 24,945 | 23,264 | 24,183 | 27,999 | 29,965
Net interest-bearing debt | 16,429 | 11,130 | 15,437 | 18,372 | 13,852
Total assets | 118,063 | 112,508 | 111,100 | 104,530 | 109,742
Total equity | 41,159 | 42,990 | 39,885 | 35,099 | 40,307
Net debt to capital employed ratio1) | 28.5% | 20.6% | 27.9% | 34.4% | 25.6%
Net debt to capital employed ratio adjusted1) | 23.8% | 22.2% | 29.0% | 35.6% | 26.8%
ROACE2) | 9.0% | 12.0% | 8.2% | -0.4% | 4.1%
Operational data |  |  |  |  |
Equity oil and gas production (mboe/day) | 2,074 | 2,111 | 2,080 | 1,978 | 1,971
Proved oil and gas reserves (mmboe) | 6,004 | 6,175 | 5,367 | 5,013 | 5,060
Reserve replacement ratio (annual) | 0.75 | 2.13 | 1.50 | 0.93 | 0.55
Reserve replacement ratio (three-year average) | 1.47 | 1.53 | 1.00 | 0.70 | 0.81
Production cost equity volumes (USD/boe) | 5.3 | 5.2 | 4.8 | 5.0 | 5.9
Average Brent oil price (USD/bbl) | 64.3 | 71.1 | 54.2 | 43.7 | 52.4
Share information3) |  |  |  |  |
Diluted earnings per share (in USD) | 0.55 | 2.27 | 1.40 | (0.91) | (1.63)
Share price at OSE (Norway) on 31 December (in NOK) | 175.50 | 183.75 | 175.20 | 158.40 | 123.70
Share price at NYSE (USA) on 31 December (in USD) | 19.91 | 21.17 | 21.42 | 18.24 | 13.96
Dividend paid per share (in USD)4) | 1.01 | 0.91 | 0.88 | 0.88 | 0.90
Weighted average number of ordinary shares outstanding (in millions) | 3,326 | 3,326 | 3,268 | 3,195 | 3,179
1) | See section 5.2 Use and reconciliation of non-GAAP financial measures for net debt to capital employed ratio.
2) | See section 5.2 Use and reconciliation of non-GAAP financial measures for return on average capital employed (ROACE).
3) | See section 5.1 Shareholder information for a description of how dividends are determined and information on share repurchases.
4) | For 2019, dividend for the third and for the fourth quarter of 2018 and dividend for the first and second quarter of 2019 were paid. For 2018, dividends for the third and fourth quarter 2017 and the first and second quarter 2018 were paid. From and including the third quarter of 2015, dividends were declared in USD. Dividends in previous periods were declared in NOK. Figures for 2015 are presented using the Central Bank of Norway year end rates for NOK.

Equinor, Annual Report on Form 20-F 2019 27

# 2.3 # Exploration & Production Norway (E&P Norway)

Johan Sverdrup, NCS.

## Overview

The Exploration & Production Norway segment covers exploration, field development and operations on the NCS, which includes the North Sea, the Norwegian Sea and the Barents Sea. E&P Norway aims to ensure safe and efficient operations, maximising the value potential from the NCS.

For 2019, Equinor reports production on the NCS from 41 Equinor-operated fields, nine partner-operated fields, as well as equity-accounted production from Lundin Petroleum AB for the first eight months of the year.

Key events and portfolio developments in 2019 and early 2020:

· Strengthening the position in the Norwegian Sea, Equinor on 5 December 2018 agreed with Faroe Petroleum on several swap transactions with no cash considerations, effective as of 1 January 2019. The transactions increase Equinor’s equity share of the prolific Njord area and reduce its share in non-core assets.

· On 15 January 2019, Equinor was awarded 29 exploration licences (13 as operator) on the NCS in the Awards for predefined areas round 2018 for mature areas.

· On 19 May, the Ministry of Petroleum and Energy approved the plan for development and operation of the second phase of the Johan Sverdrup field development. Around one fourth of the oil from the Johan Sverdrup full field will be produced in the second phase, expected to start production in late 2022.

· On 30 August, Equinor completed the sales of a 16% stake in Lundin Petroleum AB for around USD 1.51 billion and the acquisition of a 2.6% stake in the Johan Sverdrup field for USD 910 million. Following the transactions, Equinor holds a 4.9% percent stake in Lundin Petroleum AB and a 42.6% direct interest in the Johan Sverdrup field.

· Trestakk achieved first oil on 15 July. The oil discovery in the Norwegian Sea has been developed as a subsea tie-back to Åsgard A.

· Utgard achieved first gas on 16 September. The gas and condensate field in the North Sea spans the boundary between the Norwegian and UK continental shelves, and the subsea development includes two wells in a new subsea template. Gas and condensate are piped through a new 21-km pipeline to the Sleipner field for processing and onward transportation to market.

The giant Johan Sverdrup oil and gas field in the North Sea was brought on stream on 5 October. The field is expected to produce for more than 50 years. Powered by electricity from shore, the field has record-low CO2 emissions of 0.7kg per barrel.

28 Equinor, Annual Report on Form 20-F 2019

Crude oil is exported to Mongstad through a 283-km designated pipeline, and gas is exported to the gas processing facility at Kårstø through a 156-km pipeline via a subsea connection to the Statpipe pipeline.

· The plans for development and operation of Hywind Tampen, a n 88 MW floating offshore wind farm projected to provide wind power to the Snorre and Gullfaks installations in the Tampen area of the North Sea, were submitted to the Norwegian Ministry of Petroleum and Energy on 11 October.

Floating offshore wind from the pioneering Hywind Tampen development will reduce the carbon footprint from the Snorre and Gullfaks installations.

· Onshore power to offshore installations: Powered from shore, Johan Sverdrup is one of the world’s most carbon-efficient fields. In the second phase of the field development, a power hub will be installed, allowing for the Gina Krog, Ivar Aasen and Edvard Grieg fields, as well as Johan Sverdrup second phase, to be powered from the onshore grid. In October, Equinor announced that the area’s licence partners are working towards a partial electrification of the Sleipner field, as well as Gudrun and other tie-ins, maximising the utilisation of power from shore to the area. Power supply from the onshore grid will reduce the carbon footprint from these offshore installations and contribute to reaching the climate goal of the Paris agreement.

· On 1 December, Equinor assumed the operatorship of Wisting in the Barents Sea from OMV. Equinor is considering developing the Wisting oil discovery using an FPSO solution with subsea wells.

· Equinor and its partners made 11 commercial discoveries on the NCS in 2019.

· On 9 January 2020, Equinor and the Statfjord licence partners announced an extension towards 2040 of the production from the Statfjord field in the North Sea, enabled by a planned upgrade of the three platforms and maturation of new reserves for recovery.

· On 14 January 2020, Equinor was awarded 23 licences
(14 as operator) on the NCS in the Awards for predefined areas round 2019 for mature areas.

· The gas processing capacity at Troll C was increased when a new compressor was brought on stream on 30 January 2020.

Gudrun, NCS.

Equinor, Annual Report on Form 20-F 2019 29

Major producing fields and field developments operated by Equinor and Equinor’s licence partners

###

30 Equinor, Annual Report on Form 20-F 2019

### Fields in production on the NCS

The table below shows E&P Norway's average daily entitlement production for the years ending 31 December 2019, 2018 and 2017. Production in 2019 decreased owing to natural decline, reduced ownership in some fields and a lower flexible gas production, partially offset by new fields in production.

Average daily entitlement production |  |  |  |  |  |  |  |
| For the year ended 31 December
| 2019 |  | 2018 |  | 2017
| 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
Equinor operated fields | 461 | 98 | 1,079 |  | 470 | 99 | 1,090 |  | 505 | 100 | 1,136
Partner operated fields | 65 | 13 | 147 |  | 79 | 16 | 181 |  | 70 | 17 | 179
Equity accounted production | 9 | - | 9 |  | 16 | - | 16 |  | 19 | - | 19
Total | 535 | 111 | 1,235 |  | 565 | 115 | 1,288 |  | 594 | 118 | 1,334

Gina Krog, NCS.

Equinor, Annual Report on Form 20-F 2019 31

The following tables show the NCS entitlement production by fields in which Equinor was participating during the year ended
31 December 2019.

Equinor operated fields, average daily entitlement production |  |  |  |
| Geographical area | Equinor's equity interest in % |  | On stream | Licence expiry date |  | Average production in 2019 mboe/day
Field |
Troll Phase 1 (Gas) | The North Sea | 30.58 |  | 1996 | 2030 |  | 165
Gullfaks | The North Sea | 51.00 |  | 1986 | 2036 |  | 89
Oseberg | The North Sea | 49.30 |  | 1988 | 2031 |  | 88
Åsgard | The Norwegian Sea | 34.57 |  | 1999 | 2027 |  | 79
Visund | The North Sea | 53.20 |  | 1999 | 2034 |  | 73
Aasta Hansteen | The Norwegian Sea | 51.00 |  | 2018 | 2041 |  | 58
Tyrihans | The Norwegian Sea | 58.84 |  | 2009 | 2029 |  | 54
Snøhvit | The Barents Sea | 36.79 |  | 2007 | 2035 |  | 48
Kvitebjørn | The North Sea | 39.55 |  | 2004 | 2031 |  | 40
Grane | The North Sea | 36.61 |  | 2003 | 2030 |  | 37
Sleipner Vest | The North Sea | 58.35 |  | 1996 | 2028 |  | 34
Troll Phase 2 (Oil) | The North Sea | 30.58 |  | 1995 | 2030 |  | 33
Gina Krog | The North Sea | 58.70 |  | 2017 | 2032 |  | 31
Johan Sverdrup | The North Sea | 42.63 |  | 2019 | 2036-2037 |  | 31
Statfjord Unit | The North Sea | 44.34 |  | 1979 | 2026 |  | 24
Gudrun | The North Sea | 36.00 |  | 2014 | 2028-2032 |  | 23
Fram | The North Sea | 45.00 |  | 2003 | 2024 |  | 20
Snorre | The North Sea | 33.28 |  | 1992 | 2040 |  | 18
Mikkel | The Norwegian Sea | 43.97 |  | 2003 | 2024 |  | 17
Valemon | The North Sea | 53.78 |  | 2015 | 2031 |  | 15
Kristin | The Norwegian Sea | 55.30 |  | 2005 | 2027-2033 |  | 11
Heidrun | The Norwegian Sea | 13.04 |  | 1995 | 2024-2025 |  | 10
Tordis area | The North Sea | 41.50 |  | 1994 | 2040 |  | 10
Alve | The Norwegian Sea | 53.00 |  | 2009 | 2029 |  | 10
Morvin | The Norwegian Sea | 64.00 |  | 2010 | 2027 |  | 10
Norne | The Norwegian Sea | 60.00 |  | 1997 | 2026 |  | 8
Vigdis area | The North Sea | 41.50 |  | 1997 | 2040 |  | 8
Sleipner Øst | The North Sea | 59.60 |  | 1993 | 2028 |  | 6
Trestakk | The Norwegian Sea | 59.10 |  | 2019 | 2029 |  | 5
Urd | The Norwegian Sea | 63.95 |  | 2005 | 2026 |  | 5
Utgard | The North Sea | 38.441) |  | 2019 | 2028 |  | 4
Gungne | The North Sea | 62.00 |  | 1996 | 2028 |  | 4
Byrding | The North Sea | 70.00 |  | 2017 | 2024-2035 |  | 2
Sigyn | The North Sea | 60.00 |  | 2002 | 2022 |  | 2
Statfjord Nord | The North Sea | 21.88 |  | 1995 | 2026 |  | 2
Veslefrikk | The North Sea | 18.00 |  | 1989 | 2025-2031 |  | 1
Sygna | The North Sea | 30.71 |  | 2000 | 2026-2040 |  | 1
Statfjord Øst | The North Sea | 31.69 |  | 1994 | 2026-2040 |  | 1
Gimle | The North Sea | 65.13 |  | 2006 | 2023-2034 |  | 1
Tune | The North Sea | 50.00 |  | 2002 | 2025-2032 |  | 1
Heimdal | The North Sea | 29.44 |  | 1985 | 2021 |  | 0
Total Equinor operated fields |  |  |  |  | 1,079

32 Equinor, Annual Report on Form 20-F 2019

Partner operated fields, average daily entitlement production |  |  |  |
| Geographical area | Equinor's equity interest in % | Operator | On stream | Licence expiry date |  | Average production in 2019 mboe/day
Field |
Ormen Lange | The Norwegian Sea | 25.35 | A/S Norske Shell | 2007 | 2040-2041 |  | 58
Skarv | The Norwegian Sea | 36.17 | Aker BP ASA | 2013 | 2029-2033 |  | 32
Ivar Aasen | The North Sea | 41.47 | Aker BP ASA | 2016 | 2029-2036 |  | 25
Goliat | The Barents Sea | 35.00 | Vår Energi AS | 2016 | 2042 |  | 14
Ekofisk area | The North Sea | 7.60 | ConocoPhillips Skandinavia AS | 1971 | 2028 |  | 13
Marulk | The Norwegian Sea | 33.00 | Vår Energi AS | 2012 | 2025 |  | 3
Vilje | The North Sea | 0.00 | Aker BP ASA | 2008 | 2021 |  | 1
Ringhorne Øst | The North Sea | 0.00 | Vår Energi AS | 2006 | 2030 |  | 0
Enoch | The North Sea | 11.78 | Repsol Sinopec North Sea Ltd. | 2007 | 2024 |  | 0
Total partner operated fields |  |  |  |  | 147
Equity accounted production |  |  |  |  |  |  |
Lundin Petroleum AB |  | 4.902) | Lundin Petroleum AB |  |  |  | 9
Total E&P Norway including share of equity accounted production |  |  | 1,235

1) The Utgard field in the North Sea spans the boundary between the Norwegian and UK continental shelves. The volumes pertain to the Equinor 38.44% share of Utgard on the NCS. (For the volumes pertaining to the Equinor 38% share of Utgard on the UKCS, please see section 2.4 E&P International)

2) On 7 July, Equinor divested a 16 percent shareholding in Lundin for a direct interest of 2.6 percent in the Johan Sverdrup field and a cash consideration, and the last transaction was concluded on 30 August. The volumes therefore pertain to the first eight months of the year

## M ain producing fields on the NCS

###
Equinor-operated fields

Johan Sverdrup (Equinor 42.63%) is a major oil field with associated gas in the North Sea, developed with four platforms: a processing platform, a drilling platform, a riser platform and a living quarter platform. Crude oil is exported to Mongstad through a 283-km designated pipeline, and gas is exported to the gas processing facility at Kårstø through a 156-km pipeline via a subsea connection to the Statpipe pipeline.

A record-breaking lift completed the Johan Sverdrup field centre in March. The processing platform of nearly 26 000 tonnes is the heaviest lift ever performed offshore. First oil was achieved in October 2019.

The second phase of the Johan Sverdrup field is under development and includes a new processing platform linked to the field centre, and five new subsea templates.

Troll (Equinor 30.58%) in the North Sea is 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 produced mainly at Troll A, and oil mainly at Troll B and C. Fram, Fram H Nord and Byrding are tie-ins to Troll C.

New compressors have increased the gas processing capacity: one compressor was brought on stream at Troll B in September 2018, and one at Troll C in January 2020. The third phase of the Troll field is under development.

The Gullfaks (Equinor 51%) oil and gas field in the North Sea is developed with three platforms. Since production started on Gullfaks in 1986, several satellite fields have been developed with subsea wells which are remotely controlled from the Gullfaks A and C platforms.

Equinor, Annual Report on Form 20-F 2019 33

The Oseberg area (Equinor 49.30%) in the North Sea produces oil and gas. The development includes the Oseberg field centre, Oseberg C, Oseberg East and Oseberg South production platforms. Oil and gas from the satellites are transported to the Oseberg field centre for processing and transportation. Oseberg Vestflanken 2 came on stream in October 2018 and is Norway’s first unmanned platform, remotely controlled from the Oseberg field centre.

The Åsgard (Equinor 34.57%) gas and condensate field in the Norwegian Sea is developed with the Åsgard A production and storage ship for oil, the Åsgard B semi-submersible floating production platform for gas and condensate, and the Åsgard C storage vessel for oil and condensate. Åsgard C is also storage for oil produced at Kristin and Tyrihans. In 2015 Equinor started the world’s first subsea gas compression train on Åsgard. Trestakk, a tie-in to Åsgard, came on stream in July.

Visund (Equinor 53.2%, operator) oil and gas field in the North Sea is developed with Visund A semi-submersible integrated living quarter, drilling and processing unit, and a subsea installation in the northern part of the field. Visund North improved oil recovery, a subsea development with two new wells in a new subsea template, was brought on stream in September 2018.

The Aasta Hansteen (Equinor 51%, operator) gas and condensate field in the Norwegian Sea is developed with a floating spar platform and two subsea templates.

With the Snefrid North well at 1309 metres beneath the ocean’s surface, the field development is the deepest ever on the NCS.

First gas was achieved in December 2018. In September 2019, the Snefrid North gas field was brought on stream, a subsea development with one well tied back to Aasta Hansteen.

The Tyrihans (Equinor 58.84%, operator) oil and gas field in the Norwegian Sea is developed with five subsea templates tied back to Kristin.

The Snøhvit (Equinor 36.79%, operator) gas and condensate field is developed with several subsea templates. Snøhvit was the first field development in the Barents Sea and is connected ta to the liquefied natural gas processing facilities at Melkøya near Hammerfest through a 160-km long pipeline. Askeladd phase 1, the next plateau extender of Snøhvit, is under development.

### Partner-operated fields

Ormen Lange (Equinor 25.35%, operated by A/S Norske Shell) is a deepwater gas field in the Norwegian Sea. The well stream is transported to an onshore processing and export plant at Nyhamna. Gassco became operator of Nyhamna from
1 October 2017, with Shell as technical service provider.

Skarv (Equinor 36.17%, operated by Aker BP ASA) is an oil and gas field in the Norwegian Sea. The field development includes a floating production, storage and offloading vessel and five subsea multi-well installations.

Ivar Aasen (Equinor 41.47%, operated by Aker BP ASA) is an oil and gas field 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.

Goliat (Equinor 35%, operated by Vår Energi AS, formerly Eni Norge AS) is the first oil field developed in the Barents Sea. The field consists of subsea wells tied back to a circular floating production, storage and offloading vessel. The oil is offloaded to shuttle tankers.

Ekofisk area (Equinor 7.60%, operated by ConocoPhillips Skandinavia AS) consists of the Ekofisk, Tor, Eldfisk and Embla fields.

Marulk (Equinor 33%, operated by Vår Energi AS, formerly Eni Norge AS) is a gas and condensate field developed as a tie-back to the Norne FPSO.

### Exploration on the NCS

Equinor 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.

Equinor was awarded 23 licenses (14 as operator) in the Awards for predefined areas (APA) round 2019 for mature areas and completed several farm-in transactions with other companies.

There has been high activity on NCS in 2019, and Equinor and its partners have completed 26 exploratory wells and made 11 commercial and three non-commercial discoveries.

34 Equinor, Annual Report on Form 20-F 2019

Exploratory wells drilled1) |  |  |
| For the year ended 31 December
| 2019 | 2018 | 2017
North Sea |  |  |
Equinor operated | 10 | 5 | 7
Partner operated | 2 | 2 | 0
Norwegian Sea |  |  |
Equinor operated | 4 | 4 | 4
Partner operated | 6 | 4 | 0
Barents Sea |  |  |
Equinor operated | 4 | 2 | 5
Partner operated | 0 | 1 | 1
Total (gross) | 26 | 18 | 17
1) Wells completed during the year, including appraisals of earlier discoveries.

### Fields and projects under development on the NCS

Equinor’s major development projects on the NCS as of
31 December 2019[7] :

Askeladd (Equinor 36.79%, operator) is the next plateau extender of the Snøhvit gas field in the Barents Sea. The development includes two subsea templates, a 42-km tie-back to Snøhvit and drilling of three gas producers. The project was sanctioned in March 2018. First gas is expected in late 2020.

Hywind Tampen (Equinor 33.28% (Snorre) and 51% (Gullfaks), operator) The plans for development and operation of the
88 MW floating offshore wind farm to provide wind power to the Snorre and Gullfaks installations in the Tampen area of the North Sea, were submitted to the Ministry of Petroleum and Energy on 11 October. The planned eleven wind turbines, based on the Hywind technology developed by Equinor, is expected to meet around 35% of the annual power need of the five offshore platforms Snorre A, B and C and Gullfaks A and B. The wind park is expected to be brought on stream in late 2022.

Johan Castberg (Equinor 50%, operator) is the development of the three oil discoveries Skrugard, Havis and Drivis, located some 240 kilometres northwest of Hammerfest in the Barents Sea. The development includes a production vessel and a subsea development with 30 wells, ten subsea templates and two satellite structures. On 28 June 2018, the Ministry of Petroleum and Energy approved the Plan for development and operation of the field. First oil is expected in late 2022.

Johan Sverdrup, second phase (Equinor 42.6%, operator) is an oil and gas discovery in the North Sea. T he plan for development and operation for the second phase of the Johan Sverdrup field was approved by the Ministry of Petroleum and Energy on
19 May 2019. The development includes a new processing platform linked to the field centre, five new subsea templates and 28 wells. Around one fourth of the oil from the Johan Sverdrup full field will be produced in the second phase. First oil is expected in late 2022

Martin Linge (Equinor 70%, operator) is an oil and gas field near the British sector of the North Sea. The reservoir is complex with gas under high pressure and high temperatures. Effective as of January 1, 2018, Equinor acquired Total’s interest and assumed the operatorship. The development includes a fixed steel jacket platform with processing and export facilities, with electric power to be supplied from Kollsnes. The Martin Linge hook-up and completion scope is large and complex, and first oil is expected in late 2020.

Njord future (Equinor 20%, operator) is a development to enable safe, reliable and efficient exploitation of the Njord and Hyme oil discoveries through to 2040. The development includes an upgrade of the Njord A floating platform, an optimal oil export solution and drilling of ten new wells. As part of the upgrade, the platform will be prepared to bring the nearby fields Bauge and Fenja on stream. On 20 June 2017, the Ministry of Petroleum and Energy approved the plan for development and operation of the field. Oil production is expected to start in late 2020.

Snorre expansion (Equinor 33.28%, operator) is expected to increase oil recovery from the Snorre field and extend field life beyond 2040. The Ministry of Petroleum and Energy approved the plan for development and operation on 5 July 2018. T he concept consists

[7] Recently, there has been considerable uncertainty created by the Covid-19 pandemic as well as the changing dynamics among Opec+ members. We are unable to predict the impact of these events.

Equinor, Annual Report on Form 20-F 2019 35

of six subsea templates, with four well slots each. Each slot will have the possibility for either production or injection. 24 wells will be drilled, twelve production wells and twelve injection wells. Oil production is expected to start in 2021.

Troll phase 3 (Equinor 30.58%, operator) is expected to increase gas recovery from the Troll field and extend field life beyond 2050. The Ministry of Petroleum and Energy approved the plan for development and operation on 7 December 2018. The subsea development includes two subsea templates, eight production wells, a 36-inch export pipeline and a new process module on the Troll A platform. First gas from Phase 3 is expected in 2021.

Ærfugl (Equinor 36.17%, operated by Aker BP) is the development of the gas and condensate discoveries Ærfugl and Snadd Outer fields in the Norwegian Sea, near the Skarv field, some 200 km west of Sandnessjøen. The field is being developed in two phases and includes six new production wells which will be tied into the Skarv floating production, storage and offloading vessel for processing and storage. On 6 April 2018, the Ministry of Petroleum and Energy approved the plan for development and operation of the field. The operator plans for first gas in late 2020.

### 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 (Equinor 19.87%, operator) ceased production in September 2014, after 13 years in production. The permanent plugging and abandonment of wells was finalised in 2017, and the heavy-lift vessel, Thialf removed the platform in May. The demolition and recycling of the platform take place at Vats on the Norwegian coast.

Ekofisk (Equinor 7.6%, operated by ConocoPhillips Skandinavia AS): In the third removal campaign, some installations were removed in 2019.

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

36 Equinor, Annual Report on Form 20-F 2019

# 2.4 # Exploration & Production International (E&P International)

### Overview

Equinor is present in several of the most important oil and gas provinces in the world. The E&P International segment covers exploration, development and production of oil and gas outside the Norwegian continental shelf (NCS).

E&P International is present in nearly 25 countries and had production in 12 countries in 2019. E&P International produced around 40% of Equinor’s total equity production of oil and gas in 2019, compared to 39% in 2018. For information about proved reserves development see section 2.8 Operational Performance under Proved oil and gas reserves.

Peregrino Phase 2 hook up, Brazil.

Key events and portfolio developments in 2019 and early 2020:

· On 16 April, Equinor was awarded seven new licences in the 1st offshore licensing round in Argentina, five as operator and two as partner

· On 19 April, Equinor and its partners sanctioned the development of Azeri Central East (ACE) platform in the Azeri Chirag Gunashli (ACG) oilfield in Caspian Sea

· On 24 April, a significant discovery at the Blacktip prospect in the deepwater U.S. Gulf of Mexico was announced by Shell Offshore Inc. Equinor holds a 19.1% working interest in the licence

· On 30 May, the acquisition of Barra Energia do Brasil Petróleo e Gás Ltda’s 10% interest and subsequent assignment of 3.5% and 3% interests, respectively to ExxonMobil and Petrogal, in the BM-S-8 block in Brazil's Santos basin were approved by authorities. These transactions had been agreed in July 2018. After the transaction, Equinor owns a 40% operated interest in the neighbouring BM-S-8 and Bachalau North blocks

· On 4 June, Equinor was awarded five new licences in the 31st offshore licensing round on the UK continental shelf, four as operator and one as partner

· On 12 August, Equinor completed the acquisition of 22.45% interest in the Caesar Tonga oil field from Shell Offshore Inc. Equinor’s interest in the field is now 46%. The effective date of the transaction is 1 January 2019

Equinor, Annual Report on Form 20-F 2019 37

On 15 August, Equinor started production from the Mariner oil field, the group’s first operated development in the UK North Sea. The field is expected to produce oil for more than 30 years and support more than 700 long-term jobs. Mariner is a digital frontrunner, applying automated drilling and a digital copy of the platform, to deliver safe and efficient operations

· On 20 August, a waterflood project was sanctioned in the St. Malo field in the US Gulf of Mexico including two new production wells, three new injector wells, and topsides injection equipment

· On 21 August, Equinor signed an agreement with Yacimientos Petroliferos Fiscales S.A. (YPF) to acquire a 50% interest in and to jointly explore the CAN 100 offshore block, located in the northern Argentina Basin

· On 16 September, Equinor started production from the Utgard gas and condensate field, which spans the boundary between the Norwegian and UK continental shelves. Gas and condensate is piped to the Sleipner field on the Norwegian side for processing and onward transportation to market

· On 10 October, Equinor was awarded exploration acreage in the North Carnarvon Basin offshore western Australia as operator

· On 29 November, Equinor and Rosneft have taken an investment decision on the first stage of the North Komsomolskoye full field development. The licence is owned by SevKomNeftegaz LLC in which Equinor owns 33.33% of the shares

· On 6 December, Equinor completed the divestment of its 63% interest in, and operatorship of, the onshore business in the Eagle Ford shale play in the US state of Texas to Repsol. The effective date of the transaction is 1 October 2019

For more information about the transactions included above see note 4 Acquisitions and disposals to the Consolidated financial statements.

## International production

Entitlement production differs from equity production where operations are performed under production sharing agreements (PSAs) (see section 5.6 Terms and abbreviations) and in the US where 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.

Equity production represents volumes that correspond to Equinor’s percentage ownership in a particular field and is larger than Equinor’s entitlement production if the field is governed by a PSA or royalties are excluded from entitlement production.

Equinor's equity production outside Norway was around 40% of Equinor's total equity production of oil and gas in 2019. Equinor's entitlement production outside Norway was 35% of Equinor's total entitlement production in 2019.

The following table shows E&P International's average daily entitlement production of liquids and natural gas for the years ending 31 December 2019, 2018 and 2017.

Average daily entitlement production |  |  |  |  |  |  |  |  |
| For the year ended 31 December
| 2019 |  | 2018 |  | 2017
| 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 | 279 | 29 | 461 |  | 245 | 25 | 403 |  | 186 | 19 | 304
Africa | 137 | 4 | 165 |  | 168 | 6 | 209 |  | 197 | 6 | 233
Eurasia | 29 | 3 | 45 |  | 21 | 3 | 40 |  | 26 | 3 | 46
Equity accounted production | 3 | 0 | 4 |  | 0 | - | 0 |  | 5 | - | 5
Total | 447 | 36 | 676 |  | 434 | 35 | 652 |  | 415 | 27 | 588

38 Equinor, Annual Report on Form 20-F 2019

The table below provides information about the fields that contributed to production in 2019, including average equity production per field.

Average daily equity production |  |  |  |  |  |
Field | Country | Equinor's equity interest in % | Operator | On stream |  | Licence expiry date | Average daily equity production in 2019 mboe/day |
Americas |  |  |  |  |  |  | 526 |
Appalachian (APB)1) 3) | US | Varies | Equinor/others4) | 2008 |  | HBP7) | 200 |
Bakken1) | US | Varies | Equinor/others5) | 2011 |  | HBP7) | 69 |
Roncador | Brazil | 25.00 | Petróleo Brasileiro S.A. | 2018 |  | 2025 | 45 |
Eagle Ford1) | US | Varies2) | Equinor/others6) | 2010 |  | HPB7) | 40 |
Peregrino | Brazil | 60.00 | Equinor Brasil Energia Ltda. | 2011 |  | 20348) | 37 |
Tahiti | US | 25.00 | Chevron USA Inc. | 2009 |  | HBP7) | 29 |
Caesar Tonga | US | 46.00 | Anadarko U.S. Offshore LLC | 2012 |  | HBP7) | 21 |
St. Malo | US | 21.50 | Chevron USA Inc. | 2014 |  | HBP7) | 21 |
Julia | US | 50.00 | ExxonMobil Corporation | 2016 |  | HBP7) | 14 |
Jack | US | 25.00 | Chevron USA Inc. | 2014 |  | HBP7) | 12 |
Hebron | Canada | 9.01 | ExxonMobil Canada Properties | 2017 |  | HBP7) | 10 |
Stampede | US | 25.00 | Hess Corporation | 2018 |  | HBP7) | 8 |
Hibernia/Hibernia Southern Extension9) | Canada | Varies | Hibernia Management and Development Corporation Ltd. | 1997 |  | HBP7) | 7 |
Big Foot | US | 27.50 | Chevron USA Inc. | 2018 |  | HBP7) | 5 |
Terra Nova | Canada | 15.00 | Suncor Energy Inc. | 2002 |  | HBP7) | 5 |
Titan | US | 100.00 | Equinor USA E&P Inc. | 2018 |  | HBP7) | 3 |
Heidelberg | US | 12.00 | Anadarko U.S. Offshore LLC | 2016 |  | HBP7) | 2 |
Africa |  |  |  |  |  |  | 235 |
Block 17 | Angola | 23.33 | Total E&P Angola Block 17 | 2001 |  | 2022-3410) | 97 |
In Salah | Algeria | 31.85 | Sonatrach11) | 2004 |  | 2027 | 39 |
|  |  |  | BP Exploration (El Djazair) Limited |  |  |  |  |
|  |  |  | Equinor In Salah AS |  |  |  |  |
Agbami | Nigeria | 20.21 | Star Deep Water Petroleum Limited (an affiliate of Chevron in Nigeria) | 2008 |  | 2024 | 36 |
Block 15 | Angola | 13.3312) | Esso Exploration Angola Block 15 | 2004 |  | 2026-3212) | 29 |
In Amenas | Algeria | 45.90 | Sonatrach11) | 2006 |  | 2027 | 16 |
|  |  |  | BP Amoco Exploration (In Amenas) Limited |  |  |  |  |
|  |  |  | Equinor In Amenas AS |  |  |  |  |
Block 31 | Angola | 13.33 | BP Exploration Angola | 2012 |  | 2031 | 10 |
Murzuq | Libya | 10.00 | Akakus Oil Operations | 2003 |  | 2035 | 8 |
Field | Country | Equinor's equity interest in % | Operator | On stream |  | Licence expiry date | Average daily equity production in 2019 mboe/day |
Eurasia |  |  |  |  |  |  | 73 |
ACG | Azerbaijan | 7.27 | BP Exploration (Caspian Sea) Limited | 1997 |  | 2049 | 39 |
Corrib | Ireland | 36.50 | Vermilion Exploration and Production Ireland Limited | 2015 |  | 2031 | 15 |
Kharyaga | Russia | 30.00 | Zarubezhneft-Production Kharyaga LLC | 1999 |  | 2031 | 10 |
Utgard13) | UK | 38.00 | Equinor Energy AS | 2019 |  | HBP7) | 5 |
Mariner | UK | 65.11 | Equinor UK Limited | 2019 |  | HBP7) | 5 |
Barnacle14) | UK | 44.34 | Equinor UK Limited | 2019 |  | HBP7) | 0 |
Total E&P International |  |  |  | 835 |
Equity accounted production |  |  |  |  |  |  |  |
North Komsomolskoye | Russia | 33.33 | SevKomNeftegaz LLC | 2018 |  | 2112 | 4 |
Total E&P International including share of equity accounted production |  |  | 839 |
1) | Equinor’s actual equity interest varies depending on wells and area. |
2) | On 6 December 2019 Equinor completed the divestment of its 63% interest in, and operatorship of, Eagle Ford to Repsol. |
3) | Appalachian basin contains Marcellus and Utica formations. |
4) | Operators are Equinor USA Onshore Properties Inc, Chesapeake Operating INC., Southwestern Energy, Alta Resources Development LLC, Chief Oil & Gas LLC and several other operators. |
5) | Operators are Equinor Energy LP, Continental Resources INC, Oasis Petroleum North America LLC, Hess Corporation, EOG Resources INC and several other operators. |
6) | Operators are Equinor Texas Onshore Properties LLC and several other operators. |
7) | Held by Production (HBP): A company’s right to own and operate an oil and gas lease beyond its original primary term. |
8) | Licence BMC-7 expires in 2034, and licence BMC-47 related to the second phase of the development, expires in 2040. |
9) | Equinor's equity interests are 5.0% in Hibernia and 9.26% in Hibernia Southern Extension. |
10) | Licence expiry varies by field. |
11) | The complete name for Sonatrach is Société nationale de transport et de commercialisation d’hydrocarbures. |
12) | License extension to 2032 for all fields and change in ownership share to 12% was ratified on 27 January 2020 with effective date 1 October 2019. |
13) | The Utgard field spans the boundary between the Norwegian and UK continental shelves. In this section we report only volumes pertaining to the Equinor 38% share in UKCS. |
14) | Production started in December 2019. Equinor share of average daily equity production is only 0.21 mboe/day in 2019. |

Equinor, Annual Report on Form 20-F 2019 39

###

40 Equinor, Annual Report on Form 20-F 2019

### Americas

US – Offshore Gulf of Mexico

The Titan oil field is an Equinor-operated asset located in the Mississippi Canyon and is producing through a floating spar facility.

The Tahiti, Heidelberg, Caesar Tonga and Stampede oil fields are partner-operated assets located in the Green Canyon area. The Tahiti and Heidelberg oil fields are producing through floating spar facilities. On 12 August, Equinor completed the acquisition of an additional 22.45% non-operated interest in the Caesar Tonga deep water asset in the US Gulf of Mexico from Anadarko Petroleum Corporation, with an effective date of
1 January 2019.The Caesar Tonga oil field is tied back to the Anadarko-operated Constitution spar host. The Stampede oil field is producing through a tension-leg platform with downhole gas lift.

The Jack, St. Malo, Julia and Big Foot oil fields are partner-operated assets located in the Walker Ridge area. The Jack, St. Malo and Julia oil fields are subsea tie-backs to the Chevron-operated Walker Ridge regional host facility. In August 2019, Equinor agreed to participate in a Paleogene water injection project which is expected to increase the estimated ultimate recovery factor in St Malo. The Big Foot oil field is producing through a dry tree tension-leg platform with a drilling rig.

US – Onshore

Since its entry into US shale in 2008, Equinor has continued to optimise its portfolio through acreage acquisitions and divestments. On 6 December 2019, Equinor closed a transaction to divest its entire ownership interest in the Eagle Ford shale play. With this transaction, Equinor aims to high-grade its US onshore portfolio.

Equinor has an ownership interest in the Marcellus shale gas play, located in the Appalachian region in north east US. The position is mostly partner-operated through Chesapeake Energy Corporation in Pennsylvania and Southwestern Energy in West Virginia and southern Pennsylvania. Since 2012, Equinor has also been an operator in the Appalachian region in the state of Ohio, developing Marcellus and Utica formations.

Equinor has an ownership interest in the Bakken tight oil play, developing the Bakken and Three Forks formations. The majority of Equinor’s acreage position in the Bakken shale is operated by Equinor with an average working interest of approximately 70%.

In addition to the operated oil and gas producing assets, Equinor participates in gathering and facilities for initial processing of oil and gas in the Bakken and Appalachian basin assets in the US. This includes crude and natural gas gathering systems, fresh water supply systems, salt water gathering and disposal wells, oil and gas treatment and processing facilities to provide flow assurance for Equinor’s upstream production.

Brazil

The Peregrino field is an Equinor-operated heavy oil asset, located in the offshore Campos basin. The oil is produced from two wellhead platforms with drilling capability, processed on the FPSO Peregrino and offloaded to shuttle tankers.

Production from Peregrino started in 2011. As part of the second phase of the Peregrino field development, a third wellhead platform was constructed and installation activities are being conducted, which are expected to be completed by the end of 2020, extending the field life.

Equinor has interests in the Roncador field, which is operated by Petrobras, located in the offshore Campos basin. The field has been in production since 1999. The hydrocarbon is produced from two semi-submersibles and two FPSOs. The oil is offloaded to shuttle tankers, and the gas is drained out through pipelines to shore.

Canada

Equinor has interests in the Jeanne d'Arc basin offshore the province of Newfoundland and Labrador in the partner-operated producing oil fields Terra Nova, Hebron, Hibernia and Hibernia Southern Extension.

### Africa

Angola

The deep-water blocks 17, 15 and 31 contributed 24% of Equinor’s equity liquid production outside Norway in 2019. 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.

Block 17 has production from four FPSOs; CLOV, Dalia, Girassol and Pazflor. New projects on Dalia, CLOV and Pazflor are being developed to stem decline. In December 2019, the production sharing agreement was extended to 2045 by partnership and the regulator, pending ratification. As part of the extension agreement, the national oil company Sonangol will obtain a 5% interest in the block from 2020 and an additional 5% interest from 2036.

Equinor, Annual Report on Form 20-F 2019 41

Block 15 has production from four FPSOs: Kizomba A, Kizomba B, Kizomba C-Mondo, and Kizomba C-Saxi Batuque. In 2019, the production sharing agreement was extended to 2032, and ratified on 27 January 2020 with effective date 1 October 2019. As part of the extension agreement, the national oil company Sonangol will obtain a 10% interest in the block.

Block 31 has production from one FPSO producing from the PSVM fields.

The FPSOs serve as production hubs and each receives oil from more than one field through multiple wells.

Nigeria

Equinor has a 20.2% interest in the Agbami deep water field, which is governed by PSA and 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. Equinor has a 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 24 Other commitments, contingent liabilities and contingent assets to the Consolidated financial statements.

On 4 November 2019 the president of Nigeria introduced a new fiscal bill where Royalty would form part of the government take in the petroleum sector. The law passed the houses and was signed into law in January 2020 with retroactive application to
4 November2019. The royalty is paid in kind.

Algeria

The In Salah is an onshore gas development. The Northern fields have been operating since 2004. The Southern fields have been operating since 2016 and are tied back into the Northern fields existing facilities.

The In Amenas is an onshore gas development which contains significant liquid volumes. The In Amenas infrastructure includes a gas processing plant with three trains. The production facility is connected to the Sonatrach distribution system. In 2017, Equinor and its partners secured a licence extension of five years beyond 2022.

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

In Amenas, Algeria.

### Eurasia

Azerbaijan

42 Equinor, Annual Report on Form 20-F 2019

Equinor has a 7.27% interest in Azeri-Chirag-Gunashli (ACG) oil field offshore Azerbaijan. The crude oil is sent to Sangachal Terminal, where it is processed prior to export. Equinor holds 8.71 % in this pipeline. The development of Azeri Central East (ACE) platform in ACG field in Caspian Sea was sanctioned by the partners in April 2019. The new platform is expected to come on stream in 2023.

Ireland and Russia

Equinor has interest share in the Corrib gas field off Ireland’s northwest coast, and in the Kharyaga oil field onshore in the Timan-Pechora basin in northwestern Russia. The Kharyaga field is governed by a PSA.

United Kingdom

Mariner is an Equinor-operated heavy oil field in the North Sea, some 150 km east of Shetland, UK. The field includes a production, drilling and living quarter platform based on a steel jacket. Oil is exported by offshore loading from a floating storage unit. Production from the field started in August 2019, and Equinor holds 65.11% interest in the field.

Utgard is an Equinor-operated gas and condensate field, which spans the boundary between the Norwegian and UK continental shelves. Equinor has 38.44% interest in the Norwegian sector and 38% in the UK sector. Production from the field started in September 2019 and it is remotely operated from the Norwegian Sleipner field. For more information, please see section 2.3 Exploration and Production Norway.

Barnacle is an Equinor-operated oil field in the North Sea, some 2 km from the boundary between the Norwegian and UK continental shelves. Barnacle is part of a cross-border strategy to maximise Equinor’s competitive position across the North Sea and delivers value on both sides of the median line by unlocking otherwise stranded resources in the UK. Production from the field started in December 2019. Equinor holds 44.34% interest in the field.

## International exploration

Equinor has increased exploration activity outside Norway compared with 2018 and drilled offshore wells in the US Gulf of Mexico, UK and Brazil in addition to onshore exploration wells in Argentina, Turkey, US and Russia. Continued focus on access has strengthened the exploration portfolio further.

Brazil is one of Equinor’s core exploration areas. In 2019 Equinor and partners completed two wells, and Equinor intends to increase this activity in 2020.

Equinor was awarded seven offshore exploration blocks, five as operator, in the 1st Offshore Licensing Round in Argentina. Equinor and Yacimientos Petroliferos Fiscales S.A. (YPF) also signed an agreement to jointly explore the CAN 100 offshore block, located in the northern Argentina Basin.

In the 31st Offshore licensing round on the UK continental shelf Equinor was awarded five licenses, four as operator and one as partner. These awards in the frontier licensing round enable us to add new opportunities to our exploration portfolio in a prolific basin, in line with our strategy.

Equinor was awarded new exploration acreage in the North Carnarvon Basin offshore western Australia as operator and thereby expanded our position with an exploration opportunity in a proven basin.

Equinor signed an agreement with Southwind Oil & Gas LLC, a subsidiary of Marathon Oil Company, to acquire a 25 % share across Southwind’s onshore Louisiana in Austin Chalk in US.

Equinor was awarded 26 leases in US Gulf of Mexico in 2019 and is strengthening its position in the area.

Equinor participates with 49% in a project exploring the cherty limestone Domanik formation near Samara in Russia. Three pilot wells have been drilled and two of them production tested. Additional wells will be needed to conclude on commerciality.

Equinor and its partners completed 16 exploratory wells and made seven commercial and two non-commercial discoveries internationally.

Exploratory wells drilled1) |  |  |
| For the year ended 31 December
2019 | 2018 | 2017
Americas |  |  |
Equinor operated | 3 | 1 | 2
Partner operated | 4 | 4 | 4
Africa |  |  |
Equinor operated | 0 | 1 | 0
Partner operated | 0 | 0 | 0
Other regions |  |  |
Equinor operated | 5 | 0 | 4
Partner operated | 4 | 0 | 1
Total (gross) | 16 | 6 | 11
1) Wells completed during the year, including appraisals of earlier discoveries.

Equinor, Annual Report on Form 20-F 2019 43

## Fields under development internationally[8]

### Americas

US – Offshore Gulf of Mexico

Vito development project (Equinor 36.89%, operated by Shell) is a Miocene oil discovery located in the Mississippi Canyon area. The development project consists of a light-weight semi-submersible platform with a single eight-well subsea manifold. The wells will have an approximate depth of 10,000 meters and will have downhole gas lift to assist production. The project was sanctioned for development in April 2018. Production is expected to start in second half of 2021.

Brazil

Peregrino phase 2 (Equinor 60%, operator) will develop the southwestern area of the Peregrino oil field in the Campos basin, 85 km off the coast of the state of Rio de Janeiro. Peregrino phase 1 was brought on stream in 2011, and the second phase of the development will prolong the field’s productive life. The licence period extends until 2040. Fifteen oil producers and seven water injectors will be drilled in the new area from a third wellhead platform, to be tied back to the existing floating production, storage and offloading vessel. The construction of the third Peregrino wellhead platform modules was completed during the autumn, and the field installation started in December.

The Peregrino field development in the prolific Campos basin is Equinor's largest international endeavour as an operator. I n mid-January 2020, the third Peregrino wellhead platform was in place at the field after installation by Sleipnir, the largest crane vessel in the world. The floatel Olympia has connected to the platform, and in total 880 individuals will work offshore to prepare the platform for operations later this year. Once on stream, Peregrino C will provide 350 offshore and onshore jobs in Brazil.

Production is expected to start in late 2020.

Eurasia

Russia
North Komsomolskoye (Equinor 33.33%, operated by SevKomNeftegaz) is a complex viscous oil field in Western Siberia, Russia. In December 2018, Equinor Russia AS acquired shares in the JV company SevKomNeftegaz LLC which is the operator and holds the licence. Test production has been carried out during 2018 and 2019 to improve reservoir understanding and determine the potential for development. The decision for the first stage of full field development was taken at the end of 2019 and the asset is moving into project execution phase.

For information about risks related to activity in Russia see section 2.11 Risk review under “Risks related to our business”.

## Discoveries with potential development

### Americas

US – Offshore Gulf of Mexico
North Platte (Equinor 40%, operated by Total) is a Paleogene oil discovery in the Garden Banks area. It has been fully appraised since its discovery with three drilled wells and three sidetracks.

[8] Recently, there has been considerable uncertainty created by the Covid-19 pandemic as well as the changing dynamics among Opec+ members. We are unable to predict the impact of these events.

44 Equinor, Annual Report on Form 20-F 2019

Brazil

Bacalhau (formerly Carcará) (Equinor 40%, operator) oil and gas discovery straddles BM-S-8 and Bacalhau North in the Santos basin, 185 km off the coast of the state of São Paulo in Brazil.

Bacalhau phase 1 is maturing towards an investment decision, and a two-phase development of Bacalhau is being assessed to fully exploit the value potential.

BM-C-33 (Equinor 35%, operator) includes the oil and gas discoveries Pão de Açúcar, Gávea and Seat in the southwestern part of the Campos basin, off the coast of the state of Rio de Janeiro, Brazil. The project is maturing towards concept selection. A partial gas injection and rich gas export is being assessed.

Canada

Bay du Nord (Equinor 58.5%, operator) is an oil field in the Flemish pass basin which was discovered by Equinor in 2013. The field is some 500 km northeast of St. John’s in Newfoundland and Labrador, Canada. Drawing upon the experience from the Johan Castberg development in Norway, Equinor is considering developing both the Bay du Nord and nearby Baccalieu satellite field using an FPSO and a subsea tie-back concept.

### Africa

Tanzania

Block 2 (Equinor 65%, operator). Equinor made several large gas discoveries in Block 2 in the Indian Ocean, off southern Tanzania, during 2012-2015. A suitable legal, commercial and fiscal framework for developing the discoveries with an onshore LNG solution is currently being discussed with the Government of Tanzania. The exploration license expired in June 2018 but based on formal communications from the applicable Tanzanian authorities, the block continues to be in operation while the Government process for granting a new exploration license for the block is ongoing. See also note 11 Intangible assets to the Consolidated financial statements.

Eurasia

Azerbaijan
Karabagh (Equinor 50%, appraisal well operated by Equinor). In May 2018, Equinor and the Azerbaijani state oil company Socar signed a risk service agreement related to the appraisal and development of the Karabagh oil field through a joint operating agreement. The field is located 120 kilometres east of Baku.

United Kingdom
Rosebank (Equinor 40%, operator) oil and gas field, some
130 km northwest of the Shetland Islands, is the largest known undeveloped resource on the UK continental shelf. In January 2019, Equinor completed the acquisition of Chevron’s 40% interest in and assumed operatorship of Rosebank. A 3-year extension for the Rosebank licences was awarded by the UK Oil and Gas Authority in May 2019.

Equinor, Annual Report on Form 20-F 2019 45

Appalachian Basin Operations, Ohio, US

46 Equinor, Annual Report on Form 20-F 2019

# 2.5 # Marketing, Midstream & Processing (MMP)

### Overview

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

MMP markets, trades and transports approximately 50% of all Norwegian liquids export, including Equinor equity, the Norwegian State’s direct financial interest (SDFI) equity production of crude oil and NGL, and third-party volumes. MMP is also responsible for the marketing, trading and transportation of Equinor’s and SDFI’s gas together with third-party gas. This represents approximately 70% of all Norwegian gas exports. For more information, see note 2 Significant accounting policies to the Consolidated financial statements for Transactions with the Norwegian State, and section 2.7 Corporate, Applicable laws and regulations for the Norwegian State’s participation and SDFI oil and gas marketing and sale.

#

#

Melkøya in Hammerfest, Norway.

Key events in 2019 and early 2020:

· Danske Commodities, a wholly-owned subsidiary of Equinor from 1 February 2019. During 2019 integration has gone well and activities related to power purchase agreements, sourcing power to plants and manage gas storage positions have been transferred from Equinor to Danske Commodities.

· Hurricane Dorian hit our terminal on the Grand Bahamas Island in September, and this has resulted in substantial clean-up cost and the terminal has been out of operation.

· MMP to drive Equinor’s low carbon solutions business from February 2020.

· Turnaround at Mongstad refinery was prolonged due to replacement of cracker unit.

### Marketing and trading of gas, LNG and power

MMP is responsible for the sale of Equinor’s and SDFI’s (Norwegian State’s direct financial interest) gas. Equinor’s gas marketing and trading business is conducted from Norway and from the offices in Belgium, the UK, Germany and the US. In February 2019 Equinor completed the acquisition of Danske Commodities (DC), a trading company for power and gas. DC is primarily active in Europe but also has minor power activities in US and Australia.

Europe

The major export markets for natural gas from the Norwegian continental shelf (NCS) are the UK, Germany, France, the Netherlands, Italy, Belgium and Spain. LNG from the Snøhvit field, combined with third-party LNG cargoes, allows Equinor to reach the global gas

Equinor, Annual Report on Form 20-F 2019 47

markets. The gas is sold to counterparties through bilateral sales agreements and over the trading desk. Some of Equinor’s long-term gas contracts have price review mechanisms which can be triggered by the parties.

For the ongoing price reviews, Equinor provides in its financial statements for probable liabilities based on Equinor’s best judgement. For further information, see note 24 Other commitments and contingencies to the Consolidated financial statements.

Equinor is active on both the physical and exchange markets such as the Intercontinental Exchange (ICE). Equinor expects to continue to optimise the value of the gas volumes through a mix of bilateral contracts and trading via its production and transportation systems and downstream assets. MMP receives a marketing fee from DPN for the gas sold on behalf of the company.

DC is active on both the physical and exchange markets for both gas and power as a separate entity. Following the acquisition all trading and optimization of power in Equinor is performed by DC.

US

Equinor Natural Gas LLC (ENG), a wholly-owned subsidiary, has a gas marketing and trading organisation in Stamford, Connecticut that markets natural gas to local distribution companies, industrial customers and power generators. ENG also markets equity production volumes from the Gulf of Mexico, Eagle Ford and the Appalachian Basin and transports some of the Appalachian production to New York City and into Canada to the greater Toronto area.

In addition, ENG has long-term capacity contracts at the Cove Point LNG re-gasification terminal, that enable sourcing of LNG from the Snøhvit LNG facility in Norway. However, although global gas prices have fallen significantly, they are still at a premium compared to US prices. As a consequence, nearly all of Equinor's LNG cargoes have been diverted away from the US and delivered into the higher priced markets mainly in Europe.

### Marketing and trading of liquids

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

MMP also markets the equity volumes from the E&P International assets located in the US, Brazil, Angola, Nigeria, Algeria, Azerbaijan and the UK, as well as third-party volumes. The value is maximised through marketing, physical and financial trading and through the optimisation of owned and leased capacity such as refineries, processing, terminals, storages, pipelines, railcars and vessels.

### Manufacturing

Equinor owns and operates the Mongstad refinery in Norway, including a combined heat and power plant (CHP). 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 via Mongstad Terminal DA linked to offshore fields through three crude oil pipelines, a pipeline for NGL’s connecting Kollsnes and Sture (the Vestprosess pipeline) and to Kollsnes by a gas pipeline. The CHP produces heat and power from gas received from Kollsnes and from the refinery. It has capacity of generating approximately 280 megawatts of electric power and 350 megawatts of process heat. Equinor has decided to cease the operation and redesign a part of the CHP to a new heater for process heat planned to be operational in 2020. The CHP will continue operation until the new heater comes into service.

Equinor has an ownership interest in Vestprosess (34%), which transports and processes NGL and condensate. The operatorship of Vestprosess was transferred to Gassco as of
1 January 2018, with Equinor as the technical service provider.

Equinor owns and is the 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.

Equinor has an ownership interest in the methanol plant at Tjeldbergodden (82 %). The plant receives natural gas from fields in the Norwegian Sea through the Haltenpipe pipeline. In addition, Equinor holds an ownership interest in the air separation unit Tjeldbergodden Luftgassfabrikk DA (50.9%).

The following table shows the operating statistics for the plants at Mongstad, Kalundborg and Tjeldbergodden. The lower throughput in 2019 was mainly influenced by higher unplanned shut down for Mongstad compared to 2018. Reduced on-stream factor and utilization rate compared to 2018 are influenced by increased unplanned shutdown for Mongstad and Tjeldbergodden. In addition, Mongstad had four planned shutdowns, Kalundborg had two and Tjeldbergodden had one planned shutdown in 2019.

| Throughput1) | Distillation capacity2) | On stream factor %3) | Utilisation rate %4)
Refinery | 2019 | 2018 | 2017 | 2019 | 2018 | 2017 | 2019 | 2018 | 2017 | 2019 | 2018 | 2017
Mongstad | 10.5 | 11.5 | 12.0 | 9.3 | 9.3 | 9.3 | 79.0 | 95.3 | 97.5 | 87.7 | 93.8 | 94.7
Kalundborg | 5.0 | 5.3 | 5.5 | 5.4 | 5.4 | 5.4 | 98.0 | 94.1 | 99.7 | 85.4 | 90.3 | 90.4
Tjeldbergodden | 0.9 | 0.8 | 0.9 | 1.0 | 1.0 | 1.0 | 93.9 | 94.3 | 99.4 | 93.9 | 94.3 | 99.4
1) | Actual throughput of crude oils, condensates and other feed, measured in million tonnes. Throughput may be higher than the distillation capacity for the plants because the volumes of fuel oil etc. may not go through the crude-/condensate distillation unit.
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, based on throughput and capacity (per stream day).

48 Equinor, Annual Report on Form 20-F 2019

### Terminals and storage

Equinor operates the Mongstad crude oil terminal (Equinor 65%). The 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.

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

Equinor operates the South Riding Point Terminal (SRP), which is located on the 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. In September 2019 SRP was struck by Hurricane Dorian causing damage to the facility and an oil spill on land. Extensive clean-up at and around the terminal has been undertaken and will continue in 2020. Technical assessment of the terminal will be undertaken to clarify options for the restoration of the terminal.

Equinor UK holds an interest in the Aldbrough Gas Storage (Equinor 33.3%) in the UK, which is operated by SSE Hornsea Ltd.

Equinor Deutschland Storage GmbH holds an interest in the Etzel Gas Lager (Equinor 23.7%) in the northern part of Germany which has a total of 19 caverns and secures the regularity for gas deliveries from the NCS.

### Pipelines

Equinor is a significant shipper in the NCS gas pipeline system. Most of the gas pipelines on the NCS that are accessed by third-party customers are owned by a single joint venture, Gassled (Equinor 5%), 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. See Gas sales and transportation from the NCS in section 2.7 Corporate for further information.

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

In addition, MMP manages Equinor’s ownership in the following pipelines in the Norwegian oil and gas transportation system: The Grane oil pipeline (Equinor 23.5%), the Kvitebjørn oil pipeline (Equinor 39.6%), the Troll oil pipeline I and II (Equinor 30.6%), the Edvard Grieg oil pipeline (Equinor 16.6%), the Utsira High gas pipeline (Equinor 24.9%), the Valemon rich gas pipeline (Equinor 66.8 %), the Haltenpipe pipeline (Equinor 19.1%), Norpipe gas pipeline (Equinor 5%) and Mongstad gas pipeline (Equinor 30.6%).

Equinor holds an interest in the Nyhamna gas processing plant (Equinor 30.1%) in Aukra via the recently established Nyhamna Joint Venture. The venture is operated by Gassco.

The Polarled pipeline (Equinor 37.1%), operated by Gassco, connects fields in the Norwegian Sea with the Nyhamna gas processing plant.

The Johan Sverdrup pipelines (owned by the Johan Sverdrup license partners) for export of oil and gas from Johan Sverdrup, were installed in autumn 2018 and set in operation at Johan Sverdrup production starting 5 October 2019. The crude oil is exported from Johan Sverdrup to the Mongstad terminal through a 283 km, 36-inch pipeline. The gas is transported to the gas processing facility at Kårstø through a 156 km long, 18-inch pipeline with a subsea connection to the Statpipe pipeline.

Equinor, Annual Report on Form 20-F 2019 49

# 2.6 # Other group

The Other reporting segment includes activities in New Energy Solutions (NES), Global Strategy & Business Development (GSB), Technology, Projects & Drilling (TPD) and corporate staffs and support functions. In addition, the Other reporting segment includes IFRS 16 leases. All lease contracts are presented within the Other segment. For more information on the impact of IFRS 16 on the segment reporting, see note 23 Implementation of IFRS 16 leases to the Consolidated financial statements.

### New Energy Solutions (NES)

The New Energy Solutions business area reflects Equinor’s aspirations to gradually complement its oil and gas portfolio with profitable renewable energy and other low-carbon energy solutions. Offshore wind, solar and carbon capture and storage have been key strategic focus areas in 2019.

In 2019, Equinor participated in offshore wind and solar assets with a total capacity of 1.3 gigawatts, of which 0.75 gigawatts are operated by Equinor. Equinor equity generation capacity is 0.5 gigawatts. The equity renewable power production in 2019 was 1.8 terawatt hours.

Hywind Scotland, Scotland.

Key events and portfolio developments in 2019 and early 2020:

50 Equinor, Annual Report on Form 20-F 2019

· Hywind Demo outside Karmøy was sold to Unitech AS, which became the new owner and operator on 1 February 2019

· Equinor finalised the acquisition of the offshore wind lease OCS-A 0520 outside Massachusetts in first quarter 2019

· In April 2019, the Arkona offshore windfarm operated by RWE was officially opened

· Equinor signed contract with New York State Energy Research and Development Authority (NYSERDA) to deliver the 816 MW Empire Wind project

· Contracts to develop three large scale windfarms in the Dogger Bank area: Creyke Beck A, Creyke Beck B and Teesside A were awarded in September 2019

· In October 2019, Equinor and the Snorre and Gullfaks licence partners submitted to the Norwegian Ministry of Petroleum and Energy the plans for development and operation of the Hywind Tampen offshore floating wind farm in the Tampen area of the North Sea

· In November 2019 Equinor divested 25% interest in the Arkona offshore windfarm (AWE-Arkona-Windpark Entwicklunds-GMBH) to EIP Offshore Wind Germany I Holding GMBH

· Equinor joined YPF Luz for the development of the Cañadón León wind project in Argentina

· In March 2020, the Northern Lights carbon capture and storage project completed drilling a confirmation well for CO2 storage south of the Troll field in the North Sea.

· Awarded Agreement for Lease with Crown Estate for doubling the capacity of the Sheringham and Dudgeon wind farms in the UK

### Offshore wind

### Assets in production

The Sheringham Shoal offshore wind farm (Equinor 40%, operator) located off the coast of Norfolk, UK, has been in operation since September 2012. The wind farm is in full production with 88 turbines and an installed capacity of
317 megawatts (MW). The wind farm's annual production is approximately 1.1 terawatt hours (TWh).

The Dudgeon offshore wind farm (Equinor 35%, operator) lies in the Greater Wash area off the English east coast, a short distance from Sheringham Shoal. The wind farm has been in operation since November 2017, with an annual production of approximately 1.7 TWh from 67 turbines.

The Hywind Scotland wind farm (Equinor 75%, operator) is a floating wind pilot farm using the Hywind concept, developed and owned by Equinor. The wind farm is placed at Buchan Deep, approximately 25 km off Peterhead on the east coast of Scotland, UK. Equinor completed the project during 2017 and has installed five 6 MW turbines. Production is around 0.14 TWh per year.

The Arkona offshore wind farm (Equinor 25%, operated by RWE) is located in the German part of the Baltic Sea, while the operations and maintenance base is in Port Mukran on the island of Rügen in Mecklenburg-Vorpommern. First power from Arkona was supplied to the grid in September 2018, and all 60 turbines have been generating power since November 2018. The wind farm has a capacity of 385 MW and has been in full operation from early 2019. The wind farm's annual production is approximately 1.6 TWh. Following the divestment in November 2019 Equinor holds 25% interest.

### Potential developments

The Dogger Bank wind farms (Equinor 50%, joint operatorship with SSE) are three proposed 1200 MW offshore wind farms, Creyke Beck A and B and Teeside A, located 130 km off the coast of Yorkshire, UK. In September 2019 all three projects were awarded a Contract for Difference (CfD), a government financial support mechanism providing the projects a long-term predictable revenue stream This will be the world’s biggest offshore wind farm development with a total installed capacity of 3600 MW.

In 2018, Equinor and partners applied for an Agreement for Lease to double the capacity of Dudgeon (Equinor 35%, operator) and Sheringham Shoal (Equinor 40%, operator) wind farms offshore Norfolk in the UK. Both extension projects have secured a grid connection to the existing grid at Norwich Main substation in Norfolk and have been awarded an Agreement for Lease by the Crown Estate. The max total capacity for the combined projects will be 719 MW.

During 2019, Equinor closed the agreements with Polenergia to acquire a 50% interest in three offshore wind development projects in Poland, Bałtyk I, II and III. The wind farm areas are in the Baltic Sea approximately 80, 27 and 40 kilometres from shore with water depths of 20-40 meters. The three projects have a potential capacity of more than 2500 MW and are in the concept development stage.

Equinor was awarded a 816 MW offshore wind project connecting to the state of New York in 2019 through a long-term contract with the New York State Energy Research and Development Authority (NYSERDA) for offshore wind renewable energy certificates (ORECs). The project has been named Empire Wind and is planned to be in operation late 2024. The total lease area is 321 km2, large enough to support one or more offshore wind developments with a total capacity of up to 2000 MW. The lease is approximately 20 km off the south shore of Long Island, New York.

Equinor, Annual Report on Form 20-F 2019 51

Early 2019, Equinor paid the winning bid of USD 135 million for lease OCS-A 0520 outside Massachusetts in the US federal wind lease sale. The lease is located 65 km south of Cape Cod and 110 km east of Long Island, New York. It spans over 521 km2 and is large enough to support one or more windfarms with a total capacity of above 2000 MW. The Massachusetts acreage strengthens Equinor’s strategic position in the north-eastern US.

From 2020 Equinor expects annual gross capital investments the range of USD 0.5 billion to USD 1 billion. In the years of 2022 and 2023 gross capital investments are expected between
USD 2 billion and USD 3 billion per year. Most of the investment is expected to go into offshore wind projects like Dogger Bank and Empire Wind.

### Onshore renewables

The Apodi solar plant (Equinor 43.75%, operated by Scatec Solar) is located in the municipality of Quixeré, Ceará State in Brazil. The plant, with an installed capacity of 162 MW, started commercial operations in November 2018 and is expected to provide about 0.34 TWh of solar power per year.

Equinor holds a 50% interest in the Guanizul 2A solar project in Argentina. The plant will be operated by Scatec Solar and situated in the San Juan region of Argentina. The plant is expected to be in operation in the first half of 2020 and will have an installed capacity of 117 MW.

In August 2019, Equinor and YPF Luz entered an agreement where a subsidiary of Equinor will subscribe to shares in Luz del León. Luz del León is the company in charge of the Cañadón León wind farm project, currently under construction, located in the province of Santa Cruz in Argentina. The closing of the transaction is expected in first half of 2020.

In December 2019, Equinor has acquired additional 6,500,000 shares in Scatec Solar ASA, corresponding to 5.2 percent of the shares and votes, at a total purchase price of NOK 754 million. Together Equinor now owns 15.2% of the shareholding in this entity an integrated independent solar power producer, with an asset portfolio of 1.9 gigawatt (GW) in operation and under construction.

### Carbon Capture and Storage

Since 1996, Equinor has proven experience in carbon capture and storage (CCS) from the offshore oil and gas business and has continued to develop competence through research engagement at Technology Centre Mongstad, the world’s largest facility for testing and improving CO2 capture. Equinor will seek to deploy its competence and experience in other CCS projects, both to reduce carbon dioxide emissions from several sources and to drive new opportunities, including enhanced oil recovery possibilities and carbon neutral value chains based on hydrogen.

Northern Lights (Equinor 33.33%, operator): Equinor is, together with Shell and Total, developing infrastructure for transport and storage on the NCS of CO2 from various onshore industries. The solution being considered will have an initial storage capacity of around 1.5 million tons CO2 per year, scalable to around 5 million tons CO2 per year.

Capture and storage of CO2 can contribute to reaching the climate goal of the Paris agreement, and the project is part of the Norwegian authorities’ plans for full-scale carbon capture, transport and storage demonstration in Norway.

In March 2020, Northern Lights completed drilling a confirmation well for CO2 storage south of the Troll field in the North Sea. A t 2500 metres below the seabed, the well is considered being used for injection and storage of CO₂. To stimulate the development of future carbon capture and storage projects, Equinor and its partners have decided to share the well data freely with external parties.

From February 2020 Carbon Capture and Storage activity will be handled in the MMP segment.

### Equinor Energy Ventures Fund

The Equinor Energy Ventures fund, dedicated to invest in attractive and ambitious growth companies in low carbon and new energy solutions, has been operating since February 2016. More than two-third of the original USD 200 million has been committed. The fund currently holds thirteen direct investments across different segments and is a limited partner to three financial venture capital funds on two different continents.

###

52 Equinor, Annual Report on Form 20-F 2019

### Global Strategy & Business Development (GSB)

The Global Strategy and Business Development (GSB) business area is Equinor’s functional centre for strategy and business development. GSB is responsible for Equinor’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. Equinor's strategy forms the basis for guiding the company’s business development focus.

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

### Technology, projects and drilling (TPD)

The Technology, projects and drilling business area is responsible for field development, well deliveries, technology development and procurement in Equinor.

Research and technology is responsible for research, development and implementation of new technologies to meet Equinor’s business needs, and for providing specialist technology advisory services to Equinor’s operating assets within selected areas.

Project development is responsible for planning, developing and executing major field development, brownfield and field decommissioning projects where Equinor is the operator.

Drilling and well is responsible for designing wells and delivering drilling and well operations onshore and offshore globally (except for US onshore).

Procurement and supplier relations is responsible for our global procurement activities and the management of supplier relations with our extensive portfolio of suppliers.

The following tables displays major projects operated by Equinor, as well as projects operated by Equinor’s licence partners. More information about ongoing projects is provided in the E&P Norway, E&P International, MMP and NES sections. In our world-class portfolio, an additional 30-35 projects are in the early phase, maturing towards sanction.

Completed projects |  |  |
Project startups and completions 2019 | Equinor's interest | Operator | Area | Type
Mariner | 65.11% | Equinor UK Ltd | North Sea | Oil
Johan Sverdrup phase 1 | 42.63% | Equinor Energy AS | North Sea | Oil and associated gas
Utgard Norwegian sector | 38.44% | Equinor Energy AS | North Sea | Gas and condensate
Utgard UK sector | 38.00% | Equinor Energy AS | North Sea | Gas and condensate
Trestakk | 59.10% | Equinor Energy AS | Norwegian Sea | Oil and associated gas
Arkona offshore wind farm | 25.00% | RWE Renewables International GmbH | Baltic sea, off Germany | Wind
Snefrid North | 51.00% | Equinor Energy AS | Norwegian Sea | Gas
Huldra decommissioning | 19.87% | Equinor Energy AS | North Sea | Field decommissioning
Barnacle, tie-in to Statfjord B | 44.34% | Equinor UK Ltd | North Sea | Oil and gas

Projects under development |  |  |  |
Ongoing projects with expected startups and completions 2020-20243) | Equinor's interest | Operator | Area | Type |
Gullfaks Shetland / Lista phase 2 | 51.00% | Equinor Energy AS | North Sea | Oil |
Guanizul 2A solar power project1) | 50.00% | Scatec Solar Argentina B.V. | San Juan, Argentina | Solar |
St. Malo waterflood project2) | 21.50% | Union Oil Company of California | Gulf of Mexico | Oil |
Vigdis boosting station | 41.50% | Equinor Energy AS | North Sea | Oil |
Gudrun phase 2 | 36.00% | Equinor Energy AS | North Sea | Oil and gas |
Martin Linge | 70.00% | Equinor Energy AS | North Sea | Oil and gas |
Njord future | 27.50% | Equinor Energy AS | Norwegian Sea | Oil |
Peregrino phase 2 | 60.00% | Equinor Brasil Energia Ltd | Campos basin, off Brazil | Oil |
Bauge, tie-in to Njord A | 42.50% | Equinor Energy AS | Norwegian Sea | Oil and gas |
Askeladd, tie-in to Snøhvit | 36.79% | Equinor Energy AS | Barents Sea | Gas and condensate |
Ærfugl | 36.17% | Aker BP ASA | Norwegian Sea | Gas and condensate |
Zinia phase 2, block 17 satellite | 23.33% | Total E&P Angola Block 17 | Congo basin, off Angola | Oil |
CLOV phase 2, block 17 satellite | 23.33% | Total E&P Angola Block 17 | Congo basin, off Angola | Oil |
Dalia phase 3, block 17 satellite | 23.33% | Total E&P Angola Block 17 | Congo basin, off Angola | Oil |
Snorre expansion | 33.28% | Equinor Energy AS | North Sea | Oil |
Troll phase 3 | 30.58% | Equinor Energy AS | North Sea | Gas and oil |
Vito | 36.89% | Shell Offshore Inc | Gulf of Mexico | Oil |
Hywind Tampen, Snorre licence | 33.28% | Equinor Energy AS | North Sea | Floating offshore wind |
Hywind Tampen, Gullfaks licence | 51.00% | Equinor Energy AS | North Sea | Floating offshore wind |
Johan Castberg | 50.00% | Equinor Energy AS | Barents Sea | Oil |
Johan Sverdrup phase 2 | 42.63% | Equinor Energy AS | North Sea | Oil and associated gas |
North Komsomolskoye | 33.33% | SevKomNeftegaz LLC | West Siberia | Oil and gas |
Ekofisk removal campaign 3 | 7.60% | ConocoPhillips Skandinavia AS | North Sea | Field decommissioning |
Azeri Central East (Azeri Chirag Gunashli) | 7.27% | BP Exploration (Caspian Sea) Ltd | Caspian Sea | Oil |
1) Technical service provider is Scatec Equinor Solutions Argentina SA. |
2) Union Oil Company of California is a Chevron subsidiary. |
3) Recently, there has been considerable uncertainty created by the Covid-19 pandemic as well as the changing dynamics among Opec+ members. We are unable to predict the impact of these events. |

Equinor, Annual Report on Form 20-F 2019 53

### Corporate staffs and support functions

Corporate staffs and support functions comprise the non-operating activities supporting Equinor, and include head office and central functions that provide business support such as finance and control, corporate communication, safety, audit, legal services and people and leadership.

54 Equinor, Annual Report on Form 20-F 2019

# 2.7 # Corporate

#

## Applicable laws and regulations

Equinor operates in more than 30 countries and is exposed and committed to compliance with numerous laws and regulations globally.

### This section gives a general description on the legal and regulatory framework in the various jurisdictions where Equinor operates and in particular in the countries of Equinor’s core activities. For further information about the jurisdictions in which Equinor operates, see sections 2.2 Business overview and 2.11 Risk review. Further, see chapter 3 Governance for information about the domicile and legal form of Equinor, including the current articles of association, information on listing on the Oslo Børs and New York Stock Exchange (NYSE) and corporate governance.

### Regulatory framework for upstream oil and gas operations

Currently, Equinor is subject to two main regimes applicable to petroleum activities worldwide:

· Corporate income tax regimes; and

· Production sharing agreements (PSAs).

### Equinor is also subject to a wide variety of health, safety and environmental (“HSE”) laws and regulations concerning its products, operations and activities. Relevant laws and regulations include jurisdiction specific laws and regulations, international regulations, conventions or treaties, as well as EU directives and regulations.

### Concession regimes

Under a concession regime, companies are granted licences by the government to extract petroleum. This is similar to the Norwegian system described below. Typically, the licensees are offered to pre-qualified companies following bidding rounds. The criteria for the evaluation of bidding offers under these regimes can be the level of offered signature bonus (bid amount), minimum exploration programme, and local content. In exchange for those commitments, the successful bidder(s) receive a right to explore, develop and produce petroleum within a specified geographical area for a limited period of time. The terms of the licences are usually not negotiable. The fiscal regime may entitle the state to royalties, profit tax or special petroleum tax.

### PSA regimes

PSAs are normally awarded to the contractor parties after bidding rounds announced by the government. Main bid parameters are a minimum exploration programme and signature bonuses, and allocation of profit oil and tax may also be a bid parameter.

Under a PSA, the host government typically retains the right to the hydrocarbons in place. The contractor receives a share of the production for services performed. Normally, the contractor carries the exploration and development costs and risk prior to a commercial discovery and is then entitled to recover those costs during the production phase. The remaining share of the production, the profit share, is split between the government and the contractor according to a mechanism set out in the PSA. The contractor is usually subject to income tax on its own share of the profit oil. Fiscal provisions in a PSA are to a large extent negotiable and are unique to each PSA.

### Norway

The principal laws governing Equinor’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 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). Equinor’s business activities are subject to both the EFTA Convention and EU laws and regulations adopted pursuant to the EEA Agreement.

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.

Equinor, Annual Report on Form 20-F 2019 55

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

· The Norwegian State’s shareholding in Equinor is managed by the MPE. The MPE 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 Equinor 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 vote by the Norwegian State against an Equinor proposal to issue additional shares would prevent Equinor from raising additional capital in this manner and could adversely affect Equinor’s ability to pursue business opportunities. For more information about the Norwegian State’s ownership, see Risks related to state ownership in section 2.11 Risk review, chapter 3 Governance, and Major shareholders in section 5.1 Shareholder information

· The Norwegian State exercises important regulatory powers over Equinor, as well as over other companies and corporations on the NCS. As part of its business, Equinor or the partnerships to which Equinor is a party, frequently need to apply for licences and other approvals from the Norwegian State. Although Equinor 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 Equinor’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 their terms. Licensees are required to submit a plan for development and operation (PDO) to the MPE for approval. For fields of a certain size, the Storting has to accept the PDO before it is formally approved by the MPE. Equinor 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. 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 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 licence period, they are entitled to require that the licence be extended for a period specified at the time when the licence is awarded, typically
30 years.

The terms of the production licences are decided by the Ministry of Petroleum and Energy. Production licences are awarded to group of companies forming a joint venture at the MPE’s discretion. The members of the joint venture are jointly and severally liable to the Norwegian State for obligations arising from petroleum operations carried out under the licence. The MPE 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 set forth in 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 MPE and the approval of the Ministry of Finance of the tax treatment. 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 hold pre-emption rights in all licences.

The day-to-day management of a field is the responsibility of an operator appointed by the MPE. 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.

If important public interests are at stake, the Norwegian State may instruct the operators 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 MPE 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 joint operating agreements for production.

56 Equinor, Annual Report on Form 20-F 2019

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 MPE makes a decision as to the disposal of the facilities.

For an overview of Equinor’s activities and shares in Equinor’s production licences on the NCS, see section 2.3 E&P Norway.

### Gas sales and transportation from the NCS

Equinor markets gas from the NCS on its own behalf and on the Norwegian State’s behalf. Dry gas is mainly transported through the Norwegian gas transport system (Gassled) to customers in the UK and mainland Europe, while liquified natural gas is transported by vessels to worldwide destinations.

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 MPE. The tariffs are paid based on booked capacity rather than the volumes actually transported.

For further information, see section 2.5 MMP – Marketing, Midstream & Processing under Pipelines.

### The Norwegian State's participation

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 Equinor also hold interests. Petoro AS, a company wholly owned by the Norwegian State, was formed in 2001 to manage the SDFI assets.

The Norwegian State has a coordinated ownership strategy aimed at maximising the aggregate value of its ownership interests in Equinor and the Norwegian State’s oil and gas. This is reflected in the owner’s instruction described below, which contains a general requirement that, in our activities on the NCS, we are required to take account of these ownership interests in decisions that may affect the execution of this marketing arrangement.

### SDFI oil and gas marketing and sale

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

In an extraordinary shareholder meeting in 2001, the Norwegian State, as sole shareholder at the time, approved an instruction to Equinor setting out specific terms for the marketing and sale of the Norwegian State’s oil and gas (the Owner’s instruction).

Equinor is obliged under the Owner’s instruction to jointly market and sell the Norwegian State’s oil and gas as well as Equinor’s own oil and gas. The overall objective of the marketing arrangement is to obtain the highest possible total value for Equinor’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 Equinor.

The Norwegian State may at any time utilize its position as majority shareholder of Equinor to withdraw or amend the marketing instruction.

### US

Petroleum activities in the US are extensively regulated by multiple agencies in the US federal government, and by tribal, state and local regulation. The US government directly regulates development of hydrocarbons on federal lands, in the US Gulf of Mexico, and in other offshore areas. Different federal agencies directly regulate portions of the industry, and other general regulations related to environmental, safety, and physical controls apply to all aspects of the industry. In addition to regulation by the US federal government, any activities on US tribal lands (indigenous persons’ semi-sovereign territory) are regulated by governments and agencies in those areas. Significantly for Equinor’s US onshore interests, each individual state has its own regulations of all aspects of hydrocarbon development within its borders. A recent trend also includes local municipalities adopting their own hydrocarbon regulations.

In the US, hydrocarbon interests are considered a private property right. In areas owned by the US government, that means that the government owns the minerals in its capacity as land owner. The federal government, and each tribal and state government, establishes the terms of its own leases, including the length of time of the lease, the royalty rate, and other terms. The vast majority of onshore minerals, including hydrocarbons, in every state in which Equinor has onshore interests, belong to private individuals.

In order to explore for or develop hydrocarbons, a company must enter into a lease agreement from the applicable governmental agency for federal, state or tribal land, and for private lands, from each owner of the minerals the company wishes to develop. In each

Equinor, Annual Report on Form 20-F 2019 57

lease, the lessor retains a royalty interest in the production (if any) from the leased area. The lessee owns a working interest and has the right to explore and produce oil and gas. The lessee incurs all the costs and liabilities but will share only the portion of the revenue that is net of costs and expenses and not reserved to the lessor through its royalty interest.

Leases typically have a primary term for a specified number of years (from one to ten years) and a conditional secondary term that is tied to the production life of the properties. If oil and gas is being produced in paying quantities at the end of the primary term, or the operator satisfies other obligations specified in the agreement, the lease typically continues beyond the primary term (Held by Production). Leases typically involve paying the lessor both a signing bonus based on the number of leased acres and a royalty payment based on the production.

Each state has its own agencies that regulate the development, exploration, and production of oil and gas activities. These state agencies issue drilling permits and control pipeline transportation within state boundaries. The state agencies particularly relevant to Equinor’s US onshore activities include: (a) Railroad Commission of Texas; (b) Pennsylvania Department of Environmental Protection’s Office of Oil and Gas Management; (c) Ohio Department of Natural Resources, Division of Oil and Gas; (d) West Virginia Department of Environmental Protection; and (e) North Dakota Industrial Commission, Department of Mineral Resources, Oil and Gas Division. In addition, some state utility departments handle pipeline transportation within state boundaries, and each state also has its own department regulating environmental, health, and safety issues arising from oil and gas operations.

### Brazil

In Brazil, licences are mainly awarded according to a concession regime or a production sharing regime (the latter specifically for areas within the pre-salt polygon area or strategic areas) by the Federal Government. All state-owned and private oil companies may participate in the bidding rounds provided they follow the bidding rules and meet the qualification criteria. The tender protocol issued for each bidding round contains the draft of the concession agreement or the production sharing agreement that the winners must adhere to without the possibility of negotiating its terms, i.e., all the agreements signed under a certain bidding round contain the same general provisions and only differ in the particular items presented in the offers. There is no restriction on foreign participation, provided that the foreign investor incorporates a company under the Brazilian law for signing the agreement and complies with the requirements established by the National Agency of Oil, Natural Gas and Biofuels (ANP).

The current criteria for the evaluation of bidding offers under the concession regime are: (a) signature bonus; and (b) minimum exploration programme. However, in past bidding rounds the participants also had to offer a local content percentage as a firm commitment. Companies can bid individually or in consortium always observing the qualification criteria for operator and non-operators.

The concession agreements are signed by ANP on behalf of the Federal Government. Generally, concessions are granted for the total period of 35 years and typically the exploration phase lasts from two to eight years, while the production phase may last 27 years from the declaration of commerciality. Concessionaires are entitled to request the extension of each of these phases, subject to ANP approval.

In bidding rounds involving the production sharing regime, the law grants to the Brazilian mixed company Petroleo Brasileiro S.A. - Petrobras a right of preference to be the sole operator in the pre-salt fields with a minimum 30% of participating interest. If this right is exercised, Petrobras may still participate in the bidding round and present offers for the remaining 70% under the same conditions applicable to other participants. Likewise, in the concession bidding rounds, companies may bid individually or together with other companies. The winners are required to form a consortium with Pre-Sal Petroleo S.A. (PPSA), a Brazilian state-owned company, which is responsible for managing the production sharing agreement and selling the production allocated to the Government under the profit oil. PPSA also holds the role of chairperson of the operating committee, with 50% of the votes, in addition to certain veto rights and casting vote.

The current criteria for the evaluation of bidding offers under the production sharing regime is the offered percentage of profit oil. The winner will be the company which offers the highest percentage to the government in accordance with the technical and economic parameters established for each block in the tender documents under a certain bidding round.

Production sharing contracts are signed by the Ministry of Mines and Energy on behalf of the Federal Government. Generally, the contracts are valid for a period of 35 years which, in accordance with the law, cannot be extended. Of the two phases of the contract – exploration and production – the exploration phase can be extended provided that the total period of the contract remains as 35 years.

In order to perform the exploration and exploitation of oil and gas reserves, the companies must obtain an environmental licence granted by the Federal Environmental Protection Agency (IBAMA), which, together with ANP, is responsible for the safety and environmental regulations regarding upstream activities.

### HSE regulation relevant for the Norwegian upstream oil & gas activities in Norway

Equinor’s oil and gas operations in Norway must be conducted in compliance with a reasonable standard of care, taking into consideration the safety of workers, the environment and the economic values represented by installations and vessels. The Petroleum Act specifically requires that petroleum operations be carried out in such a manner that a high level of safety is maintained

58 Equinor, Annual Report on Form 20-F 2019

and developed in step with technological developments. Equinor is also required at all times to have a plan to deal with emergency situations in Equinor’s petroleum operations. During an emergency, the Norwegian Ministry of Labour/Norwegian Ministry of Fisheries and Coastal Affairs/Norwegian Coastal Administration may decide that other parties should provide the necessary resources, or otherwise adopt measures to obtain the necessary resources, to deal with the emergency for the licensees’ account.

### Liability for pollution damage

The Norwegian Petroleum Act imposes strict liability for pollution damage on all licensees, and a licensee is liable for pollution damage without regard to fault. Accordingly, as a holder of licences on the NCS, Equinor is subject to statutory strict liability under the Petroleum Act in respect of losses or damage suffered as a result of pollution caused by spills or discharges of petroleum from petroleum facilities covered by any of Equinor’s licences.

A claim against the licence holders for compensation relating to pollution damage shall initially be directed to the operator, which in accordance with the terms of the joint operating agreement, - will distribute the claim to the other licensees in accordance with their participating interest in the licence.

### Discharge permits

Emissions and discharges from Norwegian petroleum activities are regulated through several acts, including the Petroleum Act, the CO2 Tax Act, the Sales Tax Act, the Greenhouse Gas Emission Trading Act and the Pollution Control Act. Discharge of oil and chemicals in relation to exploration, development and production of oil and natural gas are regulated under the Pollution Control Act. In accordance with the provisions of this Act, an operator must apply for a discharge permit from relevant authorities on behalf of the licence group in order to discharge any pollutants into water. Further, the Petroleum Act states that burning of gas in flares beyond what is necessary for safety reasons to ensure normal operations is not permitted without approval from the MPE. All operators on the NSC have an obligation, and are responsible, for establishing sufficient procedures for the monitoring and reporting of any discharge into the sea. The Environment Agency, the Norwegian Petroleum Directorate and the Norwegian Oil Industry Association have established a joint database for reporting emissions to air and discharges to sea from the petroleum activities, the Environmental Web (EW). All operators on the NCS report emission and discharge data directly into the database.

### Regulations on reduction of carbon emissions and CO2 storage

Equinor’s operations in Norway are subject to emissions taxes as well as emissions allowances granted for Equinor’s larger European operations under the emissions trading scheme. The agreed strengthening of the EU’s emission trading scheme may result in a significant reduction in the total emissions from relevant energy and industry installations, which include Equinor’s installations at the NCS. The price of emissions allowances is also expected to increase significantly towards 2030.

The Climate Act, applicable only [to] the Norwegian Government’s [implementation of] the Storting’s climate related decisions and expectations might also impact on the industry’s regulatory framework.

The EU directive 2009/31/EU on storage of CO2 is implemented in the Pollution Control Act and the Petroleum Act. The CO2 catch and storage at Equinor’s Sleipner and Snøhvit fields are governed by these regulations.

### HSE regulation of upstream oil and gas activities in the US

Equinor’s upstream activities in the US are heavily regulated at multiple levels, including federal, state, and local municipal regulation. Equinor is subject to those regulations as a part of its activities in the US onshore (including Equinor’s assets in Texas, North Dakota, Montana, Ohio, and West Virginia), and activities in the US Gulf of Mexico.

The National Environmental Policy Act of 1969 is an umbrella procedural statute that requires federal agencies to consider the environmental impacts of their actions. Several substantive US federal statutes specifically cover certain potential environmental effects of hydrocarbon extraction activities. Those include: the Clean Air Act, which regulates air quality and emissions; the Federal Water Pollution Control Act (commonly known as the Clean Water Act), which regulates water quality and discharges; the Safe Drinking Water Act, which establishes drinking water standards for tap water and underground injection rules; the Resource Conservation and Recovery Act of 1976, which regulates hazardous and solid waste management; the Comprehensive Environmental Response, Compensation and Liability Act of 1980, which addresses remediation of legacy disposal sites and release reporting; and the Oil Pollution Act, which provides for oil spill prevention and response.

Other US federal statutes are resource-specific. The Endangered Species Act of 1973 protects listed endangered and threatened species and critical habitat. Other statutes protect certain species, including the Migratory Bird Treaty Act, the Bald and Golden Eagle Protection Act and the Marine Mammal Protection Act of 1972. Other statutes govern natural resource planning and development on federal lands onshore and on the Outer Continental Shelf, including: the Mineral Leasing Act; the Outer Continental Shelf Lands Act; the Federal Land Policy and Management Act of 1976; the Mining Law of 1872; the National Forest Management Act of 1976; the National Park Service Organic Act; the Wild and Scenic Rivers Act; the National Wildlife Refuge System Administration Act of 1966; the Rivers and Harbors Appropriation Act; and the Coastal Zone Management Act of 1972.

The federal government regulates offshore exploration and production for the Outer Continental Shelf (OCS), which extends from the edge of state waters (either 3 or 9 nautical miles from the coast, depending on the state) out to the edge of national jurisdiction, 200

Equinor, Annual Report on Form 20-F 2019 59

nautical miles from shore. The Bureau of Ocean Energy Management (BOEM) manages federal OCS leasing programmes, conducts resource assessments, and licences seismic surveys. The Bureau of Safety and Environmental Enforcement (BSEE) regulates all OCS oil and gas drilling and production. The Office of Natural Resources Revenue (ONRR) collects and disburses rents and royalties from offshore and onshore federal and Native American lands.

Additional federal statutes cover certain products or wastes, and focus on human health and safety: the Toxic Substances Control Act regulates new and existing chemicals and products that contain these chemicals; the Hazardous Materials Transportation Act regulates transportation of hazardous materials; the Occupational Safety and Health Act of 1970 regulates hazards in the workplace; the Emergency Planning and Community Right-to-Know Act of 1986 provides emergency planning and notification for hazardous and toxic chemicals.

The federal and state governments share authority to administer some federal environmental programs (e.g., the Clean Air Act and Clean Water Act). States also have their own, sometimes more stringent, environmental laws. Counties, cities and other local government entities may have their own requirements as well.

Equinor continually monitors regulatory and legislative changes at all levels and engages in the stakeholder process through trade associations and direct comments to suggested regulatory and legislative regimes, to ensure that its operations remain in compliance with all applicable laws and regulations. In particular, BSEE drilling and production regulations were extensively revised in response to the 2010 Deepwater Horizon blowout and oil spill. The revised regulatory regime includes requirements for enhanced well design, improved blowout preventer design, testing and maintenance, and an increased number of trained inspectors. The current Administration is in the process of reviewing and revising these regulations, and Equinor is engaged with relevant governmental and industry stakeholders to ensure that Equinor’s operations remain in compliance.

### HSE regulation of upstream oil & gas activities in Brazil

Equinor’s oil and gas operations in Brazil must be conducted in compliance with a reasonable standard of care, taking into consideration the safety and health of workers and the environment. The Brazilian Petroleum Law (Law No. 9,478/97) describes the government’s policy objectives for the rational use of the country’s energy resources, including the protection of the environment. In addition to the Petroleum Law, Equinor is also subject to many other laws and regulation issued by different authorities, including the National Agency of Petroleum, ANP, IBAMA, Federal Environmental Council (CONAMA) and Brazilian Navy. All those authorities have the power to impose fines in case of non-compliance with the respective rules. The concession and production sharing contracts also impose obligations on operators and consortium members, who are jointly and severally liable. They must, at their own account and risk, assume and fully respond to all losses and damages caused directly or indirectly by the applicable consortium’s operations and their performance irrespective of fault, to the ANP, the Federal Government and third parties.

The exploration, drilling and production of oil and gas depend on environmental licences which define the conditions for the implementation of the project and compliance measures to mitigate and control environment impact. Equinor is subject to fines and even licence suspension in case of non-compliance with such conditions.

In Brazil, Equinor is also required to have an emergency response system as per ANP Ordinance 44/2009 to deal with emergency situations in its petroleum operations, as well as an oil spill response plan for each asset to minimise the environmental impact of any environmental unexpected situation that may generate spill of oil or chemical to sea.

### Discharge permits

Discharges from Brazilian petroleum activities are regulated through several acts, including the CONAMA Resolution 393/2007 for produced water, CONAMA Resolution No. 357/2005 and CONAMA Resolution No. 430/2011 for effluents (sewage, etc) and IBAMA technical instructions for drilling waste. According to Environmental Ministry Ordinance No. 422/2011, the discharge of chemicals in connection with exploration, development and production of oil and natural gas is assessed as part of the permitting process and the applicable operator must apply for any discharge permit from relevant authorities on behalf of the licence group in order to discharge any pollutants into the water.

### Regulations on reduction of carbon emissions

Although Equinor’s operations in Brazil are not subject to emissions taxes (CO2 limit) yet, a proposal has been sent to the government by the Brazilian Business Council for Sustainable Development (CEBDS) proposing a tax of USD 10/ton CO2eq. Further, CONAMA No. 382/06 regulates air emissions limits (e.g. NOx) from all fixed sources that have total power consumption higher than 100MW.

ANP Ordinance No. 249/00 allows burning of gas in flares for safety reasons to ensure normal operations, but it is limited to 3% of the monthly production of associated gas. Any additional volume must be pre-approved.

The Brazilian government signed the Paris Agreement in 2016. The country’s ambition is to reduce its greenhouse gas emissions by 37% until 2025 and 43% until 2030, compared to 2005 levels. Because of the desire to boost the economy and an expected growing energy demand, the focus on emissions reduction is on improved control of Forests and Land Use. To meet the growing energy demand challenge, the Brazilian government has indicated acceptance for an increase in total emissions in the short term from the

60 Equinor, Annual Report on Form 20-F 2019

industrial and power generation sectors, although the efficiency in power generation and usage will certainly be an important part of the Brazilian government’s future approach to the issue.

### Taxation of Equinor

Norway

Equinor is subject to ordinary Norwegian corporate income tax and to a special petroleum tax relating to its offshore activities in Norway. Equinor’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 is 22 %. In addition, a special petroleum tax is levied on profits from petroleum production and pipeline transportation on the NCS. The special petroleum tax rate is 56 %. 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. For further information, see note 9 Income taxes to the Consolidated financial statements.

Equinor’s international petroleum activities are subject to tax pursuant to local legislation.

US

Equinor’s operations in the US are subject generally to corporate income, severance and production, ad valorem and transaction taxes - levied by the federal, state and local tax authorities, and to royalties payable to federal, state and local authorities and, in some cases, private landowners. The federal income tax rate in the US is 21%.

Brazil

Regardless of the applicable regime for oil and gas activities, corporate income tax and social contribution are levied on taxable income at a combined rate of 34 %. A simplified tax regime with a lower effective tax rate is available for activities with gross revenues below a threshold of 78 million Brazilian reais per year.

There are several indirect taxes but exports are exempt.

Imports of assets are subject to several customs duties, but a special regime is available for certain assets used in the oil and gas activities allowing suspension of the federal duties and reduction of state duties.

The concession regime usually includes a 10% royalty, and special participation tax that varies based on time, location and production between 10% and 40%. PSA regime usually includes a 15% royalty, an annual 80% cost recovery ceiling, and a biddable government profit share.

Regulatory framework for renewable energy operations

Equinor’s material renewables positions currently consist of offshore wind farms in operation and development in the UK and the state of New York. In both jurisdictions the legislation is structured around a lease where permission to develop is granted following a series of approvals relating largely to environmental and social impact assessments. The government separately auctions a subsidized power purchase price either through renewable offtake certificates or contracts for difference. In both cases, Equinor and its partners take the risk for developing, constructing and operating the wind farms within a fixed timeframe.

##

Equinor, Annual Report on Form 20-F 2019 61

## Subsidiaries and properties

### Significant subsidiaries

The following table shows significant subsidiaries and significant equity accounted companies within the Equinor group as of
31 December 2019.

Significant subsidiaries and significant equity accounted companies |  |  |
Name | in % | Country of incorporation |  | Name | in % | Country of incorporation
Danske Commodities AS | 100 | Norway |  | Equinor Insurance AS | 100 | Norway
Equinor Angola Block 15 AS | 100 | Norway |  | Equinor International Netherlands BV | 100 | Netherlands
Equinor Angola Block 17 AS | 100 | Norway |  | Equinor Murzuq AS | 100 | Norway
Equinor Angola Block 31 AS | 100 | Norway |  | Equinorl Natural Gas LLC | 100 | USA
Equinor Apsheron AS | 100 | Norway |  | Equinor New Energy AS | 100 | Norway
Equinor Brasil Energia Ltda. | 100 | Brazil |  | Equinor Nigeria AS | 100 | Norway
Equinor BTC (Group) | 100 | Norway |  | Equinor Nigeria Energy Company Ltd. | 100 | Nigeria
Equinor Canada Ltd. (Group) | 100 | Canada |  | Equinor Refining Norway AS | 100 | Norway
Equinor Danmark (Group) | 100 | Denmark |  | Equinor Russia AS | 100 | Norway
Equinor Dezassete AS | 100 | Norway |  | Equinor Tanzania AS | 100 | Norway
Equinor Energy AS | 100 | Norway |  | Equinor UK Ltd. (Group) | 100 | United Kingdom
Equinor Energy Brazil AS | 100 | Norway |  | Equinor US Holding Inc. (Group) | 100 | USA
Equinor Energy do Brasil Ltda. | 100 | Brazil |  | Statholding AS (Group) | 100 | Norway
Equinor Energy Ireland Ltd. | 100 | Ireland |  | Statoil Kharyaga AS | 100 | Norway
Equinor Holding Netherlands BV | 100 | Netherlands |  | Wind Power AS | 100 | Norway
Equinor In Amenas AS | 100 | Norway |  | AWE-Arkona-Windpark Entwicklungs-GmbH1 | 25 | Germany
Equinor In Salah AS | 100 | Norway |  | Roncador BV2 | 25 | Netherlands
1) Equity accounted entities. |  |  |  |  |  |
2) Roncador BV is accounted for as a jointly controlled operation and is proportionally consolidated.

### Real estate

Equinor has interests in real estate in many countries throughout the world. However, no individual property is significant. The largest office buildings are the Equinor'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 significant reserves and sources of oil and natural gas, see Proved oil and gas reserves in section 2.8 Operational performance and section 4.2 Supplementary oil and gas information (unaudited) later in this report. For a description of operational refineries, terminals and processing plants, see section 2.5 M arketing, Midstream & Processing (MMP).

For more information, see note 10 Property, plant and equipment to the Consolidated financial statements.

### Related party transactions

See note 25 Related parties to the Consolidated financial statements. See also section 3.4 Equal treatment of shareholders and transactions with close associates.

### Insurance

Equinor 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. See also section 2.11 Risk review under Risk factors.

62 Equinor, Annual Report on Form 20-F 2019

2.8 Operational performance

#

## Proved oil and gas reserves

Proved oil and gas reserves were estimated to be 6,004 million boe at year end 2019, compared to 6,175 million boe at the end of 2018.

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 or subtractions 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 divestment of assets or due to factors outside management control, such as changes in oil and gas prices.

Changes in oil and gas prices will normally affect how much oil and gas that can be recovered from the accumulations. Higher oil and gas prices will normally allow more oil and gas to be recovered, while lower prices will normally result in reductions. However, for fields with PSAs and similar contracts, increased prices may result in lower entitlement to produced volumes and lower prices may increase entitlement to produced volumes. These described changes are included in the revisions category.

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

In Norway, the UK and Ireland, Equinor 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. Undrilled well locations in the 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 88% of Equinor’s proved reserves are located in OECD countries. Norway is by far the most important contributor in this category, followed by the US and Canada. Of Equinor's total proved reserves, 5% 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 Russia, representing all together 7% of Equinor's total proved reserves.

Equinor, Annual Report on Form 20-F 2019 63

###

64 Equinor, Annual Report on Form 20-F 2019

### Changes in proved reserves in 2019

The total volume of proved reserves decreased by 171 million boe in 2019.

Change in proved reserves |  |  |
| For the year ended 31 December
(million boe) | 2019 | 2018 | 2017
Revisions and improved recovery (IOR) | 327 | 479 | 605
Extensions and discoveries | 253 | 848 | 441
Purchase of petroleum-in-place | 72 | 196 | 50
Sales of petroleum-in-place | (125) | (2) | (38)
Total reserve additions | 527 | 1,521 | 1,059
Production | (698) | (713) | (705)
Net change in proved reserves | (171) | 808 | 354

Revisions and IOR

Revisions of previously booked reserves, including the effect of improved recovery, increased the proved reserves by
327 million boe in 2019. Many producing fields had positive revisions due to better performance, maturing of new wells and improved recovery projects, as well as reduced uncertainty due to further drilling and production experience. About 60% of the total revisions came from fields in Norway, where many of the larger offshore fields continue to decline less than previously assumed for the proved reserves. Revisions and IOR included the effect of lower commodity prices, decreasing the proved reserves by approximately 35 million boe through a slightly reduced economic life time on several fields.

Extensions and discoveries

A total of 253 million boe of new proved reserves were added through extensions and discoveries booking proved reserves for the first time. The largest addition came from the North Komsomolskoye field in Russia, where the first stage of the full field development was sanctioned in 2019. Sanctioning of the second development phases on the Ærfugl and Gudrun fields in Norway also added volumes. In addition, this category includes extensions of proved areas through drilling of new wells in previously undrilled areas in the US onshore plays and at some producing fields offshore Norway. New discoveries with proved reserves booked in 2019 are all expected to start production within a period of five years.

Purchase and sale of reserves

A total of 72 million boe of new proved reserves were purchased in 2019. This includes an increased ownership share of 2.6% in the Johan Sverdrup field in Norway through a transaction with Lundin, a purchase of 22.45% ownership share in the Caesar-Tonga field in the US Gulf of Mexico from Shell Offshore Inc, and a swap agreement with Faroe Petroleum increasing Equinor’s ownership share in the Njord area in the Norwegian Sea.

Equinor, Annual Report on Form 20-F 2019 65

Sale of reserves in 2019 reduced the proved reserves by
125 million boe. This includes the divestment of a 16% shareholding in Lundin, with the result that all proved reserves previously included as equity accounted in Norway were removed from proved reserves. In addition, Equinor fully divested its ownership share in the Eagle Ford onshore asset in the US.

Production

The 2019 entitlement production was 698 million boe, a decrease of 2% compared to 2018.

### Development of reserves

In 2019, approximately 426 million boe were matured from proved undeveloped to proved developed reserves. The start-up of production from Johan Sverdrup, Trestakk and Utgard in Norway and in the UK, increased proved developed reserves by 305 million boe during 2019. The remaining 121 million boe of the matured volume is related to activities on developed assets. Over the last five years, Equinor has matured 2,012 million boe of proved undeveloped reserves to proved developed reserves.

66 Equinor, Annual Report on Form 20-F 2019

Development of reserves in 2019 |  |  |
(million boe) | Total | Developed | Undeveloped
At 31 December 2018 | 6,175 | 3,733 | 2,442
Revisions and improved recovery | 327 | 178 | 149
Extensions and discoveries | 253 | 65 | 188
Purchase of reserves-in-place | 72 | 15 | 57
Sales of reserves-in-place | (125) | (40) | (85)
Production | (698) | (698) | -
Moved from undeveloped to developed | - | 426 | (426)
At 31 December 2019 | 6,004 | 3,679 | 2,325

Net proved developed and undeveloped reserves |  |  |  |
As of 31 December 2019 | Oil and Condensate | NGL | Natural gas | Total
(mmboe) | (mmboe) | (mmcf) | (mmboe)
2019 |  | 2,575 | 337 | 17,355 | 6,004
Developed |  | 1,396 | 240 | 11,465 | 3,679
Undeveloped |  | 1,178 | 97 | 5,889 | 2,325
2018 |  | 2,558 | 393 | 18,094 | 6,175
Developed |  | 1,216 | 277 | 12,570 | 3,733
Undeveloped |  | 1,342 | 116 | 5,524 | 2,442
2017 |  | 2,302 | 379 | 15,073 | 5,367
Developed |  | 1,112 | 278 | 10,958 | 3,342
Undeveloped |  | 1,191 | 101 | 4,115 | 2,025

Proved reserves |  |  |  |
As of 31 December 2019 | Proved reserves
Oil and Condensate | NGL | Natural Gas | Total oil and gas
(mmboe) | (mmboe) | (mmcf) | (mmboe)
Developed |  |  |  |
Norway | 691 | 175 | 9,417 | 2,544
Eurasia excluding Norway | 49 | - | 178 | 81
Africa | 124 | 15 | 217 | 178
US | 278 | 49 | 1,645 | 621
Americas excluding US | 254 | - | 8 | 255
Total Developed proved reserves | 1,396 | 240 | 11,465 | 3,679
Undeveloped |  |  |  |
Norway | 772 | 78 | 4,912 | 1,725
Eurasia excluding Norway | 175 | - | 228 | 215
Africa | 13 | 3 | 23 | 20
US | 104 | 16 | 726 | 250
Americas excluding US | 115 | - | - | 115
Total Undeveloped proved reserves | 1,178 | 97 | 5,889 | 2,325
Total proved reserves | 2,575 | 337 | 17,355 | 6,004

Equinor, Annual Report on Form 20-F 2019 67

As of 31 December 2019, the total proved undeveloped reserves amounted to 2,325 million boe, 74% of which are related to fields in Norway. The Troll, Johan Sverdrup and Snøhvit fields, which have continuous development activities, together with fields not yet in production, such as Johan Castberg and Martin Linge, have the largest proved undeveloped reserves in Norway. The largest assets with proved undeveloped reserves outside Norway, are North Komsomolskoye in Russia, the Appalachian basin in the US, Peregrino in Brazil, Mariner in the UK, ACG in Azerbaijan and Vito in the US.

All these fields are either producing or will start production within the next three 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. At the Martin Linge field in Norway, where development has been going on for more than
5 years, first oil is expected in 2020. 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 US, the Appalachian basin and Bakken, all proved undeveloped reserves are limited to wells that are scheduled to be drilled within five years.

In 2019, Equinor incurred USD 8,497 million in development costs relating to assets carrying proved reserves, of which USD 7,585 million was related to proved undeveloped reserves.

Additional information about proved oil and gas reserves is provided in section 4.2 Supplementary oil and gas information (unaudited).

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 table below presents the changes in reserves for each category relating to the reserve replacement ratio for the years 2019, 2018 and 2017.

The 2019 reserves replacement ratio was 0.75 and the corresponding three-year average was 1.47.

The reserves replacement ratio excluding equity accounted entities was 0.69 in 2019.

The organic reserves replacement ratio, i.e. excluding sales and purchases, was 0.83 in 2019 compared to 1.86 in 2018. The organic average three-year replacement ratio was 1.40 at the end of 2019.

For additional information regarding proved reserves changes and the reliability of proved reserves estimates, see the sections 4.2 Supplementary oil and gas information and 2.11 Risk review, respectively.

Reserves replacement ratio |  |  |
| For the year ended 31 December
(including purchases and sales) | 2019 | 2018 | 2017
Annual | 0.75 | 2.13 | 1.50
Three-year-average | 1.47 | 1.53 | 1.00

### Proved reserves by region

68 Equinor, Annual Report on Form 20-F 2019

Proved reserves in Norway

A total of 4,270 million boe is recognised as proved reserves in 61 fields and field development projects on the NCS, representing 71% of Equinor's total proved reserves. Of these, 56 fields and field areas are currently in production, 44[9] of which are operated by Equinor.

Production experience, further drilling and improved recovery on several of Equinor’s producing fields in Norway contributed positively to the revisions of the proved reserves in 2019. Two field development projects also added proved reserves categorised as extensions and discoveries during 2019, the Ærfugl phase 2 and Gudrun phase 2 development. The increased commodity prices reduced the proved reserves on a few fields in Norway but the total net price effect on the proved reserves in Norway is a reduction of less than 0.2%.

After the divestment of a 16% shareholding in Lundin, Equinor no longer carry any equity accounted proved reserves in Norway.

Of the proved reserves on the NCS, 2,544 million boe, or 60%, are proved developed reserves. Of the total proved reserves in this area, 60% are gas reserves related to large gas fields such as Troll, Snøhvit, Oseberg, Ormen Lange, Visund, Aasta Hansteen, Åsgard and Tyrihans, and 40% are liquid reserves.

Proved reserves in Eurasia, excluding Norway

In this area, Equinor has proved reserves of 296 million boe related to seven fields in Russia, Azerbaijan, United Kingdom and Ireland. Eurasia excluding Norway represents 5% of Equinor's total proved reserves, Russia being the main contributor after sanctioning of the first stage of the full field development of the North Komsomolskoye field. This is also the largest addition to the proved reserves in this area in 2019. Other additions are related to sanctioning of the development of the Azeri Central East (ACE) platform in the Azeri Chirag Gunashli field in Azerbaijan, and the Barnacle field in the United Kingdom. All fields in this area are now producing. Of the proved reserves in Eurasia, 81 million boe or 27% are proved developed reserves.

Of the total proved reserves in this area, 76% are liquid reserves and 24% are gas reserves.

[9] Fields carrying proved reserves at year-end 2019, whereas the number of fields with production during the year referred to in section 2.3 E&P Norway may be different depending on how production is allocated and reported.

Equinor, Annual Report on Form 20-F 2019 69

Proved reserves in Africa

Equinor recognises proved reserves of 198 million boe related to 28 fields and field developments in several West and North African countries, including Algeria, Angola, Libya and Nigeria. Africa represents 3% of Equinor's total proved reserves. Angola is the primary contributor to the proved reserves in this area, with 24 of the 28 fields. The reduction in oil and gas prices in 2019 had a net positive effect on the proved reserves from production sharing contracts in this area of approximately 5%.

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

In Algeria, Libya and Nigeria, all fields carrying proved reserves are in production.

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 24 Other commitments, contingent liabilities and contingent assets to the Consolidated financial statements. The effect of this redetermination on the proved reserves, which is estimated to be less than 10 million boe, is not yet included.

Most of the fields in Africa other than in Algeria, are mature and many are on decline or approaching the expiration date of the current PSA. High production in 2019 combined with limited positive revisions resulted in further reduction of the total proved reserves in this area. In Block 15 in Angola, the production sharing agreement was extended to 2032 in December 2019, and ratified in January 2020. In Block 17 the agreement was extended to 2045, pending ratification. These extensions are not yet reflected in the proved reserves in Angola but will be included from 2020.

Of the total proved reserves in Africa, 178 million boe, or 90%, are proved developed reserves. Of the total proved reserves in this area, 78% are liquid reserves and 22% are gas reserves.

70 Equinor, Annual Report on Form 20-F 2019

Proved reserves in the US

In the US, Equinor has proved reserves equal to 870 million boe in a total of 12 fields and field development projects, ten of which are offshore field developments in the Gulf of Mexico and two are onshore tight reservoir assets.,

Nine of the ten fields in the Gulf of Mexico are producing. Vito, which was sanctioned in 2018, is the only field in this area that is not yet producing. The onshore tight reservoir assets in the Appalachian basin and Bakken are all in production.

The largest changes to the proved reserves in the US in 2019 are related to new wells extending the proved areas in the US onshore assets. The acquisition of a 22.45% interest in the Caesar Tonga field in the Gulf of Mexico adds new proved reserves, whereas the divestment of Equinor’s 63% interest in the Eagle Ford shale play reduced the proved reserves in this area. The reduced oil and gas prices have a net negative effect of approximately 5% on the total proved reserves in this area, of which approximately two thirds are related to the US onshore assets.

O f the total proved reserves in the US, 621 million boe, or 71%, are proved developed reserves. Liquid reserves are 51% and gas reserves are 49%.

Proved reserves in the US now represent 14.5% of total proved reserves but the US is still disclosed as a separate geographic area in the tables since it represented 16% in 2017.

Proved reserves in the Americas excluding US

In the Americas excluding US, Equinor has proved reserves equal to 370 million boe in a total of six fields and field development projects. Four fields are located in Canada and two in Brazil.

In Canada, proved reserves are related to offshore field developments only and all four fields are producing. In Brazil, the two fields with proved reserves are both producing. The reduced oil and gas prices have not affected the proved reserves in this area in 2019.

O f the total proved reserves in the Americas excluding US,
255 million boe or 69%, are proved developed reserves. Less than 1% of the proved reserves in this area are gas reserves.

Equinor, Annual Report on Form 20-F 2019 71

### Preparation of reserves estimates

Equinor'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 average of more than 27 years' experience in the oil and gas industry. CRM reports to the vice president of finance and control in the Technology, Projects & Drilling business area and is independent of the Development & Production business areas. All the reserves estimates have been prepared by Equinor'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 Equinor'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 34 years' experience in the oil and gas industry, 33 of them with Equinor. She is a member of the Society of Petroleum Engineering (SPE) and of the Technical Advisory Group to the UNECE Expert Group on Resource Management (EGRM).

DeGolyer and MacNaughton report

Petroleum engineering consultants DeGolyer and MacNaughton have carried out an independent evaluation of Equinor’s proved reserves as of 31 December 2019 using data provided by Equinor. The evaluation accounts for 100% of Equinor's proved reserves including equity accounted entities. The aggregated net proved reserves estimates prepared by DeGolyer and MacNaughton do not differ materially from those prepared by Equinor when compared on the basis of net equivalent barrels.

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

72 Equinor, Annual Report on Form 20-F 2019

Net proved reserves |  |  |  |
| Oil and Condensate | NGL/LPG | Natural gas | Oil Equivalent
At 31 December 2019 | (mmboe) | (mmboe) | (mmcf) | (mmboe)
Estimated by Equinor | 2,575 | 337 | 17,355 | 6,004
Estimated by DeGolyer and MacNaughton | 2,642 | 323 | 17,191 | 6,028

### Operational statistics

Total developed and undeveloped oil and gas acreage, in which Equinor had interests at 31 December 2019, are presented in the table below.

Developed and undeveloped oil and gas acreage |  |  |  |  |  |  |  |
At 31 December 2019 (in thousands of acres) |  | Norway | Eurasia excluding Norway | Africa | US | Americas excluding US | Oceania | Total
Acreage developed | - gross1) | 909 | 146 | 834 | 498 | 364 | - | 2,749
| - net2) | 352 | 43 | 268 | 192 | 61 | - | 918
Acreage undeveloped | - gross1) | 21,547 | 33,729 | 33,590 | 2,326 | 45,898 | 4,275 | 141,365
| - net2) | 9,402 | 13,885 | 14,976 | 1,129 | 21,890 | 4,275 | 65,557
1) A gross value reflects the number of wells in which Equinor owns a working interest.
2) The net value corresponds to the sum of the fractional working interests owned by Equinor in the same gross wells.

Equinor's largest net undeveloped acreage concentration is in South Africa, which represents 20% of Equinor’s total net undeveloped acreage, followed by Norway and Russia.

The largest concentrations of developed net acreage in Norway are in the Troll, Oseberg area, Snøhvit, Ormen Lange and Johan Sverdrup fields. In Africa, the Algerian gas development projects In Amenas and In Salah represent the largest concentrations of net developed acreage. Bakken (onshore US) has the largest net developed acreage in the Americas including the US.

The largest undeveloped net acreage in the Americas, including the US, is in Argentina, Surinam and Canada. In Eurasia excluding Norway, Russia is the country with the largest undeveloped net acreage. In Oceania, we have undeveloped acreage in Australia.

Equinor holds acreage in numerous concessions, blocks and leases. The terms and conditions regarding expiration dates vary significantly from property to property. Work programmes 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, Equinor may decide to apply for an extension if more time is needed in order to fully evaluate the potential of the properties. Historically, Equinor 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 proved reserves.

Productive oil and gas wells

The number of gross and net productive oil and gas wells, in which Equinor had interests at 31 December 2019, is shown in the table below.

The gross and net number of oil wells has increased from last year mainly due to continued drilling at the Bakken onshore asset in the US and added production wells through sanctioning of the North Komsomolskoye field in Russia. The divestment of the Eagle Ford onshore field in the US reduced the number of gross and net oil and gas wells.

Equinor, Annual Report on Form 20-F 2019 73

The total gross number of productive wells as of end 2019 includes 382 oil wells and 12 gas wells with multiple completions or wells with more than one branch.

74 Equinor, Annual Report on Form 20-F 2019

Number of productive oil and gas wells |  |  |  |  |  |  |
At 31 December 2019 |  | Norway | Eurasia excluding Norway | Africa | US | Americas excluding US | Total
Oil wells | - gross1) | 897 | 225 | 429 | 2,531 | 167 | 4,249
| - net2) | 300.8 | 42.0 | 68.6 | 661.7 | 46.4 | 1,119.5
Gas wells | - gross1) | 200 | 12 | 109 | 1,993 | - | 2,314
| - net2) | 88.4 | 4.2 | 41.7 | 386.7 | - | 521.1
1) A gross value reflects the number of wells in which Equinor owns a working interest.
2) The net value corresponds to the sum of the fractional working interests owned by Equinor in the same gross wells.

Net productive and dry oil and gas wells drilled

The following tables show the number of net productive and dry exploratory and development oil and gas wells completed or abandoned by Equinor over 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 a well found to be incapable of producing sufficient quantities to justify completion as an oil or gas well.

Number of net productive and dry oil and gas wells drilled1) | Norway | Eurasia excluding Norway | Africa | US | Americas excluding US | Total |
Year 2019 |  |  |  |  |  |  |
Net productive and dry exploratory wells drilled | 11.0 | 5.0 | - | 0.4 | 2.1 | 18.5 |
- Net dry exploratory wells | 5.9 | 4.0 | - | - | 0.3 | 10.2 |
- Net productive exploratory wells | 5.1 | 1.0 | - | 0.4 | 1.8 | 8.3 |
Net productive and dry development wells drilled | 30.7 | 13.4 | 2.0 | 121.6 | 3.5 | 171.1 |
- Net dry development wells | 5.1 | 1.4 | - | 0.5 | 0.8 | 7.8 |
- Net productive development wells | 25.6 | 12.0 | 2.0 | 121.1 | 2.6 | 163.3 |
Year 2018 |  |  |  |  |  |  |
Net productive and dry exploratory wells drilled | 8.6 | - | 0.7 | 0.6 | 0.5 | 10.3 |
- Net dry exploratory wells | 4.5 | - | 0.7 | 0.6 | 0.5 | 6.2 |
- Net productive exploratory wells | 4.0 | - | - | - | - | 4.0 |
Net productive and dry development wells drilled | 42.7 | 3.3 | 4.2 | 102.8 | 3.3 | 156.3 |
- Net dry development wells | 13.6 | 0.5 | 0.2 | 0.3 | 1.0 | 15.6 |
- Net productive development wells | 29.2 | 2.8 | 4.0 | 102.5 | 2.2 | 140.7 |
Year 2017 |  |  |  |  |  |  |
Net productive and dry exploratory wells drilled | 8.1 | 2.6 | - | 0.7 | 1.9 | 13.3 |
- Net dry exploratory wells | 3.5 | 2.1 | - | - | 1.9 | 7.5 |
- Net productive exploratory wells | 4.6 | 0.5 | - | 0.7 | - | 5.8 |
Net productive and dry development wells drilled | 37.5 | 5.0 | 4.3 | 103.2 | 2.3 | 152.2 |
- Net dry development wells | 10.1 | - | 0.1 | - | 0.1 | 10.3 |
- Net productive development wells | 27.4 | 5.0 | 4.2 | 103.2 | 2.2 | 142.0 |
1) The net value corresponds to the sum of the fractional working interests owned by Equinor in the same gross wells. |

Equinor, Annual Report on Form 20-F 2019 75

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 Equinor
at 31 December 2019.

Number of wells in progress |  |  |  |  |  |  |
At 31 December 2019 |  | Norway | Eurasia excluding Norway | Africa | US | Americas excluding US | Total
Development wells3) | - gross1) | 25 | 7 | 5 | 172 | 4 | 213
| - net2) | 12.1 | 1.5 | 2.1 | 34.0 | 0.6 | 50.3
Exploratory wells | - gross1) | 2 | 3 | 1 | 2 | 8 | 16
| - net2) | 0.8 | 1.5 | 0.3 | 0.8 | 3.6 | 6.9
1) A gross value reflects the number of wells in which Equinor owns a working interest.
2) The net value corresponds to the sum of the fractional working interests owned by Equinor in the same gross wells.
3) Mainly wells related to US onshore developments.

### Delivery commitments

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

Equinor’s and SDFI's delivery commitments under bilateral agreements for the calendar years 2020, 2021, 2022 and 2023, expressed as the sum of expected gas off-take, are equal to 46.9, 41.8, 36.3 and 29.1 bcm, respectively. The number of bilateral agreements is steadily declining as our customers are increasingly requesting more and more short-term contracts and higher volumes are traded on the spot market.

Equinor’s currently developed gas reserves on the NCS are more than sufficient to meet our share of these commitments for the next four years.

Any remaining volumes after covering our delivery commitments under the bilateral agreements, will be sold by trading activities at the hubs.

## Production volumes and prices

The business overview is presented based on our segment's operations as of 31 December 2019, whereas certain disclosures on oil and gas reserves are based on geographical areas as required by the SEC. For further information about extractive activities, see sections 2.3 E&P Norway and 2.4 E&P International.

Equinor 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, US and the Americas excluding US.

76 Equinor, Annual Report on Form 20-F 2019

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 section 4.2 Supplementary oil and gas information (unaudited).

###

Equinor, Annual Report on Form 20-F 2019 77

### Entitlement production

The following table shows Equinor's Norwegian and international entitlement production of oil and natural gas for the periods indicated. The stated production volumes are the volumes to which Equinor 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. Production is based on 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.

Entitlement production |  |  |  |  |  |  |  |
| Consolidated companies | Equity accounted | Total
Norway | Eurasia excluding Norway | Africa | US | Americas excluding US | Subtotal | Norway | Eurasia excluding Norway | Americas excluding US | Subtotal |
Oil and Condensate (mmboe) |  |  |  |  |
2019 | 151 | 9 | 47 | 54 | 36 | 296 | 3 | 1 | - | 4 | 300
2018 | 155 | 8 | 57 | 48 | 29 | 298 | 5 | - | - | 5 | 303
2017 | 165 | 10 | 68 | 38 | 21 | 302 | 6 | 0 | 2 | 8 | 310
NGL (mmboe) |  |  |  |  |
2019 | 41 | - | 3 | 12 | - | 57 | - | - | - | - | 57
2018 | 46 | - | 4 | 12 | - | 62 | 0 | - | - | 0 | 62
2017 | 48 | - | 4 | 9 | 0 | 61 | - | - | - | - | 61
Natural gas (mmcf) |  |  |  |  |
2019 | 1,447 | 31 | 57 | 363 | 9 | 1,907 | 2 | 4 | - | 6 | 1,913
2018 | 1,502 | 39 | 84 | 318 | 5 | 1,949 | 4 | - | - | 4 | 1,953
2017 | 1,515 | 41 | 72 | 240 | 0 | 1,868 | 4 | 0 | - | 5 | 1,873
Combined oil, condensate, NGL and gas (mmboe) |  |  |  |  |
2019 | 450 | 15 | 60 | 131 | 38 | 693 | 3 | 1 | - | 5 | 698
2018 | 469 | 15 | 76 | 116 | 30 | 707 | 6 | - | - | 6 | 713
2017 | 483 | 17 | 85 | 90 | 21 | 696 | 6 | 0 | 2 | 9 | 705
The Troll field in Norway is the only field containing more than 15% of total proved reserves based on barrels of oil equivalent.
Entitlement production |  |  |  |  |  |  |  |
|  |  |  |  |  |  |  | 2019 | 2018 | 2017
Troll field 1) |  |  |  |  |  |  |  |
Oil and Condensate (mmboe) |  |  |  |  |  | 12 | 13 | 14
NGL (mmboe) |  |  |  |  |  | 2 | 2 | 2
Natural gas (mmcf) |  |  |  |  |  | 341 | 417 | 384
Combined oil, condensate, NGL and gas (mmboe) |  |  |  |  | 74 | 89 | 85
1) Note that Troll is also included in Norway stated above. |  |  |  |

###

78 Equinor, Annual Report on Form 20-F 2019

### Operational data

The following table presents operational data for 2019, 2018 and 2017.

| For the year ended 31 December |  |
Operational data | 2019 | 2018 | 2017 | 19-18 change | 18-17 change
Prices |  |  |  |  |
Average Brent oil price (USD/bbl) | 64.3 | 71.1 | 54.2 | (9%) | 31%
E&P Norway average liquids price (USD/bbl) | 57.4 | 64.3 | 50.2 | (11%) | 28%
E&P International average liquids price (USD/bbl) | 54.5 | 61.6 | 47.6 | (12%) | 29%
Group average liquids price (USD/bbl) | 56.0 | 63.1 | 49.1 | (11%) | 29%
Group average liquids price (NOK/bbl) | 493 | 513 | 405 | (4%) | 27%
Transfer price natural gas (USD/mmBtu) | 4.46 | 5.65 | 4.33 | (21%) | 31%
Average invoiced gas prices - Europe (USD/mmBtu) | 5.79 | 7.04 | 5.55 | (18%) | 27%
Average invoiced gas prices - North America (USD/mmBtu) | 2.43 | 3.04 | 2.73 | (20%) | 11%
Refining reference margin (USD/bbl) | 4.1 | 5.3 | 6.3 | (23%) | (16%)
Entitlement production (mboe per day) |  |  |  |  |
E&P Norway entitlement liquids production | 535 | 565 | 594 | (5%) | (5%)
E&P International entitlement liquids production | 447 | 434 | 415 | 3% | 5%
Group entitlement liquids production | 983 | 999 | 1,009 | (2%) | (1%)
E&P Norway entitlement gas production | 700 | 722 | 740 | (3%) | (2%)
E&P International entitlement gas production | 228 | 218 | 173 | 5% | 26%
Group entitlement gas production | 928 | 940 | 913 | (1%) | 3%
Total entitlement liquids and gas production | 1,911 | 1,940 | 1,922 | (1%) | 1%
Equity production (mboe per day) |  |  |  |  |
E&P Norway equity liquids production | 535 | 565 | 594 | (5%) | (5%)
E&P International equity liquids production | 564 | 567 | 545 | (1%) | 4%
Group equity liquids production | 1,099 | 1,132 | 1,139 | (3%) | (1%)
E&P Norway equity gas production | 700 | 722 | 740 | (3%) | (2%)
E&P International equity gas production | 275 | 256 | 200 | 7% | 28%
Group equity gas production | 975 | 979 | 941 | (0%) | 4%
Total equity liquids and gas production | 2,074 | 2,111 | 2,080 | (2%) | 1%
Liftings (mboe per day) |  |  |  |  |
Liquids liftings | 994 | 1,002 | 1,012 | (1%) | (1%)
Gas liftings | 962 | 975 | 936 | (1%) | 4%
Total liquids and gas liftings | 1,955 | 1,976 | 1,948 | (1%) | 1%
Production cost (USD/boe) |  |  |  |  |
Production cost entitlement volumes | 5.8 | 5.7 | 5.2 | 2% | 10%
Production cost equity volumes | 5.3 | 5.2 | 4.8 | 2% | 9%

###

Equinor, Annual Report on Form 20-F 2019 79

### Sales prices

The following table presents realised sales prices.

Realised sales prices | Norway | Eurasia excluding Norway | Africa | Americas
Year ended 31 December 2019 |  |  |  |
Average sales price oil and condensate in USD per bbl | 64.0 | 61.1 | 64.3 | 55.9
Average sales price NGL in USD per bbl | 33.0 | - | 30.1 | 16.6
Average sales price natural gas in USD per mmBtu | 5.8 | 4.6 | 5.5 | 2.4
Year ended 31 December 2018 |  |  |  |
Average sales price oil and condensate in USD per bbl | 70.2 | 70.5 | 69.9 | 62.4
Average sales price NGL in USD per bbl | 42.9 | - | 41.3 | 27.1
Average sales price natural gas in USD per mmBtu | 7.0 | 7.5 | 5.7 | 3.0
Year ended 31 December 2017 |  |  |  |
Average sales price oil and condensate in USD per bbl | 54.0 | 53.6 | 53.5 | 46.0
Average sales price NGL in USD per bbl | 35.8 | - | 33.2 | 20.9
Average sales price natural gas in USD per mmBtu | 5.6 | 5.3 | 5.2 | 2.7

###

80 Equinor, Annual Report on Form 20-F 2019

### Sales volumes

Sales volumes include lifted entitlement volumes, the sale of SDFI volumes and marketing of third-party volumes. In addition to Equinor’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 2.7 Corporate under SDFI oil and gas marketing and sale.

The following table shows the SDFI and Equinor sales volume information on crude oil and natural gas for the periods indicated.

| For the year ended 31 December
Sales Volumes | 2019 | 2018 | 2017
Equinor1) |  |  |
Crude oil (mmbbls)2) | 363 | 366 | 369
Natural gas (bcm) | 55.8 | 56.5 | 54.3
Combined oil and gas (mmboe) | 714 | 721 | 711
Third-party volumes3) |  |  |
Crude oil (mmbbls)2) | 325 | 359 | 302
Natural gas (bcm) | 7.3 | 5.7 | 6.4
Combined oil and gas (mmboe) | 371 | 394 | 342
SDFI assets owned by the Norwegian State4) |  |  |
Crude oil (mmbbls)2) | 122 | 131 | 147
Natural gas (bcm) | 38.0 | 43.7 | 44.0
Combined oil and gas (mmboe) | 360 | 406 | 424
Total |  |  |
Crude oil (mmbbls)2) | 809 | 855 | 819
Natural gas (bcm) | 101.0 | 105.9 | 104.7
Combined oil and gas (mmboe) | 1,445 | 1,521 | 1,477
1) | The Equinor 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 E&P International but not sold by MMP, and volumes lifted by E&P Norway or E&P International 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) | The line item SDFI assets owned by the Norwegian State includes sales of both equity production and third-party.

Equinor, Annual Report on Form 20-F 2019 81

2.9 Financial review

#

The following discussion does not address certain items in respect of 2017 in reliance on amendments to disclosure requirements adopted by the SEC in 2019. A discussion of such items in respect of 2017 may be found in our Annual Report on Form 20-F for the year ended December 31, 2018, filed with the SEC on March 15, 2019.

## Group financial performance

Lower prices for liquids and gas largely affected the Group´s financial result in 2019. The average Brent price in 2019 was 9% lower compared to 2018 and the average gas price for Europe and North America was down 18% and 20%, respectively. In addition, lower liquids volumes and higher impairments in the E&P reporting segments contributed to the decreased result compared to 2018. New fields on the NCS and in the E&P International reporting segment led to increased depreciation expenses along with higher operations and maintenance expenses. High exploration activity and increased costs related to field development. In 2019, Equinor delivered an entitlement production of 1,911 mboe per day, down 1% from 2018. N et income was USD 1.85 billion, down from USD 7.5 billion in 2018.

Total eq uity liquids and gas production was 2,074 mboe and 2,111 mboe per day in 2019 and 2018, respectively. The 2% decrease in total equity production was mainly due to expected natural decline and reduced flexible gas production due to lower prices. The decrease was partially offset by start-up of new fields on the NCS and in the E&P International reporting segment, new wells in the US onshore business and portfolio changes.

Total entitlement liquids and gas production was 1,911 mboe per day in 2019 compared to 1,940 mboe in 2018. The total entitlement liquids and gas production was down 1% for the reasons described above in addition to increased US royalties driven by higher equity production in the US, partially offset by lower negative effect from production sharing agreements.

The combined effect of production sharing agreements (PSA effect) and US royalties was 163 mboe and 171 mboe per day in 2019 and 2018, 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.

Condensed income statement under IFRS | For the year ended 31 December |
(in USD million) | 2019 | 2018 | Change
Revenues | 62,911 | 78,555 | (20%)
Net income/(loss) from equity accounted investments | 164 | 291 | (44%)
Other income | 1,283 | 746 | 72%
Total revenues and other income | 64,357 | 79,593 | (19%)
Purchases [net of inventory variation] | (29,532) | (38,516) | (23%)
Operating, selling, general and administrative expenses | (10,469) | (10,286) | 2%
Depreciation, amortisation and net impairment losses | (13,204) | (9,249) | 43%
Exploration expenses | (1,854) | (1,405) | 32%
Net operating income/(loss) | 9,299 | 20,137 | (54%)
Net financial items | (7) | (1,263) | 99%
Income/(loss) before tax | 9,292 | 18,874 | (51%)
Income tax | (7,441) | (11,335) | (34%)
Net income/(loss) | 1,851 | 7,538 | (75%)

82 Equinor, Annual Report on Form 20-F 2019

Equinor, Annual Report on Form 20-F 2019 83

Total revenues and other income amounted to USD 64,357 million in 2019 compared to USD 79,593 million in 2018.

Revenues are generated from both the sale of lifted crude oil, natural gas and refined products produced and marketed by Equinor, 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 in this report.

Revenues were USD 62,911 million in 2019, down 20% compared to 2018. The decrease was mainly due to lower average prices and lower volumes for liquids and gas.

Net income from equity accounted investments was USD 164 million in 2019, down from USD 291 million in 2018 due to reduced profit mainly from equity accounted investments. For further information, see note 12 Equity accounted investments to the Consolidated financial statements.

Melkøya, Hammerfest, Norway.

Other income was USD 1,283 million in 2019 compared to USD 746 million in 2018. In 2019, other income was positively impacted by gain on sale of assets in Lundin and Arkona in addition to a swap transaction with Faroe Petroleum. In 2018, other income was positively impacted by gain on sale of assets mainly related to King Lear, Tommeliten and Norsea pipeline.

Because of the factors explained above, total revenue and other income was down by 19% in 2019.

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 29,532 million in 2019 compared to USD 38,516 million in 2018. The 23% decrease in 2019 was mainly related to lower average prices and volumes for liquids and gas.

Operating, selling, general and administrative expenses amounted to USD 10,469 million in 2019 compared to USD 10,286 million in 2018. The 2% increase from 2018 to 2019 was primarily impacted by higher provisions from the MMP reporting segment related to the hurricane damage to the South Riding Point oil terminal in the Bahamas. Increased transportation costs mainly related to liquids volumes and higher operation and maintenance costs mainly related to new fields added to the increase, partially offset by the implementation of IFRS 16[10] and the NOK/USD exchange rate development.

[10] For more information, see note 23 Implementation of IFRS 16 Leases to the Consolidated financial statements and notes

84 Equinor, Annual Report on Form 20-F 2019

Depreciation, amortisation and net impairment losses amounted to USD 13,204 million compared to USD 9,249 million in 2018. The 43% increase was mainly due to higher net impairments mainly related to unconventional onshore assets in North America and offshore assets on the NCS. Increased investments in the E&P International segment, ramp-up of new fields and the implementation of IFRS 161 added to the increase, partially offset by higher proved reserves estimates on several fields, no depreciation effect on one of the fields on the NCS due to all remaining proved reserves being produced in previous periods, and a net decrease in production.

Included in the total for 2019 were net impairments of USD 4,093 million, the majority of which relate to decreased price assumptions. Other elements were negative change in production profiles and reserves, cost increases and damage of the South Riding point oil terminal on the Bahamas caused by the hurricane Dorian.

Included in the total for 2018 were net impairment reversals of USD 604 million, of which impairment reversals amounted to USD 1,398 million mainly related to operational improvements, updated exchange rate assumptions, increased refinery margins assumptions, and extension of a production sharing agreement (PSA). The impairment reversals were partially offset by impairment losses of USD 794 million, mainly related to long term prices assumptions.

For further information, see note 3 Segments and note 10 Property, plant and equipment to the Consolidated financial statements.

Exploration expenses |  |  |
| For the year ended 31 December |
(in USD million) | 2019 | 2018 | Change
Exploration expenditures | 1,584 | 1,438 | 10%
Expensed, previously capitalised exploration expenditures | 120 | 68 | 78%
Capitalised share of current period's exploration activity | (507) | (390) | 30%
Net impairments / (reversals) | 657 | 289 | >100%
Total exploration expenses | 1,854 | 1,405 | 32%

In 2019, exploration expenses were USD 1,854 million, a 32% increase compared to 2018 when exploration expenses were USD 1,405 million.

The 32% increase in exploration expenses in 2019 is primarily due to higher drilling and field development costs because of higher activity, a higher portion of exploration expenditure capitalised in earlier years being expensed and higher net impairments compared to 2018. The increase was partially offset by a higher portion of exploration expenses being capitalised and lower seismic activity compared to 2018. In 2019 there was exploration activity in 58 wells compared with 36 wells in 2018. 42 wells were completed with 16 commercial discoveries in 2019 compared with 24 wells completed and 9 commercial discoveries in 2018.

Net operating income was USD 9,299 million in 2019 compared to USD 20,137 million in 2018. With reference to the development in revenues and costs as discussed above, the 54% decrease in 2019 was primarily driven by lower liquids and gas prices and liquids volumes. Higher net impairments mainly related to unconventional onshore assets in North America and offshore assets on the NCS in addition to increased provisions in the MMP reporting segment related to the hurricane damage to the South Riding Point oil terminal, contributed to the decrease. The decrease was partially offset by a net gain on the sale of assets mainly related to the E&P Norway reporting segment in 2019.

Net financial items amounted to a loss of USD 7 million in 2019. In 2018, net financial items were a loss of USD 1,263 m illion. The reduced loss of USD 1,256 million in 2019 was mainly due to gain on derivatives related to our long-term debt portfolio of USD 473 million in 2019, compared to a loss of USD 341 million in 2018. In addition, a currency gain of USD 224 million was recognised in 2019, compared to a loss of USD 166 million in 2018.

Income taxes were USD 7,441 million in 2019, equivalent to an effective tax rate of 80.1%, compared to USD 11,335 million in 2018, equivalent to an effective tax rate of 60.1%. The effective tax rate in 2019 was primarily influenced by losses recognised in countries without recognised taxes or in countries with lower than average tax rates, partially offset by tax exempted gains on divestments. For further information, see note 9 Income taxes to the Consolidated financial statements.

The effective tax rate in 2018 was primarily influenced by positive net operating income in entities without recognised taxes and a tax exempted divestment of interest at the NCS. The effective rate was also influenced by recognition of previously unrecognised deferred tax assets.

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

Equinor, Annual Report on Form 20-F 2019 85

income, including the onshore portion of net financial items, is taxed at 22% (23% in 2018), and income in other countries is taxed at the applicable income tax rates in the various countries.

In 2019, net income was USD 1,851 million compared to USD 7,538 million in 2018.

The significant decrease in 2019 was mainly a result of the decrease in net operating income, partially offset by lower income taxes and the positive change in the net financial items, as explained above.

The board of directors proposes to the AGM to increase the dividend by 4% to USD 0.27 per ordinary share for the fourth quarter of 2019.

The annual ordinary dividends for 2019 amounted to an aggregate total of USD 3,479 million. Considering the proposed dividend, USD 1,780 million will be allocated from retained earnings in the parent company.

For 2018, annual ordinary dividends amounted to an aggregate total of USD 2,826 million, net after scrip dividend of USD 338 million.

For further information, see note 17 Shareholders’ equity and dividends to the Consolidated financial statements.

In accordance with §3-3a 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.

IFRS 16 Leases

With effect from 1 January 2019, Equinor implemented IFRS 16. Reference is made to Note 22 Leases and Note 23 Implementation of IFRS 16 Leases for further information about the standard, the policy and implementation choices made by Equinor, and the IFRS 16 implementation impact.

## Segments financial performance

### E&P Norway profit and loss analysis

Net operating income in 2019 was USD 9,631 million, compared to USD 14,406 million in 2018. The USD 4,775 million decrease from 2018 to 2019 was primarily driven by lower liquids and gas prices in addition to lower production of liquids and gas volumes. In addition, impairment of assets were USD 1,284 million in 2019, compared to impairment reversal of USD 604 million in 2018.

The average daily production of liquids and gas was 1,235 mboe per day in 2019 and 1,288 mboe per day in 2018.

The average daily total production level decreased in 2019 mainly due to expected natural decline, lower production efficiency, and lower flex gas off-take from Troll, partially offset by positive contribution from new wells at producing fields and new fields Johan Sverdrup, Trestakk and Utgard.

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.

E&P Norway - condensed income statement under IFRS |  |  |
| For the year ended 31 December |
(in USD million) | 2019 | 2018 | Change
Revenues | 17,789 | 21,909 | (19%)
Net income/(loss) from equity accounted investments | 15 | 10 | 49%
Other income | 1,028 | 556 | 85%
Total revenues and other income | 18,832 | 22,475 | (16%)
Operating, selling, general and administrative expenses | (3,284) | (3,270) | 0%
Depreciation, amortisation and net impairment losses | (5,439) | (4,370) | 24%
Exploration expenses | (478) | (431) | 11%
Net operating income/(loss) | 9,631 | 14,406 | (33%)

86 Equinor, Annual Report on Form 20-F 2019

Total revenues and other income were USD 18,832 million in 2019 and USD 22,475 million in 2018.

The 19% decrease in revenue in 2019 was mainly due to decreased liquids and gas prices, in addition to lower production of liquids and gas volumes.

Other income was impacted by gain from the sale of assets of USD 977 million in 2019. In 2018 other income was impacted by gain from sale of exploration assets of USD 490 million.

Operating expenses and selling, general and administrative expenses were USD 3,284 million in 2019, compared to USD 3,270 million in 2018. The cost related to ramp-up of new fields was offset by the NOK/USD exchange rate development.

Depreciation, amortisation and net impairment losses were USD 5,439 million in 2019, compared to USD 4,370 million in 2018. The increase was mainly related to impairment of assets of USD 1,284 million in 2019[11] , compared to impairment reversals of USD 604 million in 2018. The increase was partially offset by production from assets with no remaining proved reserves in 2019 and net decrease in field-specific production.

Exploration expenses were USD 478 million in 2019, compared to USD 431 million in 2018. The increase from 2018 to 2019 was primarily due to higher drilling and field development cost mainly because of higher activity. In 2019 there was exploration activity in 28 wells with 26 wells completed, compared to activity in 23 wells with 18 wells completed in 2018.

### E&P International profit and loss analysis

Net operating income in 2019 was negative USD 800 million, compared to positive USD 3,802 million in 2018. The negative development was primarily caused by impairment losses in 2019, decreased liquids and gas prices and a positive impact in 2018 from a reduction in provisions related to a redetermination process in Nigeria.

The average daily equity liquids and gas production (see section 5.6 Terms and abbreviations) was 839 mboe per day in 2019, compared to 823 mboe per day in 2018. The increase of 2% was driven by new wells in the US onshore, particularly in Appalachian region, as well as the effect of new fields in Brazil, UK and offshore North America. The increase was partially offset by natural decline, primarily at mature fields in Angola.

The average daily entitlement liquids and gas production (see section 5.6 Terms and abbreviations) was 676 mboe per day in 2019, compared to 652 mboe per day in 2018. Entitlement production in 2019 increased by 4% due to higher equity production as described above and lower negative effect from production sharing agreements, partially offset by increased US royalties driven by the higher equity production. The combined effect of production sharing agreements (PSA effect) and US royalties was 163 mboe per day in 2019 and 171 mboe per day in 2018.

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.

E&P International - condensed income statement under IFRS |  |  |
| For the year ended 31 December |
(in USD million) | 2019 | 2018 | Change
Revenues | 10,276 | 12,322 | (17%)
Net income/(loss) from equity accounted investments | 30 | 31 | (4%)
Other income | 19 | 45 | (58%)
Total revenues and other income | 10,325 | 12,399 | (17%)
Purchases [net of inventory] | (34) | (26) | 34%
Operating, selling, general and administrative expenses | (3,352) | (3,006) | 12%
Depreciation, amortisation and net impairment losses | (6,361) | (4,592) | 39%
Exploration expenses | (1,377) | (973) | 41%
Net operating income/(loss) | (800) | 3,802 | N/A

[11] See note 10 Property, Plant and Equipment in the Consolidated financial statement and notes for more information on the basis on the impairment assessment.

Equinor, Annual Report on Form 20-F 2019 87

E&P International generated total revenues and other income of USD 10,325 million in 2019, compared to USD 12,399 million in 2018.

Revenues in 2019 decreased primarily due to lower realised liquids and gas prices, partially offset by increased entitlement production. In 2018, revenues were positively impacted by USD 774 million, due to effects from change in provisions related to a redetermination process in Nigeria. For information related to the reversal of provisions, see note 24 Other commitments, contingent liabilities and contingent assets to the Consolidated financial statements.

Other income was USD 19 million in 2019, compared to USD 45 million in 2018. In 2019, other income was mainly related to a gain from divestment of license interests in Nicaragua. In 2018, other income was mainly related to a gain from divestment of the Alba field.

As a result of the factors explained above, total revenues and other income decreased by 17% in 2019.

Operating, selling, general and administrative expenses were USD 3,352 million in 2019, compared to USD 3,006 million in 2018. The 12% increase from 2018 to 2019 was mainly due to portfolio changes, and higher operation and transportation expenses driven by new fields on stream and volume growth in the US onshore. In addition, net losses from sale of assets in 2019 contributed to the increase. The increases were partially offset by decreased royalties and production fees, caused by lower prices and related volumes.

Depreciation, amortisation and net impairment losses were USD 6,361 million in 2019, compared to USD 4,592 million in 2018. The 39% increase from 2018 to 2019 was primarily caused by impairment losses in 2019. Net impairment losses in 2019 amounted to USD 1,920 million, with impairments of unconventional onshore assets in North America as the largest contributors, caused by decreased long-term price assumption in addition to changed operational plans for certain assets. Net impairment losses in 2018 amounted to USD 154 million, with impairments of unconventional assets in North America as the largest contributors, caused by reduced long-term price assumptions and reduced fair value for one asset. In addition, depreciation increased mainly due to higher investments, new fields in operation and portfolio changes, offset by higher reserve estimates.

Exploration expenses were USD 1,377 million in 2019, compared to USD 973 million in 2018. The increase from 2018 to 2019 was mainly due to higher drilling and field development costs mainly due to higher activity, a higher portion of capitalised expenditures from earlier years being expensed and net impairment of exploration prospects and signature bonuses in 2019 of USD 656 million compared with USD 280 million in 2018. This was partially offset by a higher portion of exploration expenditures being capitalised and a lower portion of seismic costs. In 2019 there was exploration activity in 30 wells with 16 wells completed, compared to 13 wells with 6 wells completed in 2018.

### MMP profit and loss analysis

Net operating income was USD 1,004 million compared to USD 1,906 million in 2018, a decrease of 47%. The decrease was mainly due to increased operating and administrative expenses related to higher transportation costs for liquid volumes, higher provisions and impairments related to damage to the South Riding Point oil terminal in the Bahamas, in addition to onerous contract provisions in North America. In total, provisions amounted to USD 418 million and impairments of USD 206 million. Weak gas prices as well as reduced processing margins added to the decrease in 2019 compared to 2018. The decrease was partially offset by strong results from crude and liquids trading in 2019.

In 2018, the net operating income was impacted by negative operational storage effects amounting to USD 132 million and lower liquids trading results and reduced processing margins partially offset by improved LNG results, the sale of the ownership share in infrastructure assets amounting to USD 129 million and the net impairment amounting to USD 154 million.

The total natural gas sales volumes were 59.4 bcm in 2019, at the same level as total volumes for 2018. The increase in the entitlement production internationally and third-party gas volumes was offset by a reduction in the entitlement production on the NCS. The chart does not include any volumes sold on behalf of the Norwegian State's direct financial interest (SDFI).

88 Equinor, Annual Report on Form 20-F 2019

In 2019, the average invoiced natural gas sales price in Europe was USD 5.79 per mmBtu, down 18% from USD 7.04 per mmBtu in 2018. The 2018 average invoiced natural gas price in Europe was up 27% from 2017 (USD 5.55 per mmBtu).

In 2019, the average invoiced natural gas sales price in North America was USD 2.43 per mmBtu, down 20% from USD 3.04 per mmBtu in 2018. The 2018 average invoiced natural gas sales price in North Americas was up 11% from 2017 (USD 2.73 per mmBtu).

All of Equinor's gas produced on the NCS is sold by MMP and purchased from E&P Norway at the fields’ lifting point at a market-based internal price with deduction for the cost of bringing the gas from the field to the market and a marketing fee element. Our NCS transfer price for gas was USD 4.46 per mmBtu in 2019, a decrease of 21% compared to USD 5.65 per mmBtu in 2018. The 2018 NCS transfer price was up 31% from 2017 (USD 4.33 per mmBtu).

The average crude, condensate and NGL sales were 2.1 mmbbl per day in 2019 of which approximately 0.85 mmbbl were sales of our equity volumes, 0.89 mmbbl were sales of third-party volumes and 0.33 mmbbl were sales of volumes purchased from SDFI. Our average sales volumes were 2.3 mmbbl per day in 2018 and 2.2 mmbbl per day and 2017. The average daily third-party sales volumes were 0.98 and 0.83 mmbbl in 2018 and 2017.

MMP’s refining margins were lower for Mongstad and higher for Kalundborg in 2019 compared to 2018. Equinor's refining reference margin was 4.1 USD/bbl in 2019, compared to 5.3 USD/bbl in 2018, a decrease of 23%

.

Equinor, Annual Report on Form 20-F 2019 89

MMP - condensed income statement under IFRS |  |  |
| For the year ended 31 December |
(in USD million) | 2019 | 2018 | Change
Revenues | 60,928 | 75,636 | (19%)
Net income/(loss) from equity accounted investments | 25 | 16 | 56%
Other income | 2 | 142 | (98%)
Total revenues and other income | 60,955 | 75,794 | (20%)
Purchases [net of inventory] | (54,454) | (69,296) | (21%)
Operating, selling, general and administrative expenses | (4,897) | (4,377) | 12%
Depreciation, amortisation and net impairment losses | (600) | (215) | >100%
Net operating income/(loss) | 1,004 | 1,906 | (47%)

Total revenues and other income were USD 60,955 million in 2019, compared to USD 75,794 million in 2018.

The decrease in revenues from 2018 to 2019 was mainly due to a decrease in in the prices for all products as well as decreased volume for liquids. The average crude price in USD decreased by approximately 9% in 2019 compared to 2018.

Other income in 2019 was lower mainly due a gain on the sale of assets amounting to USD 133 million in 2018.

Because of the factors explained above, total revenues and other income decreased by 20% from 2018 to 2019.

Purchases [net of inventory] were USD 54,454 million in 2019, compared to USD 69,296 million in 2018. The decrease from 2018 to 2019 was mainly due to a decrease in the price for all products as well as decreased volume for liquids.

Operating expenses and selling, general and administrative expenses were USD 4,897 million in 2019, compared to USD 4,377 million in 2018. The increase from 2018 to 2019 was mainly due to higher transportation cost for liquids, higher cost for operating plants mainly due to provision booked in 2019 related to the South Riding Point Terminal.

Depreciation, amortisation and net impairment losses were USD 600 million in 2019, compared to USD 215 million in 2018. The increase in depreciation, amortisation and net impairment losses from 2018 to 2019 was mainly caused by impairment booked in 2019 related to the South Riding Point Terminal and higher reversal of impairments in 2018, as well as depreciation from a new infrastructure asset. Net reversal of impairments in 2018 was related to the refinery assets, due to an increased refinery margin forecast.

### Other

The Other reporting segment includes activities within New Energy Solutions; Global Strategy & Business Development; Technology, Projects & Drilling; and Corporate staffs and support functions, and IFRS 16 leases. All lease contracts are presented within the Other segment. For more information on impact of IFRS 16 on the segment reporting, see note 23 Implementation of IFRS 16 leases to the Consolidated financial statements and notes.

In 2019, the Other reporting segment recorded a net operating income of USD 92 million compared to a net operating loss of USD 79 million in 2018. Gain on divestment of interest in Arkona offshore windfarm is an item with single biggest impact on the result, see note 4 Acquisitions and divestments to the Consolidated financial statement and notes.

90 Equinor, Annual Report on Form 20-F 2019

2.10 Liquidity and capital resources

The following discussion does not address certain items in respect of 2017 in reliance on amendments to disclosure requirements adopted by the SEC in 2019. A discussion of such items in respect of 2017 may be found in our Annual Report on Form 20-F for the year ended December 31, 2018, filed with the SEC on March 15, 2019.

##

## R eview of cash flows

Equinor’s cash flow generation in 2019 were reduced by USD 5,800 million compared to 2018.

Consolidated statement of cash flows |  |
| Full year
(in USD million) | 2019 | 2018
Cash flows provided by operating activities | 13,749 | 19,694
Cash flows used in investing activities | (10,594) | (11,212)
Cash flows provided by/(used in) financing activities | (5,496) | (5,024)
Net increase/(decrease) in cash and cash equivalents | (2,341) | 3,458

Cash flows provided by operating activities

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.

In 2019, cash flows provided by operating activities decreased by USD 5,946 million compared to 2018. The decrease was mainly due to lower liquids and gas prices, increased derivative payments and a change in working capital, partially offset by decreased tax payments.

Cash flows used in investing activities

In 2019, c ash flows used in investing activities decreased by USD 618 million compared to 2018. The decrease was mainly due to lower cash flows used for business combinations, lower capital expenditures and increased proceeds from sale of assets, partially offset by increased financial investments.

Cash flows provided by (used in) financing activities

In 2019, cash flows used in financing activities increased by USD 472 million compared to 2018. The increase was mainly due to lease payments being reclassified to financing cash flow following the IFRS 16 implementation, increased dividend paid, and share buy-back partially offset by decreased repayment of finance debt and higher cash inflow from collateral related to derivatives.

## F inancial assets and debt

The net debt to capital employed ratio before adjustments at year end increased from 20.6% in 2018 to 28.5% in 2019, mainly due to implementation of IFRS 16 Lease. See section 5.2 for non-GAAP measures for net debt ratio. Net interest-bearing debt increased from USD 11.1 billion to USD 16.4 billion. During 2019 Equinor's total equity decreased from USD 43.0 billion to USD 41.2 billion, mainly driven by lower liquids and gas prices and liquids volumes i n 2019, higher net impairments and increased capital distributions. Equinor has paid out four quarterly dividends in 2019. For the fourth quarter of 2019 the board of directors proposed to the AGM to increase the dividend from USD 0.26 to USD 0.27 per share. For further information, see note 17 Shareholders equity and dividends to the Consolidated financial statements.

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

Equinor, Annual Report on Form 20-F 2019 91

Funding needs arise as a result of Equinor’s general business activities. Equinor generally seeks to establish financing at the corporate (top company) level. Project financing will however be used where considered appealing. Equinor aims to have access to a variety of funding sources across different markets and instruments at all times, as well as to maintain relationships with a core group of international banks that provide a wide range of banking services.

92 Equinor, Annual Report on Form 20-F 2019

Moody's and Standard & Poor's (S&P) provide credit ratings on Equinor. Equinor’s current long-term ratings are AA- with a stable outlook and Aa2 with a stable outlook from S&P and Moody’s, respectively. The short-term ratings are P-1 from Moody's and A-1+ from S&P. In order to maintain financial flexibility going forward, Equinor intends to keep key financial ratios at levels consistent with the objective of maintaining a long-term credit rating at least within the single A category on a stand-alone basis (Current corporate rating includes one notch uplift from Standard & Poor’s and two notch uplift from Moody’s).

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. Equinor’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 the long-term debt portfolio. Equinor’s funding and liquidity activities are handled centrally.

Equinor 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 2019, approximately 24% of Equinor’s liquid assets were held in USD-denominated assets, 28% in NOK, 20% in EUR, 6% in GBP, 9% in DKK and 13% in SEK, before the effect of currency swaps and forward contracts. Approximately 42% of Equinor’s liquid assets were held in time deposits, 43% in treasury bills and commercial paper, 7 % in money market funds and 3% in bank deposits. As of 31 December 2019, approximately 3.9% of Equinor’s liquid assets were classified as restricted cash (including collateral deposits).

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

Long-term funding is raised when a need is identified for such financing based on Equinor’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 filed with the SEC in the US as well as through issues under a Euro Medium-Term Note (EMTN) Programme 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 Equinor’s borrowings is in USD.

On 13 November 2019, Equinor issued USD 1 billion in new bonds with 30 years maturity. On 5 September 2018 Equinor issued USD 1 billion in new bonds with 10 years maturity. All the bonds are unconditionally guaranteed by Equinor Energy AS. For more information, see note 18 Finance debt to the Consolidated financial statements.

Financial indicators |  |
| For the year ended 31 December
(in USD million) | 2019 | 2018
Gross interest-bearing debt 1) | 29,032 | 25,727
Net interest-bearing debt before adjustments | 16,429 | 11,130
Net debt to capital employed ratio 2) | 28.5% | 20.6%
Net debt to capital emplyed ratio adjusted, including lease liabilities 3) | 29.5% |
Net debt to capital employed ratio adjusted 3) | 23.8% | 22.2%
Cash and cash equivalents | 5,177 | 7,556
Current financial investments | 7,426 | 7,041
1) | Defined as non-current and current finance debt.
2) | As calculated based on IFRS balances. 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, Equinor makes adjustments to capital employed as it would be reported under IFRS. Restricted funds held as financial investments in Equinor Insurance AS and Collateral deposits are added to the net debt while the lease liabilities are taken out of the net debt. See section 5.2 Net debt to capital employed ratio for a reconciliation of capital employed and a discussion of why Equinor considers this measure to be useful.

Equinor, Annual Report on Form 20-F 2019 93

Gross interest-bearing debt

Gross interest-bearing debt was USD 29.0 billion and USD 25.7 billion at 31 December 2019 and 2018, respectively. The implementation of IFRS 16 has increased the gross interest-bearing debt by adding lease liabilities of USD 4.2 billion on
1 January 2019. The USD 3.3 billion net increase from 2018 to 2019 was due to an increase in current finance debt of USD 1.6 billion and in non-current finance debt of USD 1.7 billion. The weighted average annual interest rate was 3.53% and 3.67% at 31 December 2019 and 2018, respectively. Equinor’s weighted average maturity on finance debt was nine years at 31 December 2019 and nine years at 31 December 2018.

Net interest-bearing debt

Net interest-bearing debt before adjustments were USD 16.4 billion and USD 11.1 billion at 31 December 2019 and 2018, respectively. The increase of USD 5.3 billion from 2018 to 2019 was mainly related to an increase in gross interest-bearing debt of USD 3.3 billion, which includes IFRS 16 Lease implementation effects of USD 4.2 billion, a decrease in cash and cash equivalents of USD 2.4 billion offset by a USD 0.4 billion increase in current financial investments.

The net debt to capital employed ratio

The net debt to capital employed ratio before adjustments was 28.5% and 20.6% in 2019 and 2018, respectively.

The net debt to capital employed ratio adjusted (non-GAAP financial measure, see footnote three above) was 23.8% and 22.2% in 2019, and 2018, respectively.

The 7.9 percentage points increase in net debt to capital employed ratio before adjustments from 2018 to 2019 was related to the increase in net interest-bearing debt of USD 5.3 billion in combination with an increase in capital employed of USD 3.5 billion.

The 1.6 percentage points increase in net debt to capital employed ratio adjusted from 2018 to 2019 was related to the increase in net interest-bearing debt adjusted of USD 0.6 billion in combination with a decrease in capital employed adjusted of USD 1.2 billion.

Cash, cash equivalents and current financial investments

Cash and cash equivalents were USD 5.2 billion and USD 7.6 billion at 31 December 2019 and 2018, 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 Equinor’s liquidity management, amounted to USD 7.4 billion and USD 7.0 billion at 31 December 2019 and 2018, respectively.

## I nvestments

In 2019, capital expenditures, defined as Additions to PP&E, intangibles and equity accounted investments in note 3 Segments to the Consolidated financial statements, amounted to USD 14.8 billion of which USD 10.0 billion were organic capital expenditures[12] .

In 2018, capital expenditures were USD 15.2 billion, as per note 3 Segments to the Consolidated financial statements, of which organic capital expenditures amounted to USD 9.9 billion12.

In 2017, capital expenditures were USD 10.8 billion, as per note 3 Segments to the Consolidated financial statements, of which organic capital expenditures amounted to USD 9.4 billion12.

In Norway, a substantial proportion of 2020 capital expenditures will be spent on ongoing development projects such as Johan Castberg, Martin Linge and Johan Sverdrup phase 2, in addition to various extensions, modifications and improvements on currently producing fields.

Internationally, we currently estimate that a substantial proportion of 2020 capital expenditure will be spent on the following ongoing and planned development projects: Peregrino in Brazil, and onshore and offshore activity in the US.

Within renewable energy, capital expenditure in 2020 is expected to be spent mainly on offshore wind projects.

[12] See section 5.2 for non-GAAP measures.

94 Equinor, Annual Report on Form 20-F 2019

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

As illustrated in section Principal contractual obligations later in this report, Equinor has 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 joint venture partners agree to commit to. A large part of the capital expenditure for 2020 is committed.

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

##

Equinor, Annual Report on Form 20-F 2019 95

## P rincipal contractual obligations

The following table summarises principal contractual obligations, excluding derivatives and other hedging instruments, as well as, asset retirement obligations, which for the most part are expected to lead to cash disbursements more than five years in the future.

Non-current finance debt in the table represents principal payment obligations, including interest obligation. Obligations payable by Equinor to entities accounted for in the Equinor group using the equity method are included in the table below with Equinor’s full proportionate share. For assets that are included in the Equinor accounts through joint operations or similar arrangements the amounts in the table include the net commitment payable by Equinor (i.e. Equinor’s proportionate share of the commitment less Equinor's ownership share in the applicable entity).

Principal contractual obligations |  |  |  |  |
| As at 31 December 2019
| 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- principal and interest2) | 2,567 | 4,370 | 6,238 | 19,016 | 32,191
Undiscounted leases3) | 1,210 | 1,483 | 673 | 1,241 | 4,607
Nominal minimum other long-term commitments4) | 2,165 | 3,927 | 2,860 | 4,518 | 13,470
Total contractual obligations | 5,942 | 9,780 | 9,771 | 24,775 | 50,268
1) | ''Less than 1 year'' represents 2020; ''1-3 years'' represents 2021 and 2022, ''3-5 years'' represents 2023 and 2024, while ''More than 5 years'' includes amounts for later periods.
2) | See note 18 Finance debt to the Consolidated financial statements. The main differences between the table and the note relate to interest.
3) | See note 5 Financial risk management to the Consolidated financial statements.
4) | See note 24 Other commitments and contingencies to the Consolidated financial statements.

Equinor had contractual commitments of USD 5,205 million at
31 December 2019. The contractual commitments reflect Equinor's share and mainly comprise construction and acquisition of property, plant and equipment.

Equinor’s projected pension benefit obligation was USD 8,363 million, and the fair value of plan assets amounted to USD 5,589 million as of 31 December 2019. Company contributions are mainly related to employees in Norway. See note 19 Pensions to the Consolidated financial statements for more information.

## O ff balance sheet arrangements

Equinor is party to various agreements, such as transportation and processing capacity contracts, that are not recognised in the balance sheet. For more information, see Principal contractual obligations in section 2.10 Liquidity and capital resources. From January 1 2019 Equinor has implemented IFRS 16 Leases which requires that all leases shall be recognised in the balance sheet, as described in note 23 Implementation of IFRS 16 to the Consolidated financial statements. Equinor 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 24 Other commitments and contingencies to the Consolidated financial statements for more information.

96 Equinor, Annual Report on Form 20-F 2019

2.11 Risk review

## Risk factors

Equinor is exposed to risks that separately, or in combination, could affect its operational and financial performance. In this section, some of the key risks are addressed.

Risks related to our business, strategy and operations

This section describes the most significant potential risks relating to Equinor`s business, strategy and operations.

Oil and natural gas price. Fluctuating prices of oil and/or natural gas impact our financial performance. Generally, Equinor will not have control over the factors that affect the prices of oil and natural gas.

The prices of oil and natural gas have fluctuated significantly over the last few years. There are several reasons for these fluctuations, but fundamental market forces beyond the control of Equinor or other similar market participants have impacted and will continue to impact oil and natural gas prices in the future.

Factors that affect the prices of oil and natural gas include:

· economic and political developments in resource-producing regions

· global and regional supply and demand;

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

· adverse social and health situations in any country, including an epidemic or pandemic, measures taken by governments and non-governmental organisations in response to such situations, and the effects of such situations on demand;

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

· regulations and actions of governments and international organizations, 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;

· increased supply from new oil and gas sources; and

· weather conditions.

Recently, there has been significant price volatility, triggered, among other things by the changing dynamic among Opec+ members and the uncertainty regarding demand created by the Covid-19 pandemic. See also Covid-19 pandemic below.

Decreases in oil and/or natural gas prices could have an adverse effect on Equinor's business, the results of operations, financial condition and liquidity and Equinor's ability to finance planned capital expenditure, including possible reductions in capital expenditures which in turn could lead to reduced reserve replacement.

A significant or prolonged period of low oil and natural gas prices or other indicators could, if deemed to have longer term impact, lead to reviews for impairment of the group's oil and natural gas assets. Such reviews would reflect 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 Equinor'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. See also Note 2 Significant accounting policies to the Consolidated financial statements for a discussion of key sources of uncertainty with respect to management’s estimates and assumptions that affect Equinor’s reported amounts of assets, liabilities, income and expenses and Note 10 Property, plants and equipment to the Consolidated financial statements for a discussion of price assumptions and sensitivities affecting the impairment analysis.

Covid-19 pandemic. The Covid-19 pandemic could affect demand for, and supply of, oil and gas, commodity prices and Equinor’s ability to operate its facilities effectively.

Recently, the Covid-19 pandemic has been declared a global emergency by the World Health Organisation (WHO), and has made countries and organisations, including Equinor, take measures to mitigate risk for communities, employees and business operations. The pandemic continues to progress and evolve, and at this juncture it is challenging to predict the full extent and duration of resulting

Equinor, Annual Report on Form 20-F 2019 97

operational and economic impact for Equinor. A continued development of the pandemic and mitigating actions implemented by health authorities create uncertainty related to commodity prices and demand for and supply of oil and gas, as well as uncertainty related to the key assumptions applied in the valuation or our assets. Mitigating actions and the consequences of the spread of the virus might also affect Equinor’s ability to operate its facilities effectively and to maintain production at planned levels, in addition to creating a risk in respect of the execution of Equinor’s project portfolio.

Proved reserves and expected reserves estimates. Equinor’s crude oil and natural gas reserves are based on estimates and Equinor’s future production, revenues and expenditures with respect to its reserves may differ from these estimates.

98 Equinor, Annual Report on Form 20-F 2019

The reliability of the reserve estimates is dependent on:

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

· the production performance of Equinor’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 the estimates are made.

Many of the factors, assumptions and variables involved in estimating reserves are beyond Equinor’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 Equinor’s reserve data.

In addition, proved reserves are estimated based on the US Securities and Exchange Commission (SEC) requirements and may therefore differ substantially from Equinor’s view on expected reserves. 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 Equinor’s proved reserves. For fields governed by production sharing agreements (PSAs), a lower price may lead to higher entitlement to the production and increased reserves for those fields. Conversely, 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.

Global operations. Equinor is engaged in global activities that involve several technical, commercial and country-specific risks.

Technical risks of Equinor’s exploration activities relate to Equinor’s ability to conduct its seismic and drilling operations in a safe and efficient manner and to encounter commercially productive oil and gas reservoirs.

Technical risks of Equinor’s renewable energy activities relate to Equinor’s ability to design and perform renewable projects, including assembly and installation of wind turbines and solar panels for our wind and solar farms, respectively, as well as the operation and maintenance.

Commercial risks relate to Equinor’s ability to secure access to new business opportunities in an uncertain global, competitive environment and to recruit and maintain competent personnel.

Country-specific risks relate, among other things, to health, safety and security, the political environment, compliance with and understanding of local laws, regulatory requirements and/or license agreements, and impact on the environment and the communities in which Equinor operates.

These risks may adversely affect Equinor’s current operations and financial results, and, for its oil- and gas activities, its long-term replacement of reserves.

Decline of reserves. Failure to acquire, discover and develop additional reserves, will result in material decline of reserves and production from current levels.

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

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

In particular, 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 Equinor is unable to develop partnerships with national oil companies, its ability to find and acquire or develop additional reserves will be limited.

In addition, Equinor’s US onshore portfolio contains significant amounts of undeveloped resources that depend on Equinor’s ability to develop these successfully. Low oil and/or gas prices over a sustained period of time may result in Equinor deciding not to develop these resources or at least deferring development awaiting improved prices.

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

Equinor, Annual Report on Form 20-F 2019 99

Exploration, project development, operation and transportation related to oil and natural gas, as well as development and operation of renewable energy production, can be hazardous. In addition, Equinor’s activities and operations are affected by external factors like difficult geographies, climate zones and environmentally sensitive regions.

Risks that could affect health, safety and the environment include human error, operational failures, detrimental substances, subsurface behavior, technical integrity failures, vessel collisions, natural disasters, adverse weather conditions and other occurrences. These risks could, among other things, lead to blowouts, structural collapses, loss of containment of hydrocarbons or other hazardous materials, fires, explosions and water contamination that cause harm to people, loss of life or environmental damage.

In particular, 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 represent a significant risk to people and the environment.

As operations are subject to inherent uncertainty, it is not possible to guarantee that the management system or other policies and procedures will be able to identify all aspects of health, safety and environmental risks. It is also not possible to say with certainty that all activities will be carried out in accordance with these systems.

Climate change and transition to a lower carbon economy. A transition to a lower carbon economy will impact Equinor’s business and entails risks related to policy, legal, regulatory, market, technology and reputation.

Risks related to changes in policies, laws and regulations: Equinor expects and is preparing for regulatory changes and policy measures targeted at reducing greenhouse gas emissions. Stricter climate regulations and policies could impact Equinor's financial outlook, including the carrying value of its assets, whether directly through changes in taxation or other costs to operations and projects, or indirectly through changes in consumer behavior or technology developments. Equinor expects greenhouse gas emission costs to increase from current levels and to have a wider geographical range than today. We apply an internal carbon price of at least USD 55 per tonne of CO2 in investment analysis. In countries where the actual or predicted carbon price is higher than USD 55, we apply the actual or expected cost, such as in Norway where both a CO2 tax and the EU Emission Trading System (EU ETS) apply.

Other regulatory risks entail litigation risk and potential direct regulations in line with increasing carbon neutrality ambitions in various jurisdictions, such as the EU’s European Green Deal. Climate-related policy changes may also reduce access to prospective geographical areas for future exploration and production. Disruptive developments may not be ruled out, possibly triggered by severe weather events affecting public perception and policy making.

Market and technology risks: A transition to a low carbon economy contributes to uncertainty over future demand and prices for oil and gas as described in the section “Oil and natural gas price”. Such price sensitivities of the project portfolio are illustrated in the “portfolio sensitivity test” as described in section 2.12. Increased demand for and improved cost competitiveness of renewable energy, and innovation and technology changes supporting the further development and use of renewable energy and low-carbon technologies, represent both threats and opportunities for Equinor. The effectiveness of the choices Equinor makes regarding investing in and pursuing renewable business opportunities is subject to risk and uncertainty.

Reputational and financial impact: Increased concern over climate change could lead to increased expectations to fossil fuel producers, as well as a more negative perception of the oil and gas industry. This could lead to litigation and divestment risk and could also have an impact on talent attraction and retention and on our licenses to operate in certain jurisdictions.

All of these risks could lead to an increased cost of capital. For example, certain lenders have recently indicated that they will direct or restrict their lending activities based on environmental parameters.

Equinor’s climate roadmap, including climate ambitions, has been established to manage risks related to climate change. There is no assurance that Equinor’s climate ambitions will be achieved. The achievement of Equinor’s Net Carbon Intensity ambition depends, in part, on broader societal shifts in consumer demands and technological advancements, each of which are beyond Equinor’s control. Should society’s demands and technological innovation not shift in parallel with Equinor’s pursuit of significant greenhouse gas emission reductions, Equinor’s ability to meet its climate ambitions will be impaired.

Physical effects of climate change. Changes in physical climate parameters could impact Equinor’s operations.

Examples of parameters that could impact Equinor’s operations include increasing frequency and severity of extreme weather events, rising sea level, changes in sea currents and restrained water availability. There is also uncertainty regarding the magnitude and time horizon for the occurrence of physical impacts of climate change, which increases uncertainty regarding their potential impact on Equinor.

Hydraulic fracturing. Equinor is exposed to risks as a result of its use of hydraulic fracturing.

Equinor'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, Regulatory and Compliance Risks”. A case of subsurface migration of hydraulic fracturing fluids

100 Equinor, Annual Report on Form 20-F 2019

or a case of spillage or mishandling of hydraulic fracturing fluids during these activities could subject Equinor to civil and/or criminal liability and the possibility of incurring substantial costs, including for environmental remediation. 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. Changes to the applicable regulatory regimes 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 Equinor's US onshore business and the demand for its fracturing services.

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

Security threats such as acts of terrorism, cyber-attacks and insider threats against Equinor's production and exploration facilities, offices, pipelines, means of transportation, digital infrastructure or computer or information systems, or breaches of Equinor's security system, could result in losses. In particular, the scale, sophistication and severity of cyber-attacks continue to evolve. Increasing digitization and reliance on information technology systems make managing cyber-risk a priority for many industries, including the energy industry. Failure to manage these 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. Equinor 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. See also “Supervision, regulatory reviews and financial reporting—Remediation [process] of material weakness in internal control over financial reporting”.

In particular, failure to maintain and develop IT security barriers, which are intended to protect Equinor’s information systems and digital infrastructure from being compromised by unauthorized parties, may affect the confidentiality, integrity and availability of Equinor’s information systems and digital infrastructure, including those critical to its operations. Attacks on Equinor’s information systems could result in significant financial damage to Equinor, including as a result of material losses or loss of life due to such attacks.

In addition, failure to remediate the material weakness in our internal control over financial reporting due to control deficiencies in the operation of controls related to our management of information technology (IT) access controls could increase our exposure to a cyber-attack on our information systems.

Crisis management systems. Equinor's crisis management systems may prove inadequate.

If Equinor 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 effectuated, or not effectuated quickly enough, its business, operations and reputation could be severely affected. Inability to restore or replace critical capacity could prolong the impact of any disruption and could severely affect Equinor's business and operations. A crisis or disruption might occur as a result of a security or cybersecurity incident or if a risk described under “Health, safety and environmental” materializes.

Competition; innovation. Equinor encounters competition from other companies in all areas of its operations. Equinor could be adversely affected if competitors move faster than it in the development and deployment of new technologies and products.

Equinor may experience increased competition from larger players with stronger financial resources, from smaller ones with increased agility and flexibility and from an increasing number of companies applying new business models. 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 and innovation are key competitive advantages in Equinor’s industry. The ability to maintain efficient operations, develop and adapt to innovative technologies and digital solutions and seek profitable low-carbon energy solutions are key success factors for future business and resulting performance. Competitors may be able to invest more than Equinor in developing or acquiring intellectual property rights to technology. Equinor could be adversely affected if it lags behind competitors and the industry in general in the development or adoption of innovative technologies, including digitalisation and low-carbon energy solutions.

Project development and production operations. Equinor’s development projects and production operations involve uncertainties and operating risks which could prevent Equinor from realising profits and cause substantial losses.

Oil and gas projects and renewable 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, challenging soil conditions, accidents, mechanical and technical difficulties, challenges due to new technology or inadequate investment decision basis. This is particularly relevant for Equinor’s activities in deep waters or other harsh environments. In US onshore, low regional prices may render certain areas unprofitable, and Equinor may curtail production until prices recover. Prolonged low oil, gas and power prices, combined with high levels of tax and government take in several jurisdictions, could erode the profitability of some of Equinor’s activities.

Equinor, Annual Report on Form 20-F 2019 101

Strategic objectives. Equinor may not achieve its strategic objective of successfully exploiting profitable opportunities.

Equinor intends to continue to nurture attractive commercial opportunities to create value. This may involve acquisition of new businesses, properties or moving into new markets. Failure by Equinor to successfully pursue and exploit new business opportunities, including in new energy solutions, could result in financial losses and inhibit value creation.

Equinor’s ability to achieve this strategic objective depends on several factors, including the ability to:

· maintain Equinor’s zero-harm safety culture;

· identify suitable opportunities;

· build a significant and profitable renewables portfolio on the expected timeline;

· achieve its ambitions to reduce net carbon intensity and reach carbon neutral global operations on the expected timeline;

· negotiate favorable terms;

· compete efficiently in the rising global competition for access to new opportunities;

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

· effectively integrate acquired properties or businesses into Equinor's operations;

· arrange financing, if necessary; and

· comply with legal regulations.

Equinor anticipates significant investments and costs as it cultivates business opportunities in new and existing markets. New projects and acquisitions may have different embedded risks than Equinor’s existing portfolio. As a result, new projects and acquisitions could result in unanticipated liabilities, losses or costs, as well as Equinor 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 Equinor’s day-to-day operations to the integration of acquired operations or properties. Equinor 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 Equinor, if at all, and it may, in the case of equity, be dilutive to Equinor’s earnings per share.

Transportation infrastructure. The profitability of Equinor’s oil, gas and power production in remote areas may be affected by infrastructure constraints.

Equinor’s ability to commercially exploit discovered petroleum resources depends, among other factors, on infrastructure to transport oil and gas to potential buyers at a commercial price. Oil is transported by vessels, rail or pipelines to refineries, and natural gas is transported to processing plants and end users by pipeline or vessels (for liquefied natural gas). Equinor’s ability to commercially exploit renewable opportunities depends on available infrastructure to transmit electric power to potential buyers at a commercial price. Electricity is transmitted through power transmission and distribution lines. Equinor must secure access to a power system with sufficient capacity to transmit the electric power to the customers. Equinor may be unsuccessful in its efforts to secure transportation, transmission and markets for all its potential production.

International political, social and economic factors. Equinor has interests in regions where political, social and economic instability could adversely affect Equinor’s business.

Equinor has assets and operations in several regions around the globe where negative political, social and economic developments could occur. These developments and related security threats require continuous monitoring. Political instability, civil strife, strikes, insurrections, acts of terrorism and acts of war, adverse and hostile actions against Equinor’s staff, its facilities, its transportation systems and its digital infrastructure (cyberattacks) may cause harm to people and disrupt or curtail Equinor’s operations and business opportunities, lead to a decline in production and otherwise adversely affect Equinor’s business, operations, results and financial condition.

Recently, the UK’s exit from the EU (Brexit) has created uncertainty with respect to the UK’s future relationship with the EU. In particular, this uncertainty affects Equinor as it relates to future energy and trade policies and the movement of people.

Equinor also has investments in Argentina where newly adopted foreign exchange and price regulations could adversely affect Equinor's business.

Workforce. Equinor may not be able to secure the right level of workforce competence and capacity.

As the energy industry is a long-term business, it needs to take a long-term perspective on workforce capacity and competence. The uncertainty of the future of the oil industry, in light of potential reduced oil and natural gas prices, climate policy changes, as well as the climate debate affecting the perception of the industry, pose a risk to securing the right level of workforce competence and capacity through industry cycles.

Insurance coverage. Equinor’s insurance coverage may not provide adequate protection from losses.

102 Equinor, Annual Report on Form 20-F 2019

Equinor maintains insurance coverage that includes coverage for physical damage to its properties, third-party liability, workers’ compensation and employers’ liability, general liability, sudden pollution and other coverage. Equinor’s insurance coverage includes deductibles that must be met prior to recovery and is subject to caps, exclusions and limitations. There is no assurance that such coverage will adequately protect Equinor against liability from all potential consequences and damages. Uninsured losses could have a material adverse effect on Equinor’s financial position.

Legal, regulatory and compliance risks

International governmental and regulatory framework. Equinor’s operations are subject to dynamic political and legal factors in the countries in which it operates.

Equinor has assets in several 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. Equinor's oil and gas 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 companies in some regions have begun to exercise greater authority and to impose more stringent conditions on energy companies. 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;

• nationalization or expropriation of Equinor’s assets;

• unilateral cancellation or modification of Equinor's license 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 Equinor vary greatly from country to country and are hard to predict. If such risks materialize, they could cause Equinor to incur material costs, cause decrease in production, and potentially have a materially adverse effect on Equinor’s operations or financial condition.

Policies and actions of the Norwegian State could affect Equinor’s business.

The Norwegian State governs the management of NCS hydrocarbon resources through legislation, such as the Norwegian Petroleum Act, tax law and safety and environmental laws and regulations. The Norwegian State awards licenses for exploration, development projects, production, transportation and applications for production rates for individual fields. The Petroleum Act provides that if important public interests are at stake, the Norwegian State may instruct operators on the NCS to reduce petroleum production.

The Norwegian State has a direct participation in petroleum activities through the State's direct financial interest (SDFI). In the production licenses in which the SDFI holds an interest, the Norwegian State has the power to direct petroleum licenses’ actions in certain circumstances. See also section 2.7.

If the Norwegian State were to change laws, regulations, policies or practices relating to energy or to the oil and gas industry (including in response to environmental, social or governance concerns), or take additional action under its activities on the NCS, Equinor’s international and/or NCS exploration, development and production activities and the results of its operations could be affected.

Health, safety and environmental laws and regulations. Compliance with health, safety and environmental laws and regulations that apply to Equinor’s activities and operations could materially increase Equinor’s costs. The enactment of, or changes to, such laws and regulations could increase such costs or create compliance challenges.

Equinor 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, as well as in response to concerns relating to climate change, including:

• higher prices on greenhouse gas emissions;

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

• remediation of environmental contamination and adverse impacts caused by Equinor’s activities;

• decommissioning obligations and related costs; and

• compensation of costs related to persons and/or entities claiming damages as a result of Equinor’s activities.

In particular, Equinor’s activities are 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.

Equinor, Annual Report on Form 20-F 2019 103

Equinor’s investments in US onshore producing assets are subject to evolving regulations that could affect these operations and their profitability. In the United States, Federal agencies have taken steps to rescind, delay, or revise regulations seen as overly burdensome to the upstream oil and gas sector, including methane emission controls. Equinor supports Federal regulation of methane emissions and aims to operate in compliance with all current requirements. Equinor has also joined voluntary emission reduction programmes (One Future and API’s Environmental Partnership) and implemented a climate roadmap to reduce CO2 and methane emissions. To the extent new or revised regulations impose additional compliance or data gathering requirements, Equinor could incur higher operating costs.

Compliance with laws, regulations and obligations relating to climate change and other health, safety and environmental laws and 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. However, more stringent climate change regulations could also represent business opportunities for Equinor. For more information about climate change related to legal and regulatory risks, see the risks described under the heading “Transition to a lower carbon economy” in “Risks related to our business, strategy and operations” in this section.

Supervision, regulatory reviews and financial reporting. Equinor conducts business in many countries and its products are marketed and traded worldwide. Equinor is exposed to risk of supervision, review and sanctions for violations of laws and regulations at the supranational, national and local level. These include, among others, laws and regulations relating to financial reporting, taxation, bribery and corruption, securities and commodities trading, fraud, competition and antitrust, safety and the environment, and labor and employment practices.

Violations of applicable laws and regulations may lead to legal liability, substantial fines and other sanctions for noncompliance.

Equinor is subject to supervision by the Norwegian Petroleum Supervisor (PSA), which supervises all aspects of Equinor’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. As its business grows internationally, Equinor may become subject to supervision or be required to report to other regulators, and such supervision could result in audit reports, orders and investigations.

Equinor is listed on both the Oslo Børs and New York Stock Exchange (NYSE) and is a reporting company under the rules and regulations of the US Securities and Exchange Commission (the SEC). Equinor is required to comply with the continuing obligations of these regulatory authorities, and violation of these obligations may result in legal liability, the imposition of fines and other sanctions.

Equinor is also subject to financial review from financial supervisory authorities such as the Norwegian Financial Supervisory Authority (FSA) and the SEC. Reviews performed by these authorities could result in changes to previously published financial statements and future accounting practices. In addition, failure of external reporting to report data accurately and in compliance with applicable standards could result in regulatory action, legal liability and damage to Equinor’s reputation.

Material weakness in internal control over financial reporting. Failure to remediate the material weakness could cause internal control over financial reporting to continue to be ineffective and potentially affect our share price.

Our management and external auditors have concluded that our internal control over financial reporting as of December 31, 2019 was not effective due to the existence of control deficiencies in the operation of controls related to our management of information technology (IT) user access controls as described under 3.10 Risk Management and internal controls that in aggregate represent a material weakness in our internal control over financial reporting. Our management is actively taking remediation efforts to address this material weakness. However, there is no assurance as to when such remediation will be completed or that additional material weaknesses will not occur in the future. These deficiencies did not result in a material misstatement to the Consolidated financial statements. However, until remediated, these deficiencies could result in a material misstatement to the Consolidated financial statements in the future that would not be prevented or detected on a timely basis. Failure to remediate the material weakness could cause internal control over financial reporting to continue to be ineffective and could also cause investors to lose confidence in reported financial information and potentially impact the share price. See 3.10 Risk management and internal controls.

Anti-corruption, anti-bribery laws, human rights policy and Equinor Code of Conduct. Non-compliance with anti-bribery, anti-corruption and other applicable laws, including failure to meet Equinor’s ethical requirements, including our Human Rights policy, exposes Equinor to legal liability and damage to its reputation, business and shareholder value.

Equinor has activities in countries which present corruption risks and which may have weak protection of human rights, weak legal institutions and lack centralised control and transparency. In addition, governments play a significant role in the energy sector, through ownership of resources, participation, licensing and local content which leads to a high level of interaction with public officials. Equinor is 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 or bribery laws could expose Equinor to investigations from multiple authorities and 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 Equinor Code of Conduct could be damaging to Equinor’s

104 Equinor, Annual Report on Form 20-F 2019

reputation, competitive position and shareholder value. Similarly, failure to uphold our Human Rights policy may damage our reputation and social licence to operate.

International sanctions and trade restrictions. Equinor’s activities may be affected by international sanctions and trade restrictions.

In 2019 there were several changes to sanctions and international trade restrictions. Equinor seeks to comply with these where they are applicable. Given that Equinor has a diverse portfolio of projects worldwide, this could expose its business and financial affairs to political and economic risks, including operations in markets or sectors targeted by sanctions and international trade restrictions.

Sanctions and trade restrictions are complex, are becoming less predictable and are often implemented on short notice. For example, in 2019 new trade restrictions were introduced in relation to Turkey, where Equinor has activities. Equinor’s business portfolio is evolving and will constantly be subject to review. Given the current trend in relation to the use of trade restrictions, it is possible that Equinor will decide to take part in new business activity in markets or sectors where sanctions and trade restrictions are particularly relevant.

While Equinor remains committed to do business in compliance with sanctions and trade restrictions and takes steps to ensure, to the extent possible, compliance therewith, there can be no assurance that no Equinor entity, officer, director, employee or agent is not in violation of such sanctions and trade restrictions. Any such violation, even if minor in monetary terms, could result in substantial civil and/or criminal penalties and could materially adversely affect Equinor’s business and results of operations or financial condition.

The following discusses Equinor’s interests in certain jurisdictions:

Equinor continues to take part in business activities in Russia, where it holds an interest in several on- and offshore oil and gas projects. Some of these projects result from a strategic cooperation with Rosneft Oil Company (Rosneft) initiated in 2012. In each of these projects, Rosneft holds the majority interest. A minority of the projects are in Arctic offshore and/or deep-water areas. Norwegian, EU and US trade restrictions and sanctions target several sectors in Russia, including the financial and energy sector, and Rosneft itself is targeted. Accordingly, the manner in which Equinor conducts its business in Russia is affected. Moreover, Equinor’s ability to continue to progress its projects in Russia relies in part on government authorisations as well as the future of sanctions and trade controls. While Equinor continues to pursue and expand its business in Russia within existing sanctions and trade controls, it is possible that future political developments could impact Equinor’s ability to continue and conclude its projects as envisaged.

In Venezuela, Equinor is a 9.67% shareholder in the mixed company Petrocedeno, which is majority owned by Venezuelan national oil company, Petróleos de Venezuela, SA (PDVSA). In addition, Equinor holds a 51% interest in a gas license offshore Venezuela. Since 2017, various international sanctions and trade controls have targeted certain Venezuelan individuals as well as the Government of Venezuela and PDVSA. In January 2019, PDVSA, and consequently its subsidiary Petrocedeno, were designated as blocked parties (SDN) by the US Office of Foreign Asset Control. The international sanctions and trade controls in place restrict to a large extent the way Equinor can conduct its business in Venezuela, and could, alone or in combination with other factors, further negatively impact Equinor’s position and ability to continue its business projects in Venezuela.

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

Equinor is providing the following disclosure pursuant to Section 13(r) of the Exchange Act. Equinor 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. Equinor’s operational obligations under these agreements have terminated and the licences have been abandoned. The cost recovery programme for these contracts was completed in 2012, except for the recovery of tax and obligations to the Social Security Organization (SSO).

From 2013 to November 2018, after closing Equinor’s office in Iran, Equinor’s activity was focused on a final settlement with the Iranian tax and SSO authorities relating to the above-mentioned agreements.

In a letter from the US State Department of 1 November 2010, Equinor was informed that [it] was not considered to be a company of concern based on its previous Iran-related activities.

Equinor has an intention to settle historic obligations in Iran while remaining compliant with applicable sanctions and trade restrictions against Iran. Since November 2018 Equinor has not conducted any activity in Iran, nor has it been able to resolve tax claims from the Iranian authorities. No payments were made to Iranian authorities during 2019.

Joint arrangements and contractors. Many of Equinor’s activities are conducted through joint arrangements and with contractors and sub-contractors which may limit Equinor’s influence and control over the performance of such operations. This exposes Equinor to financial, operational, safety and compliance risks if the operators, partners or contractors fail to fulfill their responsibilities.

Equinor, Annual Report on Form 20-F 2019 105

Operators, partners and contractors may be unable or unwilling to compensate Equinor against costs incurred on their behalf or on behalf of the arrangement. Equinor is also exposed to enforcement actions by regulators or claimants in the event of an incident in an operation where it does not exercise operational control.

International tax law. Equinor is exposed to potentially adverse changes in the tax regimes of each jurisdiction in which Equinor operates.

Changes in the tax laws of the countries in which Equinor operates could have a material adverse effect on its liquidity and results of operations.

Market, financial and liquidity risks

Foreign exchange. Equinor’s business is exposed to foreign exchange rate fluctuations that could adversely affect the results of Equinor’s operations.

A large percentage of Equinor’s revenues and cash receipts are denominated in USD, and sales of gas and refined products are mainly denominated in EUR and GBP. Further, Equinor pays a large portion of its income taxes, operating expenses, capital expenditures and dividends in NOK. The majority of Equinor’s long-term debt has USD exposure. Accordingly, changes in exchange rates between USD, EUR, GBP and NOK may significantly influence Equinor’s financial results. See also “Financial risk”.

Liquidity and interest rate. Equinor is exposed to liquidity and interest rate risks.

Equinor is exposed to liquidity risk, which is the risk that Equinor will not be able to meet obligations of financial liabilities when they become due. Equinor’s main cash outflows include the quarterly dividend payments and Norwegian petroleum tax payments which are paid six times per year. Liquidity risk sources include but are not limited to business interruptions and commodity and financial markets price movements.

Equinor is exposed to interest rate risk, which is the possibility that changes in interest rates will affect future cash flows or the fair values of its financial instruments, principally long-term debt and associated derivatives. Equinor’s bonds are normally issued at fixed rates in a variety of local currencies (USD, EUR and GBP among others). Bonds are normally converted to floating USD bonds by using interest rate and currency swaps.

It is expected that the London Inter-bank Offered Rate (LIBOR) will be discontinued and replaced with alternative reference rates by the end of 2021. Equinor is exposed to LIBOR on interest rate derivatives contracts, floating rate bonds, loan agreements and facilities, among others, the majority of which, Equinor believes, provide for alternative reference rates or calculation methods upon LIBOR discontinuation. Equinor is following this transition closely.

Trading and supply activities. Equinor is exposed to risks relating to trading and supply activities.

Equinor is engaged in trading and commercial activities in the physical markets. Equinor 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 to manage price differences and volatility. Equinor also uses financial instruments to manage foreign exchange and interest rate risk. Trading activities involve elements of forecasting, and Equinor bears the risk of market movements, the risk of losses if prices develop contrary to expectations, and the risk of default by counterparties and transport of liquids.

Financial risk. Equinor is exposed to financial risk.

The main factors influencing Equinor’s operational and financial results include oil/condensate and natural gas prices and trends in the exchange rates between mainly the USD, EUR, GBP and NOK; Equinor’s oil and natural gas entitlement production volumes (which in turn depend on entitlement volumes under PSAs where applicable) and available petroleum reserves, and Equinor’s own, as well as its partners’, expertise and cooperation in recovering oil and natural gas from those reserves; and changes in Equinor’s portfolio of assets due to acquisitions and disposals.

Equinor’s operational and financial results also are affected by trends in the international oil industry, including possible actions by governments and other regulatory authorities in the jurisdictions in which Equinor operates, 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 2019 and 2018.

106 Equinor, Annual Report on Form 20-F 2019

Yearly averages | 2019 | 2018
Average Brent oil price (USD/bbl) | 64.3 | 71.1
Average invoiced gas prices - Europe (USD/mmBtu) | 5.8 | 7.0
Refining reference margin (USD/bbl) | 4.1 | 5.3
USD/NOK average daily exchange rate | 8.8 | 8.1

The illustration shows the indicative full-year effect on the financial result for 2020 given certain changes in the oil/condensate price, natural gas contract prices and the USD/NOK exchange rate. The estimated price sensitivity of Equinor’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 Equinor’s commodity price assumptions could result in impairments on certain producing and development assets in the portfolio. See note 10 Property, plant and equipment to the Consolidated financial statements for sensitivity analysis related to impairments.

Fluctuating foreign exchange rates can also have a significant impact on the operating results. Equinor’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. In general, an increase in the value of USD in relation to NOK can be expected to increase Equinor’s reported net operating income.

Historically, Equinor’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 section 2.7 Corporate Taxation noof Equinor. Equinor’s earnings volatility is moderated as a result of the significant proportion of its Norwegian offshore income that is subject to this 78% tax rate in profitable periods and the significant tax assets generated by its Norwegian offshore operations in any loss-making periods.

Equinor, Annual Report on Form 20-F 2019 107

Currently, the majority of dividends received by Equinor ASA are from Norwegian companies. 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. For other dividends, 3% of the dividends received are subject to the standard income tax rate of 22%, giving an effective tax rate of 0.66%. Dividends from companies resident in low-tax jurisdictions in the EEA that are not able to demonstrate that they are genuinely established and carry on genuine economic business activity within the EEA and dividends from companies in low-tax jurisdictions and portfolio investments below 10% outside the EEA will be subject to the standard income tax rate of 22% based on the full amounts received.

See also note 5 Financial risk management to the Consolidated financial statements.

Disclosures about market risk

Equinor 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.

Risks related to state ownership

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

Control by the Norwegian State. The interests of Equinor’s majority shareholder, the Norwegian State, may not always be aligned with the interests of Equinor’s other shareholders, and this may affect Equinor’s activities, including its decisions relating to the NCS.

The Norwegian State has resolved that its shares in Equinor 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 Equinor to market the Norwegian State’s oil and gas together with Equinor’s own oil and gas as a single economic unit. Pursuant to this coordinated ownership strategy, the Norwegian State requires Equinor, in its activities on the NCS, to take account of the Norwegian State’s interests in all decisions that may affect the marketing of Equinor’s own and the Norwegian State’s oil and gas.

The Norwegian State directly held 67% of Equinor's ordinary shares as of 31 December 2019 and has effectively the power to influence the outcome of any vote of shareholders, including amending its articles of association and electing all non-employee members of the corporate assembly. The interests of the Norwegian State in deciding these and other matters and the factors it considers when casting its votes, especially the coordinated ownership strategy for the SDFI and Equinor’s shares held by the Norwegian State, could be different from the interests of Equinor’s other shareholders.

If the Norwegian State’s coordinated ownership strategy is not implemented and pursued in the future, then Equinor’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 Equinor’s position in the markets in which it operates.

## R isk management

As discussed above, Equinor activities carry risk, and risk management is therefore an integrated part of Equinor’s business operations. Equinor’s risk management includes identifying, analysing, evaluating and managing risk in all its activities in order to create value and avoid incidents, always with Equinor’s best interest in mind.

To achieve optimal solutions, Equinor bases its risk management on an enterprise risk management (ERM) approach where:

• focus is on the value impact for Equinor, including upside and downside risk; and

• risk is managed in compliance with Equinor’s requirements with a strong focus on avoiding HSE and business integrity incidents (such as accidents, fraud and corruption).

Managing risk is an integral part of any manager’s responsibility. In general, risk is managed in the business line, but some risks are managed at the corporate level to provide optimal solutions. Risks managed at the corporate level include oil and natural gas price risks, interest and currency risks, risk dimension in the strategy work, prioritisation processes and capital structure discussions.

ERM involves using a holistic approach where correlations between risks and the natural hedges inherent in Equinor’s portfolio are considered. This approach allows Equinor to reduce the number of risk management transactions and avoid sub-optimisation. Some risks related to operations are partly insurable and insured via Equinor’s captive insurance company operating in the Norwegian and international insurance markets. Equinor also assesses oil and gas price hedging opportunities on a regular basis as a tool to increase financial robustness and strengthen flexibility.

108 Equinor, Annual Report on Form 20-F 2019

Risk is integrated into the company’s Management Information System (IT tool) where Equinor’s purpose, vision and strategy are translated into strategic objectives, risks, actions and KPIs. This allows for aligning risk with strategic objectives and performance and makes risk an embedded part of a holistic decision basis. Equinor’s risk management process is aligned with ISO31000 Risk management – principles and guidelines. A standardised process across Equinor allows for comparing risk on a like-for-like basis and supports efficiency in decisions. The process seeks to ensure that risks are identified, analysed, evaluated and managed. In general, risk adjusting actions are subject to a cost-benefit evaluation (except certain safety related risks which could be subject to specific regulations).

Equinor’s corporate risk committee, headed by the chief financial officer, is responsible for defining, developing and reviewing Equinor's risk policies and methodology. The committee is also responsible for overseeing and developing Equinor's Enterprise Risk Management and proposing appropriate measures to adjust risk.

Equinor, Annual Report on Form 20-F 2019 109

2.12 Safety, security and sustainability

Safety and security

Our safety and security work are guided by our commitment to prevent harm to people's health, safety and security and the environment. Equinor’s strategy defines ‘’Always safe’’ as one of three pillars and our ambition is to be an industry leader in safety and security. The management approach comprises safeguarding people and the environment through design, ongoing reviews of technical and non-technical barriers, proactive maintenance work, periodic risk assessments and emergency preparedness training, as well as through collaboration with our partners and contractors. To improve our results, we regularly evaluate monitoring indicators, review and learn from incidents, conduct verification activities, and implement improvement measures as needed.

In 2019, safety initiatives were implemented through the company-wide improvement project: “Safety beyond 2020”. The goal has been to further strengthen the safety culture and performance through risk awareness and proactive behaviour at all organisational levels. The project builds on the existing “I am Safety” governance, which highlights that individuals are personally accountable for safety. Four main areas for improvement have been identified: safety visibility, leadership and behaviour, safety indicators and learning and follow-up.

In 2019, we experienced no major accidents or incidents with fatalities[13].The total serious incident frequency including incidents with potential consequence, ended up at 0.6 incidents per million work hours in 2019, up from 0.5 in 2018.

We continued to see a reduction in the number of serious oil and gas leakages (with a leakage rate ≥ 0.1 kg per second) for the fourth consecutive year and our target of a maximum of ten leakages was reached. The number of oil spills per year decreased compared to last year. Close to 90% of the total number were spills with volumes less than one barrel, but a large onshore oil spill of 8744 m³ occurred at our South Riding Point terminal caused by the hurricane Dorian which hit Grand Bahama island in September 2019.

Equinor faces a high threat of targeted terrorist attacks in some locations, furthermore, criminal violence is a concern for staff at some of the assets and offices. Worldwide there is a high threat of cyber-attacks, and this is expected to continue to grow. We continue to address these threats through a strengthened security culture and organisation which seeks to manage all security risks to our people, assets and information.

Personnel health and safety

Health and working environment are integral parts of our efforts to safeguard people by focusing on risk management of factors such as chemicals, noise, ergonomic workplace and psychosocial aspects. To reduce downsides and realize sustainable and lasting upsides, we monitor and manage psychosocial aspects on an ongoing basis. For 2019, the total recordable injury frequency per million hours worked (TRIF) ended at 2.5, which is an improvement from 2018. The last three years we have had a steady and significant improvement in the

[13] The incident caused by the Hurricane Dorian that hit Grand Bahama Island and our South Riding Point terminal is being investigated and the final classification is not concluded.

110 Equinor, Annual Report on Form 20-F 2019

number of work-related illness cases (WRI). Despite of seeing an increase in WRI from 2018 to 2019, the number of WRIs’ is still low for 2019. Psychosocial aspects are one of the key contributors to this development, along with noise and ergonomic conditions.

Climate change

Climate change is one of the main challenges of our time and a clear call for action. Equinor acknowledges the findings of the Intergovernmental Panel on Climate Change that human activities contribute to global warming with detrimental effects on nature, people and society at large.

Equinor recognises that the world's energy systems must be transformed in a profound way to drive decarbonisation, while at the same time ensuring universal access to affordable and clean energy and realising the United Nations Sustainable Development Goals.

Equinor has “low carbon” as one of the main strategic pillars on which the governance of the company is based, and we embed climate considerations into decision making, portfolio sensitivity tests, incentives and reporting. In 2019, Equinor reviewed its climate ambitions and launched a new Climate Roadmap at the Capital Markets Update on 6 February 2020. To ensure a competitive and resilient business model in the energy transition, and to contribute to the dual societal challenge of providing energy with less emissions, Equinor aims to:

· reduce the net carbon intensity, from initial production to final consumption, of energy produced by at least 50% by 2050,

· grow renewable energy capacity tenfold by 2026, developing as a global offshore wind major, and

· strengthen its industry leading position on carbon efficient production, aiming to reach carbon neutral global operations by 2030.

Equinor’s Climate Roadmap sets out new short-, mid- and long-term ambitions to reduce our own greenhouse gas emissions and to shape our portfolio. To achieve these ambitions, we need to strengthen our collaboration with governments, customers, and industry sectors to speed up the pace of the transition and deliver solutions at scale.

Industry leading carbon efficiency – carbon neutral operations

Equinor aims to reduce the CO2 intensity of its globally operated oil and gas production to below 8kg CO2 per barrel of oil equivalent (boe) by 2025, five years earlier than the previous ambition. We also aim for carbon neutral global operations, for our operated scope 1[14] and 2[15] emissions, by 2030. The main priority will be to reduce GHG emission from our own operations. Subject to positive investment decisions in the licenses, these investments will have neutral to positive net present value, in addition to strengthening future competitiveness. Remaining emissions will be compensated through quota trading systems, such as the EU ETS, or high-quality offset mechanisms such as natural sinks. By setting this ambition, Equinor demonstrates its long-standing support to carbon pricing and the establishment of global carbon market mechanisms as outlined in the Paris Agreement.

For our operated offshore fields and onshore plants in Norway our new climate ambitions includes reducing the absolute greenhouse gas emissions by 40% by 2030, 70% by 2040 and to near zero by 2050. By 2030 this implies annual cuts of more than 5 million tonnes, corresponding to around 10% of Norway’s total CO2 emissions. A 40% reduction by 2030 will be achieved through large industrial measures, including energy efficiency, digitalization and launch of several electrification projects. The 2030 ambition is expected to require investments of around USD 5.7 billion for Equinor and its partners.

Equinor’s operated upstream CO2 intensity for 2019 was 9.5kg CO2/boe, which is considerably lower than the industry average of 18kg CO2/boe. Scope 1 greenhouse gas emissions (GHG) were 14.7 million tonnes of CO2 equivalents in 2019. This is down 2% from 2018 and was mainly due to turnaround activities in the midstream segment.

[14] Direct GHG emissions from operations that are owned and/or controlled by the organisation.

[15] Indirect GHG emissions from energy imported from third parties, heating, cooling, and steam consumed within the organisation.

Equinor, Annual Report on Form 20-F 2019 111

We delivered 303,000tonnes of CO2 emission reductions in 2019, mainly due to many smaller energy efficiency projects. So far, we have achieved around 0.9 million of the previous 2030 target[16] of 3 million tonnes of CO2 emission reductions per year.

We are exploring opportunities for further electrification of offshore fields. In 2019, the Johan Sverdrup field came on stream powered by electricity from land, making it one of the most carbon-efficient fields worldwide. In the second phase of the field development, a power hub will be installed, allowing for the Gina Krog, Ivar Aasen and Edvard Grieg fields, as well as Johan Sverdrup second phase, to be powered from the onshore grid. The area’s license partners have also agreed to work towards partial electrification of the Sleipner field, together with the Gudrun platform and other tie-ins.

The Hywind Tampen project was sanctioned in 2019. Floating wind turbines will be installed, capable of generating renewable electricity to cover around 35% of the power demand of the Snorre and Gullfaks fields in the Tampen area offshore Norway. CO2 emissions reductions are estimated to more than 200,000 tonnes per year.

Our flaring intensity in 2019 was 0.25% of hydrocarbons produced (operated control), which is slightly above our ambition of 0.2% in 2020 mainly due to increased flaring at Bakken and Mariner. This is significantly lower than the industry average of 1.1%[17]. Equinor will continue focusing on reducing flaring to achieve the ambition of zero routine flaring by 2030.

Methane is the second most important greenhouse gas contributing to climate change. We have estimated the methane intensity[18] for our operated upstream and midstream activities to be as low as approximately 0.03%. Equinor aims to continue to pursue a methane intensity ambition of “near zero”.

Natural climate solutions, particularly protection of tropical rainforests and other land-based solutions, can contribute up to one-third of the climate efforts the world needs over the next decades. We plan to invest in the protection of tropical forests as an effective measure to combat climate change. In 2019 we collaborated with Emergent and Architecture for REDD+ Transactions (ART) on establishing high-integrity nature-based climate solutions for the private market.

Global offshore wind major

The past few years have been transformational for Equinor’s offshore wind portfolio. With the recent additions of Dogger Bank (UK) and Empire Wind (US), we are on the path to becoming a global offshore wind major. Dogger Bank will be the world’s largest offshore wind farm development and Empire Wind will provide renewable electricity to the equivalent of one million homes in New York City.

As part of our Climate Roadmap, we expect a production capacity from renewable projects of 4 to 6 GW (Equinor equity share) in 2026, and to increase installed renewables capacity further to 12 to 16 GW towards 2035.

In 2019, Equinor’s renewable energy production (equity basis) was 1.8TWh compared to 1.3TWh in 2018. See section 2.6 Other for more details.

Accelerating decarbonisation

While it is critical for Equinor to be at the forefront of the energy transition, we will only succeed if other industries, suppliers, governments and consumers come together to find common solutions. That is why Equinor is committed to taking tangible steps to contribute to accelerating

[16] Equinor aims to achieve by 2030 annual CO2 emissions that are 3 million tonnes less than they would have been, had no reduction measures been implemented between 2017 and 2030

[17] The International Association of Oil and Gas Producers (IOGP) in their Environmental Performance Indicators report 2018.

[18] Total methane emissions from our up- and midstream activities divided by the marketed gas, both on a 100% operated basis.

112 Equinor, Annual Report on Form 20-F 2019

decarbonisation. Our ambition to reduce net carbon intensity by at least 50% by 2050 is a platform for further collaboration with our stakeholders in finding solutions to reducing emissions across the whole value chain.

Net carbon intensity represents the net greenhouse gases (GHG) from energy products and services provided by Equinor, from initial production to final consumption, divided by the energy produced by the company. The indicator accounts for scope 1, 2 and 3 GHG emissions, net of negative emissions from third party carbon capture, utilisation and storage (CCUS) and natural sinks. The net carbon intensity ambition is expected to be met primarily through significant growth in renewables and changes in the scale and composition of the oil and gas portfolio. Operational efficiency, CCUS and hydrogen will also be important, and recognised offset mechanisms and natural sinks may be used as a supplement[19].

We believe new technologies and innovation will provide the future solutions to energy and climate challenges. This is why Equinor’s R&D projects are essential. Equinor’s current ambition is to increase the low carbon (renewable energy, low carbon solutions and energy efficiency) share of R&D expenditure to 25% by 2020. In 2019 the share was around 20%.

Climate-related business risks and portfolio resilience

Our business needs to be resilient to the multiple risks – both upside and downside – posed by climate change. These include potential stricter climate regulations, changing demand for oil and gas, technologies that could disrupt our market, as well as physical effects of climate change.  A detailed overview of climate-related risk factors is provided in previous section 2.11 Risk review. We continue to report on climate related risks and opportunities in line with the recommendations of the Task Force on Climate-Related Financial Disclosures (TCFD).

We require all potential projects to be assessed for carbon intensity and emission reduction opportunities, at every decision phase – from exploration and business development to project development and operations. Furthermore, we require all projects to include a carbon price of at least USD 55 per tonne, to be resilient towards expected higher carbon taxes.

Since 2015 we have been performing an annual sensitivity test of our portfolio against IEA’s energy scenarios described in their World Energy Outlook (WEO) reports. The WEO 2019 describes three scenarios: Current Policies, Stated Policies and Sustainable Development (SDS). These scenarios have different oil, gas and CO2 price assumptions, which are applied in the sensitivity testing to our portfolio. The results are compared to the results generated based on our own economic planning assumptions. The SDS is a “well below 2°C” scenario (1.7-1.8 °C). However, according to the report of the International Panel on Climate Change on impacts of a 1.5°C scenario, the oil and gas demand needs to be significantly lower than in a “well below 2°C” scenario and thus represents a larger downside for Equinor than estimated in the SDS scenario. To cater for this uncertainty, we have added a sensitivity to the IEA price, where we apply a gradual reduction in the oil price from 2020, reaching a long-term oil price assumption of USD 50 per barrel in 2040, which is USD 9 per barrel lower than the long-term oil price of USD 59 per barrel in the SDS. Under the Current Policies and the Stated Policies scenarios we would expect to see an increase in portfolio value, but under the Sustainable Development scenario (using both the IEA price assumptions and our USD 50 per barrel assumption), there would be a significant value reduction. As noted under 2.11 Risk Review—Risk Factors—Risks related to our business, strategy and operations—Oil and natural gas price, a significant or prolonged period of low oil and natural gas prices or other indicators could, if deemed to have longer term impact, lead to reviews for impairment of the group's oil and natural gas assets. See also Note 2 Significant accounting policies to the Consolidated financial statements for a discussion of key sources of uncertainty with respect to management’s estimates and assumptions that affect Equinor’s reported amounts of assets, liabilities, income and expenses and Note 10 Property, plants and equipment to the Consolidated financial statements for a discussion of price assumptions and sensitivities affecting the impairment analysis. Further details about the portfolio sensitivity test are available in our 2019 Sustainability Report.

Climate-related upside and downside risks, and Equinor’s strategic response to these are discussed frequently by our corporate executive committee and board of directors. In 2019, the board of directors specifically discussed climate-related issues in seven of their eight ordinary board meetings. Climate-related risks were also assessed in relation to specific investment decisions. The board of director’s Safety, Sustainability and Ethics committee discussed climate-related issues in all committee meetings in 2019.

Collaboration
We collaborate with peers and business partners to find innovative and commercially viable ways to reduce emissions across the oil and gas value chain. We have teamed up with 12 peer companies in the Oil and Gas Climate Initiative (OGCI) to help shape the industry’s climate response. To spur technology development, we are a partner in the USD +1 billion investment fund OGCI Climate Investment.

To enhance our work on reducing methane emissions, we have joined the One Future Coalition, the Climate and Clean Air Coalition Oil and Gas Methane Partnership and the Guiding Principles on Reducing Methane Emissions Across the Natural Gas Value Chain. We also welcome the constructive engagement with investors participating in Climate Action 100+.

During 2019, Equinor has undertaken a comprehensive review of its memberships in industry associations that have a position on climate and energy policy.

[19] The achievement of Equinor’s net carbon intensity ambition depends, in part, on broader societal shifts in consumer demands and technological advancements, each of which are beyond Equinor’s control. Should society’s demands and technological innovation not shift in parallel with Equinor’s pursuit of significant greenhouse gas emission reductions, Equinor’s ability to meet its climate ambitions will be impaired.

Equinor, Annual Report on Form 20-F 2019 113

Creating shared value

Creating shared value is one of the three key sustainability priorities of Equinor. We aim to contribute to the development of communities where we have long-term operations. We work together with our stakeholders and partners to find mutual benefits and lasting solutions to common challenges and engage in dialogue with local communities to explain our actions and manage expectations.

Equinor creates shared value that contributes to sustainable development through:

· Providing access to affordable, reliable, sustainable and modern energy

· Creating value for shareholders

· Our innovation and research and development activities

· Hiring and development of staff, and promotion of diversity and inclusion on our workforce

· The purchase of goods and services

· Creating opportunities for social and economic development across our value chain through payments to governments, local job creation, local sourcing of goods and services

· Management of social impacts and outcomes and contributing to ripple effects

During 2019, we have engaged with local industries, suppliers and other stakeholders to support major project developments in core areas like the Johan Sverdrup field offshore Norway and the Mariner field offshore UK. The Hywind Tampen project will contribute to further developing floating offshore wind technology and reducing the costs of future floating offshore wind farms, offering new industrial opportunities for the supplier industry.

In Brazil, Equinor together with Shell expanded the Mar Atento project to six municipalities along the coast. Around 300 additional fishermen were trained to provide emergency response support in case of oil spills.

As part of our long-term commitment to creating shared value, building skills and capacity in the communities where we have activities, is important. A large part of our sponsorships, donations and social investments is allocated to capacity building within science, technology, engineering and mathematics (STEM) in partnerships with academic institutions and science centers, and through our Heroes of Tomorrow programme.

During 2019, we continued to strengthen diversity and inclusion in Equinor as described in section 2.13 Our people in this report.

Environmental impact and resource efficiency

Responsible management of our waste, emissions to air, discharges to sea and impact on biodiversity and eco-systems are of great importance to Equinor. We are committed to using resources efficiently.

As a large offshore oil and gas operator and a growing offshore wind power provider, responsible management of the oceans is important to us. Equinor is one of the founding patrons of the UN Global Compact Action platform for sustainable ocean business. In 2019, Equinor contributed to the development of the Ocean Opportunities Report and UN Global Compact Principles for Sustainable Ocean Business, launched in September 2019. Equinor has signed up to these nine principles.

Other focus areas for 2019 have been:

· Improved management of produced and processed water from our offshore and onshore facilities in Norway

· Minimising the use of freshwater and disposal of waste water in US onshore operations

· Improved management of drilling waste

· Improved management of our impact on biodiversity and eco-system

· Preparation and submittal of an Environmental Plan for a possible exploration well in the Great Australian Bight. The Environmental plan was later in 2019 accepted by the Australian National Offshore Petroleum Safety and Environmental Management Authority

NOx emissions have decreased by 2% from 2018 to 2019, largely due to reduced drilling activities in the tight oil segment. SOx emissions increased with 22%, mainly caused by downtime of the sulphur treatment unit during a planned turnaround of the Mongstad refinery. Regular discharges of oil to water has increased by 9% since 2018, mostly due to higher volume of produced water from wells. Emissions of non-volatile organic compounds were reduced by 13%, mainly as a result of a decrease in oil loading volumes on the Norwegian continental shelf.

Hazardous waste quantities increased by 30% from 2018 to 2019, as large process water volumes from the Troll field was dispatched through pipelines to shore and shipped to external contractors as waste, instead of being remediated at our own facilities. Non-hazardous waste quantities increased by 29%​ mainly due large volumes of polluted soil from ground work and tank cleaning at the Kalundborg refinery.

The volume of drill cuttings from US onshore operations, classified as exempt waste, increased by 53% in 2019. The increase is mainly due to cuttings being transported as waste to landfill sites rather than collected in on-site disposal pits. Management of such waste varies with location and landowner preferences and causes year to year variations in solid exempt waste. The disposal of liquid exempt waste has increased by 17% since 2018 due to higher amount of produced water from wells.

114 Equinor, Annual Report on Form 20-F 2019

The consumption of freshwater and fracking chemicals decreased by 8% and 15%, respectively due to reduced fracking activity at Bakken and Eagle Ford in 2019.

Respecting human rights

The safety of our employees and others affected by our operations, including workers of our suppliers, are at the heart of our business. Our strategic commitment to “always safe” also translates into an expectation to respect the internationally recognised human rights of people affected by our operations.

Our human rights policy has been created to be consistent with the United Nations Guiding Principles on Business and Human Rights. The policy addresses the most relevant human rights issues pertaining to our operations and role as an employer, business partner, buyer, and to our presence in local communities. We express our commitment to provide a safe, healthy and secure working environment, and to treat employees and those impacted by our operations fairly and without discrimination.

After a company-wide review process on the progress of the implementation of the human rights policy, a human rights improvement project was established with the aim of strengthening processes and capabilities in our company.

The senior leadership team have continued to develop their approach to human rights throughout 2019, and the CEO gave a keynote speech about human rights at the annual Thorolf Rafto Challenge at the Norwegian School of Economics in Bergen. In addition, human rights have been discussed and evaluated in two meetings by the BoD SSEC and once with the full BoD.

In 2019, we implemented a human rights risk assessment methodology, allowing risk to people to be reported in a consistent manner through our risk management system.

Our efforts towards awareness and training on human rights across the company have continued in 2019. In total, over 500 employees attended classroom-based targeted training sessions. Our e-learning programme on human rights has been revisited and is now made available in three languages. We have created a standalone human rights page on our website with our human rights policy translated into seven languages relevant to our business activities.

Engaging with potentially affected stakeholders is imperative to inform our operations and business plans. Grievance mechanisms form an important part of our stakeholder engagement process. Operational-level grievance mechanisms cover our activities in Brazil, Tanzania and Empire Wind operations in the USA. In addition, all seismic surveys and our renewable projects are covered by operational-level grievance mechanisms. An extensive engagement with stakeholders was undertaken in connection with the Environmental Plan for possible exploration drilling programme in the Great Australian Bight. Close engagement with fisheries has been important for our operations in Brazil and in preparation for developing the Dogger Bank offshore wind farm. In addition to these efforts, Equinor has an Ethics Helpline available to all our employees and third parties who want to communicate concerns.

The supply chain continues to be an important focus area for our human rights efforts. Equinor’s Human Rights Expectations to Suppliers were launched in 2019. In addition, we continued onsite assessments of more than 50 suppliers across 16 countries. These assessments have enabled us to identify gaps and areas of improvement in collaboration with our suppliers to ensure that potential harm to people is reduced or eliminated.

Our specific efforts to prevent modern slavery are described in our annual UK Modern Slavery Statement, available online.

Transparency, ethics and anti-corruption

Equinor is a global company with a presence in parts of the world where corruption represents a high risk. With a strategy to accelerate internationalisation and increase investments in new energy markets, 2019 represented a year of continued focus on ethics and anti-corruption. Equinor is committed to conduct our business in an ethical, socially responsible and transparent manner. We maintain an open dialog on ethical issues, both internally and externally.

Equinor’s Anti-Corruption Compliance Programme summarises the standards, requirements and procedures implemented to comply with applicable laws and regulations and maintaining our high ethical standards. Our group-wide policy ensures that anti-bribery and corruption risks are identified, and measures are taken to mitigate risk in all parts of the organisation and that concerns are reported. In 2019, we have had particular focus on integrating money laundering into to our anti-corruption workshops to increase awareness of money laundering risk within the organisation. Our ethics and anti-corruption training efforts during 2019 included both general and targeted training sessions through a combination of e-learning and workshops.

We report our payments to governments on a country-by-country and on a project-by-project and legal entities basis. Since 2018, we have published our global tax strategy, available online. These disclosures are in line with our commitment to conduct our business activities in a transparent way.

In 2019, we continued to raise awareness of the Ethics Helpline through internal information channels and training, and the number of cases totalled 194.

Equinor has long standing relationships with the UN Global Compact, the World Economic Forum’s Partnering Against Corruption Initiative

Equinor, Annual Report on Form 20-F 2019 115

(PACI) and Transparency International (TI).

Equinor has been a supporter of the Extractive Industries Transparency Initiative (EITI) for many years, through board and committee representation and active participation in working groups. An Equinor representative is elected member of the EITI international board. In 2019, we were present in ten EITI-implementing countries.

116 Equinor, Annual Report on Form 20-F 2019

2.13 Our people

Developing our people

As Equinor develops into a broad energy company and accelerates the use of digital solutions, our ability to drive people development is critical to the delivery of our business strategy. Building a culture of lifelong learning where our employees develop new skills faster to match changing job requirements, has been a key focus area in 2019.

We continue to use deployment across the company as a strong tool for driving on-the-job learning. Through all the academies in The Equinor University we intensified our formal learning activities, particularly relating to safety and digitalisation. In 2019 we more than tripled our learning activities in digital topics, including the introduction of ‘Digital Leadership’ training for our leaders. In addition, we significantly increased learning activities across the company, using e-learning and virtual classrooms as a flexible, accessible and cost-effective means to increase participation.

Early Talents

We continue to invest in our early talents through our graduate and apprentice programmes. In 2019 we welcomed 182 graduates and 157 apprentices. Through our recruitment and attraction activities we strive to increase the diversity of our early talent applicant base and hires, and our ambition was to achieve a 50-50 balance on gender and non-Norwegian background in 2019. In 2019, we made strides towards achieving this goal with a 43-57 split between female and male graduates recruited, and a 45-55 split between graduates recruited with a non-Norwegian and Norwegian background.

Integrated Operations Centre, Sandsli, Bergen, Norway. Bakken, Williston, North Dakota, US.

Permanent employees and percentage of women in the Equinor group |  |  |
| Number of employees | Women
Geographical region | 2019 | 2018 | 2017 | 2019 | 2018 | 2017
Norway | 18,128 | 17,762 | 17,632 | 31% | 31% | 30%
Rest of Europe | 1,359 | 978 | 947 | 23% | 25% | 25%
Africa | 73 | 79 | 78 | 36% | 38% | 37%
Asia | 70 | 75 | 69 | 49% | 53% | 52%
North America | 1,199 | 1,191 | 1,174 | 31% | 32% | 33%
South America | 583 | 439 | 345 | 30% | 32% | 35%
Australia | - | 1 | - | 0% | 0% | 0%
Total | 21,412 | 20,525 | 20,245 | 30% | 31% | 30%
Non-OECD | 823 | 701 | 599 | 32% | 35% | 37%

Equinor, Annual Report on Form 20-F 2019 117

118 Equinor, Annual Report on Form 20-F 2019

Total workforce by region, employment type and new hires in the Equinor group in 2019
Geographical region | Permanent employees | Consultants | Total workforce1) | Consultants (%) | Part time (%) | New hires
Norway | 18,128 | 1,013 | 19,141 | 5% | 3% | 801
Rest of Europe | 1,359 | 57 | 1,416 | 4% | 2% | 487
Africa | 73 | 5 | 78 | 6% | 0% | 2
Asia | 70 | 17 | 87 | 20% | 0% | 12
North America | 1,199 | 117 | 1,316 | 9% | 0% | 104
South America | 583 | 22 | 605 | 4% | 0% | 162
Australia | - | - | - | 0% | 0% | -
Total | 21,412 | 1,231 | 22,643 | 5% | 3% | 1,568
Non-OECD | 823 | 45 | 868 | 5% | NA | 177
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 38,200 in 2019.

People performance data relates to permanent employees in our direct employment. Equinor defines consultants as contracted personnel that are mainly based in our offices. Temporary employees and contractor personnel, defined as third party service providers to onshore and offshore operations, are not included in the table. These were roughly estimated to be 38,200 in 2019. The information about people policies applies to Equinor ASA and its subsidiaries.

### Equal opportunities

Workforce diversity and inclusion

We aspire to be an inclusive workplace where all individuals can share their perspectives, be themselves, develop and thrive in a safe working environment. This includes working actively to ensure that everyone has equal opportunities at Equinor.

Embracing diversity and driving inclusion is a fundamental part of our values - open, collaborative, courageous and caring - and an integral part of our leadership expectations. This includes working actively to ensure that everyone has equal opportunities at Equinor.

In 2019, we continued to strengthen diversity and inclusion in Equinor by embedding it into our key human resources processes, such as recruitment, succession planning, performance management and leadership development. We monitor diversity in our workforce at all levels and locations and encourage and support employee initiatives that contribute to a diverse and inclusive culture. In 2019 we

Equinor, Annual Report on Form 20-F 2019 119

established guidelines to further support employee resource groups in Equinor, including Women in Equinor, Differently Abled and LGBTQ+ groups.

Diversity to us includes age, gender, nationality, experience, competence, education, cultural background, religion, ethnicity, sexual orientation and disabilities – everything that helps shape our thoughts and perspectives. Inclusion to us means that everyone in Equinor feels like that they are part of one team, are able to bring their whole self to work, and have their voices heard to perform at their best. We believe we can only leverage the value of diversity if we have an inclusive culture where everyone feels safe to contribute.

In 2019 Equinor implemented a corporate diversity and inclusion (D&I) KPI, which is measured at the team level. The KPI is based on a diversity index and an inclusion index. The diversity index is flexible and holistic, meaning teams may focus on different dimensions of diversity to achieve the balance that adds most value to them. The diversity KPI monitors each business area’s progression on team diversity. The Inclusion Index is measured in our Global People Survey, and measures employees’ perception of inclusion in their teams. Our ambition is for all teams in Equinor to be diverse and inclusive by 2025.

To show our commitment to equal and inclusive workplaces, Equinor participated in several Gender Equality Indexes that aim to give more visibility into reporting on environmental, social and governance (ESG) from public companies. In 2019 we submitted our employees’ gender profile for inclusion in the Bloomberg Gender-Equality Index, and the Norwegian SHE Index where Equinor was ranked number 10 out of 91 of Norway’s largest companies.

We continuously work on mitigating unconscious biases. During 2019 classroom and online training on unconscious bias was delivered across the organisation, including all top-level leadership teams and our external recruitment providers. We will continue to deliver training on this important topic in 2020.

We aim for gender balance and diversity in all our leadership activities, including talent and succession reviews, leadership assessments, leadership development courses and top-tier leadership deployment. As a part of this, we pay close attention to positions and discipline areas dominated by employees of one gender. In 2019, both shares of female leaders at different levels as well as leaders with non-Norwegian background have increased and this indicates that our management approach related to diversity is contributing to improved diversity.

Consistent with our values and to strengthen our brand and attractiveness as an employer, we successfully implemented a global parental leave policy in all Equinor companies and health insurance in Equinor ASA effective from January 2019. A minimum of 16 weeks paid leave is offered to all employees in the group becoming parents through birth or adoption. The health insurance scheme, supplementing public health services, offers access to private specialists, medical examinations and treatments, and is similar to local health insurance already provided in our subsidiaries. We expect the scheme to have a positive effect on employees’ health and believe that both benefits support our agenda on diversity and inclusion and our general attractiveness as an employer.

### Unions and employee representatives

### Employee relations

We believe in involving our people in the development of the company. In all countries where we are present, we involve our employees and/or their appropriate representatives according to local laws and practices. This varies from formal bodies with employee representatives to employee engagement and involvement through team or town hall meetings.

In 2019, we maintained close cooperation with employee representatives through formal and informal dialogue, at relevant levels and areas of the business. In our European Works Council, we discussed matters, such as Equinor´s strategy, human rights, safety, digitalisation, GDPR and future ways of working. In May 2019, we renewed our union agreement in Brazil, covering our onshore and offshore workers, and included an amendment covering specific regulations for offshore workers.

#

120 Equinor, Annual Report on Form 20-F 2019

# 3 Corporate governance

#

Equinor, Annual Report on Form 20-F 2019 121

# 3.1 Introduction

### Articles of association

Equinor's current articles of association were adopted at the annual general meeting of shareholders on 15 May 2018.

Summary of Equinor’s articles of association:

Name of the company

The registered name is Equinor ASA. Equinor is a Norwegian public limited company.

Registered office

Equinor’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 Equinor 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

Equinor’s share capital is NOK 8,346,653,047.50 divided into 3,338,661,219 ordinary shares.

Nominal value of shares

The nominal value of each ordinary share is NOK 2.50.

Board of directors

Equinor’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

Equinor 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 among the employees.

General meetings of shareholders

Equinor’s annual general meeting is held no later than 30 June each year. The annual general meeting shall address and decide adoption of 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 Equinor’s website. A shareholder may request that such documents be sent to him/her.

Shareholders may vote in writing, including through electronic communication, during a specified period before the general meeting. In order to allow advance voting, the board of directors must stipulate applicable guidelines. Equinor'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

Equinor’s articles of association provide that Equinor 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. Equinor’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
15 May 2018.

Nomination committee

The tasks of the nomination committee are:

· to present a recommendation to the general meeting regarding the election of shareholder-elected members and deputy members to the corporate assembly.

· to present a recommendation to the general meeting regarding the election of members of the nomination committee.

· to present a recommendation to the general meeting for the remuneration for members of the corporate assembly and the nomination committee.

122 Equinor, Annual Report on Form 20-F 2019

· to present a recommendation to the corporate assembly regarding the election of shareholder-elected members to the board of directors.

· to present a recommendation to the corporate assembly for the remuneration for members of the board of directors.

The general meeting may adopt instructions for the nomination committee.

### Code of Conduct

Ethics – Equinor’s approach

Equinor believes that responsible and ethical behaviour is a necessary condition for a sustainable business. Equinor’s Code of Conduct is based on its values and reflects Equinor’s commitment to high ethical standards in all its activities.

Our Code of Conduct

The Code of Conduct describes Equinor’s code of business practice and the requirements for expected behaviour. The Code of Conduct applies to Equinor’s board members, employees and hired personnel. It is divided into five main categories: The Equinor way, Respecting our people, Conducting our operations, Relating to our business partners and Working with our communities.

The Code of Conduct is approved by the board of directors.

Equinor seeks to work with others who share its commitment to ethics and compliance, and Equinor manages its risks through in-depth knowledge of suppliers, business partners and markets. Equinor 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 Equinor’s ethical requirements when working for or together with Equinor. In joint ventures and entities where Equinor does not have control, Equinor makes good faith efforts to encourage the adoption of ethics and anti-corruption policies and procedures that are consistent with its standards. Equinor will not tolerate any breaches of the Code of Conduct. Remedial measures may include termination of employment and reporting to relevant authorities.

Training and Certifying the Code of Conduct

The Code of Conduct training and comprehensive trainings on specific issues, including anti-corruption, anti-trust and reporting, is carried out to explain how the Code of Conduct applies and to describe the tools that Equinor has made available to address risk. The Code of Conduct e-learning is mandatory for all Equinor employees and hired contractors.

All Equinor employees have to annually confirm electronically that they understand and will comply with the Code of Conduct (Code certification). The Code certification reminds the individuals of their duty to comply with Equinor’s values and ethical requirements and creates an environment with open dialogue on ethical issues, both internally and externally.

Anti-Corruption Compliance Program

Equinor is against all forms of corruption including bribery, facilitation payments and trading in influence and has a company-wide anti-corruption compliance program which implements its zero-tolerance policy. The program includes mandatory procedures designed to comply with applicable laws and regulations and guidance and training on relevant topics such as gifts, hospitality and conflict of interest. A global network of compliance officers, who support the integration of ethics and anti-corruption considerations into Equinor’s business activities, constitute an important part of the program.

Equinor consistently works with its partners and suppliers on ethics and anti-corruption and has initiated dialogue with several partners on the risks that we jointly face and actions that can be taken to address them. The Equinor Joint Venture Anti-Corruption Compliance Program describes Equinor’s management of third-party corruption risk in non-operated joint ventures.

In 2019, we focused on targeted training to ensure the follow-up of the Joint Venture Anti-Corruption Compliance Program. During 2019, we also improved the anti-money laundering workstream by integrating it into the Anti-Corruption training and held targeted workshops to increase awareness of money laundering risk within the organisation. A company-wide awareness campaign regarding the Code of Conduct was held in November/December 2019.

Open dialogue and raising concerns

Equinor is committed to maintain an open dialogue on ethical issues. The Code of Conduct requires those who suspect a violation of the Code of Conduct or other unethical conduct to raise their concern. Employees are encouraged to discuss concerns with their leader. Equinor recognises that raising a concern is not always easy so there are several internal channels for taking concerns forward, including through People and Leadership or the ethics and compliance function in the legal department. Concerns can also be raised through the externally operated Ethics Helpline which is available 24/7 and allows for anonymous reporting and two-way communication. Equinor has a non-retaliation policy for anyone who raises an ethical or legal concern in good faith.

More information about Equinor’s policies and requirements related to the Code of Conduct is available on www.equinor.com/en/about-us/ethics-and-compliance-in-equinor.html.

Equinor, Annual Report on Form 20-F 2019 123

## Compliance with NYSE listing rules

Equinor's primary listing is on the Oslo Børs, but its ADRs are listed on the NYSE. In addition, Equinor is a foreign private issuer subject to the reporting requirements of the US Securities and Exchange Commission.

ADRs represent the company's ordinary shares listed on the NYSE. While Equinor's corporate governance practices follow the requirements of Norwegian law, Equinor is also subject to the NYSE's listing rules.

As a foreign private issuer, Equinor is exempted from most of the NYSE corporate governance standards that domestic US companies must comply with. However, Equinor 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. Equinor's corporate governance principles are developed by the management and the board of directors, in accordance with the Code 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 requires an affirmative determination by the board of directors that the director has no material relationship with the company.

Pursuant to Norwegian company law, Equinor's board of directors consists of members elected by shareholders and employees. Equinor's board of directors has determined that, in its judgment, all shareholder-elected directors 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 takes into consideration all relevant circumstances which may in the board’s view affect the directors’ independence. The directors elected from among Equinor's employees would not be considered independent under the NYSE rules because they are employees of Equinor. None of the employee-elected directors is an executive officer of the company.

For further information about the board of directors, see 3.8 Corporate assembly, board of directors and management.

Board committees

Pursuant to Norwegian company law, managing the company is the responsibility of the board of directors. Equinor 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 instructions that are broadly comparable to the applicable committee charters required by the NYSE rules. They report on a regular basis to, and are subject to, oversight by the board of directors. For further information about the board’s committees, see 3.9 The work of the board of directors.

Equinor 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.

The members of Equinor's audit committee include an employee-elected director. Equinor relies on the exemption provided 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. Equinor does not believe that its reliance on this exemption will materially adversely affect the ability of the audit committee to act independently or to satisfy the other requirements of Rule 10A-3 relating to audit committees. 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.

Equinor does not have a nominating/corporate governance 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 are 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. Equinor, as a foreign private issuer, is exempted from complying with these rules and is permitted to follow its home country regulations. Equinor considers all its compensation committee members to be independent (under Equinor’s framework which, as discussed above, is not identical to that of NYSE). Equinor'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,

124 Equinor, Annual Report on Form 20-F 2019

which is elected by the general meeting of shareholders, recommends to the corporate assembly the candidates and remuneration of the board of directors. The nomination committee also 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 Equinor'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 Equinor’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 14 May 2020 in Stavanger, Norway. As Equinor has a large number of shareholders with a wide geographic distribution, Equinor offers shareholders the opportunity to follow the AGM by live webcast from our website. The AGM is conducted in Norwegian, with simultaneous English translation during the webcast. At Equinor's AGM on 15 May 2019, 77.85 % of the share capital was represented either by advance voting, in person or by proxy.

The main framework for convening and holding Equinor's AGM is as follows:

Pursuant to Equinor’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 Equinor'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 Equinor's AGMs will be made available on Equinor's website. A shareholder may 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 in person may vote by proxy.

As described in the notice of the general meeting, shareholders may vote in writing, including through electronic communication, during a specified 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.

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.

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 Depository (VPS), cf. section 4-10 of the Norwegian Public Limited Liability Companies Act, and the beneficial shareholder wants to vote such shares, the beneficial shareholder must re-register the shares in a separate VPS account in such beneficial shareholder’s 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 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 Equinor’s website immediately after the AGM.

Equinor, Annual Report on Form 20-F 2019 125

An extraordinary general meeting (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.

The following sections outline certain types of resolutions by the general meeting of shareholders:

New share issues

If Equinor 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 (i.e. two-thirds of votes cast as well as two-thirds of the share capital). In addition, under Norwegian law, the shareholders have a preferential right to subscribe for new shares issued by Equinor. 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 two-thirds 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 US may require Equinor to file a registration statement in the US under US securities laws. If Equinor 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

Equinor’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 to repurchase shares 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 Equinor'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:

· The annual general meeting for the election of shareholder-elected members and deputy members of the corporate assembly, and the remuneration for 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 for 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 seeks to ensure that the shareholders’ views are taken into consideration when candidates to the governing bodies of Equinor ASA are proposed. The nomination committee invites Equinor'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 Equinor's governing bodies considering Equinor's strategy and challenges and opportunities going forward. The deadline for providing input is normally set to early/mid-January so that such input may be taken into account in the upcoming nominations. In addition, all shareholders have an opportunity to submit proposals through an electronic mailbox as described on Equinor’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

126 Equinor, Annual Report on Form 20-F 2019

makes its final recommendations. The committee regularly utilises external expertise in its work and provides reasons for its recommendations of candidates.

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 attends in lieu of the permanent member if the appointment of that member terminates before the term of office has expired.

Equinor's nomination committee consists of the following members as of 31 December 2019 and are elected for the period up to the annual general meeting in 2020:

· Tone Lunde Bakker (chair), General Manager, Swedbank Norge (also chair of Equinor’s corporate assembly)

· Elisabeth Berge, Secretary General, Norwegian Ministry of Petroleum and Energy until 1 December 2019 (personal deputy for Elisabeth Berge is Bjørn Ståle Haavik, Director, Department of Economic and Administrative Affairs, at the Norwegian Ministry of Petroleum and Energy)

· Jarle Roth, CEO of Umoe AS (also a member of Equinor’s corporate assembly)

· Berit L. Henriksen, self-employed advisor

The board considers all members of the nomination committee to be independent of Equinor's management and board of directors. The general meeting decides the remuneration for the nomination committee.

The nomination committee held 14 ordinary meetings and five telephone meetings in 2019.

The instructions for the nomination committee are available at www.equinor.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 Equinor'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 in Equinor ASA or a subsidiary in Norway. 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 2019 follows.

Equinor, Annual Report on Form 20-F 2019 127

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 December 2019 | Share ownership for members as of 11 March 2020 | First time elected | Expiration date of current term
Tone Lunde Bakker | General Manager, Swedbank Norge | Oslo | 1962 | Chair, Shareholder-elected | No | 0 | 0 | 2014 | 2020
Nils Bastiansen | Executive director of equities in Folketrygdfondet | Oslo | 1960 | Deputy chair, Shareholder-elected | No | 0 | 0 | 2016 | 2020
Jarle Roth | CEO, Umoe AS | Bærum | 1960 | Shareholder-elected | No | 500 | 500 | 2016 | 2020
Greger Mannsverk | Managing director, Kimek AS | Kirkenes | 1961 | Shareholder-elected | No | 0 | 0 | 2002 | 2020
Finn Kinserdal | Associate professor, Norwegian School of Economics and Business (NHH) | Bergen | 1960 | Shareholder-elected | No | 0 | 0 | 2018 | 2020
Kari Skeidsvoll Moe | General Counsel, Trønderenergi AS | Trondheim | 1975 | Shareholder-elected | No | 0 | 0 | 2018 | 2020
Ingvald Strømmen | Professor at the Faculty of Engineering at Norwegian University of Science and Technology | 0 | 1950 | Shareholder-elected | No | 0 | 0 | 2006 | 2020
Rune Bjerke | Chair of the board, Vipps | Oslo | 1960 | Shareholder-elected | No | 0 | 3050 | 2007 | 2020
Birgitte Ringstad Vartdal | CEO of Golden Ocean Management AS until November 2019 | Oslo | 1977 | Shareholder-elected | No | 250 | 250 | 2016 | 2020
Siri Kalvig | CEO, Nysnø Klimainvesteringer AS | Stavanger | 1970 | Shareholder-elected | No | 0 | 0 | 2010 | 2020
Terje Venold | Independent advisor with various directorships | Bærum | 1950 | Shareholder-elected | No | 250 | 250 | 2014 | 2020
Kjersti Kleven | Co-owner of John Kleven AS | Ulsteinvik | 1967 | Shareholder-elected | No | 0 | 0 | 2014 | 2020
Sun Maria Lehmann | Union representative, Advisor Enterprise Data | Trondheim | 1972 | Employee-elected | No | 5633 | 5987 | 2015 | 2021
Oddvar Karlsen | Union representative, Industri Energi | Brattholmen | 1957 | Employee-elected | No | 604 | 757 | 2019 | 2021
Berit Søgnen Sandven | Union representative, Tekna/NITO, Principal Engineer Fiscal metering | Kalandseidet | 1962 | Employee-elected | No | 3665 | 3905 | 2019 | 2021
Terje Enes | Union representative, SAFE, Discipl Resp Maint Mech | Stavanger | 1958 | Employee-elected | No | 5058 | 1056 | 2017 | 2021
Lars Olav Grøvik | Union representative, Tekna, Advisor Petech | Bergen | 1961 | Employee-elected | No | 7104 | 7481 | 2017 | 2021
Frode Mikkelsen | Union representative, Industri Energi | Hauglandshella | 1957 | Employee-elected | No | 393 | 513 | 2019 | 2021
Per Helge Ødegård | Union representative, Lederne, Discipl resp operation process | Porsgrunn | 1963 | Employee-elected, observer | No | 901 | 1103 | 1994 | 2021
Peter B. Sabel | Union representative, Tekna/NITO, Project Leader Geophysics | Hafrsfjord | 1968 | Employee-elected, observer | No | 0 | 0 | 2019 | 2021
Anne Kristi Horneland | Union representative, Industri Energi, employee representative RIR | Hafrsfjord | 1956 | Employee-elected, observer | No | 6768 | 7080 | 2006 | 2021
Total |  |  |  |  |  | 31,126 | 31,932 |  |

128 Equinor, Annual Report on Form 20-F 2019

An election of the employee-elected members of the corporate assembly was held early 2019. As of 16 May 2019, Oddvar Karlsen, Frode Mikkelsen, Sun Maria Lehmann (previous observer) and Berit Søgnen Sandven (previous deputy) were elected as new members, replacing Steinar Kåre Dale, Anne Kristi Horneland, Hilde Møllerstad and Dag-Rune Dale. Lars Olav Grøvik and Terje Enes were re-elected as members of the corporate assembly. Peter B. Sabel (previous deputy) and Anne Kristi Horneland (previous member) were elected as new observers replacing Sun Maria Lehmann and Dag Unnar Mongstad. Per Helge Ødegård was re-elected as an observer. Steinar Kåre Dale, Dag-Rune Dale (both from the former position as members), Ingvild Berg Martiniussen, Lisbeth Dybvik, Vidar Frøseth, Nils Kåre Rovik, Kjetil Gjerstad, Raymond Midtgård, Porfirio Esquivel and Terje Herland were elected as new deputy members. Tove Bjordal was re-elected as deputy member.

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.

Equinor's corporate assembly held four ordinary meetings in 2019. The chair of the board participated in all four meetings, and the CEO in three meetings (with the CFO acting on the CEO’s 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.equinor.com/corporateassembly.

##

Equinor, Annual Report on Form 20-F 2019 129

## 3.5 Board of directors

﻿﻿﻿﻿﻿﻿﻿﻿﻿﻿

Pursuant to Equinor'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, Equinor's board of directors consists of 11 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 three 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 an "audit committee financial expert", as defined in the SEC rules. Equinor’s board of directors has determined that, in its judgment, all the shareholder representatives on the board are considered independent. Seven board members are men, four board members are women and three board members are non-Norwegians resident outside of Norway.

The board held eight ordinary board meetings and two extraordinary meetings in 2019. Average attendance at these board meetings was 98.15%.

Further information about the members of the board and its committees, including information about expertise, experience, other directorships, independence, share ownership and loans, follows and is available on our website at www.equinor.com/board.

130 Equinor, Annual Report on Form 20-F 2019

Members of the board of directors as of 31 December 2019:

Jon Erik Reinhardsen

Born: 1956

Position: Shareholder-elected chair of the board and chair of the board's compensation and executive development committee.

Term of office: Chair of the board of Equinor ASA since 1 September 2017. Up for election in 2020.

Independent: Yes

Other directorships: Member of the board of directors of Oceaneering International, Inc.,Telenor ASA and Awilhelmsen AS.

Number of shares in Equinor ASA as of 31 December 2019: 4,584

Loans from Equinor: None
Experience: Reinhardsen was the chief executive officer of Petroleum Geo-Services (PGS) from 2008 to August 2017. PGS delivers global geophysical- and reservoir services. In the period 2005 to 2008, Reinhardsen was president of Growth, Primary Products in the international aluminium company Alcoa Inc. with headquarters in the US, and he was in this period based in New York. From 1983 to 2005, Reinhardsen held various positions in the Aker Kværner group, including group executive vice president of Aker Kværner ASA, deputy chief executive officer and executive vice president of Aker Kværner Oil & Gas AS in Houston and executive vice president in Aker Maritime ASA.

Education: Reinhardsen has a Master’s Degree in Applied Mathematics and Geophysics from the University of Bergen. He has also attended the International Executive Program at the Institute for Management Development (IMD) in Lausanne, 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 2019, Reinhardsen participated in eight ordinary board meetings, two extraordinary board meetings, five meetings of the compensation and executive development committee and one ordinary and one extraordinary meeting of the audit committee. Reinhardsen is a Norwegian citizen and resident in Norway.

Jeroen van der Veer

Born: 1947

Position: Shareholder-elected deputy chair of the board, chair of the board's audit committee and member of the board's safety, sustainability and ethics committee.

Term of office: Deputy chair of the board of Equinor ASA since 1 July 2019 and member since 18 March 2016. Up for election in 2020.

Independent: Yes

Other directorships: Chair of the Supervisory Boards of Royal Philips and Royal Boskalis Westminster NV, chair of the Supervisory Council of Technical University of Delft and member of the boards of Platform Talent voor Technologie and Prorsum AG.

Number of shares in Equinor ASA as of 31 December 2019: 3,000

Loans from Equinor: None

Experience: van der Veer was the chief executive officer in the international oil and gas company Royal Dutch Shell Plc (Shell) from 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.

Equinor, Annual Report on Form 20-F 2019 131

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 2019 van der Veer participated in eight ordinary board meetings, two extraordinary board meetings, six ordinary and one extraordinary meeting of the audit committee and two ordinary and one extraordinary meeting of the safety, sustainability and ethics committee. van der Veer is a Dutch citizen and resident in the Netherlands.

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.

Term of office: Member of the board of Equinor ASA since 1 September 2010. Up for election in 2020.

Independent: Yes

Other directorships: None

Number of shares in Equinor ASA as of 31 December 2019: None

Loans from Equinor: None

Experience: Godal was a member of the Norwegian parliament for 15 years from 1986 to 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 to 2010, Godal was special adviser for international energy and climate issues at the Norwegian Ministry of Foreign Affairs. From 2003 to 2007, Godal was Norway´s ambassador to Germany and from 2002 to 2003 he was senior adviser at the department of political science at the University of Oslo. From 2014 to 2016, Godal led a government-appointed committee responsible for the evaluation of the civil and military contribution from Norway in Afghanistan in the period 2001 to 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 2019, Godal participated in eight ordinary board meetings, two extraordinary board meetings, five meetings of the compensation and executive development committee and four ordinary and one extraordinary meeting of the safety, sustainability and ethics committee. Godal is a Norwegian citizen and resident in Norway.

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 Equinor ASA since 19 March 2015. Up for election in 2020.

Independent: Yes

Other directorships: Member of the board of Norwegian Hull Club (NHC) and SATS. As part of the role as chief financial officer in Wallenius Wilhelmsen ASA, Herlofsen is a board member and chair of the board of various companies within the Wallenius Wilhelmsen group.

132 Equinor, Annual Report on Form 20-F 2019

Number of shares in Equinor ASA as of 31 December 2019: None

Loans from Equinor: None

Experience: In April 2017, Herlofsen took on the position of chief financial officer in Wallenius Willhelmsen ASA, an international shipping company. Before joining Wallenius Willhelmsen ASA she was the chief financial officer of the shipping company Torvald Klaveness since 2012. 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 Programme (AFA) from the Norwegian School of Economics (NHH). Breakthrough Programme 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 2019, Herlofsen participated in seven ordinary board meetings, two extraordinary board meetings and six ordinary and one extraordinary 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 and the board’s compensation and executive development committee.

Term of office: Member of the board of Equinor ASA since 21 August 2015. Up for election in 2020.

Independent: Yes

Other directorships: Member of the board of the seismic company TGS ASA. As part of the role as senior vice president in Group Holdings in Telenor, Agerup is a board member and chair of the board in various companies within the Telenor Group

Number of shares in Equinor ASA as of 31 December 2019: 2,677
Loans from Equinor: None

Experience: Agerup is senior vice president Group Holdings in Telenor ASA. Agerup was previously executive vice president (Corporate Affairs) and general counsel in Telenor from 2015 to 2018 and executive vice president for Corporate Staffs and the general counsel of Norsk Hydro ASA from 2010 to 2015. 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 and a Master of Business Administration from Babson College, USA.

Family relations: No family relations to other members of the board, members of the corporate executive committee or the corporate assembly.

Other matters: In 2019, Agerup participated in eight ordinary board meetings, two extraordinary board meetings and five meetings of the compensation and executive development committee. Agerup is a Norwegian citizen and resident in Norway.

Equinor, Annual Report on Form 20-F 2019 133

Anne Drinkwater

Born: 1956

Position: Shareholder-elected member of the board, chair of the board’s safety, sustainability and ethics committee and member of the board’s audit committee.

Term of office: Member of the board of Equinor ASA since 1 July 2018. Up for election in 2020.

Independent: Yes

Other directorships: Member of the board of Balfour Beatty plc.

Number of shares in Equinor ASA as of 31 December 2019: 1,100

Loans from Equinor: None

Experience: Drinkwater was employed with BP from 1978 to 2012, holding a number of different leadership positions in the company. From 2009 to 2012 she was chief executive officer of BP Canada. S he has extensive international experience, including being responsible for operations in the US, Norway, Indonesia, the Middle East and Africa. Throughout her career Drinkwater has acquired a deep understanding of the oil and gas sector, holding both operational roles, and more distinct business responsibilities.

Education: Drinkwater has a Bachelor of Science in Applied Mathematics and Statistics from Brunel University London.

Family relations: No family relations to other members of the board, members of the corporate executive committee or the corporate assembly.

Other matters: In 2019, Drinkwater participated in eight ordinary board meetings, one extraordinary board meeting, six ordinary and one extraordinary meeting of the audit committee and four ordinary and one extraordinary meeting of the safety, sustainability and ethics committee. Drinkwater is a British citizen and resident in the United States.

Jonathan Lewis

Born: 1961

Position: Shareholder-elected member of the board and member of 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 Equinor ASA since 1 July 2018. Up for election in 2020.

Independent: Yes

Other directorships: Member of the board of Capita plc.

Number of shares in Equinor ASA as of 31 December 2019: None

Loans from Equinor: None

Experience: Lewis assumed the position as chief executive officer of Capita plc in December 2017, having previously spent 30 years working in large multi-national companies in technology-enabled industries. Lewis came to Capita plc from Amec Foster Wheeler plc, a global consulting, engineering and construction company where he was employed from 1996 to 2016. Lewis has previously held several directorships within technology and the oil and gas industry.

Education: Lewis has an education from Stanford Executive Program (SEP) at Stanford University Graduate School of Business, a PhD, Reservoir Characterisation, Geology/Sedimentology from University of Reading as well as a Bachelor of Science, Geology from Kingston University.

Family relations: No family relations to other members of the board, members of the corporate executive committee or the corporate assembly.

Other matters: In 2019, Lewis participated in eight ordinary board meetings, one extraordinary board meeting, five meetings of the compensation and executive development committee, three ordinary and one extraordinary meeting of the safety, sustainability and ethics committee and three meetings of the audit committee. Lewis is a British citizen and resident in the UK.

134 Equinor, Annual Report on Form 20-F 2019

Finn Bjørn Ruyter

Born: 1964

Position: Shareholder-elected member of the board and member of the board’s audit committee and the board’s compensation and executive development committee.

Term of office: Member of the board of Equinor ASA since 1 July 2019. Up for election in 2020.

Independent: Yes

Other directorships: Member of the board of Vistin Pharma ASA, Fortum Oslo Varme AS, Sysco AS, Eidsiva Energi AS and several subsidiaries of Hafslund E-CO AS.

Number of shares in Equinor ASA as of 31 December 2019: 620

Loans from Equinor: None

Experience: Ruyter has since July 2018 been chief executive officer of Hafslund E-CO AS. He was chief executive officer of Hafslund ASA from January 2012, and chief financial officer in the company from 2010 to 2011. In 2009 and 2010 he was the chief operating officer of the Philippine hydro power company SN Aboitiz Power. From 1996 to 2009 he led the power trading entity and from 1999 also the energy division in Elkem. From 1991 to 1996 Ruyter worked within energy trading in Norsk Hydro.

Education: Ruyter has a Master’s Degree in Mechanical Engineering from the Norwegian University of Technology (NTNU) and an MBA from BI Norwegian School of Management.

Family relations: No family relations to other members of the board, members of the corporate executive committee or the corporate assembly.

Other matters: In 2019, Ruyter participated in four ordinary board meetings, one extraordinary board meeting, three meetings of the audit committee and two meetings of the compensation and executive development committee. Ruyter is a Norwegian citizen and resident in Norway.

P er Martin Labråten
Born: 1961

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 Equinor ASA since 8 June 2017. Up for election in 2021.

Independent: No

Other directorships: Labråten is a member of the executive committee of the Industry Energy (IE) trade union and holds a number of positions as a result of this membership.

Number of shares in Equinor ASA as of 31 December 2019: 1,995
Loans from Equinor: None

Experience: Labråten has worked as a process technician at the petrochemical plant on Oseberg field in the North Sea. Labråten is now a full-time employee representative as the leader of IE Equinor branch.

Education: Labråten 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 2019, Labråten participated in eight ordinary board meetings, two extraordinary board meetings and four ordinary and one extraordinary meeting of the safety, sustainability and ethics committee. Labråten is a Norwegian citizen and resident in Norway.

Equinor, Annual Report on Form 20-F 2019 135

Hilde Møllerstad

Born: 1966

Position: Employee-elected member of the board and member of the board's audit committee.

Term of office: Member of the board of Equinor ASA since 1 July 2019. Up for election in 2021.

Independent: No

Other directorships: Chair of Tekna’s ethical board and board member of Tekna Private Nomination Committee.

Number of shares held in Equinor ASA as of 31 December 2019: 7,515

Loans from Equinor: None

Experience: Møllerstad has been employed by Equinor since 1991 and works within petroleum technology discipline in Development and Production International. Møllerstad held several trust positions in Tekna Equinor since 1993 and she was a member of the corporate assembly in Equinor from 2013 to 2019. She was a board member of Tekna Private from 2012 to 2017.

Education: Chartered engineer from Norwegian University of Science and Technology (NTNU) and Project Management Essential (PME) from Norwegian Business School BI/ Norwegian University of Science and Technology (BI/NTNU).

Familiy relations: No family relationships to other board members, members of the corporate executive committee or the corporate assembly.

Other matters: In 2019 Møllerstad participated in four ordinary board meetings, one extraordinary board meeting and three meetings of the audit committee. Møllerstad is a Norwegian citizen and resident in Norway.

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 Equinor ASA since 1 July 2013. Up for election in 2021.

Independent: No

Other directorships: None

Number of shares held in Equinor ASA as of 31 December 2019: 1,995

Loans from Equinor: None

Experience: Lægreid was e mployed in ÅSV and Norsk Hydro from 1985. Primarily 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, Equinor.

Education: Bachelor’s Degree, Mechanical Construction from Oslo college of engineering (OIH).

Family relations: No family relationships to other board members, members of the corporate executive committee or the corporate assembly.

Other matters: In 2019, Lægreid participated in eight ordinary board meetings, two extraordinary board meetings and four ordinary and one extraordinary meeting of the safety, sustainability and ethics committee. Lægreid is a Norwegian citizen and resident in Norway.

136 Equinor, Annual Report on Form 20-F 2019

The most recent changes to the composition of the board of directors was the election of Finn Bjørn Ruyter by the corporate assembly in June, with effect from 1 July 2019. Jeroen van der Veer replaced Roy Franklin as deputy chair of the board from 1 July 2019. Employee-elected member Hilde Møllerstad was elected as of 1 July 2019, replacing Ingrid Elisabeth Di Valerio.

## The work of the board of directors

The board is responsible for managing the Equinor 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 Equinor operates in compliance with laws and regulations, with our values as stated in The Equinor Book and 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 Equinor'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 of 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. Recurring items on the board's annual plan are: security, safety, sustainability and climate, corporate strategy, business plans, targets, 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, two yearly discussions of main risks and risk issues and an annual review of the board's governing documentation. In addition, the board has in 2019 held deep-dive sessions on other topics, including digitalisation. 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 determine which matters are to be handled by the board. The rules of procedure also determine 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.equinor.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.

New members of the board attend an induction programme where meetings with key members of the management are arranged, an introduction to Equinor’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 generally 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 Equinor locations in Norway and globally, and a longer board trip for all board members to an international location is made at least every two years. When visiting Equinor locations globally, the board emphasises the importance of improving its insight into, and knowledge about, safety and security in Equinor’s operations, Equinor’s technical and commercial activities as well as the company's local organisations. In 2019, the board visited Equinor’s operations in Norway, including the Mongstad refinery. Further, the chair of the board visited several Norwegian and international locations, including Hammerfest, Aberdeen and Stamford.

Requirements for board members and management

Under our Code of Conduct, which is approved by the board, and which applies to both management, employees and board members, individuals must behave impartially in all business dealings and not give other companies, organisations or individuals improper advantages. The importance of transparency is underlined, and any situations that might lead to an actual or perceived conflict of interest should be discussed with the individual’s leader. All external directorships or other material assignments held or carried out by Equinor employees must be approved by Equinor.

The board's rules of procedures state that members of the board and the chief executive officer may not participate in the discussion or decision of issues which are of special personal importance to them, or to any closely-related party, so that the individual must be regarded as having a major personal or special financial interest in the matter. Each board member and the chief executive officer are individually responsible for ensuring that they are not disqualified from discussing any particular matter. Members of the board are obliged to disclose any interests they or their closely-related parties may have in the outcome of a particular issue. The board must approve any agreement between the company and a member of the board or the chief executive officer. The board must also approve any agreement between the company and a third party in which a member of the board or the chief executive officer may have a special interest. Each member of the board shall also continually assess whether there are circumstances which could undermine the general confidence in his or her independence. It is incumbent on each board member to be especially vigilant when making such assessments in

Equinor, Annual Report on Form 20-F 2019 137

connection with the board's handling of transactions, investments and strategic decisions. The board member shall immediately notify the chair of the board if such circumstances are present or arise and the chair of the board will determine how the matter will be dealt with.

Equinor’s board has established three 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 committees’ 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 2019, the audit committee members were Jeroen van der Veer (chair), Rebekka Glasser Herlofsen, Anne Drinkwater, Finn Bjørn Ruyter and Hilde Møllerstad (employee-elected board member).

The CFO, the general counsel, the senior vice president for accounting and financial compliance and the senior vice president for corporate audit, as well as representatives from the external auditor regularly participate in the audit committee meetings.

The audit committee is a 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, to 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 Equinor’s Code of Conduct and supervises compliance activities relating to corruption related to financial matters, as further described below. The audit committee also supervises implementation of and compliance with Equinor’s Global Tax Strategy.

Corporate Audit reports administratively to the president and CEO of Equinor and functionally to the chair of the board of directors’ audit committee.

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 US Code of Federal Regulations.

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

138 Equinor, Annual Report on Form 20-F 2019

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 regular meetings and one extraordinary meeting in 2019. There was 97.14% attendance at the committee's meetings.

﻿﻿﻿﻿

The board of directors has determined that a member of the audit committee, Jeroen van der Veer, qualifies as an "audit committee financial expert", as defined in the SEC rules. The board of directors has also concluded that Jeroen van der Veer, Rebekka Glasser Herlofsen, Anne Drinkwater and Finn Bjørn Ruyter are independent within the meaning of Rule 10A-3 under the Securities Exchange Act.

The committee's mandate is available at www.equinor.com/auditcommittee.

### Compensation and executive development committee

The compensation and executive development committee is a 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 Equinor's remuneration strategy for senior executives and in drawing up appropriate remuneration policies for senior executives; and

(3) to review Equinor's remuneration policies in order to safeguard the owners' long-term interests.

The committee consists of up to five board members. At year-end 2019, the committee members were Jon Erik Reinhardsen (chair), Bjørn Tore Godal, Wenche Agerup, Jonathan Lewis and Finn Bjørn Ruyter. All the committee members are non-executive directors. All members are deemed independent.

The senior vice president People and Leadership participates in the compensation and executive development committee meetings.

The committee held five meetings in 2019 and attendance was 100%.

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.equinor.com/compensationcommittee.

### Safety, sustainability and ethics committee

The safety, sustainability and ethics committee is a committee of the board of directors that assists the board in matters relating to safety, security, sustainability, climate and ethics.

In its business activities, Equinor 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, security, sustainability, climate and ethics policies, systems and principles with the exception of aspects related to “financial matters”. The committee also reviews the annual Sustainability report.

Establishing and maintaining a committee dedicated to safety, security, sustainability, climate 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.

At year-end 2019, the safety, sustainability and ethics committee was chaired by Anne Drinkwater and the other members were Jeroen van der Veer, Bjørn Tore Godal, Jonathan Lewis, Stig Lægreid (employee-elected board member) and Per Martin Labråten (employee-elected board member).

The senior vice president Safety, the general counsel, the chief operating officer, the senior vice president Corporate Sustainability, the senior vice president Corporate Audit and the chief compliance officer regularly participate in the safety, sustainability and ethics committee meetings.

Equinor, Annual Report on Form 20-F 2019 139

The committee held four regular meetings in 2019, including a site visit to CHC Helikopter Service AS at Sola in June. In addition, one extraordinary meeting was held in September. Attendance was on average 93%.

For a more detailed description of the objective, duties and composition of the committee, please see the instructions available at www.equinor.com/ssecommittee.

## 3.6 Management

The president and CEO has overall responsibility for day-to-day operations in Equinor and appoints the corporate executive committee (CEC). The president and CEO is responsible for developing Equinor'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 Equinor'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 Equinor's corporate executive committee as of 31 December 2019:

Eldar Sætre

Born: 1956

Position: President and chief executive officer (CEO) of Equinor ASA since 15 October 2014.

E xternal offices: Member of the board of Strømberg Gruppen AS and Trucknor AS.

Number of shares in Equinor ASA as of 31 December 2019: 82,418

Loans from Equinor: None
Experience: Sætre joined Equinor in 1980. He was executive vice president and chief financial officer from October 2003 until December 2010 and executive vice president for Marketing, Processing & Renewable Energy 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 corporate executive committee, members of the board or the corporate assembly.

Other matters: Sætre is a Norwegian citizen and resident in Norway.

Lars Christian Bacher

140 Equinor, Annual Report on Form 20-F 2019

Born: 1964
Position: Executive vice president and chief financial officer (CFO) of Equinor ASA since 1 August 2018.

External offices: None

Number of shares in Equinor ASA as of 31 December 2019: 31,137

Loans from Equinor: None

Experience: Bacher joined Equinor in 1991 and held a number of leading positions, including Platform Manager on the Norne and Statfjord fields on the Norwegian Continental Shelf. He was senior vice president for Gullfaks operations and subsequently for the Tampen area. Bacher was in charge of the merger process involving the offshore installations of Norsk Hydro and Equinor. He was country manager for our Canadian operations until he became executive vice president for Development and Production International in September 2012.

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, members of the board or the corporate assembly.
Other matters: Bacher is a Norwegian citizen and resident in Norway.

Jannicke Nilsson

Born: 1965
Position: Executive vice president and chief operating officer (COO) of Equinor ASA since 1 December 2016.

E xternal offices: Member of the board of Odfjell SE

Number of shares in Equinor ASA as of 31 December 2019: 47,906

Loans from Equinor: None

Experience: Nilsson joined Equinor in 1999 and 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 the Equinor technical efficiency programme (STEP), responsible for a project portfolio delivering yearly efficiency gains of 3.2 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 corporate executive committee, members of the board or the corporate assembly.
Other matters: Nilsson is a Norwegian citizen and resident in Norway.

Equinor, Annual Report on Form 20-F 2019 141

Pål Eitrheim

Born: 1971
Position: Executive vice president New Energy Solutions (NES) of Equinor ASA since 17 August 2018.

External offices: None

Number of shares in Equinor ASA as of 31 December 2019: 13,302

Loans from Equinor: None

Experience: Eitrheim joined Equinor in 1998. He held a range of leadership positions in Equinor in Azerbaijan, Washington DC, the CEO office, corporate strategy and Brazil. In 2013, he led the Secretariat for the investigation into the terrorist attack on the In Amenas gas processing facility in Algeria. He led Equinor’s upstream business in Brazil between 2014 and 2017, and served as Chief Procurement Officer in 2017 to 2018.

Education: Master degree in Comparative Politics from the University of Bergen, Norway and University College Dublin, Ireland.

Family relations: No family relations to other members of the corporate executive committee, the board of directors or the corporate assembly.

Other matters: Eitrheim is a Norwegian citizen and resident in Norway.

Torgrim Reitan

Born: 1969
Position: Executive vice president Development & Production International (DPI) of Equinor ASA since 17 August 2018.

External offices: None

Number of shares in Equinor ASA as of 31 December 2019: 50,984

Loans from Equinor: None

Experience: Reitan held the position of executive vice president of Development & Production USA from 1 August 2015 to 17 August 2018. Prior to this role, he held the position of executive vice president and chief financial officer of Equinor. He held several managerial positions in Equinor, including senior vice president in trading and operations in the Natural Gas business area from 2009 to 2010, SVP in Performance Management and Analysis from 2007 to 2009 and SVP in Performance Management, Tax and M&A from 2005 to 2007. From 1995 to 2004, he held various positions in the Natural Gas business area and corporate functions in Equinor.

Education: Master of science degree from the Norwegian School of Economics and Business Administration (Siviløkonom).

Family relations: No family relations to other members of the corporate executive committee, members of the board or the corporate assembly.
Other matters: Reitan is a Norwegian citizen and resident in Norway

142 Equinor, Annual Report on Form 20-F 2019

Anders Opedal
Born: 1968

Position: Executive vice president Technology, Projects & Drilling (TPD) of Equinor ASA since 15 October 2018.

E xternal offices: None

Numbers of shares in Equinor ASA as of 31 December 2019: 27,614

Loans from Equinor: None

Experience: Opedal joined Equinor in 1997 as a petroleum engineer in the Statfjord operations. Previously he worked for Schlumberger and Baker Hughes. He held a range of positions in Equinor in Drilling and Well, Procurement and Projects. He served as chief procurement officer in Equinor from 2007 to 2010. In 2011 he took on the role of senior vice president for Projects in Technology, Projects & Drilling responsible for Equinor’s approximately NOK 300 billion project portfolio. He served as Equinor’s executive vice president and chief operating officer before taking the role of senior vice president for Development & Production International, Brazil. His most recent position, which he held from August 2018, was executive vice president for Development & Production Brazil.

Education: Opedal has an MBA from Heriot-Watt University and master’s degree in Engineering (sivilingeniør) from Norwegian Institute of Technology (NTH) in Trondheim.

Family relations: No family relations to other members of the corporate executive committee, members of the board or the corporate assembly.

Other matters: Opedal is a Norwegian citizen and resident in Norway.

Tim Dodson
Born: 1959
Position: Executive vice president Exploration (EXP) of Equinor ASA since 1 January 2011.

E xternal offices: None
Number of shares in Equnor ASA as of 31 December 2019: 36,586

Loans from Equinor: None

Experience: Dodson has worked for Equinor since 1985 and has 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 corporate executive committee, members of the board or the corporate assembly.

Other matters: Dodson is a British citizen and resident in Norway.

Equinor, Annual Report on Form 20-F 2019 143

Margareth Øvrum

Born: 1958

Position: Executive vice president Development & Production Brazil (DPB) of Equinor ASA since October 2018.

External offices: Member of the board of FMC Corporation (US) and member of the nomination committee for Storebrand ASA.

Number of shares in Equinor ASA as of 31 December 2019: 67,749

Loans from Equinor: None

Experience: Øvrum has worked for Equinor since 1982 and has held central management positions in the company, including the position of executive vice president for Health, Safety and the Environment, executive vice president for Technology & Projects and executive vice president for Technology and New Energy. She 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. She joined the corporate executive committee in 2004. Her most recent position was executive vice president for Technology, Projects & Drilling, which she held from September 2011.

Education: Master's degree in engineering (sivilingeniør) from the Norwegian Institute of Technology (NTH), specialising in technical physics.

Family relations: No family relations to other members of the corporate executive committee, members of the board or the corporate assembly.

Other matters: Øvrum is a Norwegian citizen and resident in Brazil.

Arne Sigve Nylund

Born: 1960

Position: Executive vice president Development & Production Norway (DPN) of Equinor ASA since 1 January 2014.

E xternal offices: Member of the board of directors of The Norwegian Oil & Gas Association (Norsk Olje & Gass).

Number of shares in Equinor ASA as of 31 December 2019: 19,785

Loans from Equinor: None

Experience: Nylund was employed by Mobil Exploration Inc. from 1983 to 1987. Since 1987, he has held several central management positions in Equinor.

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 corporate executive committee, members of the board or the corporate assembly.

Other matters: Nylund is a Norwegian citizen and resident in Norway.

144 Equinor, Annual Report on Form 20-F 2019

Al Cook

Born: 1975

Position: Executive vice president Global Strategy & Business Development (GSB) of Equinor ASA since 1 May 2018.

E xternal offices: Member of the board of The Power of Nutrition

Number of shares in Equinor ASA as of 31 December 2019: 2,173

Loans from Equinor: None

Experience: Cook joined Equinor in 2016 as senior vice president in Development & Production International. He joined from BP, where he was chief of staff to the CEO. Cook joined BP in 1996, taking on a series of project development and commercial roles in the North Sea and Gulf of Mexico. He then worked in field operations in the North Sea from 2002 to 2005, becoming offshore installation manager. From 2005, he led the IGB2 Project in Vietnam and acted as president for BP Vietnam. From 2009 to 2014 Cook worked as BP’s vice president, leading the development of the Shah Deniz field in Azerbaijan and construction of the Southern Gas corridor.

Education: MA in Natural Sciences from St. John’s College, Cambridge University and International Executive Programme at INSEAD.

Family relations: No family relations to other members of the corporate executive committee, members of the board or the corporate assembly.

Other matters: Cook is a British citizen and resident in the UK.

Irene Rummelhoff

Born: 1967

Position: Executive vice president Marketing, Midstream & Processing (MMP) of Equinor ASA since 17 August 2018.

External offices: Deputy chair of the board of directors of Norsk Hydro ASA.

Number of shares in Equinor ASA as of 31 December 2019: 34,040

Loans from Equinor: None

Experience: Rummelhoff joined Equinor in 1991. She held a number of management positions within international business development, exploration and the downstream business in Equinor. Her most recent position, which she held from June 2015, was as executive vice president of New Energy Solutions.

Education: Master’s degree in Petroleum Geosciences from the Norwegian Institute of Technology (NTH).

Family relations: No family relations to other members of the corporate executive committee, members of the board or the corporate assembly.

Other matters: Rummelhoff is a Norwegian citizen and resident in Norway.

Equinor has granted loans to Equinor-employed spouses of certain of the executive vice presidents as part of its general loan arrangement for Equinor employees. Employees in salary grade 12 or higher may take out a car loan from Equinor in accordance with standardised provisions set by the company. The standard maximum car loan is limited to the cost of the car, including registration

Equinor, Annual Report on Form 20-F 2019 145

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 of Equinor ASA may also apply for a consumer loan up to NOK 350,000. The interest rate on consumer loans corresponds 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 benefit for the employee.

##

146 Equinor, Annual Report on Form 20-F 2019

## 3.7 Compensation to governing bodies

### Remuneration to the board of directors

The remuneration of the board and its 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 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 measures. 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 Equinor in addition to their board membership, this will be disclosed to the full board.

In 2019, the total remuneration to the board, including fees for the board's three committees, was USD 853,816 (NOK 7,516,726).

Equinor, Annual Report on Form 20-F 2019 147

Detailed information about the individual remuneration to the members of the board of directors in 2019 and their share ownership is provided in the table below.

Members of the board (figures in USD thousand except number of shares) | Total remuneration | Share ownership as of 31 December 2019
Jon Erik Reinhardsen (chair of the board) | 110 | 4,584
Jeroen van der Veer (deputy chair of the board)1) | 101 | 3,000
Roy Franklin (deputy chair of the board)2) | 52 | n.a.
Wenche Agerup | 56 | 2,677
Bjørn Tore Godal | 67 | -
Rebekka Glasser Herlofsen | 62 | -
Anne Drinkwater | 100 | 1,100
Jonathan Lewis | 93 | -
Finn Bjørn Ruyter3) | 37 | 620
Per Martin Labråthen | 56 | 1,995
Stig Lægreid | 56 | 1,995
Hilde Møllerstad3) | 32 | 7,515
Ingrid Elisabeth Di Valerio4) | 31 | n.a.
Total | 854 | 23,486
1) Deputy chair from 1 July 2019. |  |
2) Deputy chair and member until 30 June 2019. |  |
3) Member from 1 July 2019. |  |
4) Member until 30 June 2019. |  |

### 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 2019, the total remuneration to the corporate assembly was USD 132,052 (NOK 1,162,546).

## Remuneration to the corporate executive committee

In 2019, the aggregate remuneration to the corporate executive committee was USD X. The board of directors’ complete declaration on remuneration of executive personnel follows below.

148 Equinor, Annual Report on Form 20-F 2019

Main elements - Equinor executive remuneration
Remuneration element | Objective | Award level | Performance criteria

Base salary | Attract and retain the right individuals by 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.
Fixed salary addition | The fixed salary addition 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 fixed salary addition in lieu of pension accrual above 12G1[20]with reference to the section on pension and insurance scheme. | No performance criteria are linked to the fixed salary addition. The fixed salary addition is not included in the pensionable income.
Annual variable pay | Encourage a strong performance culture. Rewarding individuals for annual achievement of business objectives, both the “What” and the “How”. | Members of the corporate executive committee are entitled to annual variable pay ranging from 0 – 50% of their fixed remuneration. Target2 value is 25%. The threshold principles and the company performance modifier are applied (see explanations below). The company reserves the right to reclaim variable components of the remuneration awarded for performance, if performance data is subsequently proven to be misstated. | Achievement of annual performance goals (“How” and “What” to deliver), in order to create long-term and sustainable shareholder value. Assessment of goals defined in 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 shareholders’ long-term interests. Retention of key executives. | The LTI is calculated as a portion of the participant’s fixed remuneration. 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. If the lock-in obligations are not fulfilled, the executive has to pay back the gross value of the locked-in shares limited to the gross value of the grant amount. The level of the annual LTI reward is in the range of 25-30% of the fixed remuneration. The threshold principles are applied to the annual grant. The company performance modifier is not applied to the LTI in Equinor ASA. | In Equinor ASA, LTI participation and grant level reflect the level and impact of the position and are not directly linked to the incumbent’s performance.
Threshold | Financial threshold for payment of variable remuneration and award of LTI grant. The threshold is implemented to ensure that no or reduced variable pay would be granted if the company’s financial performance and position is weak. | The threshold has the following guiding parameters; 1) Cash flows provided by operating activities after tax and before working capital items, 2) Net debt ratio and development and 3) Company’s overall operational and financial performance. Cash flows provided by operating activities after tax and before working capital items higher than USD 12 billion and a net debt ratio below 30% will normally guide for no reduction of bonus. | Application of the threshold is subject to a discretionary assessment of the company’s overall performance by the board of directors. These measures and targets are indicative and form part of a broader assessment of bonus award.
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 concept is decided 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 a discretionary assessment of the company’s overall performance.
Pension & insurance schemes | Provide competitive post-employment and other benefits. | The company offers a general occupational pension plan and insurance scheme aligned with local markets. Reference is made to the section on pension and insurance scheme. | N/A
Employee share savings plan | Align and strengthen employee and shareholders’ 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 Equinor 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 G represents the basic amount of the Norwegian social security system

2 Target value reflects satisfactory deliveries according to agreed goals

Equinor, Annual Report on Form 20-F 2019 149

Pension and insurance schemes

Members of the corporate executive committee in Equinor 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 G. A defined benefit scheme is retained by a grandfathered group of employees. For new members of the corporate executive committee appointed after 13 February 2015, a cap on pension contribution at 12 G is applied. In lieu of pension accrual above 12 G a fixed salary addition 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 agreements 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 these executives are entitled to a pension amounting to 66% of pensionable salary and a retirement age of 62. When calculating the number of years of membership in Equinor’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 2017 it was agreed that the chief executive officer would not use his contractual right to retire at the age of 62. Sætre retains the right to early retirement, with nine months’ notice to the chair of the board, subject to endorsement by the board of directors. Sætre will retire no later than at age 67.

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

The pension terms for executive vice presidents outlined above are the results of previously established individual agreements.

Equinor 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 Equinor’s general pension plan/defined benefit plan. Members of the corporate executive committee are covered by the general insurance schemes applicable within Equinor.

Severance pay arrangements

The chief executive officer and the executive vice presidents are entitled to a severance payment equivalent to six months’ salary, commencing after the six months’ notice period, when the resignation is requested by 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 Equinor’s performance development process.

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 Organisation, Operations, Market and Finance. Generally, Equinor believes in setting ambitious targets to inspire and drive strong performance.

Goals on “How” we deliver are based on Equinor’s core values and leadership principles and address the behaviour required and expected to achieve the delivery goals. We believe in developing strong leadership and a culture recognised by our values, to drive the long-term sustainable success of the company. The CEO and the executive vice presidents have individual goals on “How to deliver” within prioritised themes such as safety, sustainability and climate, empowerment, continuous improvement, diversity and inclusion and collaboration.

150 Equinor, Annual Report on Form 20-F 2019

Performance evaluation is holistic, involving both measurement and assessment. Since KPIs are indicators only, sound judgement is applied. Significant changes in assumptions are taken into account, as well as target ambition levels, sustainability of delivered results and strategic contribution.

The balanced approach, which involves a broad set of goals defined in relation to both “What” and “How” dimensions and an overall performance evaluation, significantly reduces the likelihood that remuneration policies may incentivise 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 on various targets including but not limited to the company's relative TSR.

Equinor, Annual Report on Form 20-F 2019 151

In 2019, the main business objectives and KPIs for each perspective were as outlined below. Each perspective was in addition supported by comprehensive plans and actions.

Strategic objectives | 2019 assessment
Safety, security and sustainability | These strategic objectives and actions address safety, security and sustainability | The development for the Total Recordable Injury Frequency (TRIF) is positive and improved compared to 2018 and ended on target and at record low 2.5. In 2018 the TRIF was 2.8. Over the last few years, there have been material reductions in oil and gas leakages, and this continued in 2019. Oil and gas leakages in 2019 were on target at 10, compared to 12 in 2018. The Serious Incident Frequency (SIF) ended slightly up in 2019 at 0.6, compared to 0.5 the prior year and behind the target of 0.4. A large portion of the SIF result is related to potential incidents while actual SIF is at a relatively low level. The 2019 CO2 intensity for the upstream portfolio ended at 9.5 kg/boe, slightly higher than the 2018 level. The increase in CO2 intensity was negatively impacted by deferral of production of gas volumes in order to capture higher prices. Equinor’s CO2 intensity is almost half the average level of companies in The International Association of Oil & Gas Producers (IOGP).
People and organisation | These strategic objectives and actions address a value based and high performing organisation | The People development results for 2019 were above target and reflect a solid improvement in learning activities (from 70 000 learning days in 2018 to 84 500 in 2019). In addition, there was a significant increase in e-learning compared to the previous year. Much of this improvement has been enabled by improved accessibility to courses and the intensification of training in digital skills. Internal job market and formal deployment figures have remained stable, and an increased use of competence pools has positively impacted workforce flexibility and the building of broader value chain capability.
Operations | These strategic objectives and actions address reliable and cost-efficient operations, and industry transformation | The 2019 production was 2,074 mboe/day, slightly behind the record production achieved in 2018. The performance is measured towards the rebased production of 2,092 mboe/day in 2018. In 2019, production was primarily impacted by divestments, and the deferral of gas production due to lower gas prices in 2019, compared to long-term outlook. Six fields started production during 2019, including the Johan Sverdrup and Mariner Fields. Production efficiency (PE) of 87.5% was below target, having been significantly impacted by a small number of assets. However, there are several assets with PE above 94%. Fixed operating costs and SG&A per boe increased and did not reach the target, being impacted by new field start-up costs, and the loss of production from the divested assets.
Market | These strategic objectives and actions address a flexible and resilient energy portfolio | Capex has been reduced during the year through further efficiency improvements and continuous capital allocation prioritisation. Organic capex ended at USD 10 billion, which is better than the target set for 2019 of USD 11 billion. The organic capex guidance was reduced to USD 10-11 billion during the year and the result is at the lower end of this range. Value creation from exploration has been strong and at target level even though some high impact wells were postponed to 2020. Exploration delivered strong value creation on the NCS from a high discovery rate and valuable incremental barrels close to existing infrastructure. Resource replacement is 0% and below target of 100% due to divestments and the postponement of high impact wells to 2020. Our reserve replacement ratio (RRR) was 76%, behind our target of 100%. The organic reserves replacement ratio was 83%. Equinor also secured access to attractive new acreage in 2019.
Finance | These strategic objectives and actions address cash generation, profitability and competitiveness | On Relative Total Shareholder Return, Equinor ranked tenth in our peer group, a position of fourth quartile, below our target of being better than average in the peer group. The TSR has been impacted by low European gas prices. On relative ROACE Equinor ranked fourth in our peer group, a position of second quartile, which was better than the target for 2019.

152 Equinor, Annual Report on Form 20-F 2019

Board of director’s assessment of the chief executive officer’s performance In its assessment of the chief executive officer’s performance and consequently his annual variable pay for 2019, the board of directors has emphasised that deliveries in key areas have been both above, at, and below target. The Total Recordable Injury Frequency (TRIF) is at the best level in the company’s history. The Total Serious Incident Frequency (SIF) however ended behind the target and is an area of continued focus. A strong delivery within People Development is observed. Capex has been further reduced due to efficiency improvements and strict prioritisation. Value creation from exploration had a positive development in 2019 and came in at target. Production is below the 2018 record level, mainly impacted by divestments and deferral of gas production in order to capture higher prices, and the rebased production level ended slightly below the target. Production efficiency was below target, impacted negatively by a few assets. The cost development (fixed opex and SG&A per barrel) did not reach the target and needs continued strong focus going forward. While relative TSR performance was below target, relative ROACE was above target performance. The chief executive officer has been a strong role model for sustainable development and the transition into renewable energy sources both inside and outside of the company.

| Fixed remuneration |  |  |  |  |  |  |  |  |  |
Members of the corporate executive committee (figures in USD thousand, except no. of shares)1), 2) | Fixed pay3) | Fixed salary addition4) | LTI 5) | Annual variable pay6) | Taxable benefits | 2019 Taxable compensation | Non-taxable benefits in-kind | Estimated pension cost7) | Estimated present value of pension obligation 8) |  | 2018 Taxable compensation9) | Number of shares at 31 December 2019
Eldar Sætre10) | 1,070 | 0 | 307 | 282 | 78 | 1,737 | 0 | 0 | 14,655 |  | 2,069 | 82,418
Margareth Øvrum 11) | 700 | 0 | 106 | 116 | 102 | 1,023 | 83 | 0 | 7,581 |  | 914 | 67,749
Timothy Dodson | 455 | 0 | 104 | 117 | 42 | 718 | 49 | 149 | 5,323 |  | 829 | 36,586
Irene Rummelhoff | 450 | 76 | 122 | 123 | 27 | 797 | 0 | 29 | 1,454 |  | 895 | 34,040
Arne Sigve Nylund | 489 | 0 | 115 | 118 | 31 | 753 | 0 | 136 | 5,268 |  | 876 | 19,785
Lars Christian Bacher | 473 | 0 | 106 | 111 | 3 | 694 | 51 | 133 | 3,025 |  | 869 | 31,137
Jannicke Nilsson | 407 | 62 | 101 | 90 | 28 | 688 | 33 | 36 | 1,436 |  | 820 | 47,906
Torgrim Reitan11) | 486 | 0 | 106 | 111 | 36 | 739 | 39 | 127 | 2,974 |  | 1,064 | 50,984
Pål Eitrheim9) | 374 | 60 | 97 | 97 | 18 | 646 | 0 | 23 | 1,160 |  | 292 | 13,302
Anders Opedal9) | 500 | 78 | 126 | 136 | 15 | 854 | 0 | 27 | 1,456 |  | 429 | 27,614
Alasdair Cook9), 12) | 800 | 0 | 173 | 203 | 145 | 1,320 | 44 | 0 | 0 |  | 853 | 2,173

1) All figures in the table are presented in USD based on average currency rates.
2019: NOK/USD = 0,1136, GBP/USD = 1,2760, BRL/USD = 0,2755 (2018: NOK/USD = 0,1231, GBP/USD = 1,3350, BRL/USD = 0,2562).
The figures are presented on accrual basis.

2) All CEC members receive their remuneration in NOK except Alasdair Cook who receives the remuneration in GBP, and Margareth Øvrum who receives the remuneration in BRL and NOK.

3) Fixed pay consists of base salary, fixed remuneration element, holiday allowance, cash compensation (Alasdair Cook) and other administrative benefits.

4) Fixed salary addition in lieu of pension accrual above 12 G (G is the base amount in the national insurance scheme).

5) The long-term incentive (LTI) element implies an obligation to invest the net amount in Equinor 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 Equinor ASA. Alasdair Cook participates in Equinor’s international long-term incentive program as described in the section Execution of the remuneration policy and principles in 2019.

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 2018 and is recognised as pension cost in the statement of income for 2019.

8) Eldar Sætre, Arne Sigve Nylund, Margareth Øvrum and Timothy Dodson are maintained in the closed defined benefit scheme, whereas the remaining members of corporate executive committee employed by Equinor ASA, is covered by the defined contribution pension scheme.

9) Includes figures for 2018 CEC members who are also CEC members in 2019. All members of the CEC have served their positions in the CEC the full year of 2019. For the comparable figures for 2018, the following members served only part of the year: Alasdair Cook was appointed EVP as of 1 May 2018. Anders Opedal and Pål Eitrheim were both appointed EVPs as of 17 August 2018.

10) Estimated present value of pension obligation for Eldar Sætre is based on retirement at the age of 67. Eldar Sætre has the right to retire at an earlier stage.

11) Terms and conditions for Margareth Øvrum also include compensation according to Equinor’s international assignment terms. 2018 Taxable compensation for Torgrim Reitan includes compensation according to Equinor’s international assignment terms.

12) Alasdair Cook’s fixed pay includes USD 72 thousand in lieu of pension contribution.

There are no loans from the company to members of the corporate executive committee.

###

Equinor, Annual Report on Form 20-F 2019 153

### Company performance modifier

Introduction

Based on initial approval by the annual general meeting in 2016, a company performance modifier was introduced to be applied in calculation of variable pay. The intention is to continue with the performance modifier in 2020. The relative total shareholder return is recommended as one of the criteria in the modifier. Thus, the proposal 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

Equinor has an annual variable pay schemes (AVP) for members of the corporate executive committee. The schemes are described in section on remuneration policy and 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 2020. 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 determine Equinor’s relative position. A position of Quartile 1 means that Equinor is amongst the top scoring quartile of peer companies. A position of Quartile 4 means that Equinor 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, it will be 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 2020 annual 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 2020 with subsequent impact on annual variable pay in 2021. 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 of directors’ annual declaration on remuneration and other employment terms for Equinor’s corporate executive committee.

##

154 Equinor, Annual Report on Form 20-F 2019

## 3.8 Share ownership

The number of Equinor 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 Equinor shares.

Equinor, Annual Report on Form 20-F 2019 155

156 Equinor, Annual Report on Form 20-F 2019

|  | As of 31 December | As of 11 March
Ownership of Equinor shares (including share ownership of «close associates») | 2019 | 2020
Members of the corporate executive committee |  |
Eldar Sætre | 82,418 | 84,297
Lars Christian Bacher | 31,137 | 31.137
Jannicke Nilsson | 47,906 | 48,248
Anders Opedal | 27,614 | 28,106
Torgrim Reitan | 50,984 | 50,984
Alasdair Cook | 2,173 | 3,057
Tim Dodson | 36,586 | 37,684
Margareth Øvrum | 67,749 | 69,185
Arne Sigve Nylund | 19,785 | 19,785
Pål Eitrheim | 13,302 | 13,302
Irene Rummelhoff | 34,040 | 34,870
|  |  | 0
Members of the board of directors |  | 0
Jon Erik Reinhardsen | 4,584 | 4,584
Jeroen van der Veer | 3,000 | 6,000
Bjørn Tore Godal | 0 | 0
Wenche Agerup | 2,677 | 2,677
Rebekka Glasser Herlofsen | 0 | 0
Jonathan Lewis | 0 | 0
Finn Bjørn Ruyter | 620 | 620
Per Martin Labråten | 1,995 | 2,153
Hilde Møllerstad | 4,859 | 7,515
Stig Lægreid | 1,995 | 1,995

Individually, each member of the corporate assembly owned less than 1% of the outstanding Equinor shares as of 31 December 2019 and as of 11 March 2020. In aggregate, members of the corporate assembly owned a total of 31,126 shares as of
31 December 2019 and a total of 31,932 shares as of
11 March 2020. 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 independent registered public accounting firm (external auditor) is independent in relation to Equinor and is elected by the general meeting of shareholders. Our independent registered public accounting firm, Ernst & Young AS, has been engaged to provide and audit in accordance with standards of the Public Company Accounting Oversight Board (United States). Ernst & Young AS will also issue a report in accordance with law, regulations, and auditing standards and practices generally accepted in Norway, including International Standards on Auditing (ISAs), which includes opinions on the Consolidated financial statements and the parent company financial statements of Equinor ASA. The reports are set out in section 4.1.

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.

Equinor, Annual Report on Form 20-F 2019 157

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 meets the requirements in Norway and in the countries where Equinor 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.

When evaluating the external auditor, emphasis is placed on the firm's qualifications, capacity, local and international availability and the auditor’s fee.

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 2017 – 2019

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.

On 15 May 2019, the general meeting of shareholders appointed Ernst & Young AS as Equinor's auditor, thereby replacing KPMG AS. The following table sets out the aggregate fees related to professional services rendered by Equinor's external auditor Ernst & Young AS, for the fiscal year 2019, and KPMG AS for the fiscal year 2017, 2018 and until 15 May 2019.

158 Equinor, Annual Report on Form 20-F 2019

Auditor's remuneration
| Full year
(in USD million, excluding VAT) | 2019 | 2018 | 2017
Audit fee Ernst & Young (principal accountant 2019) | 4.7 |  |
Audit fee KPMG (principal accountant 2018 and 2017) | 2.8 | 7.1 | 6.1
Audit related fee Ernst & Young (principal accountant 2019) | 0.5 |  |
Audit related fee KPMG (principal accountant 2018 and 2017) | 1.2 | 1.0 | 0.9
Tax fee Ernst & Young (principal accountant 2019) | 0.2 |  |
Tax fee KPMG (principal accountant 2018 and 2017) | 0.0 | 0.0 | 0.0
Other service fee Ernst & Young (principal accountant 2019) | 0.9 |  |
Other service fee KPMG (principal accountant 2018 and 2017) | 0.0 | 0.0 | 0.0
Total | 10.3 | 8.1 | 7.0

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 Equinor's Consolidated financial statements, on Equinor'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, if any, 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 Equinor lated fees relating to Statoil-159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 159 operated licences for the years 2019, 2018 and 2017 amounted to USD 0.5 million, USD 0.9 million and USD 0.8 million, respectively.

## 3.10 Risk management and internal controls

### Risk management

The board focuses on ensuring adequate control of the company's internal control and overall risk management. Two times a year, the board is presented with and discusses the main risks and risk issues Equinor is facing, based on enterprise risk management. The board is also provided with the main risks related to cases for investment decisions. The board´s audit committee assists the board and acts as a preparatory body in connection with monitoring of the company´s internal control, internal audit and risk management systems. The board´s safety, sustainability and ethics committee monitors and assesses safety, sustainability and climate risks which are relevant for Equinor´s operations and both committees report regularly to the full board.

Equinor manages risk to make sure that operations are safe and in compliance with requirements. Our overall risk management approach includes continuously assessing and managing risks related to the value chain in order to support the achievement of our principal objectives, i.e. value creation and avoiding incidents.

The company has a separate corporate risk committee chaired by the chief financial officer. The committee meets around four to six times a year to give advice and make recommendations on Equinor's enterprise risk management. Further information about the company's risk management is presented in section 2.11 of the form 20-F Risk review.

All risks are related to Equinor's value chain - from access, maturing, project execution and operations to market. In addition to the financial impact these risks could have on Equinor's cash flows, we have also implemented procedures and systems to reduce safety, security and integrity incidents (such as fraud and corruption), as well as any reputation impact resulting from human rights, labour standards and transparency issues. Most of the risks are managed by principal business area line managers. Some operational risks are insured by the captive insurance company, which operates in the Norwegian and international insurance markets.

##

Equinor, Annual Report on Form 20-F 2019 159

## Controls and procedures

This section describes controls and procedures relating to our financial reporting.

Evaluation of disclosure controls and procedures

The management of Equinor, 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 as a result of a material weakness in internal control over financial reporting described below, as of 31 December 2019, our disclosure controls and procedures were not effective.

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 possible controls and procedures. Because of the limitations inherent in all controls 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 Equinor 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 Equinor’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).

Equinor’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 Equinor; and provide reasonable assurance regarding the prevention or timely detection of any unauthorised acquisition, use or disposition of Equinor’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.

In the first quarter of 2019, Equinor acquired 100% of the shares of Danske Commodities (DC), a Danish energy trading company. We are in the process of evaluating internal control over financial reporting for DC and, accordingly, have excluded DC from our assessment of the effectiveness of our internal control of financial reporting as of 31 December 2019, as permitted by SEC guidance. Total assets of DC as of 31 December 2019 represented 1.1% of Equinor’s total assets as of such date, and revenues associated with DC for the period from acquisition to 31 December 2019 represented 0.4% of Equinor’s revenues for the year ended 31 December 2019.

Material weakness

The management of Equinor 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, management has concluded that Equinor’s internal control over financial reporting as of 31 December 2019 was not effective due to the existence of control deficiencies related to user access management within the Information Technology (IT) environment. As a consequence a material weakness exists in our internal control over financial reporting.

IT user access controls management

IT user access controls are intended to ensure that access to financial applications and data is adequately restricted to appropriate personnel. Management has identified control deficiencies related to information technology general controls over information technology systems that support our financial reporting process. Specifically, control deficiencies were identified in the operation of controls related to user access controls management to appropriately segregate duties and to adequately restrict user and privileged access to financial applications, data and programs to appropriate Company personnel. The deficiencies primarily related to insufficient controls with respect to granting access, lack of performance of review controls covering segregation of duties, sensitive and critical access.

These IT deficiencies did not result in a material misstatement to the Consolidated financial statements. However, the deficiencies, when aggregated, impacted the effectiveness of IT application and IT dependent controls and created a possibility that a material

160 Equinor, Annual Report on Form 20-F 2019

misstatement to the Consolidated financial statements would not be prevented or detected on a timely basis and accordingly a remediation plan has been undertaken.

Management has analysed the material weakness and performed additional analysis and mitigation controls and procedures in preparing our Consolidated financial statements. We have concluded that our Consolidated financial statements fairly present, in all material respects, our financial condition, results of operations and cash flow at and for the periods presented. Apart from the material weakness described above, Equinor’s management has not identified any other deficiencies that have led management to conclude that Equinor’s internal control over financial reporting was not effective.

Attestation report of the registered public accounting firm

The effectiveness of internal control over financial reporting as of 31 December 2019 has been audited by Ernst & Young AS, an independent registered accounting firm that also audits the Consolidated financial statements in this report. Their report on internal control over financial reporting expresses an adverse opinion on the effectiveness of our internal control over financial reporting as of 31 December 2019.

Remediation plan

Our management is actively undertaking remediation efforts to address the material weakness identified above through the following actions:

· providing additional training to relevant personnel to strengthening competence at the relevant levels across the organization regarding risks and internal controls

· improving the operation of controls over IT user access and the level of privileges assigned to IT users

· increasing coordination and monitoring activities related to the execution of the IT user access management controls

Management believes the foregoing plan will effectively remediate the deficiencies constituting the material weakness. As the remediation plan is implemented, management may take additional measures or modify the plan described above.

Changes in internal control over financial reporting

Other than the material weakness described above, there were no changes in our internal control over financial reporting during the year ended 31 December 2019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

#

Equinor, Annual Report on Form 20-F 2019 161

# 4.1 Consolidated financial statements

# of the Equinor group

Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors of Equinor ASA

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheet of Equinor and its subsidiaries (Equinor or the Company) as of
31 December 2019, the related consolidated statements of income, comprehensive income, changes in equity and cash flows for the year ended 31 December 2019, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at 31 December 2019 and the results of its operations and its cash flows the year then ended, in conformity with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB) and in conformity with IFRS as adopted by the European Union.

We also audited the reclassification and disaggregation (the “adjustments”) described in Note 3 Segments that were applied to the Revenues from contracts with customers and other revenue disclosure in the 2018 consolidated financial statements. In our opinion, such adjustments are appropriate and have been properly applied. However, we were not engaged to audit, review or apply any procedures to the 2018 and 2017 consolidated financial statements of the Company other than with respect to the adjustments and, accordingly, we do not express an opinion or any other form of assurance on the 2018 and 2017 consolidated financial statements taken as a whole.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of 31 December 2019, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated 19 March 2020 expressed an adverse opinion thereon.

Adoption of New Accounting Standard

As discussed in Note 23 to the consolidated financial statements, the Company changed its method of accounting for leases due to the adoption of IFRS 16 Leases on 1 January 2019.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audit included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audit provides a reasonable basis for our opinion.

Supplemental Information

The accompanying supplementary oil and gas information has been subjected to audit procedures performed in conjunction with the audit of the Company’s financial statements. Such information is the responsibility of the Company’s management. Our audit procedures included determining whether the information reconciles to the financial statements or the underlying accounting and other records, as applicable, and performing procedures to test the completeness and accuracy of the information. In our opinion, the information is fairly stated, in all material respects, in relation to the consolidated financial statements as a whole.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or

162 Equinor, Annual Report on Form 20-F 2019

disclosures to which they relate.

Recoverable amounts of production plants and oil and gas assets including assets under development

Description of the Matter | As at 31 December 2019, the Company has recognised production plants and oil and gas assets and assets under development of USD 179,063 million and USD 10,371 million, respectively, within Property, plant and equipment. Refer to note 10 to the consolidated financial statements for the related disclosure. As disclosed in note 2 to the consolidated financial statements, assessing the recoverable amounts of the assets involves significant judgement. When estimating the recoverable amount, the expected cash flow approach is applied to reflect uncertainties in timing and amount inherent in the assumptions used in the estimated future cash flows. These assets’ operational performance and external factors could have a significant impact on the estimated future cash flows and therefore, the recoverable amounts of the assets. The assumptions used in forecasting future cash flows are future price assumptions, future expected production volumes and capital and operating expenditures and the discount rate applied. These critical assumptions are forward-looking and can be affected by future economic and market conditions.
How We Addressed the Matter in Our Audit | We obtained an understanding, evaluated the design, and tested the operating effectiveness of controls over the Company’s process for evaluating the recoverability of production plants and oil and gas assets including assets under development. This included obtaining an understanding, evaluating the design, and testing the operating effectiveness of controls over management’s review of assumptions and inputs to the impairment assessments. Among other procedures, where impairment assessments were carried out, we involved valuation specialists to assist in evaluating management’s methodology, testing the clerical accuracy of the models used, evaluating the reasonableness of the discount rate used by comparing against external sources, and independently recalculating the value in use of the assets being assessed. For those assets impaired previously, we evaluated actual results versus the forecasts used in historical impairment analyses and evaluated management’s analyses regarding reversals of previous impairments. Among other procedures to assess inputs to the discounted cash flow models, we compared the operating expenditure profiles and capital costs to approved operator budgets or management forecasts; evaluated management’s methodology to determine future short- and long-term commodity prices and compared such assumptions to consensus analysts’ forecasts and those adopted by other international oil companies; compared management’s income tax assumptions against the applicable tax regulations; and where applicable, compared reserves volumes in the impairment models to external verifications of expected reserves.

Estimation of the asset retirement obligation

Description of the Matter | The total provision for decommissioning and removal activities amounted to USD 14,719 million as of 31 December 2019 and is classified under Provisions in the consolidated balance sheet. Refer to notes 2 and 20 to the consolidated financial statements for disclosures related to the asset retirement obligation (ARO) provision. The determination of the ARO involves judgement related to the assumptions used in the estimate, the inherent complexity and uncertainty in estimating future costs, and the limited historical experience against which to benchmark estimates of future costs. Significant assumptions used in the estimate are the discount rate and the expected future cost, which includes underlying factors such as time required to decommission, the day rates for rigs, marine operations and heavy lift vessels, and currency exchange rates.
How We Addressed the Matter in Our Audit | We obtained an understanding, evaluated the design, and tested the operating effectiveness of controls over the Company’s process to determine the present value of the estimated future decommissioning and removal expenditures determined in accordance with local conditions and requirements. This included controls over management’s review of assumptions used in the calculation of the ARO. To test management’s estimation of the provision for decommissioning and removal activities, our audit procedures included evaluating the completeness of the provision by inquiring with relevant personnel and comparing significant additions to property, plant and equipment to management’s assessment of new ARO obligations recognized in the period. We also evaluated the methodology used and performed a sensitivity analysis of management’s assumptions in order to evaluate which assumptions have the most impact on the estimate. Among other procedures, we compared day rates for rigs, marine operations and heavy lift vessels to external market data or existing contracts. For time required to decommission, we compared against experience data on a sample basis. We compared the year of abandonment to management’s reserves assessments and compared discount rates to external market data. We involved our valuation specialists to assist in testing of the models supporting the ARO provision including sensitivity assessments.

Equinor, Annual Report on Form 20-F 2019 163

Effect on financial statements of material weakness in internal control over financial reporting

Description of the Matter | As disclosed in management’s report on internal control over financial reporting, the Company identified a material weakness as at 31 December 2019 in their internal control over financial reporting as it did not maintain effective controls over IT user access management to ensure segregation of duties that manage user and privileged access to financial applications that support the preparation of the consolidated financial statements. This material weakness impacts the Company’s controls over IT applications and related business process controls and affects substantially all financial statement account balances. Significant auditor judgment was required to design and execute the incremental audit procedures related to the IT applications and financial statement account balances effected by the ineffective internal controls and to assess the sufficiency of the procedures performed and evidence obtained. Auditing the significant financial statement accounts affected by the material weakness in controls over IT user access was determined to be a critical audit matter because significant auditor judgment and the assistance of IT professionals was required to design and execute the incremental audit procedures related to the IT applications and to assess the sufficiency of the procedures performed and evidence obtained.
How We Addressed the Matter in Our Audit | We involved our IT professionals to assist us in performing additional audit procedures related to users with access to IT applications, including procedures to assess users with potential segregation of duties conflicts and critical and sensitive accesses rights. We also increased the extent of testing of application controls. Furthermore, we evaluated the impact on relevant account balances, taking into account the complexity of the business processes impacted by the user access controls. This included lowering the testing threshold, increasing the samples for instance related to obtaining external documentation and confirmations, and tailoring the audit procedures for the impacted accounts, such as those related to the sale and purchase of oil and gas, compared to what we would have performed if the Company’s user access controls were operating effectively.

/s/ Ernst & Young AS

We have served as the Company’s auditor since 2019.

Stavanger, Norway

19 March 2020

164 Equinor, Annual Report on Form 20-F 2019

Report of Independent Registered Public Accounting Firm

The board of directors and shareholders of Equinor ASA

Opinion on the Consolidated Financial Statements

We have audited, before the effects of the adjustments to retrospectively apply the changes noted in the paragraph below, the consolidated balance sheet of Equinor ASA and subsidiaries (the Company) as of 31 December 2018, the related consolidated statements of income, comprehensive income, changes in equity, and cash flows for each of the years in the two year period ended
31 December 2018, and the related notes (collectively, the consolidated financial statements). The 2018 and 2017 consolidated financial statements before the effects of the adjustments to retrospectively apply the changes noted in the paragraph below are not presented herein. In our opinion, the consolidated financial statements before the effects of the adjustments to retrospectively apply the changes noted in the paragraph below, present fairly, in all material respects, the financial position of the Company as of 31 December 2018, and the results of its operations and its cash flows for each of the years in the two year period ended 31 December 2018, 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.

We were not engaged to audit, review, or apply any procedures to the adjustments in relation to the following:

· retrospectively apply the reclassification of Physically settled commodity derivatives to Total other revenues, previously presented as Natural gas revenues included in Total revenues from contracts with customers in Note 3; and

· retrospectively apply the disaggregation of Natural gas revenues in Note 3.

Accordingly, we do not express an opinion or any other form of assurance about whether such adjustments are appropriate and have been properly applied. Those adjustments were audited by other auditors.

Changes in Accounting Policy

With effect from 1 January 2018, the Company elected to change its policy for accounting for lifting imbalances, impacting the recognition of revenue from the production of oil and gas properties in which the Company shares an interest with other companies.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ KPMG AS

We served as the Company’s auditor from 2012 to 2019.

Stavanger, Norway

5 March 2019

Equinor, Annual Report on Form 20-F 2019 165

Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors of Equinor ASA

Opinion on Internal Control Over Financial Reporting

We have audited Equinor ASA and subsidiaries’ internal control over financial reporting as of 31 December 2019, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, because of the effect of the material weakness described below on the achievement of the objectives of the control criteria, Equinor ASA and subsidiaries (the Company) has not maintained effective internal control over financial reporting as of 31 December 2019, based on the COSO criteria.

A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the Company’s annual or interim financial statements will not be prevented or detected on a timely basis. The following material weakness has been identified and included in management’s assessment.

In our opinion, the Company did not maintain, in all material respects, effective internal control over financial reporting as of 31 December 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO because the Company did not maintain effective controls over IT user access management to ensure appropriate segregation of duties and that adequately restrict sensitive and critical access to significant applications and maintain effective application and IT-dependent controls in the preparation of the consolidated financial statements.

As indicated in the accompanying Management’s report on internal control over financial reporting, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of Danske Commodities, which is included in the 2019 consolidated financial statements of the Company and constituted 1.1% and 1.6% of total and net assets, respectively, as of 31 December 2019 and 0.4% and 2.2% of revenues and net income, respectively, for the year then ended. Our audit of internal control over financial reporting of the Company also did not include an evaluation of the internal control over financial reporting of Danske Commodities.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of the Company as of 31 December 2019, the related consolidated statements of income, comprehensive income, changes in equity and cash flows for the year ended 31 December 2019, and the related notes (collectively referred to as the “consolidated financial statements”). This material weakness was considered in determining the nature, timing and extent of audit tests applied in our audit of the 2019 consolidated financial statements, and this report does not affect our report dated 19 March 2020, which expressed an unqualified opinion thereon.

Basis for Opinion

The Company’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 Management's report on internal control over financial reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. 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, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

166 Equinor, Annual Report on Form 20-F 2019

Definition and Limitations of Internal Control Over Financial Reporting

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.

/s/ Ernst & Young AS
Stavanger, Norway
19 March 2020

Equinor, Annual Report on Form 20-F 2019 167

CONSOLIDATED STATEMENT OF INCOME |  |  |  |
|  | Full year
(in USD million) | Note | 2019 | 2018 | 2017
Revenues | 3 | 62,911 | 78,555 | 60,971
Net income/(loss) from equity accounted investments | 12 | 164 | 291 | 188
Other income | 4 | 1,283 | 746 | 27
Total revenues and other income | 3 | 64,357 | 79,593 | 61,187
Purchases [net of inventory variation] |  | (29,532) | (38,516) | (28,212)
Operating expenses |  | (9,660) | (9,528) | (8,763)
Selling, general and administrative expenses |  | (809) | (758) | (738)
Depreciation, amortisation and net impairment losses | 10, 11 | (13,204) | (9,249) | (8,644)
Exploration expenses | 11 | (1,854) | (1,405) | (1,059)
Total operating expenses |  | (55,058) | (59,456) | (47,416)
Net operating income/(loss) | 3 | 9,299 | 20,137 | 13,771
Interest expenses and other financial expenses |  | (1,450) | (1,040) | (903)
Other financial items |  | 1,443 | (224) | 552
Net financial items | 8 | (7) | (1,263) | (351)
Income/(loss) before tax |  | 9,292 | 18,874 | 13,420
Income tax | 9 | (7,441) | (11,335) | (8,822)
Net income/(loss) |  | 1,851 | 7,538 | 4,598
Attributable to equity holders of the company |  | 1,843 | 7,535 | 4,590
Attributable to non-controlling interests |  | 8 | 3 | 8
Basic earnings per share (in USD) |  | 0.55 | 2.27 | 1.40
Diluted earnings per share (in USD) |  | 0.55 | 2.27 | 1.40
Weighted average number of ordinary shares outstanding (in millions) |  | 3,326 | 3,326 | 3,268
Weighted average number of ordinary shares outstanding, diluted (in millions) |  | 3,334 | 3,335 | 3,288

168 Equinor, Annual Report on Form 20-F 2019

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
|  | Full year
(in USD million) | Note | 2019 | 2018 | 2017
Net income/(loss) |  | 1,851 | 7,538 | 4,598
Actuarial gains/(losses) on defined benefit pension plans | 19 | 427 | (110) | 172
Income tax effect on income and expenses recognised in OCI1) |  | (98) | 22 | (38)
Items that will not be reclassified to the Consolidated statement of income |  | 330 | (88) | 134
Currency translation adjustments |  | (51) | (1,652) | 1,710
Net gains/(losses) from available for sale financial assets |  | 0 | 64 | (64)
Share of OCI from equity accounted investments | 12 | 44 | (5) | (40)
Items that may subsequently be reclassified to the Consolidated statement of income |  | (7) | (1,593) | 1,607
Other comprehensive income/(loss) |  | 323 | (1,681) | 1,741
Total comprehensive income/(loss) |  | 2,174 | 5,857 | 6,339
Attributable to the equity holders of the company |  | 2,166 | 5,855 | 6,331
Attributable to non-controlling interests |  | 8 | 3 | 8

1) Other Comprehensive Income (OCI).

Equinor, Annual Report on Form 20-F 2019 169

CONSOLIDATED BALANCE SHEET |  |  |
|  | At 31 December
(in USD million) | Note | 2019 | 2018
ASSETS |  |  |
Property, plant and equipment | 10, 22 | 69,953 | 65,262
Intangible assets | 11 | 10,738 | 9,672
Equity accounted investments | 12 | 1,442 | 2,863
Deferred tax assets | 9 | 3,881 | 3,304
Pension assets | 19 | 1,093 | 831
Derivative financial instruments | 26 | 1,365 | 1,032
Financial investments | 13 | 3,600 | 2,455
Prepayments and financial receivables | 13 | 1,214 | 1,033
Total non-current assets |  | 93,285 | 86,452
Inventories | 14 | 3,363 | 2,144
Trade and other receivables | 15 | 8,233 | 8,998
Derivative financial instruments | 26 | 578 | 318
Financial investments | 13 | 7,426 | 7,041
Cash and cash equivalents | 16 | 5,177 | 7,556
Total current assets |  | 24,778 | 26,056
Total assets |  | 118,063 | 112,508
EQUITY AND LIABILITIES |  |  |
Shareholders’ equity |  | 41,139 | 42,970
Non-controlling interests |  | 20 | 19
Total equity | 17 | 41,159 | 42,990
Finance debt | 18, 22 | 24,945 | 23,264
Deferred tax liabilities | 9 | 9,410 | 8,671
Pension liabilities | 19 | 3,867 | 3,820
Provisions and other liabilities | 20 | 17,951 | 15,952
Derivative financial instruments | 26 | 1,173 | 1,207
Total non-current liabilities |  | 57,346 | 52,914
Trade, other payables and provisions | 21 | 10,450 | 8,369
Current tax payable |  | 3,699 | 4,654
Finance debt | 18, 22 | 4,087 | 2,463
Dividends payable | 17 | 859 | 766
Derivative financial instruments | 26 | 462 | 352
Total current liabilities |  | 19,557 | 16,605
Total liabilities |  | 76,904 | 69,519
Total equity and liabilities |  | 118,063 | 112,508

170 Equinor, Annual Report on Form 20-F 2019

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
(in USD million) | Share capital | Additional paid-in capital | Retained earnings | Currency translation adjustments | OCI from equity accounted investments | Shareholders' equity | Non-controlling interests | Total equity
At 31 December 2016 | 1,156 | 6,607 | 32,573 | (5,264) | 0 | 35,072 | 27 | 35,099
Net income/(loss) |  |  | 4,590 |  |  | 4,590 | 8 | 4,598
Other comprehensive income/(loss) |  |  | 71 | 1,710 | (40) | 1,741 |  | 1,741
Total comprehensive income/(loss) |  |  |  |  |  |  |  | 6,339
Dividends | 24 | 1,333 | (2,891) |  |  | (1,534) |  | (1,534)
Other equity transactions |  | (8) | 0 |  |  | (8) | (10) | (18)
At 31 December 2017 | 1,180 | 7,933 | 34,342 | (3,554) | (40) | 39,861 | 24 | 39,885
Net income/(loss) |  |  | 7,535 |  |  | 7,535 | 3 | 7,538
Other comprehensive income/(loss) |  |  | (24) | (1,652) | (5) | (1,681) |  | (1,681)
Total comprehensive income/(loss) |  |  |  |  |  |  |  | 5,857
Dividends | 5 | 333 | (3,064) |  |  | (2,726) |  | (2,726)
Other equity transactions |  | (19) | 0 |  |  | (19) | (8) | (27)
At 31 December 2018 | 1,185 | 8,247 | 38,790 | (5,206) | (44) | 42,970 | 19 | 42,990
Net income/(loss) |  |  | 1,843 |  |  | 1,843 | 8 | 1,851
Other comprehensive income/(loss) |  |  | 330 | (51) | 44 | 323 |  | 323
Total comprehensive income/(loss) |  |  |  |  |  |  |  | 2,174
Dividends |  |  | (3,453) |  |  | (3,453) |  | (3,453)
Share buy-back |  | (500) |  |  |  | (500) |  | (500)
Other equity transactions |  | (15) | (29) |  |  | (44) | (7) | (52)
At 31 December 2019 | 1,185 | 7,732 | 37,481 | (5,258) | 0 | 41,139 | 20 | 41,159

Refer to note 17 Shareholders’ equity and dividends.

Equinor, Annual Report on Form 20-F 2019 171

CONSOLIDATED STATEMENT OF CASH FLOWS |  |  |  |
|  | Full year |
(in USD million) | Note | 2019 | 2018 | 2017
Income/(loss) before tax |  | 9,292 | 18,874 | 13,420
Depreciation, amortisation and net impairment losses | 10 | 13,204 | 9,249 | 8,644
Exploration expenditures written off | 11 | 777 | 357 | (8)
(Gains)/losses on foreign currency transactions and balances |  | (224) | 166 | (127)
(Gains)/losses on sale of assets and businesses | 4 | (1,187) | (648) | 395
(Increase)/decrease in other items related to operating activities |  | 1,016 | (526) | (884)
(Increase)/decrease in net derivative financial instruments | 26 | (595) | 409 | 19
Interest received |  | 215 | 176 | 148
Interest paid |  | (723) | (441) | (622)
Cash flows provided by operating activities before taxes paid and working capital items |  | 21,776 | 27,615 | 20,985
Taxes paid |  | (8,286) | (9,010) | (5,766)
(Increase)/decrease in working capital |  | 259 | 1,090 | (417)
Cash flows provided by operating activities |  | 13,749 | 19,694 | 14,802
Cash used in business combinations1) | 4 | (2,274) | (3,557) | 0
Capital expenditures and investments |  | (10,204) | (11,367) | (10,755)
(Increase)/decrease in financial investments |  | (1,012) | 1,358 | 592
(Increase)/decrease in derivative financial instruments |  | 298 | 238 | (439)
(Increase)/decrease in other interest bearing items |  | (10) | 343 | 79
Proceeds from sale of assets and businesses | 4 | 2,608 | 1,773 | 406
Cash flows used in investing activities |  | (10,594) | (11,212) | (10,117)
New finance debt | 18 | 984 | 998 | 0
Repayment of finance debt | 22 | (2,419) | (2,875) | (4,775)
Dividends paid | 17 | (3,342) | (2,672) | (1,491)
Share buy-back | 17 | (442) | 0 | 0
Net current finance debt and other |  | (277) | (476) | 444
Cash flows provided by/(used in) financing activities | 18 | (5,496) | (5,024) | (5,822)
Net increase/(decrease) in cash and cash equivalents |  | (2,341) | 3,458 | (1,137)
Effect of exchange rate changes on cash and cash equivalents |  | (38) | (292) | 436
Cash and cash equivalents at the beginning of the period (net of overdraft) | 16 | 7,556 | 4,390 | 5,090
Cash and cash equivalents at the end of the period (net of overdraft) | 16 | 5,177 | 7,556 | 4,390

1) Net after cash and cash equivalents acquired.

Cash and cash equivalents include bank overdrafts which were zero at 31 December 2019, 2018 and 2017.

Interest paid in cash flows provided by operating activities excludes capitalised interest of USD 480 million, USD 552 million and USD 454 million for the years ending 31 December 2019, 2018 and 2017, respectively. Capitalised interest is included in Capital expenditures and investments in cash flows used in investing activities.

##

172 Equinor, Annual Report on Form 20-F 2019

## Notes to the Consolidated financial statements

### 1 Organisation

Equinor 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.

Equinor ASA’s shares are listed on the Oslo Børs (OSL, Norway) and the New York Stock Exchange (NYSE, USA).

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

The Consolidated financial statements of Equinor for the full year 2019 were authorised for issue in accordance with a resolution of the board of directors on 16 March 2020.

### 2 Significant accounting policies

Statement of compliance

The Consolidated financial statements of Equinor ASA and its subsidiaries (Equinor) have been prepared in accordance with International Financial Reporting Standards (IFRSs) as adopted by the European Union (EU) and with IFRSs as issued by the International Accounting Standards Board (IASB), effective at 31 December 2019.

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. The policies described in this note are, unless otherwise noted, in effect at the balance sheet date. These policies have been applied consistently to all periods presented in these Consolidated financial statements, except as otherwise noted in disclosure related to the impact of policy changes following the adoption of new accounting standards and voluntary changes in 2019, and the adoption of IFRS 15 Revenue from Contracts with Customers and IFRS 9 Financial Instruments in 2018. Certain amounts in the comparable years have been restated to conform to current year presentation. The subtotals and totals in some of the tables in the notes may not equal the sum of the amounts shown in the primary financial statements 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 based on 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.

Changes in significant accounting policies in the current period

IFRS 16 Leases

With effect from 1 January 2019, Equinor implemented IFRS 16. Reference is made to Note 22 Leases and Note 23 Implementation of IFRS 16 Leases for further information about the standard, the policy and implementation choices made by Equinor, and the IFRS 16 implementation impact.

Other standard amendments and interpretations of standards

Other standard amendments or interpretations of standards effective as of 1 January 2019 and adopted by Equinor, were not material to Equinor’s Consolidated financial statements upon adoption.

Voluntary change in accounting policy (sales method)
With effect from 1 January 2019, Equinor changed the accounting policy for recognising revenue from the production of oil and gas properties in which Equinor shares an interest with other companies. Instead of recognising revenue based on Equinor’s ownership in producing fields, Equinor now recognises revenue on the basis of volumes lifted and sold to customers during the period (the sales method). This policy change was made due to the agenda decision in the IFRS Interpretations Committee (IFRIC) on the topic “Sale of output by a joint operator (IFRS 11)”, which was finalised in March 2019. The impact of this change on Equinor’s financial statements was not material.

Equinor, Annual Report on Form 20-F 2019 173

Standards, amendments to standards, and interpretations of standards, issued but not yet adopted

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

IFRS 3 Business Combinations amendments

The amendments to IFRS 3, issued in October 2018 and effective from 1 January 2020, introduce clarification to the definition of a business. The amendments also establish an optional test to identify a concentration of fair value that, if applied and met, would lead to the conclusion that an acquired set of activities and assets is not a business. The amendments are to be applied for relevant transactions that occur on or after the implementation date, and Equinor will implement the amendments accordingly.

Other standards, amendments to standards and interpretations of standards

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

Basis of consolidation

The Consolidated financial statements include the accounts of Equinor ASA and its subsidiaries and include Equinor’s interest in jointly controlled and equity accounted investments.

#### Subsidiaries

Entities are determined to be controlled by Equinor, and consolidated in Equinor's financial statements, when Equinor 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 Equinor's internal transactions, have been eliminated.

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 Equinor holds a long-term interest which is jointly controlled by Equinor 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, Equinor considers the nature of products and markets of the arrangements and whether the substance of their agreements is that the parties involved have rights to substantially all the arrangement's assets. Equinor accounts for its share of assets, liabilities, revenues and expenses in joint operations in accordance with the principles applicable to those particular assets, liabilities, revenues and expenses.

Acquisition of ownership shares in joint operations in which the activity constitutes a business, are accounted for in accordance with the requirements applicable to business combinations.

Those of Equinor'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 Equinor'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 Equinor's ownership share. Currently there are no significant differences in Equinor's accounting for unincorporated licence arrangements whether in scope of IFRS 11 or not.

Joint ventures, in which Equinor has rights to the net assets, are accounted for using the equity method. These currently include the majority of Equinor’s investments in the New Energy Solutions (NES) area, presented within the reportable segment ‘Other’.

Investments in companies in which Equinor has neither control nor joint control, but has the ability to exercise significant influence over operating and financial policies, as well as Equinor’s participation in joint arrangements that are joint ventures, are classified as Equity accounted investments. Under the equity method, the investment is carried on the balance sheet at cost plus post-acquisition changes in Equinor’s share of net assets of the entity, less distributions received and less any impairment in value of the investment. The part of an equity accounted investment’s dividend distribution exceeding the entity’s carrying amount in the consolidated balance sheet is reflected as income from equity accounted investments in the Consolidated statement of income. Equinor will subsequently only reflect the share of net profit in the investment that exceeds the dividend already reflected as income. Goodwill may arise as the surplus of the cost of investment over Equinor’s share of the net fair value of the identifiable assets and liabilities of the joint venture or associate. Such

174 Equinor, Annual Report on Form 20-F 2019

goodwill is recorded within the corresponding investment. The Consolidated statement of income reflects Equinor’s share of the results after tax of an equity-accounted entity, adjusted to account for depreciation, amortisation 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 applied into line with Equinor’s. Material unrealised gains on transactions between Equinor and its equity-accounted entities are eliminated to the extent of Equinor’s interest in each equity-accounted entity. Unrealised losses are also eliminated unless the transaction provides evidence of an impairment of the asset transferred. Equinor assesses investments in equity-accounted entities for impairment whenever events or changes in circumstances indicate that the carrying value may not be recoverable.

#### Equinor 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 business areas and Equinor 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 Equinor's share of the statement of income and balance sheet items related to Equinor operated joint operations and similar arrangements are reflected in the Consolidated statement of income and the Consolidated balance sheet. The accounting for lease contracts in joint operations or similar arrangements is described in further detail in Note 23 Implementation of IFRS 16 Leases, in the ‘Distinguishing operators and joint operators as lessees, including sublease considerations’ section, and depends on whether or not Equinor or all partners equally have the primary responsibility for the lease payments.

#### Reportable segments

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

Equinor'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, with the exception of IFRS 16 Leases. Note 3 Segments includes further information about lease accounting in the reportable segments.

#### 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. Loans from Equinor ASA to subsidiaries with other functional currencies than the parent company, and for which settlement is neither planned nor likely in the foreseeable future, are considered part of the parent company’s net investment in the subsidiary. Foreign exchange differences arising on such loans are recognised in Other comprehensive income (OCI) in the Consolidated financial statements.

#### Presentation currency

For the purpose of preparing 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 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

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
Equinor presents ‘Revenue from contracts with customers’ and ‘Other revenue’ as a single caption, Revenues, in the Consolidated statement of income.

Revenue from contracts with customers
Revenue from contracts with customers is recognised upon satisfaction of the performance obligations for the transfer of goods and services in each such contract. The revenue amounts that are recognised reflect the consideration to which Equinor expects to be entitled in exchange for those goods and services. Revenue from the sale of crude oil, natural gas, petroleum products and other

Equinor, Annual Report on Form 20-F 2019 175

merchandise is recognised when a customer obtains control of those products, which normally is when title passes at point of delivery, based on the contractual terms of the agreements. Each such sale normally represents a single performance obligation. In the case of natural gas, sales are completed over time in line with the delivery of the actual physical quantities.

Sales and purchases of physical commodities, when they are not settled net due to being deemed financial instruments or part of separate trading strategies, are presented on a gross basis as revenues from contracts with customers and purchases [net of inventory variation] in the statement of income. Sales of Equinor’s own produced oil and gas volumes are always reflected gross as revenue from contracts with customers.

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

Revenue is presented net of customs, excise taxes and royalties paid in-kind on petroleum products.

Other revenue

Items representing a form of revenue, or which are closely connected with revenue from contracts with customers, are presented as other revenue if they do not qualify as revenue from contracts with customers. These other revenue items include taxes paid in-kind under certain production sharing agreements (PSAs) and the net impact of commodity trading and commodity-based derivative instruments connected with sales contracts or revenue-related risk management.

Revenue from contracts with customers and Other revenue are presented as a single caption, Revenues, in the Consolidated statement of income.

#### Transactions with the Norwegian State

Equinor 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 from contracts with customers, respectively. Equinor 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. Natural gas sales made in the name of Equinor subsidiaries are also presented net of the SDFI’s share in the Consolidated statement of income, but this activity is reflected gross in the Consolidated balance sheet.

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 Equinor.

#### Research and development

Equinor undertakes research and development both on a funded basis for licence holders and on an unfunded basis for projects at its own risk. Equinor'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 most likely amount for probable 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, and on unused tax losses and credits carried forward, 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

176 Equinor, Annual Report on Form 20-F 2019

active markets, expected volatility of trading profits, expected currency rate movements and similar facts and circumstances. When an asset retirement obligation or a lease contract is initially reflected in the accounts, a deferred tax liability and a corresponding deferred tax asset are recognized simultaneously and accounted for in line with other deferred tax items.

#### Oil and gas exploration, evaluation and development expenditures

Equinor 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 discovery. 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 Equinor has made arrangements to fund a portion of the selling partner'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. Equinor reflects exploration and evaluation asset dispositions (farm-out arrangements) on a historical cost basis with no gain or loss recognition.

A gain 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 is recognised in full in other income in the Consolidated statement of income.

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. Contingent consideration included in the acquisition of an asset or group of similar assets is initially measured at its fair value, with later changes in fair value other than due to the passage of time reflected in the book value of the asset or group of assets, unless the asset is impaired. 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 Equinor. 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 fair value, primarily 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 Equinor, the expenditure is capitalised. Inspection and overhaul costs, associated with regularly scheduled major maintenance programmes 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

Equinor, Annual Report on Form 20-F 2019 177

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, Equinor 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 de-recognised 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 de-recognised.

#### 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, which is when 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

Following the implementation of IFRS 16 Leases on 1 January 2019, the accounting policies for lease accounting in Equinor have changed. Relevant accounting policies applied throughout 2019, including policy choices made, are described in Note 23 Implementation of IFRS 16 Leases.

#### 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.

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 (CGU), 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. In acquisitions made on a post-tax basis according to the rules on the NCS, a provision for deferred tax is reflected in the accounts based on the difference between the acquisition cost and the transferred tax depreciation basis. The offsetting entry to such deferred tax amounts is reflected as goodwill, which is allocated to the CGU or group of CGUs on whose tax depreciation basis the deferred tax has been computed.

#### Financial assets

Financial assets are initially recognised at fair value when Equinor 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, Equinor classifies its financial assets into the following three categories: Financial investments at amortised cost, at fair value through profit or loss, and at fair value through other comprehensive income based on an evaluation of the contractual terms and the business model applied. Certain long-term investments in other entities, which do not qualify for the equity method or consolidation, are included as at fair value through profit or loss.

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. Short-term highly liquid investments with original maturity exceeding 3 months are classified as current financial investments. Cash and cash equivalents and current financial investment are accounted for at amortised cost or at fair value through profit or loss.

Trade receivables are carried at the original invoice amount less a provision for doubtful receivables which represent expected losses computed on a probability-weighted basis.

178 Equinor, Annual Report on Form 20-F 2019

Equinor’s financial asset impairment losses are measured and recognised based on expected losses.

A part of Equinor's financial investments is managed together as an investment portfolio of Equinor'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 at fair value 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 Equinor 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.

Financial assets are de-recognised when assets are sold or the contractual rights expire, are redeemed, or cancelled. Gains and losses arising on the sale, settlement or cancellation of financial assets are recognised either in interest income and other financial items or in interest and other finance expenses within Net financial items.

#### Inventories

Commodity 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. Inventories of drilling and spare parts are reflected according to the weighted average method.

#### Impairment

Impairment of property, plant and equipment and intangible assets other than goodwill

Equinor 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 Equinor'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 Equinor’s estimate of the price that would be received for the asset in an orderly transaction between market participants. Such fair value estimates are mainly based on discounted cash flow models, using assumed market participants’ assumptions, but may also reflect market multiples observed from comparable market transactions or independent third-party valuations. Value in use is determined using a discounted cash flow model. The estimated future cash flows applied in establishing value in use 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 Equinor's most recently approved long-term forecasts. Updates of assumptions and economic conditions in establishing the long-term forecasts are reviewed by management on regular basis and updated at least annually. For assets and CGUs with an expected useful life or timeline for production of expected oil and natural gas reserves extending beyond 5 years, including planned onshore production from shale assets with a long development and production horizon, the forecasts reflect expected production volumes, and the related cash flows include project or asset specific estimates reflecting the relevant period. Such estimates are established based on Equinor's principles and assumptions and are 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 Equinor's post-tax weighted average cost of capital (WACC). The use of post-tax discount rates in determining value in use does not result in a materially different determination of the need for, or the amount of, impairment that would be required if pre-tax discount rates had been used.

Unproved oil and gas properties are assessed for impairment when facts and circumstances suggest that the carrying amount of the asset or CGU to which the unproved properties belong 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 in 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

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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. When impairment testing goodwill originally recognised as an offsetting item to the computed deferred tax provision in a post-tax transaction on the NCS, the remaining amount of the deferred tax provision will factor into the impairment evaluations. Once recognised, impairments of goodwill are not reversed in future periods.

#### Financial liabilities

Financial liabilities are initially recognised at fair value when Equinor 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 Equinor 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 Equinor'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 de-recognised 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.

Share buy-backs

Where Equinor has either acquired own shares under a share buy-back programme, or has placed an irrevocable order with a third party for Equinor shares to be acquired in the market, such shares are reflected as a reduction in equity as treasury shares. The remaining outstanding part of an irrevocable order to acquire shares is accrued for and classified as Trade, other payables and provisions.

Derivative financial instruments

Equinor 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 other revenues, as such derivative instruments are related to sales contracts or revenue-related risk management for all significant purposes. The impact of other derivative 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. Derivative financial instruments held for the purpose of being traded are however always classified as short term.

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 Equinor's expected purchase, sale or usage requirements, also referred to as own-use, are not accounted for as financial instruments. Such sales and purchases of physical commodity volumes are reflected in the statement of income as revenue from contracts with customers and purchases [net of inventory variation], respectively. 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.

For contracts to sell a non-financial item that can be settled net in cash, but which ultimately are physically settled despite not qualifying as own-use prior to settlement, the changes in fair value prior to settlement is included in gain/(loss) on commodity derivatives. The resulting impact upon physical settlement is shown separately and included in other revenues. Actual physical deliveries made by Equinor through such contracts are included in revenue from contracts with customers at contract price.

Derivatives embedded in host contracts which are not financial assets within the scope of IFRS 9 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

180 Equinor, Annual Report on Form 20-F 2019

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, Equinor 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.

#### Pension liabilities

Equinor 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.

Equinor'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.

Equinor'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 Equinor'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 within Net financial items. 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 Equinor ASA's functional currency being USD, the significant part of Equinor'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 Equinor ASA, are recognised as pension liabilities with the actual value of the notional contributions and promised return at reporting date. Notional contributions are recognised in the statement of income as periodic pension cost, while changes in fair value of notional assets are reflected in the statement of income under Net financial items.

Periodic pension cost is accumulated in cost pools and allocated to business areas and Equinor 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

Equinor 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 Equinor 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 Equinor's own credit risk. Normally an obligation arises for a new facility, such as

Equinor, Annual Report on Form 20-F 2019 181

an oil and natural gas production or transportation facility, upon construction or installation. An obligation may also arise 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 Equinor'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.

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 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 Equinor'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 Equinor in determining the fair values of assets and liabilities to the extent possible. Financial instruments quoted in active markets will typically include financial 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, Equinor 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 Equinor 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 Equinor 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, Equinor markets and sells the Norwegian State's share of oil and gas production from the NCS. Equinor includes the costs of purchase and proceeds from the sale of the SDFI oil production in purchases [net of inventory variation] and revenues from contracts with customers, respectively. In making the judgement, Equinor has considered whether it controls the State originated crude oil volumes prior to onwards sales to third party customers. Equinor directs the use of the volumes, and although certain benefits from the sales subsequently flow to the State, Equinor purchases the crude oil volumes from the State and obtains substantially all the remaining benefits. On that basis, Equinor has concluded that it acts as principal in these sales.

Equinor 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 Equinor's Consolidated financial statements. In making the judgement, Equinor concluded that ownership of the gas had not been transferred from the SDFI to Equinor. Although Equinor 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, Equinor is not considered the principal in the sale of the SDFI’s natural gas volumes.
Distinguishing between operators and joint operations as lessees in the application of IFRS 16 Leases

In implementing and applying IFRS 16 Leases, the matter of distinguishing between operators and joint operations as lessees, including sublease considerations, has been deemed critical. It involves a considerable degree of judgement with significant impact for the lease-related amounts recognised as assets and liabilities. This matter and the judgements involved are discussed in Note 23 Implementation of IFRS 16 Leases.

Acquisition accounting

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, and the conclusion may materially affect the financial statements both in the transaction period and in terms of future periods’ operating income. 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.

182 Equinor, Annual Report on Form 20-F 2019

Equinor applies the acquisition method for transactions involving business combinations, and applies the requirements applicable to the acquisition method when an interest or an additional interest is acquired in a joint operation which constitutes a business. Application of the acquisition method for business combinations may in itself require significant judgement in applying accounting policies in, among other matters, determining and measuring the full transaction consideration including contingent consideration elements, identifying all tangible and intangible assets acquired as well as liabilities assumed, establishing their fair values, determining deferred tax elements, and allocating the purchase price accordingly, including measurement and allocation of goodwill.

#### 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 when these 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.

Equinor 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, Equinor'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 that have a significant risk of resulting in a material adjustment to the carrying amounts of assets and liabilities within the next financial year, and therefore may most significantly impact the amounts reported on the results of operations and the financial position.

#### Proved oil and gas reserves

Proved oil and gas reserves may materially impact the carrying amounts of producing oil and gas assets, particularly for assets in the later stages of their useful lives, 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 are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations. Unless evidence indicates that renewal is reasonably certain, estimates of economically producible reserves only reflect the period before the contracts providing the right to operate expire. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence within a reasonable time.

Proved reserves are divided into proved developed and proved undeveloped reserves. Proved developed reserves are to be recovered through existing wells with existing equipment and operating methods, or where the cost of the required equipment is relatively minor compared to the cost of a new well. Proved undeveloped reserves are to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major capital expenditure is required for recompletion. Undrilled well locations can be classified as having proved undeveloped reserves if a development plan is in place indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time horizon. Specific circumstances are for instance fields which have large up-front investments in offshore infrastructure, such as many fields on the NCS, where drilling of wells is scheduled to continue for much longer than five years. For unconventional reservoirs where continued drilling of new wells is a major part of the investments, such as the US onshore assets, the proved reserves are always limited to proved well locations scheduled to be drilled within five years.

Proved oil and gas reserves have been estimated by internal qualified professionals on the basis of industry standards and are governed by the oil and gas rules and disclosure requirements in the U.S. Securities and Exchange Commission (SEC) regulations S-K and S-X, and the Financial Accounting Standards Board (FASB) requirements for supplemental oil and gas disclosures. The estimates have been based on a 12-month average product price and on existing economic conditions and operating methods as required, and recovery of the estimated quantities have a high degree of certainty (at least a 90% probability).

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 availability of the technical and economic data and the efficiency of extracting and processing the hydrocarbons. An independent third party has evaluated Equinor's proved reserves estimates, and the results of this evaluation do not differ materially from Equinor's estimates.

#### Expected oil and gas reserves

Expected oil and gas reserves may materially impact the carrying amounts of oil and gas assets, deferred tax assets, and certain related liabilities. Changes in the expected reserves, for instance as a result of changes in prices, will impact the amounts of asset retirement obligations and impairment testing of upstream assets, which in turn may lead to changes in impairment charges affecting operating

Equinor, Annual Report on Form 20-F 2019 183

income and the carrying value of upstream assets. Expected oil and gas reserves are the estimated remaining, commercially recoverable quantities, based on Equinor's judgement of future economic conditions, from projects in operation or decided 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 classified in accordance with the Norwegian resource classification system issued by the Norwegian Petroleum Directorate, 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. Such estimates are inherently less reliable in early field life or where the available data is limited following a recently implemented change in the method of production.

For unconventional reservoirs the expected reserves are the recoverable oil and gas quantities associated with production from both existing wells and continued drilling of future wells, not limited to proved locations only. In general, the reserve volumes in these reservoirs are therefore more dependent on future capital expenditures, compared to conventional fields with larger up-front investments in central facilities. Future development of the unconventional reservoirs and the resulting reserves can therefore more easily be adjusted as expectations of future commodity prices change, through removing or adding future wells to the drilling schedule.

#### Exploration and leasehold acquisition costs

Equinor capitalises the costs of drilling exploratory wells pending determination of whether the wells have found proved oil and gas reserves. Equinor 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, be de-recognised or written down in the period may materially affect the carrying values of these assets and consequently, the operating income for the period.

Impairment/reversal of impairment

Equinor 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 its 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 expected cash flow approach is applied to reflect uncertainties in timing and amount inherent in the assumptions used in the estimated future cash flows.

Unproved oil and gas properties are assessed for impairment when facts and circumstances suggest that the carrying amount of the relevant asset or CGU 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.

Where recoverable amounts are based on estimated future cash flows, reflecting Equinor’s or market participants’ assumptions about the future and discounted to their present value, the estimates involve complexity. 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, impact of the timing of tax incentive regulations, 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.

Asset retirement obligations

Equinor has significant obligations to decommission and remove offshore installations at the end of the production period. Establishing the appropriate provisions for such obligations involve the application of considerable judgement and involve an inherent risk of significant adjustments. 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. Moreover, changes in the discount rate and currency exchange rates may impact the estimates significantly. As a result, the initial

184 Equinor, Annual Report on Form 20-F 2019

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.

#### Income tax

Every year Equinor 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. There may be uncertainties related to interpretations of applicable tax laws and regulations regarding amounts in Equinor’s tax returns, which are filed in a considerable number of tax regimes. For cases of uncertain tax treatments it may take several years to complete the discussions with relevant tax authorities or to reach resolutions of the appropriate tax positions through litigation.

The carrying values of income tax related assets and liabilities are based on Equinor's interpretations of applicable laws, regulations and relevant court decisions. The quality of these estimates, including the most likely outcomes of uncertain tax treatments, 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.

#### The Covid-19 virus pandemic

The coronavirus (Covid-19) pandemic has been declared a global emergency by the World Health Organisation (WHO), and has made countries, organisations and Equinor take measures to mitigate risk for communities, employees and business operations. The pandemic continues to progress and evolve, and at this juncture it is challenging to predict the full extent and duration of resulting operational and economic impact for Equinor. A continued development of the pandemic and mitigating actions enforced by health authorities create uncertainty related to key assumptions applied in the valuation of our assets and measurement of our liabilities. These key assumptions include commodity prices, changes to demand for and supply of oil and gas, and the discount rate to be applied.

### 3 Segments

Equinor’s operations are managed through the following operating segments (business areas): Development & Production Norway (DPN), Development & Production Brazil (DPB), Development & Production International (DPI), Marketing, Midstream & Processing (MMP), New Energy Solutions (NES), Technology, Projects & Drilling (TPD), Exploration (EXP) and Global Strategy & Business Development (GSB).

The development and production business areas are responsible for the commercial development of the oil and gas portfolios within their respective geographical areas: DPN on the Norwegian continental shelf, DPB in Brazil and DPI worldwide outside of DPN and DPB.

Exploration activities are managed by a separate business area, 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 business areas.

TPD is responsible for the global project portfolio, well delivery, new technology and sourcing across Equinor. The activities are allocated and presented in the respective business areas receiving the deliveries.

The MMP business area 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 business area is responsible for wind parks, carbon capture and storage as well as other renewable energy and low-carbon energy solutions.

The business areas DPI and DPB are aggregated into the reporting segment Exploration & Production International (E&P International). The aggregation has its basis in similar economic characteristics, such as the assets’ long term and capital-intensive nature and exposure to volatile oil and gas commodity prices, the nature of products, service and production processes, the type and class of customers, the methods of distribution and regulatory environment. The reporting segments Exploration & Production Norway (E&P Norway) and MMP consists of the business areas DPN and MMP respectively. The business areas NES, GSB, TPD, EXP and corporate staffs and support functions are aggregated into the reporting segment “Other” due to the immateriality of these areas. The majority of costs within the business areas GSB, TPD and EXP are allocated to the E&P International, E&P Norway and MMP reporting segments.

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 2019, 2018 and 2017 are presented below. The measurement basis of segment profit is n et operating income/(loss). In the tables below, deferred tax assets, pension assets and non-current financial assets are not allocated to the segments.

Equinor, Annual Report on Form 20-F 2019 185

The measurement basis for segments is IFRS as applied by the group with the exception of IFRS 16 Leases and the line item Additions to property, plant and equipment (PP&E), intangibles and equity accounted investments. All IFRS 16 leases are presented within the Other segment. The lease costs for the period are allocated to the different segments based on underlying lease payments, with a corresponding credit in the Other segment. Lease costs allocated to licence partners are recognised as other revenue in the Other segment. Additions to PP&E, intangible assets and equity accounted investments in the E&P and MMP segments include the period’s allocated lease costs related to activity being capitalised with a corresponding negative addition in the Other segment. The line item Additions to property, plant and equipment (PP&E), intangibles and equity accounted investments excludes movements related to changes in asset retirement obligations .

(in USD million) | E&P Norway | E&P International | MMP | Other | Eliminations | Total
Full year 2019 |  |  |  |  |  |
Revenues third party, other revenues and other income | 1,048 | 2,127 | 60,491 | 527 | 0 | 64,194
Revenues inter-segment | 17,769 | 8,168 | 439 | 4 | (26,379) | 0
Net income/(loss) from equity accounted investments | 15 | 30 | 25 | 93 | 0 | 164
Total revenues and other income | 18,832 | 10,325 | 60,955 | 624 | (26,379) | 64,357
Purchases [net of inventory variation] | (1) | (34) | (54,454) | (1) | 24,958 | (29,532)
Operating, selling, general and administrative expenses | (3,284) | (3,352) | (4,897) | 272 | 793 | (10,469)
Depreciation, amortisation and net impairment losses | (5,439) | (6,361) | (600) | (804) | 0 | (13,204)
Exploration expenses | (478) | (1,377) | 0 | 0 | 0 | (1,854)
Total operating expenses | (9,201) | (11,124) | (59,951) | (533) | 25,750 | (55,058)
Net operating income/(loss) | 9,631 | (800) | 1,004 | 92 | (629) | 9,299
Additions to PP&E, intangibles and equity accounted investments | 7,316 | 5,855 | 788 | 823 | 0 | 14,782
Balance sheet information |  |  |  |  |  |
Equity accounted investments | 3 | 321 | 90 | 1,028 | 0 | 1,442
Non-current segment assets | 33,795 | 37,558 | 5,124 | 4,214 | 0 | 80,691
Non-current assets, not allocated to segments |  |  |  |  |  | 11,152
Total non-current assets |  |  |  |  |  | 93,285

186 Equinor, Annual Report on Form 20-F 2019

(in USD million) | E&P Norway | E&P International | MMP | Other | Eliminations | Total
Full year 2018 |  |  |  |  |  |
Revenues third party, other revenues and other income | 588 | 3,181 | 75,487 | 45 | 0 | 79,301
Revenues inter-segment | 21,877 | 9,186 | 291 | 2 | (31,355) | 0
Net income/(loss) from equity accounted investments | 10 | 31 | 16 | 234 | 0 | 291
Total revenues and other income | 22,475 | 12,399 | 75,794 | 280 | (31,355) | 79,593
Purchases [net of inventory variation] | 2 | (26) | (69,296) | (0) | 30,805 | (38,516)
Operating, selling, general and administrative expenses | (3,270) | (3,006) | (4,377) | (288) | 653 | (10,286)
Depreciation, amortisation and net impairment losses | (4,370) | (4,592) | (215) | (72) | 0 | (9,249)
Exploration expenses | (431) | (973) | 0 | 0 | 0 | (1,405)
Total operating expenses | (8,069) | (8,597) | (73,888) | (360) | 31,458 | (59,456)
Net operating income/(loss) | 14,406 | 3,802 | 1,906 | (79) | 103 | 20,137
Additions to PP&E, intangibles and equity accounted investments | 6,947 | 7,403 | 331 | 519 | 0 | 15,201
Balance sheet information |  |  |  |  |  |
Equity accounted investments | 1,102 | 296 | 92 | 1,373 | 0 | 2,863
Non-current segment assets | 30,762 | 38,672 | 5,148 | 353 | 0 | 74,934
Non-current assets, not allocated to segments |  |  |  |  |  | 8,655
Total non-current assets |  |  |  |  |  | 86,452

Equinor, Annual Report on Form 20-F 2019 187

(in USD million) | E&P Norway | E&P International | MMP | Other | Eliminations | Total
Full year 2017 |  |  |  |  |  |
Revenues third party, other revenues and other income | (23) | 1,984 | 58,935 | 102 | 0 | 60,999
Revenues inter-segment | 17,586 | 7,249 | 83 | 1 | (24,919) | 0
Net income/(loss) from equity accounted investments | 129 | 22 | 53 | (16) | 0 | 188
Total revenues and other income | 17,692 | 9,256 | 59,071 | 87 | (24,919) | 61,187
Purchases [net of inventory variation] | 0 | (7) | (52,647) | (0) | 24,442 | (28,212)
Operating, selling, general and administrative expenses | (2,954) | (2,804) | (3,925) | (235) | 418 | (9,501)
Depreciation, amortisation and net impairment losses | (3,874) | (4,423) | (256) | (91) | 0 | (8,644)
Exploration expenses | (379) | (681) | 0 | 0 | 0 | (1,059)
Total operating expenses | (7,207) | (7,915) | (56,828) | (326) | 24,860 | (47,416)
Net operating income /(loss) | 10,485 | 1,341 | 2,243 | (239) | (59) | 13,771
Additions to PP&E, intangibles and equity accounted investments | 4,869 | 5,063 | 320 | 543 | 0 | 10,795
Balance sheet information |  |  |  |  |  |
Equity accounted investments | 1,133 | 234 | 134 | 1,050 | 0 | 2,551
Non-current segment assets | 30,278 | 36,453 | 5,137 | 390 | 0 | 72,258
Non-current assets, not allocated to segments |  |  |  |  |  | 9,102
Total non-current assets |  |  |  |  |  | 83,911

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

See note 10 Property, plant and equipment for further information on impairment losses and impairment reversals that affect the different segments.

See note 11 Intangible assets for information on impairment losses and impairment reversals that affect the different segments.

See note 24 Other commitments, contingent liabilities and contingent assets for information on contingencies that affect the segments.

### Revenues from contracts with customers by geographical areas

Equinor has business operations in more than 30 countries. When attributing the line item Revenues third party, other revenue and other income to the country of the legal entity executing the sale for 2019, Norway constitutes 75% and the US constitutes 18%. For 2018 the revenues to Norway and US constituted 75% and 18% respectively and for 2017 74% and 17% respectively.

188 Equinor, Annual Report on Form 20-F 2019

Non-current assets by country |  |  |
| At 31 December
(in USD million) | 2019 | 2018 | 2017
Norway | 40,292 | 34,952 | 34,588
USA | 17,776 | 19,409 | 19,267
Brazil | 8,724 | 7,861 | 4,584
UK | 5,657 | 4,588 | 4,222
Canada | 1,672 | 1,546 | 1,715
Azerbaijan | 1,598 | 1,452 | 1,472
Angola | 1,564 | 1,874 | 2,888
Denmark | 984 | 407 | 266
Tanzania | 964 | 957 | 960
Algeria | 915 | 986 | 1,114
Other countries | 1,986 | 3,764 | 3,732
Total non-current assets1) | 82,133 | 77,797 | 74,809

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

Revenues from contracts with customers and other revenues
(in USD million) | 2019 | 2018 | 2017
Crude oil | 33,505 | 40,948 | 29,519
Natural gas1) | 11,281 | 14,070 | 11,420
- European gas | 9,366 | 11,675 | 9,739
- North American gas | 1,359 | 1,581 | 1,248
- Other incl LNG | 556 | 814 | 433
Refined products | 10,652 | 13,124 | 11,423
Natural gas liquids | 5,807 | 7,167 | 5,647
Transportation | 967 | 1,033 |
Other sales | 445 | 903 | 2,963
Total revenues from contracts with customers | 62,657 | 77,246 | 60,971
Over/Under lift |  | 137 |
Taxes paid in-kind | 344 | 865 |
Physically settled commodity derivatives2) | (1,086) | 488 |
Gain/(loss) on commodity derivatives | 732 | (216) |
Other revenues | 265 | 36 |
Total other revenues | 254 | 1,309 |
Revenues | 62,911 | 78,555 | 60,971
1) Retrospectively applied the disaggregation of Natural gas revenues. |  |  |
2) Retrospectively reclassified Physically settled commodity derivatives to Total other revenues, previously presented as Natural gas revenues included in Total revenues from contracts with customers.
For 2017 the transportation element included in sales transactions with customers are included in Crude Oil, Refined Products and Natural Gas Liquids. Other transportation was included in other sales. For 2018 and 2019, these elements are included in Transportation. The elements included in Total other revenues were for 2017 included in other sales.

###

Equinor, Annual Report on Form 20-F 2019 189

### 4 Acquisitions and disposals

2019

Acquisition of interest in Rosebank project in UK

In the first quarter of 2019 Equinor closed an agreement to acquire Chevron’s 40% operated interest in the Rosebank project. A cash consideration of USD 71 million was paid on the closing date and is subject to final adjustment. The payment of the remaining consideration is subject to certain conditions being met and was reflected at fair value at the transaction date. The transaction represents an asset purchase. The fair value of the acquired exploration asset has been recognised in the Exploration & Production International (E&P International) segment.

Acquisition of 100% shares in Danske Commodities

In the first quarter of 2019 Equinor closed an agreement to acquire 100% of the shares in a Danish energy trading company Danske Commodities (DC) for a cash consideration of EUR 465 million (USD 535 million). In addition, Equinor recognised an insignificant liability for contingent consideration depending on DC’s performance measured at the fair value on the transaction date. The assets and liabilities related to the acquired business have been reflected according to IFRS 3 Business Combinations. The acquisition resulted in an increase of Equinor’s non-current assets of USD 13 million, current assets of USD 836 million, current liabilities of USD 749 million, and deferred tax liability of USD 2 million. The transaction has been accounted for in the Marketing, Midstream & Processing (MMP) segment and resulted in goodwill of USD 437 million reflecting the expected synergies on the acquisition and competence and access to the energy markets. In the fourth quarter of 2019, the purchase price allocation was finalised with no significant change compared to initial recognition.

Acquisition of offshore wind lease in USA

In the first quarter of 2019 Equinor paid a winning bid of USD 135 million in an auction for the rights to develop a wind farm within an offshore wind lease OCS-A 0520, in an area offshore the Commonwealth of Massachusetts. The transaction was accounted for as an asset acquisition. Upon completion the acquisition was recognised in the Other segment as an increase in the intangible assets.

Swap of interests in the Norwegian Sea and the North Sea region of the Norwegian continental shelf

In the second quarter of 2019 Equinor and Faroe Petroleum closed a swap transaction in the Norwegian Sea and the North Sea region of the Norwegian continental shelf (NCS) with no cash effect at the effective date. The effective date of the swap transaction is 1 January 2019. The assets and liabilities related to the acquired interests have been reflected in accordance with the principles of IFRS 3 Business Combinations. The acquisition resulted in increased assets of USD 280 million, including goodwill of USD 82 million, and increased liabilities of USD 97 million. In the third quarter of 2019 the purchase price allocation was finalised with no significant change compared to initial recognition. A gain of USD 137 million on the divested interests has been presented in the line item Other income in the Consolidated statement of income. The transactions were tax-exempted and have been accounted for in the E&P Norway segment.

Acquisition and divestment of operated interest in the Bacalhau (formerly Carcará) field in Brazil

In the second quarter of 2019 Equinor and Barra Energia (“Barra”) closed an agreement for Equinor to acquire Barra’s 10% interest in the BM-S-8 licence in Brazil’s Santos basin. Upon closing, Equinor sold 3.5% to ExxonMobil and 3% to Galp, fully aligning interests across BM-S-8 and Bacalhau (formerly Carcará North). The total consideration for Barra’s 10% interest was USD 415 million, and the transaction was accounted for as an asset acquisition. The total consideration for divested interests is on the same terms as the invested interest and amounts to USD 269 million. The value of the net acquired exploration assets resulted in an increase in intangible assets of USD 146 million at the date of transactions. The net cash payment from the transactions is USD 101 million. The transactions have been accounted for in the E&P International segment.

Acquisition of interest in the Caesar Tonga field in the Gulf of Mexico

In the third quarter of 2019 Equinor received governmental approval and closed a deal to acquire preferential rights to an additional 22.45% interest in the Caesar Tonga oil field from Shell Offshore Inc. The total consideration, including interim period settlement, was USD 813 million in cash. The assets and liabilities related to the acquired interests have been reflected in accordance with the principles of IFRS 3 Business Combinations. The acquisition resulted in increased assets of USD 850 million and increased liabilities of USD 37 million. The transaction increased Equinor’s interest in the field from 23.55% to 46.00%. The transaction was recognised in the E&P International segment.

Acquisition of interest in the Johan Sverdrup field and divestment of Lundin Petroleum AB shares

In the third quarter of 2019 Equinor closed a deal to divest a 16% shareholding in Lundin Petroleum AB (Lundin) for a direct interest of 2.6% in the Johan Sverdrup field in addition to a cash consideration. The consideration for the Lundin shares was SEK 14,510 million (USD 1,508 million) at the closing date, while the consideration for the Johan Sverdrup interest was USD 981 million including interim period settlement.

On 5 August 2019 the divestment of the shares in Lundin was closed, and Equinor recognised a gain of USD 837 million including recycling of other comprehensive income and a fair value adjustment of the remaining 4.9% shares (subsequent to Lundin redeeming the acquired shares). The gain on the divested interest is presented in the line item Other income in the E&P Norway segment.

190 Equinor, Annual Report on Form 20-F 2019

After the divestment the remaining investment in Lundin is recognised at fair value through profit and loss and classified as non-current financial investment in the balance sheet.

On 30 August 2019 the acquisition of 2.6% of the Johan Sverdrup field was closed. The acquired interest has been reflected in accordance with the principles of IFRS 3 Business Combinations. The acquisition resulted in increased assets of USD 1,580 million, including goodwill of USD 612 million, increased deferred tax of USD 612 million and other changes of USD 13 million. The acquisition has been accounted for in the E&P Norway segment.

Both transactions were tax-exempted.

Divestment of interest in Arkona offshore windfarm

In the fourth quarter of 2019, Equinor closed an agreement to sell a 25% ownership interest in the AWE-Arkona-Windpark Entwicklunds-GMBH to EIP Offshore Wind Germany I Holding GMBH for a total amount of EUR 475 million (USD 526 million) including interim period settlement. Following the transaction, Equinor retains a 25% interest in the Arkona offshore windfarm. RWE Renewables will remain the operator with a 50% interest. A gain of USD 212 million has been presented in the line item Other income in the Consolidated statement of income in the Other segment.

Divestment of interest in Eagle Ford asset in the onshore USA

In the fourth quarter of 2019, Equinor closed an agreement to sell all its interests in the Eagle Ford onshore asset as well as all of Equinor’s shares in Edwards Lime Gathering LLC for a consideration of USD 352 million. An immaterial loss has been presented in the line item Operating expenses in the Consolidated statement of income. The loss on sale is presented in the E&P International segment.

Investment of interest onshore Argentina

On 18 December 2019 Equinor entered into an agreement to acquire a 50% interest in SPM Argentina S.A (SPM) from Schlumberger Production Management Holding Argentina B.V. SPM holds a 49% interest in the Bandurria Sur onshore block in Argentina, and the block is in the late pilot phase of development. The consideration before adjustments is USD 177,5 million. The consideration will be adjusted for cash flows, including cash flows related to working capital and debt, from 1 January 2020 until closing. Upon closing, the acquisition is expected to be accounted for by using the equity method. Closing is expected in the first quarter of 2020 and the investment will be accounted for in the E&P International segment.

2018

Acquisition of interests in Martin Linge field and Garantiana discovery

In the first quarter of 2018 Equinor and Total closed an agreement to acquire Total’s equity stakes in the Martin Linge field (51%) and the Garantiana discovery (40%) on the NCS. Through this transaction Equinor increased the ownership share in the Martin Linge field from 19% to 70%. Equinor has paid Total a consideration of USD 1,541 million and has taken over the operatorships. The assets and liabilities related to the acquired portion of Martin Linge and Garantiana have been reflected in accordance with the principles of IFRS 3 Business Combinations. The acquisition resulted in an increase of Equinor’s property, plant and equipment of USD 1,418 million, intangible assets of USD 116 million, goodwill of USD 265 million, deferred tax liabilities of USD 265 million and other assets of USD 7 million. The partners have joint control and Equinor continues to account for its interest on a pro-rata basis using Equinor's new ownership share. The transaction has been accounted for in the E&P Norway segment.

Acquisition of Cobalt’s North Platte interest in the Gulf of Mexico

In the first quarter of 2018 Equinor’s co-bid with Total in the bankruptcy auction for Cobalt’s interest in the North Platte discovery was successful with an aggregate bid of USD 339 million. The transaction was closed in April 2018. Upon closing, Total as operator owns 60% of North Platte and Equinor owns the remaining 40%. The value of the acquired exploration assets has been recognised in the E&P International segment for an amount of USD 246 million as intangible assets. Additionally, the transaction includes a contingent consideration up to USD 20 million.

Acquisition of interest in Roncador field in Brazil

In the second quarter of 2018 Equinor closed an agreement with Petrobras to acquire a 25% interest in Roncador, an oil field in the Campos Basin in Brazil. Equinor paid Petrobras a cash consideration of USD 2,133 million, in addition to recognising a liability for contingent consideration of USD 392 million. The assets and liabilities related to the acquired portion of Roncador have been reflected in accordance with the principles of IFRS 3 Business Combinations. The acquisition resulted in an increase of Equinor’s property, plant and equipment of USD 2,550 million, intangible assets of USD 392 million and an increase in provisions of USD 808 million. In the second quarter of 2019 the purchase price allocation was finalised with no significant change compared to initial recognition. The partners have joint control and Equinor will account for its interest on a pro-rata basis. The transaction has been accounted for in the E&P International segment.

Acquisition and divestment of operated interest in Bacalhau (formerly Carcará) field in Brazil

In the fourth quarter of 2016 Equinor acquired a 66% operated interest in the Brazilian offshore licence BM-S-8 in the Santos basin from Petróleo Brasileiro S.A. (“Petrobras”). The value of the acquired exploration assets resulted in an increase in intangible assets of USD 2,271 million at the transaction date.

Equinor, Annual Report on Form 20-F 2019 191

In the fourth quarter of 2017, a consortium comprising Equinor (operator, 40%), ExxonMobil (40%) and Galp (20%) presented the winning bid (67.12% of profit oil) for the Bacalhau (formerly Carcará North) block in the Santos basin. Equinor’s share of the pre-determined signature bonus paid by the consortium in December 2017 was USD 350 million and was recognised as an intangible asset.

In the fourth quarter of 2017 Equinor acquired Queiroz Galvão Exploração e Produção (“QGEP”)’s 10% interest in licence BM-S-8 in Brazil’s Santos basin increasing the operated interest to 76%. The value of the acquired exploration assets resulted in an increase in intangible assets of USD 362 million at the transaction date.

In the second quarter of 2018 Equinor completed the divestment of 39.5% of its 76% interest in BM-S-8, agreed in October 2017. 36.5% interest was divested to ExxonMobil and 3% to Galp for a total consideration of USD 1,493 million. The transaction is accounted for with no impact on the Consolidated statement of income. The cash proceeds from the sale were USD 1,016 million. The transactions are accounted for in the E&P International segment.

Divestment of interests in discoveries on the Norwegian continental shelf

In the fourth quarter of 2018 Equinor closed an agreement with Aker BP to sell its 77.8% operated interest in the King Lear discovery on the Norwegian continental shelf (NCS) for a total consideration of USD 250 million and an agreement with PGNiG to sell its non-operated interests in the Tommeliten discovery on the NCS for a total consideration of USD 220 million. A gain of USD 449 million has been presented in the line item Other income in the Consolidated statement of income in the E&P Norway segment. The transaction was tax exempt under the Norwegian petroleum tax legislation.

2017

Sale of interest in Kai Kos Dehseh

In the first quarter of 2017 Equinor closed an agreement with Athabasca Oil Corporation to divest its 100% interest in Kai Kos Dehseh (KKD) oil sands. The total consideration consisted of cash consideration of CAD 431 million (USD 328 million), 100 million common shares in Athabasca Oil Corporation and a series of contingent payments, measured at a combined fair value of CAD 185 million (USD 142 million) on the closing date. A loss on the transaction of USD 351 million was recognised as operating expense and included a reclassification of accumulated foreign exchange losses, previously recognised in other comprehensive income/(loss). The transaction was reflected in the E&P International segment.

Extension of the Azeri-Chirag-Deepwater Gunashli production sharing agreement

In the third quarter of 2017 the Azeri-Chirag-Deepwater Gunashli (ACG) production sharing agreement was extended by 25 years. The transaction was recognised in the E&P International segment in the fourth quarter of 2017, following ratification by the Parliament (Milli Majlis) of the Republic of Azerbaijan. As part of the new agreement, Equinor’s participating interest was adjusted to 7.27% down from 8.56%. Equinor's share of a total payment of USD 3.6 billion to the State Oil Fund of the Republic of Azerbaijan will be approximately USD 349 million to be paid over a period of 8 years.

### 5 Financial risk and capital management

General information relevant to financial risks

Equinor's business activities naturally expose Equinor to financial risk. Equinor’s approach to risk management includes assessing and managing risk in all activities using a holistic risk approach. Equinor consider correlations between the most important market risks and the natural hedges inherent in Equinor’s portfolio. This approach allows Equinor to reduce the number of risk management transactions and avoid sub-optimisation.

The corporate risk committee, which is headed by the chief financial officer, is responsible for defining, developing and reviewing Equinor’s risk policies. The chief financial officer, assisted by the committee, is also responsible for overseeing and developing Equinor’s Enterprise Risk Management and proposing appropriate measures to adjust risk at the corporate level.

Mandates in the trading organisations within crude oil, refined products, natural gas and electricity are relatively small compared to the total market risk of Equinor.

Financial risks

Equinor’s activities expose Equinor to m arket risk (including commodity price risk, currency risk, interest rate risk and equity price risk), liquidity risk and c redit risk.

Market risk

Equinor 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 Equinor 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.

192 Equinor, Annual Report on Form 20-F 2019

For more information on sensitivity analysis of market risk see note 26 Financial instruments: fair value measurement and sensitivity analysis of market risk.

Commodity price risk

Equinor’s most important long-term commodity risk (oil and natural gas) is related to future market prices as Equinor´s risk policy is to be exposed to both upside and downside price movements. To manage short-term commodity risk, Equinor 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. Equinor’s bilateral gas sales portfolio is exposed to various price indices with a combination of 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

Equinor’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 and a share of our operating expenses and capital expenditures are in NOK. Accordingly, Equinor’s currency management is primarily linked to mitigate currency risk related to payments in NOK. This means that Equinor 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. Equinor 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 Equinor’s long-term debt portfolio see note 18 Finance debt.

Equity price risk

Equinor’s captive insurance company holds listed equity securities as part of its portfolio. In addition, Equinor holds some other listed and non-listed equities mainly for long-term strategic purposes. By holding these assets Equinor is exposed to equity price risk, defined as the risk of declining equity prices, which can result in a decline in the carrying value of Equinor’s assets recognised in the balance sheet. The equity price risk in the portfolio held by Equinor’s captive insurance company is managed, with the aim of maintaining a moderate risk profile, through geographical diversification and the use of broad benchmark indexes.

Liquidity risk

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

The main cash outflows include 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.

Short-term funding needs will normally be covered by the USD 5.0 billion US Commercial paper programme (CP) which is backed by a revolving credit facility of USD 5.0 billion, supported by 21 core banks, maturing in 2022. The facility supports secure access to funding, supported by the best available short-term rating. As at 31 December 2019 the facility has not been drawn.

Equinor raises debt in all major capital markets (US, Europe and Asia) for long-term funding purposes. The policy is to have a maturity profile with repayments not exceeding 5% of capital employed in any year for the nearest five years. Equinor’s non-current financial liabilities have a weighted average maturity of approximately nine years.

For more information about Equinor’s non-current financial liabilities see note 18 Finance debt.

Equinor, Annual Report on Form 20-F 2019 193

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

| At 31 December
| 2019 | 2018
(in USD million) | Non-derivative financial liabilities | Lease liabilities | Derivative financial liabilities | Non-derivative financial liabilities | Lease liabilities | Derivative financial liabilities
Year 1 | 13,388 | 1,210 | 204 | 11,958 | 61 | 271
Year 2 and 3 | 4,370 | 1,483 | 606 | 5,504 | 120 | 677
Year 4 and 5 | 6,238 | 673 | 175 | 4,919 | 123 | 203
Year 6 to 10 | 8,449 | 892 | 479 | 10,611 | 150 | 611
After 10 years | 10,567 | 349 | 370 | 9,570 | 48 | 725
Total specified | 43,012 | 4,607 | 1,835 | 42,562 | 502 | 2,488

The comparison numbers related to lease liabilities relates to finance leases according to IAS 17, for more information see note 23 Implementation of IFRS 16 Leases to the Consolidated financial statements.

Credit risk

Credit risk is the risk that Equinor’s cust omers or counterparties will cause Equinor financial loss by failing to honor 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, Equinor’s credit policy requires all counterparties to be formally identified and assigned internal credit ratings. The internal credit ratings reflect Equinor’s assessment of the counterparties' credit risk and are based on a quantitative and qualitative analysis of recent financial statements and other relevant business. All counterparties are re-assessed regularly.

Equinor 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.

Equinor has pre-defined limits for the absolute credit risk level allowed at any given time on Equinor’s portfolio as well as maximum credit exposures for individual counterparties. Equinor monitors the portfolio on a regular basis and individual exposures against limits on a daily basis. The total credit exposure of Equinor 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 Equinor’s credit exposure is with investment grade counterparties.

194 Equinor, Annual Report on Form 20-F 2019

The following table contains the carrying amount of Equinor’s financial receivables and derivative financial instruments split by Equinor’s assessment of the counterparty's credit risk. Trade and other receivables include 2% 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 Equinor’s working interest partners within its US unconventional activities. Provisions have been made for expected losses utilising the expected credit loss model. 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 2019 |  |  |  |
Investment grade, rated A or above | 682 | 2,089 | 962 | 201
Other investment grade | 80 | 4,778 | 403 | 368
Non-investment grade or not rated | 296 | 508 | 0 | 9
Total financial asset | 1,057 | 7,374 | 1,365 | 578
At 31 December 2018 |  |  |  |
Investment grade, rated A or above | 460 | 1,811 | 682 | 100
Other investment grade | 150 | 5,412 | 350 | 183
Non-investment grade or not rated | 244 | 1,265 | 0 | 35
Total financial asset | 854 | 8,488 | 1,032 | 318

For more information about Trade and other receivables, see note 15 Trade and other receivables.

At 31 December 2019, USD 585 million of cash was held as collateral to mitigate a portion of Equinor's credit exposure. At 31 December 2018, USD 213 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 2019, USD 2,187 million have been offset and USD 603 million presented as liabilities do not meet the criteria for offsetting. At 31 December 2018, USD 119 million were offset and USD 655 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 1,309 million have been offset as of 31 December 2019, and respectively USD 557 million as of 31 December 2018.

Equinor, Annual Report on Form 20-F 2019 195

Capital management

The main objectives of Equinor's capital management policy are to maintain a strong overall financial position and to ensure sufficient financial flexibility. Equinor’s primary focus is on maintaining its credit rating in the A category on a stand alone basis (ignoring uplifts for Norwegian Government ownership). In order to monitor financial robustness on a day to day basis, a key ratio utilized by Equinor is the non-GAAP metric of “adjusted net interest-bearing debt (ND) to adjusted capital employed (CE)”.

| At 31 December
(in USD million) | 2019 | 2018
Net interest-bearing debt adjusted, including lease liabilities (ND1) | 17,219 |
Net interest-bearing debt adjusted (ND2) | 12,880 | 12,246
Capital employed adjusted, including lease liabilities (CE1) | 58,378 |
Capital employed adjusted (CE2) | 54,039 | 55,235
Net debt to capital employed adjusted, including lease liabilities (ND1/CE1) | 29.5% | -
Net debt to capital employed adjusted (ND2/CE2) | 23.8% | 22.2%

ND1 is defined as Equinor's interest bearing financial liabilities less cash and cash equivalents and current financial investments, adjusted for collateral deposits and balances held by Equinor's captive insurance company (amounting to USD 791 million and USD 1,261 million for 2019 and 2018, respectively) and balances related to the SDFI (amounting to USD 0 million and USD 146 million for 2019 and 2018, respectively. CE1 is defined as Equinor's total equity (including non-controlling interests) and ND1. ND2 is defined as ND1 adjusted for lease liabilities (amounting to USD 4,339 million and USD 0 million for 2019 and 2018, respectively). CE2 is defined as Equinor's total equity (including non-controlling interests) and ND2.

### 6 Remuneration

| Full year
(in USD million, except average number of employees) | 2019 | 2018 | 2017
Salaries1) | 2,766 | 2,863 | 2,671
Pension costs | 446 | 463 | 469
Payroll tax | 413 | 409 | 387
Other compensations and social costs | 330 | 318 | 290
Total payroll costs | 3,955 | 4,052 | 3,818
Average number of employees2) | 21,400 | 20,700 | 20,700

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

2) Part time employees amount to 4% for 2019 and 3% for each of the years 2018 and 2017 respectively.

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

196 Equinor, Annual Report on Form 20-F 2019

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

| Full year
(in USD thousand)1) | 2019 | 2018 | 2017
Current employee benefits | 10,958 | 12,471 | 11,067
Post-employment benefits | 661 | 667 | 636
Other non-current benefits | 18 | 21 | 25
Share-based payment benefits | 147 | 197 | 175
Total | 11,782 | 13,356 | 11,902

1) All figures in the table are presented on accrual basis.

For management remuneration details, see note 4 Remuneration in the parent company financial statements and notes.

At 31 December 2019, 2018 and 2017 there are no loans to the members of the BoD or the CEC.

Share-based compensation

Equinor's share saving plan provides employees with the opportunity to purchase Equinor shares through monthly salary deductions and a contribution by Equinor. 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 Equinor for purchased shares, amounts vested for bonus shares granted and related social security tax was USD 73 million, USD 72 million and USD 62 million related to the 2019, 2018 and 2017 programmes, respectively. For the 2020 programme (granted in 2019) the estimated compensation expense is USD 74 million. At 31 December 2019 the amount of compensation cost yet to be expensed throughout the vesting period is USD 158 million.

### 7 Other expenses

Auditor's remuneration
| Full year
(in USD million, excluding VAT) | 2019 | 2018 | 2017
Audit fee Ernst & Young (principal accountant 2019) | 4.7 |  |
Audit fee KPMG (principal accountant 2018 and 2017) | 2.8 | 7.1 | 6.1
Audit related fee Ernst & Young (principal accountant 2019) | 0.5 |  |
Audit related fee KPMG (principal accountant 2018 and 2017) | 1.2 | 1.0 | 0.9
Tax fee Ernst & Young (principal accountant 2019) | 0.2 |  |
Tax fee KPMG (principal accountant 2018 and 2017) | 0.0 | 0.0 | 0.0
Other service fee Ernst & Young (principal accountant 2019) | 0.9 |  |
Other service fee KPMG (principal accountant 2018 and 2017) | 0.0 | 0.0 | 0.0
Total | 10.3 | 8.1 | 7.0

In addition to the figures in the table above, the audit fees and audit related fees related to Equinor operated licences amount to USD 0.5 million, USD 0.9 million and USD 0.8 million for 2019, 2018 and 2017, respectively.

On 15 May 2019, the general meeting of shareholders appointed Ernst & Young AS as Equinor’s auditor, thereby replacing KPMG AS.

Research and development expenditures

Research and development (R&D) expenditures were USD 300 million, USD 315 million and USD 307 million in 2019, 2018 and 2017, respectively. R&D expenditures are partly financed by partners of Equinor operated licences. Equinor's share of the expenditures has been recognised as expense in the Consolidated statement of income.

###

Equinor, Annual Report on Form 20-F 2019 197

### 8 Financial items

| Full year
(in USD million) | 2019 | 2018 | 2017
Foreign exchange gains/(losses) derivative financial instruments | 132 | 149 | (920)
Other foreign exchange gains/(losses) | 92 | (315) | 1,046
Net foreign exchange gains/(losses) | 224 | (166) | 126
Dividends received | 75 | 150 | 63
Gains/(losses) financial investments | 245 | (72) | 108
Interest income financial investments, including cash and cash equivalents | 124 | 45 | 64
Interest income non-current financial receivables | 21 | 27 | 24
Interest income other current financial assets and other financial items | 280 | 132 | 228
Interest income and other financial items | 746 | 283 | 487
Gains/(losses) derivative financial instruments | 473 | (341) | (61)
Interest expense bonds and bank loans and net interest on related derivatives | (987) | (922) | (1,004)
Interest expense lease liabilities | (126) | (23) | (26)
Capitalised borrowing costs | 480 | 552 | 454
Accretion expense asset retirement obligations | (456) | (461) | (413)
Interest expense current financial liabilities and other finance expense | (360) | (185) | 86
Interest and other finance expenses | (1,450) | (1,040) | (903)
Net financial items | (7) | (1,263) | (351)

Equinor's main financial items relate to assets and liabilities categorised in the fair value through profit or loss and the amortised cost category. For more information about financial instruments by category see note 26 Financial instruments: fair value measurement and sensitivity analysis of market risk. For information related to the implementation of IFRS 16, see note 23 Implementation of IFRS 16 leases.

The line item Interest expense bonds and bank loans and net interest on related derivatives primarily includes interest expenses of USD 861 million, USD 868 million, and USD 1,084 million from the financial liabilities at amortised cost category and net interest on related derivatives from the fair value through profit or loss category with net interest expense of USD 129 million, net interest expense of USD 55 million and net interest income of USD 80 million for 2019, 2018 and 2017, respectively.

The line item Gains/(losses) derivative financial instruments primarily includes fair value changes from the fair value through profit or loss category on derivatives related to interest rate risk, with a gain of USD 457 million in 2019. Correspondingly a loss of USD 357 million and a loss of USD 77 million for 2018 and 2017, respectively.

The line item Interest expense current financial liabilities and other finance expense includes an income of USD 319 million in 2017 related to release of a provision.

Foreign exchange gains/(losses) derivative financial instruments include fair value changes of currency derivatives related to liquidity and currency risk. The line item Other foreign exchange gains/(losses) includes a net foreign exchange loss of USD 74 million, a loss of USD 422 million and a gain of USD 427 million from the fair value through profit or loss category for 2019, 2018 and 2017, respectively.

###

198 Equinor, Annual Report on Form 20-F 2019

### 9 Income taxes

Significant components of income tax expense
| Full year
(in USD million) | 2019 | 2018 | 2017
Current income tax expense in respect of current year | (7,892) | (10,724) | (7,680)
Prior period adjustments | 69 | (49) | (124)
Current income tax expense | (7,822) | (10,773) | (7,805)
Origination and reversal of temporary differences | 410 | (1,359) | (904)
Recognition of previously unrecognised deferred tax assets | 0 | 923 | 0
Change in tax regulations | (6) | (28) | (14)
Prior period adjustments | (23) | (99) | (100)
Deferred tax income/(expense) | 381 | (563) | (1,017)
Income tax expense | (7,441) | (11,335) | (8,822)

Equinor, Annual Report on Form 20-F 2019 199

Reconciliation of statutory tax rate to effective tax rate
| Full year
(in USD million) | 2019 | 2018 | 2017
Income/(loss) before tax | 9,292 | 18,874 | 13,420
Calculated income tax at statutory rate1) | (2,284) | (5,197) | (3,827)
Calculated Norwegian Petroleum tax2) | (5,499) | (8,189) | (5,945)
Tax effect uplift3) | 632 | 736 | 784
Tax effect of permanent differences regarding divestments | 380 | 400 | (85)
Tax effect of permanent differences caused by functional currency different from tax currency | 8 | 116 | (229)
Tax effect of other permanent differences | 395 | 337 | 291
Tax effect of dispute with Angolan Ministry of Finance4) | 0 | 0 | 496
Recognition of previously unrecognised deferred tax assets5) | 0 | 923 | 0
Change in unrecognised deferred tax assets | (974) | 72 | (169)
Change in tax regulations | (6) | (28) | (14)
Prior period adjustments | 47 | (148) | (224)
Other items including currency effects | (139) | (357) | 100
Income tax expense | (7,441) | (11,335) | (8,822)
Effective tax rate | 80.1% | 60.1% | 65.7%

1) The weighted average of statutory tax rates was 24.6% in 2019, 27.5% in 2018 and 28.5% in 2017. The rates are influenced by earnings composition between tax regimes with lower statutory tax rates and tax regimes with higher statutory tax rates. The change in weighted average statutory tax rate from 2018 to 2019 and from 2017 to 2018 is also caused by the reduction in the Norwegian statutory tax rate from 24% in 2017 to 23% in 2018 to 22% in 2019.

2) The Norwegian petroleum tax rate is 56% for 2019, 55% for 2018 and 54% for 2017.

3) When computing the petroleum tax of 56% on income from the Norwegian continental shelf, an additional tax-free allowance, or uplift, is granted on the basis of the original capitalised cost of offshore production installations. The uplift may be deducted from taxable income for a period of four years starting in the year in which the capital expenditure is incurred. For investments made in 2019 the uplift is calculated at a rate of 5.2% per year, while the rate is 5.3% per year for investments made in 2018, 5.4% per year for investments made in 2017 and 5.5% per year for investments made in 2016. 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. For these investments the rate is 7.5% per year. Unused uplift may be carried forward indefinitely. At year end 2019 and 2018, unrecognised uplift credits amounted to USD 1,678 million and USD 1,780 million, respectively.

4) In June 2017 Equinor signed an agreement with the Angolan Ministry of Finance which resolved the dispute over previously assessed additional profit oil and taxes due, and established how to allocate profit oil and assess petroleum income tax (PIT) related to Equinor’s participation in Block 4, Block 15, Block 17 and Block 31 offshore Angola for the years 2002 to 2016.

5) An amount of USD 923 million of previously unrecognised deferred tax assets was recognised in the E&P International reporting segment in 2018. The recognition of the deferred tax assets is based on the expectation that sufficient taxable income will be available through reversals of taxable temporary differences or future taxable income supported by business forecast.

200 Equinor, Annual Report on Form 20-F 2019

Deferred tax assets and liabilities comprise
(in USD million) | Tax losses carried forward | Property, plant and equipment and intangible assets | Asset retirement obligations | Lease liabilities1) | Pensions | Derivatives | Other1) | Total
Deferred tax at 31 December 2019 |  |  |  |  |  |  |
Deferred tax assets | 5,173 | 369 | 9,397 | 1,898 | 733 | 108 | 1,612 | 19,291
Deferred tax liabilities | 0 | (24,115) | (0) | (0) | (13) | (119) | (573) | (24,820)
Net asset/(liability) at 31 December 2019 | 5,173 | (23,746) | 9,397 | 1,898 | 720 | (11) | 1,040 | (5,530)
Deferred tax at 31 December 2018 |  |  |  |  |  |  |
Deferred tax assets | 5,761 | 351 | 8,118 | 0 | 785 | 95 | 1,095 | 16,205
Deferred tax liabilities | (0) | (20,987) | 0 | 0 | (14) | (96) | (476) | (21,573)
Net asset/(liability) at 31 December 2018 | 5,761 | (20,636) | 8,118 | 0 | 771 | (1) | 620 | (5,367)

1) For 2019 deferred tax related to lease liabilities has been included in a separate column Lease liabilities, while deferred tax related to lease liabilities for 2018 has not been reclassified due to immateriality and is included in Other.

Changes in net deferred tax liability during the year were as follows:
(in USD million) | 2019 | 2018 | 2017
Net deferred tax liability at 1 January | 5,367 | 5,213 | 4,231
Charged/(credited) to the Consolidated statement of income | (381) | 563 | 1,017
Charged/(credited) to Other comprehensive income | 98 | (22) | 38
Translation differences and other | 446 | (386) | (73)
Net deferred tax liability at 31 December | 5,530 | 5,367 | 5,213

Equinor, Annual Report on Form 20-F 2019 201

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) | 2019 | 2018
Deferred tax assets | 3,881 | 3,304
Deferred tax liabilities | 9,410 | 8,671

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 2019 and 2018 the deferred tax assets of USD 3,881 million and USD 3,304 million, respectively, were primarily recognised in Norway, Angola, Brazil, the UK and Canada. Of these amounts USD 995 million and USD 1,868 million, respectively, is recognised in entities which have suffered a tax loss in either the current or preceding period. These losses are mainly caused by accelerated tax depreciations and start-up costs related to oil and gas assets in the construction phase. The losses will be utilised through reversal of taxable temporary differences and other taxable income from production of oil and gas when these assets start production.

Unrecognised deferred tax assets
| At 31 December
| 2019 | 2018
(in USD million) | Basis | Tax | Basis | Tax
Deductible temporary differences | 2,550 | 1,138 | 2,439 | 1,123
Tax losses carried forward | 18,259 | 4,366 | 14,802 | 3,940
Total | 20,809 | 5,504 | 17,241 | 5,062

Approximately 11% 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 2030. 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.

At year end 2019 unrecognised deferred tax assets in the US, Angola and Ireland represents USD 3,788 million, USD 833 million and USD 191 million of the total unrecognised deferred tax assets of USD 5,504 million. Similar amounts for 2018 were USD 3,480 million in the US, USD 884 million in Angola and USD 109 million in Ireland of a total of USD 5,062 million.

###

202 Equinor, Annual Report on Form 20-F 2019

### 10 Property, plant and equipment

(in USD million) | Machinery, equipment and transportation equipment | Production plants and oil and gas assets | Refining and manufacturing plants | Buildings and land | Assets under development | Right of use assets4) | Total
Cost at 31 December 2018 | 3,596 | 166,766 | 8,660 | 932 | 14,961 | 0 | 194,916
Implementation of IFRS 16 Leases 5) | (813) | (184) | 0 | 0 | 0 | 4,989 | 3,992
Cost at 1 January 2019 | 2,783 | 166,582 | 8,660 | 932 | 14,961 | 4,989 | 198,908
Additions through business combinations | 1 | 1,706 | 5 | 0 | 381 | 0 | 2,093
Additions and transfers | 44 | 16,023 | 300 | (16) | (4,448) | 426 | 12,330
Disposals at cost | (7) | (4,911) | (0) | (7) | (59) | (35) | (5,020)
Effect of changes in foreign exchange | (2) | (337) | (44) | (0) | (464) | (41) | (888)
Cost at 31 December 2019 | 2,818 | 179,063 | 8,920 | 909 | 10,371 | 5,339 | 207,422
Accumulated depreciation and impairment losses at 31 December 2018 | (2,802) | (119,589) | (6,613) | (465) | (185) | 0 | (129,654)
Implementation of IFRS 16 Leases 5) | 511 | 106 | 0 | 0 | 0 | (617) | 0
Accumulated depreciation and impairment losses at 1 January 2019 | (2,291) | (119,483) | (6,613) | (465) | (185) | (617) | (129,654)
Depreciation | (120) | (8,555) | (298) | (25) | 0 | (752) | (9,750)
Impairment losses | (6) | (2,430) | (178) | (3) | (707) | (26) | (3,350)
Reversal of impairment losses | 0 | 120 | 0 | 0 | 0 | 0 | 120
Transfers | 13 | (134) | (0) | 13 | 26 | 42 | (40)
Accumulated depreciation and impairment on disposed assets | 7 | 4,540 | 0 | 5 | 0 | 24 | 4,576
Effect of changes in foreign exchange | 1 | 616 | 38 | (0) | (26) | (1) | 628
Accumulated depreciation and impairment losses at 31 December 2019 | (2,395) | (125,327) | (7,051) | (475) | (892) | (1,329) | (137,469)
Carrying amount at 31 December 2019 | 423 | 53,736 | 1,870 | 434 | 9,479 | 4,011 | 69,953
Estimated useful lives (years) | 3 - 20 | UoP1) | 15 - 20 | 20 - 332) |  | 1 - 193) |

Equinor, Annual Report on Form 20-F 2019 203

(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 2017 | 3,470 | 157,533 | 8,646 | 866 | 18,140 | 188,656
Additions through business combinations | 76 | 2,473 | 0 | 48 | 1,370 | 3,968
Additions and transfers | 90 | 13,017 | 328 | 32 | (3,322) | 10,144
Disposals at cost | (12) | (505) | (0) | (1) | (366) | (884)
Effect of changes in foreign exchange | (28) | (5,752) | (314) | (13) | (861) | (6,967)
Cost at 31 December 2018 | 3,596 | 166,766 | 8,660 | 932 | 14,961 | 194,916
Accumulated depreciation and impairment losses at 31 December 2017 | (2,853) | (113,781) | (6,200) | (439) | (1,746) | (125,019)
Depreciation | (137) | (9,249) | (426) | (29) | 0 | (9,841)
Impairment losses | 0 | (762) | 0 | 0 | (32) | (794)
Reversal of impairment losses | 155 | 1,087 | 0 | 0 | 156 | 1,398
Transfers | (0) | (1,799) | (229) | (1) | 1,067 | (961)
Accumulated depreciation and impairment on disposed assets | 12 | 602 | 0 | 0 | 366 | 980
Effect of changes in foreign exchange | 21 | 4,312 | 242 | 4 | 5 | 4,583
Accumulated depreciation and impairment losses at 31 December 2018 | (2,802) | (119,589) | (6,613) | (465) | (185) | (129,654)
Carrying amount at 31 December 2018 | 794 | 47,177 | 2,048 | 467 | 14,776 | 65,262
Estimated useful lives (years) | 3 - 20 | UoP 1) | 15 - 20 | 20 - 33 2) |  |

1) Depreciation according to unit of production method (UoP), see note 2 Significant accounting policies.

2) Land is not depreciated.

3) Depreciation linearly over contract period.

4) See note 22 Leases.

5) See note 23 Implementation of IFRS 16 Leases.

The carrying amount of assets transferred to Property, plant and equipment from Intangible assets in 2019 and 2018 amounted to USD 213 million and USD 161 million, respectively.

For additions through business combinations, see note 4 Acquisitions and disposals.

204 Equinor, Annual Report on Form 20-F 2019

Impairments/reversal of impairments

(in USD million) | Property, plant and equipment | Intangible assets3) | Total
At 31 December 2019 |  |  |
Producing and development assets1) | 3,230 | 608 | 3,838
Goodwill1) | - | 164 | 164
Other intangible assets1) | - | 41 | 41
Acquisition costs related to oil and gas prospects2) | - | 49 | 49
Total net impairment loss/(reversal) recognised | 3,230 | 863 | 4,093
At 31 December 2018 |  |  |
Producing and development assets1) | (604) | 237 | (367)
Acquisition costs related to oil and gas prospects2) | - | 52 | 52
Total net impairment loss/(reversal) recognised | (604) | 289 | (315)

1) Producing and development assets, goodwill and other intangible assets are subject to impairment assessment under IAS 36. The total net impairment losses recognised under IAS 36 in 2019 amount to USD 4,043 million, compared to 2018 when the net impairment reversal amounted to USD 367 million, 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.

For impairment purposes, 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. The discount rate is derived from Equinor's weighted average cost of capital. A derived pre-tax discount is in the range of 15%-25% for E&P Norway and 4-9% for E&P International and MMP, depending on asset specific characteristics, such as specific tax treatments, cash flow profiles and economic life. See note 2 Significant accounting policies to the Consolidated financial statements for further information regarding impairment on property, plant and equipment.

Equinor, Annual Report on Form 20-F 2019 205

The table below describes per area the assets being impaired/(reversed) and the valuation method used to determine the recoverable amount; the net impairment/(reversal), and the carrying amount after impairment.

|  | 2019 | 2018 |
(in USD million) | Valuation method | Carrying amount after impairment | Net impairment loss/ (reversal) | Carrying amount after impairment | Net impairment loss/ (reversal) |
At 31 December |  |  |  |  |  |
Exploration & Production Norway | VIU | 4,406 | 1,119 | 1,966 | (201) |
| FVLCOD | 0 | 0 | 1,232 | (402) |
North America - unconventional | VIU | 7,509 | 1,631 | 5,771 | 762 |
| FVLCOD | 0 1) | 610 | 0 | 0 |
North America - conventional offshore US Gulf of Mexico | VIU | 1,079 | 292 | 3,989 | (246) |
| FVLCOD | 0 | 0 | 0 | 0 |
North Africa | VIU | 0 | 0 | 451 | (126) |
| FVLCOD | 0 | 0 | 0 | 0 |
Europe and Asia | VIU | 645 | (18) | 0 | 0 |
| FVLCOD | 0 | 0 | 0 | 0 |
Marketing, Midstream & Processing | VIU | 65 | 178 | 403 | (155) |
| FVLCOD | 0 | 0 | 0 | 0 |
Right of use assets | VIU | 0 | 26 | 0 | 0 |
| FVLCOD | 0 | 0 | 0 | 0 |
Total |  | 13,704 | 3,838 | 13,813 | (367) |
1) Asset is disposed. |

Exploration & Production Norway

In 2019 impairment losses of USD 1,119 million were recognised. The impairments were triggered by cost increases and decreased price assumptions. The impairment amount is impacted by how tax uplift is to be included in the pre-tax net present value estimate.

In 2018 impairment reversals of USD 604 million were recognised mainly due to change in long term exchange rate assumptions.

North America - unconventional

In 2019 impairment losses of USD 2,241 million of which USD 608 million was classified as exploration expenses were recognised mainly caused by reduced long term price assumptions and reduced fair value of one asset.

In 2018 impairment losses of USD 762 million of which USD 237 million was classified as exploration expenses were recognised mainly caused by reduced long term price assumptions and reduced fair value of one asset.

North America - conventional offshore Gulf of Mexico

In 2019 net impairment loss of USD 292 million was recognised due to reduced reserve estimates.

In 2018 net impairment reversal of USD 246 million was recognised due to improved production profile and various operational improvements partially offset by negative changes in reserve estimates.

North Africa

In 2019 no impairments or reversals were recognised.

In 2018 an impairment reversal of USD 126 million was recognised due to an extension of licence period.

Marketing, Midstream & Processing

In 2019 impairment loss of USD 178 million was recognised related to the South Riding Point oil terminal as a result of the damages caused by the hurricane Dorian on Bahamas.

In 2018 an impairment reversal of USD 155 million was recognised due to increased refinery margin forecast.

Value in Use (VIU) estimates and discounted cash flows used to determine the recoverable amount of assets tested for impairment are based on internal forecasts on costs, production profiles and commodity prices. Short term commodity prices (2020/2021/2022) are forecasted by using observable forward prices for 2020 and a linear projection towards the 2023 internal forecast.

206 Equinor, Annual Report on Form 20-F 2019

The price assumptions as per year-end 2019 are as follows (year-end 2018 price assumptions the respective years are indicated in brackets):

Year Prices in real terms 1) |  |  | 2020 |  | 2025 |  | 2030
Brent Blend – USD/bbl |  |  |  | 59 | (68) |  | 77 | (78) |  | 80 | (82)
NBP - USD/mmBtu |  |  |  | 4.2 | (7.7) |  | 7.0 | (8.2) |  | 7.5 | (8.2)
Henry Hub – USD/mmBtu |  |  |  | 2.4 | (3.2) |  | 3.1 | (4.1) |  | 3.6 | (4.1)
1) Basis year 2019. |  |  |  |  |  |  |  |  |  |  |

The long-term price assumptions were updated in the third quarter of 2019.

Sensitivities

Commodity prices have historically been volatile. Significant downward adjustments of Equinor’s commodity price assumptions would result in impairment losses on certain producing and development assets in Equinor’s portfolio. If a decline in commodity price forecasts over the lifetime of the assets were 30%, considered to represent a reasonably possible change, the impairment amount to be recognised could illustratively be in the region of USD 15 billion before tax effects. This illustrative impairment sensitivity, based on a simplified method, assumes no changes to input factors other than prices; however, a price reduction of 30% 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 Equinor and its licence 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 2018 | 2,685 | 5,854 | 565 | 797 | 9,901
Additions through business combinations | 0 | 0 | 1,070 | 10 | 1,080
Additions | 515 | 900 | 0 | 155 | 1,571
Disposals at cost | (7) | (361) | 0 | (0) | (367)
Transfers | (71) | (143) | 0 | 0 | (213)
Expensed exploration expenditures previously capitalised | (120) | (657) | 0 | 0 | (777)
Impairment of goodwill | 0 | 0 | (164) | 0 | (164)
Effect of changes in foreign exchange | 11 | 5 | (12) | (1) | 3
Cost at 31 December 2019 | 3,014 | 5,599 | 1,458 | 962 | 11,033
Accumulated depreciation and impairment losses at 31 December 2018 |  |  |  | (229) | (229)
Amortisation and impairments for the year |  |  |  | (60) | (60)
Amortisation and impairment losses disposed intangible assets |  |  |  | (6) | (6)
Effect of changes in foreign exchange |  |  |  | 1 | 1
Accumulated depreciation and impairment losses at 31 December 2019 |  |  |  | (295) | (295)
Carrying amount at 31 December 2019 | 3,014 | 5,599 | 1,458 | 667 | 10,738

Equinor, Annual Report on Form 20-F 2019 207

(in USD million) | Exploration expenses | Acquisition costs - oil and gas prospects | Goodwill | Other | Total
Cost at 31 December 2017 | 2,715 | 5,363 | 339 | 419 | 8,836
Additions through business combinations | 0 | 116 | 265 | 392 | 773
Additions | 392 | 917 | 0 | (7) | 1,302
Disposals at cost | (272) | (89) | 0 | (4) | (364)
Transfers | (13) | (148) | 0 | 0 | (161)
Expensed exploration expenditures previously capitalised | (68) | (289) | 0 | 0 | (357)
Effect of changes in foreign exchange | (70) | (17) | (39) | (2) | (128)
Cost at 31 December 2018 | 2,685 | 5,854 | 565 | 797 | 9,901
Accumulated depreciation and impairment losses at 31 December 2017 |  |  |  | (215) | (215)
Amortisation and impairments for the year |  |  |  | (13) | (13)
Amortisation and impairment losses disposed intangible assets |  |  |  | (2) | (2)
Effect of changes in foreign exchange |  |  |  | 1 | 1
Accumulated depreciation and impairment losses at 31 December 2018 |  |  |  | (229) | (229)
Carrying amount at 31 December 2018 | 2,685 | 5,854 | 565 | 568 | 9,672

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.

For additions through business combinations, see note 4 Acquisitions and disposals.

During 2019, Acquisition costs-oil and gas prospects were impacted by net impairment of signature bonuses and acquisition costs totalling USD 608 million related to North America – unconventional assets and impairment of acquisition costs related to exploration activities of USD 49 million primarily as a result from dry wells and uncommercial discoveries in Europe and Asia and Sub Sahara areas. In 2018, Acquisition costs-oil and gas prospects were impacted by net impairment of signature bonuses and acquisition costs totalling USD 237 million related to North America – unconventional assets, and impairment of acquisition costs related to exploration activities of USD 52 million primarily as a result from dry wells and uncommercial discoveries in South America, North America - conventional offshore US Gulf of Mexico and E&P Norway.

During 2019, Other intangible assets were impacted by impairment losses of USD 41 million.

Equinor’s Block 2 Exploration License in Tanzania was formally due to expire in June 2018, but based on communication with the applicable Tanzanian authorities, continues to be in operation while the process related to the grant of a new exploration license to the existing licensees for the block is ongoing. The Block 2 asset remains capitalised within Intangible assets in the E&P International segment as of 31 December 2019.

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) | 2019 | 2018
Less than one year | 1,274 | 392
Between one and five years | 1,056 | 1,406
More than five years | 684 | 887
Total | 3,014 | 2,685

208 Equinor, Annual Report on Form 20-F 2019

The table below shows the components of the exploration expenses.
| Full year
(in USD million) | 2019 | 2018 | 2017
Exploration expenditures | 1,584 | 1,438 | 1,234
Expensed exploration expenditures previously capitalised | 777 | 357 | (8)
Capitalised exploration | (507) | (390) | (167)
Exploration expenses | 1,854 | 1,405 | 1,059

### 12 Equity accounted investments

(in USD million) | Lundin Petroleum AB | Other equity accounted investments | Total
Net investment at 31 December 2018 | 1,100 | 1,763 | 2,862
Net income/(loss) from equity accounted investments | 15 | 149 | 164
Acquisitions and increase in capital | 0 | 188 | 188
Dividend and other distributions | (51) | (223) | (273)
Other comprehensive income/(loss) | (13) | 3 | (10)
Divestments, derecognition and decrease in paid in capital | (1,051) | (393) | (1,444)
Net investment at 31 December 2019 | 0 | 1,487 | 1,487
Included in equity accounted investments | 0 | 1,441 | 1,441
Other long-term receivable in equity accounted investments | 0 | 46 | 46

For the equity accounted investments, voting rights corresponds to ownership.

In 2019 Equinor sold 16.0% of the shares in Lundin Petroleum AB. Equinor´s remaining ownership share in Lundin Petroleum AB is 4.9%, and is recognized as a financial investment at fair market value.

###

Equinor, Annual Report on Form 20-F 2019 209

### 13 Financial investments and non-current prepayments

Non-current financial investments
| At 31 December
(in USD million) | 2019 | 2018
Bonds | 1,629 | 1,261
Listed equity securities | 1,261 | 530
Non-listed equity securities | 710 | 664
Financial investments | 3,600 | 2,455

Bonds and equity securities mainly relate to investment portfolios held by Equinor's captive insurance company and other listed and non-listed equities held for long-term strategic purposes, mainly accounted for using fair value through profit or loss.

Non-current prepayments and financial receivables
| At 31 December
(in USD million) | 2019 | 2018
Interest bearing financial receivables | 413 | 345
Prepayments and other non-interest bearing receivables | 800 | 688
Prepayments and financial receivables | 1,214 | 1,033

Interest bearing financial receivables primarily relate to loans to employees and project financing of equity accounted companies.

Current financial investments
| At 31 December
(in USD million) | 2019 | 2018
Time deposits | 4,158 | 4,129
Interest bearing securities | 3,268 | 2,912
Financial investments | 7,426 | 7,041

At 31 December 2019, current f inancial investments include USD 377 million investment portfolios held by Equinor’ s captive insurance company which mainly are accounted for using fair value through profit or loss. The corresponding balance at 31 December 2018 was USD 896 million.

For information about financial instruments by category, see note 26 Financial instruments: fair value measurement and sensitivity analysis of market risk.

###

210 Equinor, Annual Report on Form 20-F 2019

### 14 Inventories

| At 31 December
(in USD million) | 2019 | 2018
Crude oil | 2,137 | 1,173
Petroleum products | 572 | 345
Natural gas | 277 | 274
Other | 377 | 351
Inventories | 3,363 | 2,144

Other inventory consists mainly of drilling and well equipment.

The write-down of inventories from cost to net realisable value amounted to an expense of USD 147 million and USD 164 million in 2019 and 2018, respectively.

### 15 Trade and other receivables

| At 31 December
(in USD million) | 2019 | 2018
Trade receivables from contracts with customers | 5,624 | 6,267
Other current receivables | 1,189 | 1,800
Joint venture receivables | 429 | 390
Receivables from equity accounted associated companies and other related parties | 132 | 31
Total financial trade and other receivables | 7,374 | 8,488
Non-financial trade and other receivables | 859 | 510
Trade and other receivables | 8,233 | 8,998

Trade receivables from contracts with customers are shown net of an immaterial provision for expected losses.

For more information about the credit quality of Equinor's counterparties, see note 5 Financial risk and capital management. For currency sensitivities, see note 26 Financial instruments: fair value measurement and sensitivity analysis of market risk.

### 16 Cash and cash equivalents

| At 31 December
(in USD million) | 2019 | 2018
Cash at bank available | 1,666 | 1,140
Time deposits | 604 | 2,068
Money market funds | 700 | 2,255
Interest bearing securities | 1,656 | 1,590
Restricted cash, including margin deposits | 552 | 501
Cash and cash equivalents | 5,177 | 7,556

Restricted cash at 31 December 2019 and 2018 includes collateral deposits related to trading activities of USD 414 million and USD 365 million, respectively. Collateral deposits are related to certain requirements set out by exchanges where Equinor is participating. The terms and conditions related to these requirements are determined by the respective exchanges.

###

Equinor, Annual Report on Form 20-F 2019 211

### 17 Shareholders' equity and dividends

At 31 December 2019, Equinor’s share capital of NOK 8,346,653,047.50 (USD 1,184,547,766) comprised 3,338,661,219 shares at a nominal value of NOK 2.50. Share capital at 31 December 2018 was NOK 8,346,653,047.50 (USD 1,184,547,766 )comprised 3,338,661,219 shares at a nominal value of NOK 2.50.

Equinor 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 the annual general meeting of the company.

A temporary 2-year scrip programme, approved by Equinor’s annual general meeting in May 2016 ended as planned with the last scrip shares issued in the first quarter of 2018 based on the dividend related to third quarter 2017.

During 2019 dividend for the third and for the fourth quarter of 2018 and dividend for the first and second quarter of 2019 were settled. Dividend declared but not yet settled, is presented as dividends payable in the Consolidated balance sheet. The Consolidated statement of changes in equity shows declared dividend in the period (retained earnings), Dividend declared in 2019 relate to the fourth quarter of 2018 and to the first three quarters of 2019.

On 5 February 2020, the board of directors proposed to declare a dividend for the fourth quarter of 2019 of USD 0.27 per share (subject to annual general meeting approval). The Equinor share will trade ex-dividend 15 May 2020 on Oslo Børs and for ADR holders on New York Stock Exchange. Record date will be 18 May 2020 and payment date will be 29 May 2020.

| At 31 December
(in USD million) | 2019 | 2018
Dividends declared | 3,453 | 3,064
USD per share or ADS | 1.0400 | 0.9200
Dividends paid in cash | 3,342 | 2,672
USD per share or ADS | 1.0100 | 0.9101
NOK per share | 8.9664 | 7.4907
Scrip dividends | 0 | 338
Number of shares issued (millions) | 0.0 | 15.5
Sum dividends settled | 3,342 | 3,010

Share buy-back programme

In September 2019 Equinor launched a USD 5 billion share buy-back programme, where the first tranche of the programme of around USD 1.5 billion ended 4 February 2020. For the first tranche Equinor has entered into an irrevocable agreement with a third party for up to USD 500 million of shares to be purchased in the market, while around USD 1.0 billion of shares from the Norwegian State will in accordance with an agreement with the Ministry of Petroleum and Energy be redeemed at the next annual general meeting in order for the Norwegian State to maintain their ownership percentage in Equinor. As of 31. December 2019 USD 442 million of the USD 500 million order has been acquired in the open market, of which USD 442 million has been settled.

The first tranche of USD 500 million (both acquired and remaining order) has been recognised as a reduction in equity as treasury shares due to the irrevocable agreement with the third party. The remaining order of the first tranche is accrued for and classified as Trade, other payables and provisions. The recognition of the State’s share will be deferred until the decision at the annual general meeting in May 2020.

Number of shares | 2019
Share buy-back programme at 1 January | -
Purchase | 23,578,410
Cancellation | -
Share buy-back programme at 31 December | 23,578,410

212 Equinor, Annual Report on Form 20-F 2019

Employees share saving plan |  |
Number of shares | 2019 | 2018
Share saving plan at 1 January | 10,352,671 | 11,243,234
Purchase | 3,403,469 | 2,740,657
Allocated to employees | (3,681,428) | (3,631,220)
Share saving plan at 31 December | 10,074,712 | 10,352,671

In 2019 and 2018 treasury shares were purchased and allocated to employees participating in the share saving plan for USD 68 million and USD 68 million, respectively. For further information, see note 6 Remuneration.

### 18 Finance debt

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)
| 2019 | 2018 | 2019 | 2018 | 2019 | 2018
Unsecured bonds |  |  |  |  |  |
United States Dollar (USD) | 4.14 | 4.14 | 13,308 | 13,088 | 14,907 | 13,657
Euro (EUR) | 2.25 | 2.10 | 8,201 | 8,928 | 8,992 | 9,444
Great Britain Pound (GBP) | 6.08 | 6.08 | 1,815 | 1,760 | 2,765 | 2,532
Norwegian Kroner (NOK) | 4.18 | 4.18 | 342 | 345 | 389 | 388
Total |  |  | 23,666 | 24,121 | 27,053 | 26,021
Unsecured loans |  |  |  |  |  |
Japanese Yen (JPY) | 4.30 | 4.30 | 92 | 91 | 123 | 119
Total |  |  | 92 | 91 | 123 | 119
Non-current bonds and bank loans |  |  | 23,758 | 24,212 | 27,175 | 26,140
Less current portion |  |  | 2,004 | 1,322 | 2,036 | 1,321
Total |  |  | 21,754 | 22,889 | 25,139 | 24,819
Lease liabilities3) |  |  | 4,339 | 432 |  |
Less current portion |  |  | 1,148 | 57 |  |
Non-current finance debt |  |  | 24,945 | 23,264 |  |

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) Fair values are determined from external calculation models based on market observations from various sources, classified at level 2 in the fair value hierarchy. For more information regarding fair value hierarchy, see note 26 Financial Instruments: fair value measurement and sensitivity of market risk.

3) For more information regarding comparable figures on lease liabilities, see note 23 Implementation of IFRS 16 Leases.

Unsecured bonds amounting to USD 13,308 million are denominated in USD and unsecured bonds denominated in other currencies amounting to USD 9,404 million are swapped into USD. One bond denominated in EUR amounting to USD 954 million is 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 26 Financial instruments: fair value measurement and sensitivity analysis of market risk.

Equinor, Annual Report on Form 20-F 2019 213

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 2019 Equinor issued the following bond:
Issuance date | Amount in USD million | Interest rate in % | Maturity date
13 November 2019 | 1,000 | 3.250 | November 2049

Out of Equinor's total outstanding unsecured bond portfolio, 37 bond agreements contain provisions allowing Equinor 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 23,024 million at the 31 December 2019 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 and capital management.

Non-current finance debt maturity profile
| At 31 December
(in USD million) | 2019 | 2018
Year 2 and 3 | 4,156 | 4,003
Year 4 and 5 | 5,680 | 3,736
After 5 years | 15,109 | 15,525
Total repayment of non-current finance debt | 24,945 | 23,264
Weighted average maturity (years - including current portion) | 9 | 9
Weighted average annual interest rate (% - including current portion) | 3.53 | 3.67

For more information regarding lease liabilities, see note 22 Leases.

Current finance debt
| At 31 December
(in USD million) | 2019 | 2018
Collateral liabilities | 585 | 213
Non-current finance debt due within one year | 3,152 | 1,380
Other including US Commercial paper programme and bank overdraft | 350 | 870
Total current finance debt | 4,087 | 2,463
Weighted average interest rate (%) | 2.39 | 1.62

Collateral liabilities and other current liabilities relate mainly to cash received as security for a portion of Equinor's credit exposure and outstanding amounts on US Commercial paper (CP) programme. Issuance on the CP programme amounted to USD 340 million as of
31 December 2019 and USD 842 million as of 31 December 2018.

Non-current finance debt due within one year includes current portion of leases. For more information regarding leases, see note 22 Leases.

214 Equinor, Annual Report on Form 20-F 2019

Reconciliation of cash flow from financing activities to finance line items in balance sheet |
(in USD million) | Non-current finance debt | Current finance debt | Financial receivable Collaterals 1) | Additional paid in capital /Treasury shares | Non-controlling interest | Dividend payable | Total
At 31 December 2018 | 23,264 | 2,463 | (591) | (196) | 19 | 766 | 25,725
Transfer to current portion2) | (3,152) | 3,152 | - | - | - | - | -
Effect of exchange rate changes | (108) | - | - | - | - | 7 | (101)
Dividend decleared | - | - | - | - | - | 3,453 | 3,453
Cash flows provided by/(used in) financing activities2) | 984 | (2,585) | (32) | (514) | (7) | (3,342) | (5,496)
Other changes2) | 3,957 | 1,057 | (11) | 2 | 8 | (25) | 4,988
At 31 December 2019 | 24,945 | 4,087 | (634) | (708) | 20 | 859 | 28,569
1) Financial receivables collaterals are in included in trade and other receivables in the balance sheet. See note 15 Trade and other receivables for more information. |
2) Leases are included in columns for non-current finance debt and current finance debt. See note 22 Leases for more information. |
(in USD million) | Non-current finance debt | Current finance debt | Financial receivable Collaterals 1) | Additional paid in capital /Treasury shares | Non-controlling interest | Dividend payable | Total
At 31 December 2017 | 24,183 | 4,091 | (272) | (191) | 24 | 729 | 28,564
Transfer to current portion | (1,380) | 1,380 | - | - | - | - | -
Effect of exchange rate changes | (556) | 2 | - | - | - | (1) | (555)
Dividend decleared | - | - | - | - | - | 3,064 | 3,064
Scrip dividend | - | - | - | - | - | (338) | (338)
Cash flows provided by/(used in) financing activities | 998 | (2,949) | (331) | (64) | (7) | (2,672) | (5,025)
Other changes | 20 | (61) | 11 | 59 | 2 | (16) | 15
At 31 December 2018 | 23,264 | 2,463 | (591) | (196) | 19 | 766 | 25,725
1) Financial receivables collaterals are in included in trade and other receivables in the balance sheet. See note 15 Trade and other receivables for more information. |

###

Equinor, Annual Report on Form 20-F 2019 215

### 19 Pensions

The main pension plans for Equinor 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 Equinor 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 to the Consolidated financial statements for more information about the accounting treatment of the notional contribution plans reported in Equinor ASA.

In addition, Equinor ASA has a defined benefit plan. This benefit plan was closed in 2015 for new employees and for employees with more than 15 year to regular retirement age. Equinor'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 Equinor Pensjon (Equinor's pension fund - hereafter "Equinor Pension"). Equinor Pension is an independent pension fund that covers the employees in Equinor's Norwegian companies. The pension fund's assets are kept separate from the company's and group companies' assets. Equinor Pension is supervised by the Financial Supervisory Authority of Norway ("Finanstilsynet") and is licenced to operate as a pension fund.

Equinor is a member of a Norwegian national agreement-based early retirement plan (“AFP”), and the premium is calculated based on the employees' income, but limited to 7.1 times the basic amount in the National Insurance scheme (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. Equinor 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 increase, 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 2019 the discount rate for the defined benefit plans in Norway was established on the basis of seven years' mortgage covered bonds interest rate extrapolated on a yield curve which matches the duration of Equinor's payment portfolio for earned benefits, which was calculated to be 15.8 years at the end of 2019. Social security tax is calculated based on a pension plan's net funded status and is included in the defined benefit obligation.

Equinor 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 tables in this note presents pension costs on a gross basis, before allocation to licence partners. In the Consolidated statement of income, the pension costs in Equinor ASA are presented net of costs allocated to licence partners.

Net pension cost
(in USD million) | 2019 | 2018 | 2017
Current service cost | 206 | 214 | 242
Losses/(gains) from curtailment, settlement or plan amendment | 3 | 20 | 15
Actuarial(gains)/losses related to termination benefits | (0) | 0 | (1)
Notional contribution plans | 56 | 55 | 51
Defined benefit plans | 265 | 289 | 308
Defined contribution plans | 182 | 173 | 162
Total net pension cost | 446 | 462 | 469

In addition to the pension cost presented in the table above, financial items related to defined benefit plans are included in the statement of income within Net financial items. Interest cost and changes in fair value of notional assets of USD 260 million in 2019, and USD 167 million in 2018. Interest income of USD 142 million has been recognised in 2019, and USD 127 million in 2018.

216 Equinor, Annual Report on Form 20-F 2019

(in USD million) | 2019 | 2018
Defined benefit obligations (DBO) |  |
Defined benefit obligations at 1 January | 8,176 | 8,286
Current service cost | 206 | 214
Interest cost | 263 | 182
Actuarial (gains)/losses - Financial assumptions | (23) | 174
Actuarial (gains)/losses - Experience | 6 | (27)
Benefits paid | (236) | (219)
Losses/(gains) from curtailment, settlement or plan amendment | 0 | (1)
Paid-up policies | (14) | (18)
Foreign currency translation | (71) | (469)
Changes in notional contribution liability | 56 | 55
Defined benefit obligations at 31 December | 8,363 | 8,176
Fair value of plan assets |  |
Fair value of plan assets at 1 January | 5,187 | 5,687
Interest income | 143 | 136
Return on plan assets (excluding interest income) | 384 | (135)
Company contributions | 127 | 49
Benefits paid | (195) | (217)
Paid-up policies and personal insurance | (13) | (18)
Foreign currency translation | (44) | (315)
Fair value of plan assets at 31 December | 5,589 | 5,187
Net pension liability at 31 December | (2,774) | (2,990)
Represented by: |  |
Asset recognised as non-current pension assets (funded plan) | 1,093 | 831
Liability recognised as non-current pension liabilities (unfunded plans) | (3,867) | (3,821)
DBO specified by funded and unfunded pension plans | 8,363 | 8,176
Funded | 4,496 | 4,359
Unfunded | 3,867 | 3,817
Actual return on assets | 527 | 1

Equinor recognised an actuarial gain from changes in financial assumptions in 2019. The actuarial loss in 2018 was mainly due to a higher expected rate of pension increase and higher expected compensation increase.

Actuarial losses and gains recognised directly in Other comprehensive income (OCI) |  |  |
(in USD million) | 2019 | 2018 | 2017
Net actuarial (losses)/gains recognised in OCI during the year | 401 | (282) | 331
Actuarial (losses)/gains related to currency effects on net obligation and foreign exchange translation | 27 | 172 | (158)
Tax effects of actuarial (losses)/gains recognised in OCI | (98) | 22 | (38)
Recognised directly in OCI during the year net of tax | 330 | (88) | 135
Cumulative actuarial (losses)/gains recognised directly in OCI net of tax | (812) | (1,141) | (1,053)

Equinor, Annual Report on Form 20-F 2019 217

Actuarial assumptions
| Assumptions used to determine benefit costs in % | Assumptions used to determine benefit obligations in %
| 2019 | 2018 | 2019 | 2018
Discount rate | 2.75 | 2.50 | 2.25 | 2.75
Rate of compensation increase | 2.75 | 2.25 | 2.25 | 2.75
Expected rate of pension increase | 2.00 | 1.75 | 1.50 | 2.00
Expected increase of social security base amount (G-amount) | 2.75 | 2.25 | 2.25 | 2.75
Weighted-average duration of the defined benefit obligation |  |  | 15.8 | 15.9

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

Expected attrition at 31 December 2019 was 0.3% and 3.3% for employees between 50-59 years and 60-67 years, and 0.2% and 3.2% in 2018. The attrition rate for the age group 60-67 years represent employees with immediate withdrawal of vested pension, thus remaining in the scheme.

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 2019.

| 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 2019 | (596) | 675 | 213 | (202) | 518 | (471) | 298 | (325)
Service cost 2020 | (21) | 24 | 11 | (10) | 15 | (14) | 7 | (8)

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.

218 Equinor, Annual Report on Form 20-F 2019

Pension assets

The plan assets related to the defined benefit plans were measured at fair value. Equinor Pension invests in both financial assets and real estate.

The table below presents the portfolio weighting as approved by the board of Equinor Pension for 2019. The portfolio weight during a year will depend on the risk capacity.

Pension assets on investments classes | Target portfolio weight
(in %) | 2019 | 2018
Equity securities | 32.3 | 36.5 | 27 - 38
Bonds | 46.4 | 44.9 | 40 - 53
Money market instruments | 14.5 | 12.3 | 0 - 29
Real estate | 6.3 | 6.3 | 5 - 10
Other assets | 0.5 | 0.0 |
Total | 100.0 | 100.0 |

In 2019 92% of the equity securities and 6% of bonds had quoted market prices in an active market. 8% of the equity securities, 94% of bonds and 100% of money market instruments had market prices based on inputs other than quoted prices. If quoted market prices are not available, fair values are determined from external calculation models based on market observations from various sources.

In 2018 92% of the equity securities, 31% of bonds and 55% of money market instruments had quoted market prices in an active market. 8% of the equity securities, 69% of bonds and 45% of money market instruments had market prices based on inputs other than quoted prices.

For definition of the various levels, see note 26 Financial instruments: fair value measurement and sensitivity analysis of market risk.

### 20 Provisions and other liabilities

(in USD million) | Asset retirement obligations | Claims and litigations | Other provisions and liabilities | Total
Non-current portion at 31 December 2018 | 12,544 | 905 | 2,503 | 15,952
Current portion at 31 December 2018 reported as trade, other payables and provisions | 65 | 56 | 103 | 224
Provisions and other liabilities at 31 December 2018 | 12,609 | 961 | 2,606 | 16,175
New or increased provisions and other liabilities | 563 | (2) | 1,130 | 1,692
Change in estimates | (115) | 5 | (143) | (253)
Amounts charged against provisions and other liabilities | (218) | (0) | (268) | (485)
Effects of change in the discount rate | 1,779 | - | 49 | 1,828
Reduction due to divestments | (175) | - | - | (175)
Accretion expenses | 456 | - | - | 456
Reclassification and transfer | (92) | 0 | 113 | 21
Currency translation | (88) | (0) | (9) | (96)
Provisions and other liabilities at 31 December 2019 | 14,719 | 965 | 3,479 | 19,163
Non-current portion at 31 December 2019 | 14,616 | 54 | 3,282 | 17,951
Current portion at 31 December 2019 reported as trade, other payables and provisions | 104 | 910 | 197 | 1,211

The line item New or increased provisions and other liabilities includes additional provisions incurred in the period, liabilities and contingent considerations related to acquisitions, and an onerous transportation contract in North America.

The timing of cash outflows of asset retirement obligations depends on the expected production cease at the various facilities.

Equinor, Annual Report on Form 20-F 2019 219

The asset retirement obligation (ARO), a legal or constructive obligation to decommission and remove on- and offshore installations at the end of the production period, is of nature long term and with uncertainty to timing, discount rate, estimates, currency, regulations and market situation.

In certain production sharing agreements (PSA), Equinor’s estimated share of ARO is paid into an escrow account over the producing life of the field. Equinor presents asset retirement obligations net of these payments in the consolidated balance sheet.

The claims and litigations category mainly relates to expected payments for unresolved claims. The timing and amounts of potential settlements in respect of these claims are uncertain and dependent on various factors that are outside management's control. The main change in the caption claims and litigations relates to the reclassification of Agbami claim from long-term to short-term. For further information on the development of other contingent liabilities, see note 24 Other commitments, contingent liabilities and contingent assets.

The other provision and other liabilities category relates to liabilities for contingent consideration, expected net payments on onerous contracts, and other. For further information, see note 4 Acquisitions and disposals. The line item reclassification and transfer mainly relates to Equinor’s divestment of the ownership interests in offshore licences, where certain commitments related to asset removal were retained by Equinor. The previous ARO for the licences has been reclassified and included under Other provisions and liabilities.

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

Expected timing of cash outflows
(in USD million) | Asset retirement obligations | Other provisions and liabilites, including claims and litigations | Total
2020 - 2024 | 1,410 | 3,119 | 4,529
2025 - 2029 | 1,247 | 657 | 1,904
2030 - 2034 | 3,605 | 81 | 3,686
2035 - 2039 | 3,719 | 156 | 3,875
Thereafter | 4,738 | 430 | 5,168
At 31 December 2019 | 14,719 | 4,443 | 19,163

### 21 Trade, other payables and provisions

| At 31 December
(in USD million) | 2019 | 2018
Trade payables | 3,047 | 2,532
Non-trade payables and accrued expenses | 2,405 | 2,604
Joint venture payables | 2,628 | 2,254
Payables to equity accounted associated companies and other related parties | 947 | 725
Total financial trade and other payables | 9,027 | 8,115
Current portion of provisions and other non-financial payables | 1,423 | 255
Trade, other payables and provisions | 10,450 | 8,369

Included in current portion of provisions and other non-financial payables are certain provisions that are further described in note 20 Provisions and other liabilities and in note 24 Other commitments, contingent liabilities and contingent assets. For information regarding currency sensitivities, see note 26 Financial instruments: fair value measurement and sensitivity analysis of market risk. For further information on payables to equity accounted associated companies and other related parties, see note 25 Related parties.

###

220 Equinor, Annual Report on Form 20-F 2019

### 22 Leases

Equinor leases certain assets, notably drilling rigs, transportation vessels, storages and office facilities for operational activities. Equinor is mostly a lessee and the use of leases serves operational purposes rather than as a tool for financing.

Certain leases, such as land bases, supply vessels, helicopters and office buildings are entered into by Equinor for subsequent allocation of costs to licences operated by Equinor. These lease liabilities are recognized on a gross basis in the balance sheet, income statement and statement of cash flows when Equinor is considered to have the primary responsibility for the full lease payments. Lease liabilities related to assets dedicated to specific licences, where each licence participants are considered to have the primary responsibility for lease payments, are reflected net of partner share. This would typically involve drilling rigs dedicated to specific licences on the Norwegian continental shelf.

Information related to lease payments and lease liabilities |  |
(in USD million) |  | Lease liabilities
Lease liabilities at 1 January 2019 |  | 4,660
New leases, including remeasurements and cancellations |  | 861
Gross lease payments | (1,280) |
Lease interest | 144 |
Lease down-payments | (1,136) | (1,136)
Currency |  | (47)
Lease liability at 31 December 20191) |  | 4,339
1) Of which USD 1,148 million is presented within current Finance debt and USD 3,191 million is presented within non-current Finance debt.
Lease expenses not included in lease liabilities |  |
(in USD million) |  | 2019
Short-term lease expenses |  | 435

Payments related to short term leases are mainly related to drilling rigs and transportation vessels, for which a significant portion of the lease costs have been included in the cost of other assets, such as rigs used in exploration or development activities. Variable lease expense and lease expense related to leases of low value assets are not significant.

In 2019, Equinor recognized revenues of USD 264 million related to lease costs recovered from licence partners related to lease contracts being recognized gross by Equinor. In addition, Equinor received repayments of USD 34 million related to finance subleases. Total finance sublease receivables at 31 December 2019 were USD 54 million.

Commitments relating to lease contracts which had not yet commenced at 31 December 2019 are included within other commitments in note 24 Commitments, contingent liabilities and contingent assets.

A maturity profile for lease liabilities is disclosed in note 5 Financial risk and capital management.

Equinor, Annual Report on Form 20-F 2019 221

Information related to Right of use assets |  |  |  |
(in USD million) | Drilling rigs | Vessels | Lands and buildings | Storage facilities | Other | Total
Right of use assets at 1 January 2019 | 1,212 | 1,302 | 1,537 | 72 | 249 | 4,372
Additions including remeasurements and cancellations1) | 160 | 439 | 59 | 141 | 56 | 855
Depreciation and impairment1) | (398) | (413) | (225) | (57) | (81) | (1,174)
Currency and other | (23) | (8) | (6) | 0 | (5) | (42)
Right of use assets at 31 December 2019 | 951 | 1,320 | 1,365 | 156 | 219 | 4,011
1) USD 375 million of the depreciation cost have been allocated to activities being capitalised.

The right of use assets are included within the line item Property, plant and equipment in the Consolidated balance sheet. See also note 10 Property, plant and equipment.

See note 23 Implementation of IFRS 16 Leases for information regarding the change in accounting policy for leases, including transition effects and policy choices made upon implementing this standard.

### 23 Implementation of IFRS 16 Leases

###

This disclosure note presents the implementation impact of the new accounting standard IFRS 16 Leases, which was implemented by Equinor on 1 January 2019. Reference is made to note 22 Leases for lease related information required under IFRS 16 for the year 2019.

The new standard 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. In the financial statement of lessees, IFRS 16 requires recognition in the balance sheet for each contract that meets its definition of a lease as right-of-use (RoU) asset and a lease liability, while lease payments are reflected as interest expense and a reduction of lease liabilities. The RoU assets are depreciated over the shorter of each contract’s term and the assets useful life.

IFRS 16 has replaced IAS 17 Leases, under which only leases considered to be financing were capitalized while operating leases were expensed as incurred and reported as off-balance commitments.

Upon implementation of IFRS 16, the following main implementation and application policy choices were made by Equinor:

IFRS 16 transition choices

· IFRS 16 has been implemented according to the modified retrospective method, without restatement of prior periods’ reported figures, which are still presented in accordance with IAS 17.

· Contracts already classified either as leases under IAS 17 or as non-lease service arrangements have maintained their respective classifications upon the implementation of IFRS 16 (“grandfathering of contracts”).

· Leases for which the lease term ends within 12 months from 1 January 2019 were not reflected as lease liabilities under IFRS 16.

· RoU assets have for most contracts initially been reflected at an amount equal to the corresponding lease liability. Prior onerous contract provisions related to operating leases have been reversed and have reduced the value of the corresponding RoU asset recognized in the opening balance under IFRS 16.

IFRS 16 policy application choices

· Short term leases (12 months or less) and leases of low value assets are not reflected in the balance sheet but are expensed or (if appropriate) capitalised as incurred, depending on the activity in which the leased asset is used.

· Non-lease components within lease contracts will be accounted for separately for all underlying classes of assets and reflected in the relevant expense category or (if appropriate) capitalised as incurred, depending on the activity involved.

222 Equinor, Annual Report on Form 20-F 2019

Impact of IFRS 16 on the Consolidated balance sheet

The implementation of IFRS 16 on 1 January 2019 has increased the Consolidated balance sheet by adding lease liabilities of USD 4.2 billion and RoU assets of USD 4.0 billion. The difference between the recognized lease liabilities and the right of use assets relates mainly to the derecognition of former onerous contract provisions which are now presented as impairment of RoU assets, and the recognition of financial sublease receivables. Equinor’s equity was not impacted by the implementation of IFRS 16. The following line items in the balance sheet have been impacted as a result of the new accounting standard:

| At 31 December |  | IFRS 16 | At 1 January
(in USD million) | 2018 |  | Adjustments | 2019
Property, plant and equipment | 65,262 |  | 3,992 | 69,254
Prepayments and financial receivables | 1,033 |  | 52 | 1,085
Total non-current assets |  |  | 4,044 |
Trade and other receivables | 8,998 |  | 45 | 9,043
Total current assets |  |  | 45 |
Total assets |  |  | 4,089 |
Non-current finance debt | 23,264 |  | 3,159 | 26,423
Provisions | 15,952 |  | (105) | 15,847
Total non-current liabilities |  |  | 3,054 |
Trade and other payables and provisions | 8,369 |  | (34) | 8,335
Current finance debt | 2,463 |  | 1,069 | 3,532
Total current liabilities |  |  | 1,035 |
Total liabilities |  |  | 4,089 |

Including former finance leases, already recognized in the balance sheet under IAS 17, the lease liabilities and RoU assets at 1 January 2019 were USD 4.7 billion and USD 4.4 billion respectively.

The table below shows a maturity profile, based on undiscounted cash flows, for Equinor’s lease liabilities at 1 January 2019:

(in USD million) | 2019 | 2020-2021 | 2022-2023 | 2024-2028 | After 2028 | Total
Lease payments | 1,133 | 1,655 | 921 | 1,086 | 472 | 5,267

The weighted average incremental borrowing rate used when calculating lease liabilities at 1 January 2019 was 3.1%.

The table below shows the impact on the balance sheet at 31 December 2019 from the implementation of IFRS 16:

| At 31 December 2019
(in USD million) | IFRS as reported (IFRS 16) | IAS 17 | Difference
Total non-current assets | 93,285 | 89,546 | 3,738
Total current assets | 24,778 | 24,750 | 29
Total assets | 118,063 | 114,296 | 3,767
Total equity | 41,159 | 41,235 | (76)
Total non-current liabilities | 57,346 | 54,565 | 2,781
Total current liabilities | 19,557 | 18,496 | 1,061
Total equity and liabilities | 118,063 | 114,296 | 3,767

Equinor, Annual Report on Form 20-F 2019 223

Impact of IFRS 16 on the Consolidated statement of income

Under IFRS 16, lease costs consist of interest expense on the lease liability, presented within Interest expense and other financial expenses, and depreciation of right of use assets, presented within Depreciation, amortisation and net impairment losses.

For leases allocated to activities which are capitalised, the costs will continue to be expensed as before, through depreciation of the asset involved or through the subsequent expensing of capitalised exploration.

Lease costs recovered from licence partners on Equinor operated licences, when the lease liability is reported gross by Equinor, are presented within Revenues. Under IAS 17, these costs only reflected Equinor’s proportional share.

The table below shows the difference between the reported Consolidated statement of income under IFRS 16 and an estimated income statement for 2019 presented under the former principles of IAS 17:

| Full year 2019
(in USD million) | IFRS as reported (IFRS 16) | IAS 17 | Difference
Total revenues and other income | 64,357 | 64,127 | 230
Purchases [net of inventory variation] | (29,532) | (29,532) | 0
Operating expenses | (9,660) | (10,179) | 519
Selling, general and administrative expenses | (809) | (825) | 16
Depreciation, amortisation and net impairment losses | (13,204) | (12,476) | (728)
Exploration expenses | (1,854) | (1,854) | (0)
Net operating income/(loss) | 9,299 | 9,261 | 38
Net financial items | (7) | 87 | (94)
Income/(loss) before tax | 9,292 | 9,348 | (56)
Income tax | (7,441) | (7,421) | (20)
Net income/(loss) | 1,851 | 1,927 | (76)

Impact of IFRS 16 on the Consolidated statement of cash flows

In the cash flow statement, down-payment of lease liabilities are presented as a cash flow used in financing activities under IFRS 16, while interests are presented within cash flow used in operating activities. Under IAS 17, operating lease costs were presented within cash flows from operations or investing cash flows respectively, depending on whether the leased asset is used in operating activities or activities being capitalised.

In situations where Equinor is considered to have the primary responsibility for a lease liability, and consequently reflects the lease liability on a gross basis, any corresponding payments from partner recharges recognised as other revenue in the income statement will also be reported on a gross basis in the statement of cash flows, with the gross lease down-payments being recognised as a financing cash flow and the revenues from partners recognised within operating cash flows.

Consequently, cash flows from operating activities will increase, cash flow used in investing activities will decrease and cash flow used in financing activities will increase due to the implementation of IFRS 16.

224 Equinor, Annual Report on Form 20-F 2019

The table below shows the difference between the reported cash flows under IFRS 16 and an estimate for how the cash flows for 2019 would have been presented under the former principles of IAS 17:

| Full year 2019
(in USD million) | IFRS as reported (IFRS 16) | IAS 17 | Difference
Cash flows provided by operating activities | 13,749 | 13,062 | 687
Cash flows used in investing activities | (10,594) | (11,003) | 409
Cash flows provided by/(used in) financing activities | (5,496) | (4,400) | (1,096)
Net increase/(decrease) in cash and cash equivalents | (2,341) | (2,341) | 0

Impact of IFRS 16 on the segment reporting

IFRS 16 has not changed how Equinor’s management monitors and follows up lease contracts used in its business operations. Therefore, the E&P segments as well as the MMP segment continue to be presented without reflecting IFRS 16 lease accounting, while all lease contracts are presented within the Other segment. In the E&P and MMP segments, the cost of leases is presented as operating expenses rather than depreciation and interests. A corresponding credit has been recognised in the Other segment to offset the lease costs recognised in the E&P and MMP segments.

Accounting interpretations and judgments related to the IFRS 16 application

IFRS 16 in general, as well as the policy application choices made, involve several accounting interpretations and the application of judgement impacts Equinor’s Consolidated financial statements. The accounting judgments and interpretations which most significantly affected the implementation of IFRS 16 in Equinor are summarised below.

Distinguishing operators and joint operations as lessees, including sublease considerations
The most significant accounting judgment in Equinor’s application of IFRS 16 has been and remains distinguishing between the joint operation (licences) or the operator as the relevant lessee in upstream activity lease contracts, and consequently whether such contracts are to be reflected gross (100%) in the operator’s financial statements, or according to each joint operation partner’s proportionate share of the lease.

In the oil and gas industry, where activity frequently is carried out through joint arrangements or similar arrangements, the application of IFRS 16 requires evaluations of whether the joint arrangement or its operator is the lessee in each lease agreement.

In many cases where an operator is the sole signatory to a lease contract of an asset to be used in the activities of a specific joint operation, the operator does so implicitly or explicitly on behalf of the joint arrangement. In certain jurisdictions, and importantly for Equinor this includes the Norwegian continental shelf (NCS), the concessions granted by the authorities establish both a right and an obligation for the operator to enter into necessary agreements in the name of the joint operations (licences).

As is the customary norm in upstream activities operated through joint arrangements, the operator will manage the lease, pay the lessor, and subsequently re-bill the partners for their share of the lease costs. In each such instance, it is necessary to determine:

· Whether the operator is the sole lessee in the external lease arrangement, and if so, whether the billings to partners may represent sub-leases, or;

· Whether it is in fact the joint arrangement which is the lessee, with each participant accounting for its proportionate share of the lease.

Depending on facts and circumstances in each case, the conclusions reached may vary between contracts and legal jurisdictions.

In summary, Equinor has recognised lease liabilities based on the principles described below. In the following, the term “licence” references non-incorporated joint operations and similar arrangements.

Leases to be recognised by Equinor as the operator of a licence

Where all partners in a licence are considered to share the primary responsibility for lease payments under a contract, the related lease liability and RoU asset will be recognised net by Equinor, on the basis of Equinor’s participation interest in the licence. Such instances include contracts where all licence partners have co-signed a lease contract and situations where Equinor as the operator of the licence has been given a legally binding mandate to sign the external lease contract on behalf of the licence partners, provided that this mandate makes all licence participants primary liable for the external lease liability.

Equinor has recognised a lease liability on a gross (100%) basis when it is considered to have the primary responsibility for the full external lease payments. When a financial sublease is considered to exist between Equinor and a licence, Equinor has derecognised a

Equinor, Annual Report on Form 20-F 2019 225

portion of the RoU asset equal to the non-operator’s interests in the lease, and instead recognised a corresponding financial lease receivable. A financial sublease will typically exist where Equinor enters into a contract in its own name, where it has the primary responsibility for the external lease payments, where the leased asset is to be used on one specific licence, and where the costs and risks related to the use of this asset are carried by that specific licence.

Where Equinor reports its lease liabilities on a gross basis, due to being considered to have the primary responsibility for the external lease payment, and where the use of the leased asset on a licence is not considered a financial sublease, Equinor will recognise the related RoU asset on a gross basis. Lease payments recovered by Equinor from its licence partners based on their proportionate shares of the lease will be recognised as other revenues. Such expenses have under the previous lease accounting rules been reflected net by Equinor, on the basis of Equinor’s net participation interest in the licence. Expenses which are not included in a recognised lease obligation, such as payments for short term leases, non-lease components and variable lease payments, will continue to be reported net in Equinor’s statement of income, on the basis of Equinor’s net participation interest.

Leases to be recognised by Equinor as a non-operator of a licence

As a non-operating licence participant in an oil and gas licence, Equinor will recognise its proportionate share of a lease when Equinor is considered to share the primary responsibility for a licence committed lease liability. This includes contracts where Equinor has co-signed a lease contract and contracts for which the operator has been given a legally binding mandate to sign the external lease contract on behalf of the licence partners.

Equinor will also recognise its proportionate share when a lease contract is entered in to by the operator of a licence, and where the operator’s use of the leased asset represents a sublease from the operator to the licence. A sublease is considered to exist where the operator agrees with its licence partners that an identified asset is committed to be used solely in the operations of the specific licence for a specified period of time, and where the use of the asset is deemed to be controlled jointly by the licence partnership.

Recognition of rig sharing arrangements

As a significant operator on the NCS, Equinor might sign lease contracts on behalf of one or more individual licences which have committed to use a leased rig for specific periods of time. A rig sharing arrangement will determine where and when the rig will be used throughout the contract period. When a licence is considered a lessee in a rig sharing arrangement, the licence is considered a lessee for its respective portion of the full lease period. Accordingly, Equinor will account for these lease contracts from a licence perspective, both with regards to considering when to use the short-term exemption from IFRS 16’s requirements, and when determining the commencement of the lease.

When a rig lease is entered in Equinor’s own name, the lease liability will be recognised in Equinor’s Consolidated balance sheet on a gross (100%) basis. However, Equinor will not recognise any lease liability for periods where the rig is assigned to another party, in effect transferring both the legal and economic right to use the leased asset and the primary responsibility for lease payments under the contract to this other party.

When a leased asset is assigned to a licence for two or more non-consecutive periods within the same contract, Equinor will account for these non-consecutive periods in combination, both when considering whether to use the short-term exemption, and when determining the commencement of the lease.

Separation of lease and non-lease components

Many of Equinor’s lease contracts, such as rig and vessel leases, involve several additional services and components, including personnel cost, maintenance, drilling related activities, and other items. For a number of these contracts, the additional services represent a not inconsiderable portion of the total contract value. Where the additional services are not separately priced, the consideration paid has been allocated based on the relative stand-alone prices of the lease and non-lease components. Equinor’s previous practice for lease commitments reporting was to not distinguish fixed non-lease components within a lease contract from the actual lease components. The choice made under IFRS 16 to account for non-lease components separately for all classes of assets consequently represents a change in Equinor’s lease accounting.

Evaluating the impact of option periods on lease terms
Many of Equinor’s major leases, such as leases of vessels, rigs and buildings, include options to extend the lease term. Under IFRS 16, the evaluation of whether each lease contract’s extension options are considered reasonably certain to be exercised, are made at commencement of the leases and subsequently when facts and circumstances which are under the control of Equinor require it. In Equinor’s view, the term ‘reasonably certain’ implies a probability level significantly higher than ‘probable’, and this has been reflected in Equinor’s evaluations.

Distinguishing fixed and variable lease payment elements
Under IFRS 16, fixed and in-substance fixed lease payments are to be included in the commencement date computation of a lease liability, while variable payments dependent on use of the asset are not. Particularly as regards drilling rig leases, Equinor’s lease contracts include fixed rates for when the asset in question is in operation, and various alternative, lower rates (“stand-by rates”) for periods where the asset is engaged in specified activities or idle, but still under contract. In general, variability in lease payments under

226 Equinor, Annual Report on Form 20-F 2019

these contracts has its basis in different use and activity levels, and the variable elements have been determined to relate to non-lease components only. Consequently, the lease components of these contractual payments are considered fixed for the purposes of IFRS 16.

Determining the incremental borrowing rate to be used as discount factor
In establishing Equinor’s lease liabilities, the incremental borrowing rates used as discount factors in discounting payments have been established based on a consistent approach reflecting the Group’s borrowing rate, the currency of the obligation, the duration of the lease term, and the credit spread for the legal entity entering into the lease contract.

Reconciliation of IFRS 16 lease liabilities to IAS 17 operating lease commitments

Under IAS 17, Equinor disclosed the following commitments related to operating leases at 31 December 2018:

| Operating leases
(in USD million) | Rigs | Vessels | Land and buildings | Storage | Other | Total
2019 | 998 | 662 | 143 | 83 | 113 | 2,001
2020 | 523 | 599 | 141 | 60 | 84 | 1,406
2021 | 349 | 534 | 140 | 41 | 50 | 1,114
2022 | 372 | 384 | 136 | 40 | 28 | 960
2023 | 280 | 316 | 198 | 25 | 13 | 832
2024-2028 | 75 | 789 | 544 | 68 | 50 | 1,527
2029-2033 | - | 131 | 223 | 6 | 17 | 376
Thereafter | - | - | 32 | - | 7 | 39
Total future minimum lease payments | 2,597 | 3,414 | 1,558 | 322 | 363 | 8,253

The table below presents a reconciliation between operating lease commitments at 31 December 2018 under IAS 17 Leases and the lease liability recognised under IFRS 16 Leases:

(in USD million) |
Operating lease commitments (IAS 17) at 31 December 2018 | 8,253
Short term leases and leases expiring during 2019 | (666)
Non-lease components | (1,469)
Commitments related to leases not yet commenced | (2,116)
Leases reported gross vs net | 711
Effect of discounting | (485)
Finance leases (IAS 17) included in the balance sheet at 31 December 2018 | 432
Lease liability reported under IFRS 16 at 1 January 2019 | 4,660

Reference is made to the policy descriptions above for explanations of the reconciling items. Leases not yet commenced relates to situations where a contract is signed, but where Equinor has not yet obtained the right to control an underlying asset, either on its own or through a joint operation.

Extension and termination options within the lease contracts are in all material respect reported on the same basis as under IAS 17 Leases. Most leases are used in operational activities. Extension options which are considered reasonably certain to be exercised are included in the reported lease liability. These are mainly those extension options for which operational decisions have been made which make the leased assets vital to the continued relevant business activities.

###

Equinor, Annual Report on Form 20-F 2019 227

### 24 Other commitments, contingent liabilities and contingent assets

Contractual commitments

Equinor had contractual commitments of USD 5,205 million at 31 December 2019. The contractual commitments reflect Equinor's proportional share and mainly comprise construction and acquisition of property, plant and equipment as well as committed investments/funding or resources in equity accounted entities.

As a condition for being awarded oil and gas exploration and production licences, participants may be committed to drill a certain number of wells. At the end of 2019, Equinor was committed to participate in 38 wells, with an average ownership interest of approximately 44%. Equinor's share of estimated expenditures to drill these wells amounts to USD 663 million. Additional wells that Equinor may become committed to participating in depending on future discoveries in certain licences are not included in these numbers.

Other long-term commitments

Equinor 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 Equinor the obligation to pay for the agreed-upon service or commodity, irrespective of actual use. The contracts' terms vary, with durations of up to 2044.

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 Equinor to entities accounted for in the Equinor group using the equity method are included in the table below with Equinor’s full proportionate share. For assets (such as pipelines) that are included in the Equinor accounts through joint operations or similar arrangements, and where consequently Equinor’s share of assets, liabilities, income and expenses (capacity costs) are reflected on a line-by-line basis in the Consolidated financial statements, the amounts in the table include the net commitment payable by Equinor (i.e. Equinor’s proportionate share of the commitment less Equinor's ownership share in the applicable entity).

The table below includes USD 3,009 million related to the non-lease components of lease agreements reflected in the accounts according to IFRS 16, as well as leases not yet commenced. The latter includes approximately USD 300 million related to crude tankers to be applied in future under Equinor’s long-term charter agreement with Teekay over the lifetime of producing fields in the North Sea.

Nominal minimum other long-term commitments at 31 December 2019:

(in USD million) |
2020 | 2,165
2021 | 2,082
2022 | 1,845
2023 | 1,581
2024 | 1,279
Thereafter | 4,518
Total | 13,470

Guarantees

Equinor has guaranteed for its proportionate share of an associate’s long-term bank debt, payment obligations under contracts, and certain third-party obligations. The total amount guaranteed at year-end 2019 is USD 1,2 billion. The book value of the guarantees are immaterial.

Contingent liabilities and contingent assets

Redetermination process for Agbami field

Through its ownership in OML 128 in Nigeria, Equinor is a party to an ownership interest redetermination process for the Agbami field, which will reduce Equinor’s ownership interest. A non-binding agreement for settlement of the redetermination was reached during the fourth quarter of 2018. The parties to the non-binding agreement have continued to work towards a final settlement and agreed-upon ownership percentage adjustment during 2019. Equinor’s provision for the best estimate of the impact of the redetermination process as of year-end 2019 amounts to USD 853 million. During 2019 the provision has been reclassified from long term Provisions to short term Trade and other payables in the Consolidated balance sheet, due to expectations that there will be a cash outflow in the process within a year. The impact of the redetermination process on the Consolidated statement of income was immaterial in 2019.

228 Equinor, Annual Report on Form 20-F 2019

Price review arbitration

Some long-term gas sales agreements contain price review clauses, which in certain cases lead to claims subject to arbitration. The range of exposure related to ongoing arbitration has been estimated to approximately USD 1.3 billion for gas delivered prior to year-end 2019. Based on Equinor’s assessment, no provision is included in the Consolidated financial statements at year-end 2019. The timing of resolution is uncertain but is estimated to 2020. Price review arbitration related changes in provisions throughout 2019 are immaterial and have been reflected in the Consolidated statement of income as adjustments to revenue from contracts with customers.

Deviation notices from Norwegian tax authorities

In the fourth quarter of 2019, Equinor received a draft decision from Norwegian tax authorities in the matter related to internal pricing on certain transactions between Equinor Service Center Belgium (ESCB) and Equinor ASA. The main issue in this matter relates to ESCB’s capital structure and its compliance with the arm length’s principle. The draft decision covers the fiscal years 2012 to 2016 and represents an exposure of approximately USD 180 million. Equinor is currently evaluating the draft decision and will respond to the tax authorities. It continues to be Equinor’s view that arm’s length pricing has been applied and that the group has a strong position, and at year-end 2019 no amounts have consequently been provided for this matter in the accounts.

In February 2018, Equinor received a notice of deviation from Norwegian tax authorities related to an ongoing dispute regarding the level of Research & Development cost to be allocated to the offshore tax regime. The maximum exposure in this matter is estimated to approximately USD 500 million. Equinor has provided for its best estimate in the matter.

A dispute between the Federal Government of Nigeria and the Governments of Rivers, Bayelsa and Akwa Ibom States in Nigeria

In October 2018, Supreme Court of Nigeria rendered a judgement in a dispute between the Federal Government of Nigeria and the Governments of Rivers, Bayelsa and Akwa Ibom States in favour of the latter. The Supreme Court judgement provides for potential retroactive adjustment of certain production sharing contracts in favour of the Federal Government, including OML 128 (Agbami). Equinor sees no merit to the case. No provision has been made for this matter.

Dispute concerning termination of a long-term contract for the drilling rig COSL Innovator

In January 2020, Equinor on behalf of the Troll licence signed a settlement agreement with COSL Offshore Management AS in the dispute over the 2016 termination of the long-term contract for the rig COSL Innovator. Equinor’s share of the agreed settlement payment amounts to USD 57.5 million, which has been reflected in Operating expenses in the E&P Norway segment in 2019.

Dispute with Brazilian tax authorities

Brazilian tax authorities have issued an updated tax assessment for 2011 for Equinor’s Brazilian subsidiary which was party to Equinor’s divestment of 40% of the Peregrino field to Sinochem at that time. The assessment disputes Equinor’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. Equinor disagrees with the assessment and has provided responses to this effect. The ongoing 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. Equinor 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.

Suit for an annulment of Petrobras’ sale of the interest in BM-S-8 to Equinor

In March 2017, the Union of Workers of Oil Tankers of Sergipe (Sindipetro) filed a class action suit against Petrobras, Equinor, and ANP - the Brazilian Regulatory Agency - to seek annulment of Petrobras’ sale of the interest and operatorship in BM-S-8 to Equinor, which was closed in November 2016 after approval by the partners and authorities. There was also an injunction request to suspend the assignment which was granted in April 2017 by a federal judge and was subsequently lifted by the Federal Regional Court. The cases are progressing through the court system. At the end of 2019 the acquired interest remains in Equinor’s balance sheet as intangible assets of the Exploration & Production International (E&P International) segment. For further information about Equinor’s acquisitions and divestments in BM-S-8, reference is made to note 4 Acquisitions and disposals

ICMS indirect tax (Imposto sobre Circulaçao de Mercadorias - Tax on the Circulation of Goods and Certain Services)

In Brazil, the State of Rio de Janeiro in 2015 published a law whereby crude oil extraction as of March 2016 would be subject to a 20% ICMS indirect tax (Imposto sobre Circulaçao de Mercadorias - Tax on the Circulation of Goods and Certain Services). Equinor, in line with other affected international peer companies, are of the opinion that this tax is unconstitutional, and have initiated legal processes concerning the matter in the legal system of the State of Rio de Janeiro, with favorable decisions so far. The Brazilian Industry Association

also filed a suit with the Federal Supreme Court of Brazil challenging the law’s constitutionality. Due to the ongoing production from the Peregrino field, and more recently also from the Roncador field, Equinor’s downside exposure in connection with this case is increasing, and at year-end 2019 amounted to approximately USD 700 million. Equinor is of the opinion that the group has a strong position in the case, and no amounts have consequently been provided for this issue in the accounts. The timing of the final resolution of this matter cannot be ascertained with sufficient certainty, but the process may be expected to take several years. No payment of the ICMS will become due until a court decision is rendered declaring this law to be constitutional.

Other claims

During the normal course of its business, Equinor 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. Equinor has provided

Equinor, Annual Report on Form 20-F 2019 229

in its Consolidated financial statements for probable liabilities related to litigation and claims based on its best estimate. Equinor does not expect that its financial position, results of operations or cash flows will be materially affected by the resolution of these legal proceedings. Equinor 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 other than those related to income tax are reflected within note 20 Provisions and other liabilities. Uncertain income tax related liabilities are reflected as current tax payables or deferred tax liabilities as appropriate, while uncertain tax assets are reflected as current or deferred tax assets.

### 25 Related parties

Transactions with the Norwegian State

The Norwegian State is the majority shareholder of Equinor and also holds major investments in other Norwegian companies. As of
31 December 2019, the Norwegian State had an ownership interest in Equinor of 67.0% (excluding Folketrygdfondet, the Norwegian national insurance fund, of 3.4%). This ownership structure means that Equinor participates in transactions with many parties that are under a common ownership structure and therefore meet the definition of a related party.

Total purchases of oil and natural gas liquids from the Norwegian State amounted to USD 7,505 million, USD 8,604 million and USD 7,352 million in 2019, 2018 and 2017, respectively. Total purchases of natural gas regarding the Tjeldbergodden methanol plant from the Norwegian State amounted to USD 36 million, USD 49 million and USD 39 million in 2019, 2018 and 2017, respectively. These purchases of oil and natural gas are recorded in Equinor ASA. In addition, Equinor 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 payables to equity accounted associated companies and other related parties 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 Equinor enters into contracts such as pipeline transport, gas storage and processing of petroleum products, with companies in which Equinor has ownership interests. Such transactions 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. Equinor payments that flowed through Gassco in this respect amounted to USD 1,396 million, USD 1,351 million and USD 1,155 million in 2019, 2018 and 2017, respectively. These payments are mainly recorded in Equinor ASA. In addition, Equinor 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 5 August 2019, Equinor reduced its ownership interest in Lundin Petroleum AB (Lundin) from 20.1% to 4.9% of the outstanding shares and votes. In the period of 1 January to 5 August 2019, total purchase of oil and related products from Lundin amounted to USD 107 million. Total purchase of oil and related products from Lundin amounted to USD 879 million and USD 176 million in 2018 and 2017, respectively. In 2018, Equinor also sold oil and related products to Lundin, at an amount of USD 296 million. The sale and purchase of oil and related products are recorded in Equinor ASA. For information concerning the divestment of Lundin shares, see note 4 Acquisitions and disposals.

Equinor leases two office buildings, located in Bergen and Harstad, owned by Equinor’s pension fund (“Equinor Pension”). The lease contracts extend to the years 2034 and 2037 and Equinor ASA has recognised lease liabilities of USD 372 million related to these contracts.

Related party transactions with management are presented in note 6 Remuneration. Management remuneration for 2019 is presented in note 4 Remuneration in the financial statements of the parent company, Equinor ASA.

###

230 Equinor, Annual Report on Form 20-F 2019

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

Financial instruments by category

The following tables present Equinor's classes of financial instruments and their carrying amounts by the categories as they are defined in IFRS 9 Financial Instruments: Classification and Measurement. For financial investments the difference between measurement as defined by IFRS 9 categories and measurement at fair value is immaterial. For trade and other receivables and payables, and cash and cash equivalents, the carrying amounts are considered a reasonable approximation of fair value. See note 18 Finance debt for fair value information of non-current bonds, bank loans and lease liabilities.

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

(in USD million) | Note | Amortised cost | Fair value through profit or loss | Non-financial assets | Total carrying amount
At 31 December 2019 |  |  |  |  |
Assets |  |  |  |  |
Non-current derivative financial instruments |  | - | 1,365 | - | 1,365
Non-current financial investments | 13 | 167 | 3,433 | - | 3,600
Prepayments and financial receivables | 13 | 1,057 | - | 157 | 1,214
Trade and other receivables | 15 | 7,374 | - | 859 | 8,233
Current derivative financial instruments |  | - | 578 | - | 578
Current financial investments | 13 | 7,050 | 377 | - | 7,426
Cash and cash equivalents | 16 | 4,478 | 700 | - | 5,177
Total |  | 20,125 | 6,452 | 1,016 | 27,593
(in USD million) | Note | Amortised cost | Fair value through profit or loss | Non-financial assets | Total carrying amount
At 31 December 2018 |  |  |  |  |
Assets |  |  |  |  |
Non-current derivative financial instruments |  | - | 1,032 | - | 1,032
Non-current financial investments | 13 | 90 | 2,365 | - | 2,455
Prepayments and financial receivables | 13 | 854 | - | 179 | 1,033
Trade and other receivables | 15 | 8,488 | - | 510 | 8,998
Current derivative financial instruments |  | - | 318 | - | 318
Current financial investments | 13 | 6,145 | 896 | - | 7,041
Cash and cash equivalents | 16 | 5,301 | 2,255 | - | 7,556
Total |  | 20,878 | 6,866 | 689 | 28,433

Equinor, Annual Report on Form 20-F 2019 231

(in USD million) | Note | Amortised cost | Fair value through profit or loss | Non-financial liabilities | Total carrying amount
At 31 December 2019 |  |  |  |  |
Liabilities |  |  |  |  |
Non-current finance debt | 18, 22 | 21,754 | - | 3,191 | 24,945
Non-current derivative financial instruments |  | - | 1,173 | - | 1,173
Trade, other payables and provisions | 21 | 9,027 | - | 1,423 | 10,450
Current finance debt | 18, 22 | 2,939 | - | 1,148 | 4,087
Dividend payable |  | 859 | - | - | 859
Current derivative financial instruments |  | - | 462 | - | 462
Total |  | 34,580 | 1,635 | 5,762 | 41,976
(in USD million) | Note | Amortised cost | Fair value through profit or loss | Non-financial liabilities | Total carrying amount
At 31 December 2018 |  |  |  |  |
Liabilities |  |  |  |  |
Non-current finance debt | 18, 22 | 23,264 | - | - | 23,264
Non-current derivative financial instruments |  | - | 1,207 | - | 1,207
Trade, other payables and provisions | 21 | 8,115 | - | 255 | 8,369
Current finance debt | 18, 22 | 2,463 | - | - | 2,463
Dividend payable |  | 766 | - | - | 766
Current derivative financial instruments |  | - | 352 | - | 352
Total |  | 34,608 | 1,559 | 255 | 36,422

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 Equinor'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 2019 |  |  |  |  |  |  |  |
Level 1 | 1,456 | 7 | - | 86 | - | (6) | (70) | 1,473
Level 2 | 1,700 | 1,139 | 377 | 461 | 700 | (1,148) | (394) | 2,835
Level 3 | 277 | 219 | - | 33 | - | (19) | - | 510
Total fair value | 3,433 | 1,365 | 377 | 578 | 700 | (1,173) | (462) | 4,817
At 31 December 2018 |  |  |  |  |  |  |  |
Level 1 | 1,088 | - | 365 | - | - | - | - | 1,453
Level 2 | 1,027 | 806 | 531 | 274 | 2,255 | (1,172) | (351) | 3,370
Level 3 | 250 | 227 | - | 44 | - | (35) | (1) | 485
Total fair value | 2,365 | 1,032 | 896 | 318 | 2,255 | (1,207) | (352) | 5,307

232 Equinor, Annual Report on Form 20-F 2019

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 Equinor this category will, in most cases, only be relevant for investments in listed equity securities and government bonds.

Level 2, fair value based on inputs other than quoted prices included within level 1, which are derived from observable market transactions, includes Equinor'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 Equinor 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 Equinor'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. Applying this assumption would have an insignificant impact on the fair value for these contracts.

The reconciliation of the changes in fair value during 2019 and 2018 for financial instruments classified as level 3 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
Opening as at 1 January 2019 | 250 | 227 | 44 | (35) | (1) | 485
Total gains and losses recognised in statement of income | (38) | (6) | 31 | 16 | 1 | 4
Purchases | 78 | - | - | - | - | 78
Settlement | (11) | - | (42) | - | - | (52)
Transfer to level 1 | (3) | - | - | - | - | (3)
Foreign currency translation differences | (0) | (2) | (0) | - | - | (3)
Closing as at 31 December 2019 | 277 | 219 | 33 | (19) | - | 510
Opening as at 1 January 2018 | 397 | 283 | 37 | - | (4) | 713
Total gains and losses recognised in statement of income | (91) | (44) | 46 | (35) | 3 | (122)
Purchases | 35 | - | - | - | - | 35
Settlement | - | - | (36) | - | - | (36)
Transfer into level 3 | (88) | - | - | - | - | (88)
Foreign currency translation differences | (3) | (13) | (3) | - | - | (18)
Closing as at 31 December 2018 | 250 | 227 | 44 | (35) | (1) | 485

During 2019 the financial instruments within level 3 have had a net increase in fair value of USD 25 million. The USD 4 million recognised in the Consolidated statement of income during 2019 are impacted by an increase of USD 24 million related to changes in fair value of certain earn-out agreements. Related to the same earn-out agreements, USD 42 million included in the opening balance for 2019 has been fully realised as the underlying volumes have been delivered during 2019.

Sensitivity analysis of market risk

Commodity price risk

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

Equinor, Annual Report on Form 20-F 2019 233

Equinor'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 2019 and 2018 at 30%, are assumed to represent a reasonably possible change based on the duration of the derivatives.

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 | 2019 | 2018
(in USD million) | - 30% | + 30% | - 30% | + 30%
At 31 December |  |  |  |
Crude oil and refined products net gains/(losses) | 569 | (563) | 275 | (230)
Natural gas and electricity net gains/(losses) | (33) | 49 | 1,157 | (1,156)

Currency risk

The following currency risk sensitivity has been calculated, by assuming a 9% reasonable change in the main exchange rates that impact Equinor’s financial accounts, based on balances at 31 December 2019. Also at 31 December 2018 a change of 9% in the main exchange rates were viewed as a reasonable change. With reference to table below, an increase in the exchange rates means that the disclosed currency has strengthened in value against all other currencies. The estimated gains and the estimated losses following from a change in the exchange rates would impact the Consolidated statement of income. For further information related to the currency risk and how Equinor manages these risks, see note 5 Financial risk and capital management.

Currency risk sensitivity | 2019 | 2018
(in USD million) | - 9% | + 9% | - 9% | + 9%
At 31 December |  |  |  |
USD net gains/(losses) | (220) | 220 | (230) | 230
NOK net gains/(losses) | 282 | (282) | 311 | (311)

Interest rate risk

The following interest rate risk sensitivity has been calculated by assuming a change of 0.6 percentage points as a reasonable possible change in interest rates at the end of 2019. A change of 0.6 percentage points in interest rates was also in 2018 viewed as a reasonable possible change. A decrease in interest rates will have an estimated positive impact on net financial items in the Consolidated statement of income, while an increase in interest rates has an estimated negative impact on net financial items in the Consolidated statement of income. For further information related to the interest risks and how Equinor manages these risks, see note 5 Financial risk and capital management.

Interest risk sensitivity | 2019 | 2018
(in USD million) | - 0.6 percentage points | + 0.6 percentage points | - 0.6 percentage points | + 0.6 percentage points
At 31 December |  |  |  |
Positive/(negative) impact on net financial items | 526 | (526) | 575 | (575)

Equity price risk

The following equity price risk sensitivity has been calculated, by assuming a 35% possible change in equity prices that impact Equinor’s financial accounts, based on balances at 31 December 2019. The estimated gains and the estimated losses following from a change in equity prices would impact the Consolidated statement of income. For further information related to the equity price risk and how Equinor manages these risks, see note 5 Financial risk and capital management.

Equity price sensitivity | 2019
(in USD million) | - 35% | + 35%
At 31 December |  |
Net gains/(losses) | (631) | 631

234 Equinor, Annual Report on Form 20-F 2019

### 27 Subsequent events

On 30 January 2020, Equinor closed a transaction with Schlumberger Production Management Holding Argentina B.V. SPM to acquire a 50% interest in SPM Argentina S.A. For further information see note 4 Acquisitions and disposals.

During the first quarter of 2020 the spread of the coronavirus (Covid-19) has impacted an increasing number of countries with increasing severity. In March 2020, the World Health Organisation (WHO) declared Covid-19 a global pandemic. During this period countries, organisations and Equinor have taken considerable measures to mitigate risk for communities, employees and business operations. The full extent, consequences, and duration of the Covid-19 pandemic and the resulting operational and economic impact for Equinor cannot be predicted at the time of publication of these Consolidated financial statements.

### 28 Condensed consolidated financial information related to guaranteed debt securities

Equinor Energy AS, a 100% owned subsidiary of Equinor ASA, is the co-obligor of certain existing debt securities of Equinor ASA that are registered under the US Securities Act of 1933 ("US registered debt securities"). As co-obligor, Equinor Energy AS fully, unconditionally and irrevocably assumes and agrees to perform, jointly and severally with Equinor ASA, the payment and covenant obligations for these US registered debt securities. In the future, Equinor ASA may from time to time issue future US registered debt securities for which Equinor Energy AS will be the co-obligor or guarantor.

The following financial information on a condensed consolidated basis provides financial information about Equinor ASA, as issuer, and Equinor Energy 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 Equinor'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 2019, 2018 and 2017, and as of 31 December 2019 and 2018.

CONDENSED CONSOLIDATED STATEMENT OF INCOME AND OTHER COMPREHENSIVE INCOME
| Equinor ASA | Equinor Energy AS | Non-guarantor subsidiaries | Consolidation adjustments | The Equinor group
Full year 2019 (in USD million)
Revenues and other income | 42,786 | 20,694 | 25,054 | (24,340) | 64,194
Net income/(loss) from equity accounted companies | 538 | (2,941) | 144 | 2,423 | 164
Total revenues and other income | 43,324 | 17,753 | 25,198 | (21,918) | 64,357
Total operating expenses | (42,014) | (10,780) | (26,003) | 23,739 | (55,058)
Net operating income/(loss) | 1,309 | 6,973 | (805) | 1,822 | 9,299
Net financial items | 545 | (318) | (381) | 147 | (7)
Income/(loss) before tax | 1,855 | 6,654 | (1,186) | 1,969 | 9,292
Income tax | (156) | (6,822) | (532) | 70 | (7,441)
Net income/(loss) | 1,699 | (168) | (1,718) | 2,038 | 1,851
Other comprehensive income/(loss) | 467 | (15) | 165 | (294) | 323
Total comprehensive income/(loss) | 2,166 | (183) | (1,553) | 1,744 | 2,174

Equinor, Annual Report on Form 20-F 2019 235

CONDENSED CONSOLIDATED STATEMENT OF INCOME AND OTHER COMPREHENSIVE INCOME
| Equinor ASA | Equinor Energy AS | Non-guarantor subsidiaries | Consolidation adjustments | The Equinor group
Full year 2018 (in USD million)
Revenues and other income | 51,567 | 25,365 | 29,374 | (27,004) | 79,301
Net income/(loss) from equity accounted companies | 7,832 | 1,065 | 262 | (8,868) | 291
Total revenues and other income | 59,399 | 26,430 | 29,636 | (35,872) | 79,593
Total operating expenses | (51,596) | (10,138) | (24,862) | 27,140 | (59,456)
Net operating income/(loss) | 7,803 | 16,292 | 4,774 | (8,732) | 20,137
Net financial items | (1,300) | (274) | (505) | 817 | (1,263)
Income/(loss) before tax | 6,503 | 16,018 | 4,269 | (7,916) | 18,874
Income tax | 219 | (10,719) | (786) | (49) | (11,335)
Net income/(loss) | 6,722 | 5,299 | 3,483 | (7,965) | 7,538
Other comprehensive income/(loss) | (867) | (334) | (620) | 140 | (1,681)
Total comprehensive income/(loss) | 5,855 | 4,965 | 2,863 | (7,825) | 5,857

CONDENSED CONSOLIDATED STATEMENT OF INCOME AND OTHER COMPREHENSIVE INCOME
| Equinor ASA | Equinor Energy AS | Non-guarantor subsidiaries | Consolidation adjustments | The Equinor group
Full year 2017 (in USD million)
Revenues and other income | 39,750 | 20,579 | 22,204 | (21,535) | 60,999
Net income/(loss) from equity accounted companies | 5,051 | (401) | 33 | (4,495) | 188
Total revenues and other income | 44,801 | 20,178 | 22,237 | (26,029) | 61,187
Total operating expenses | (39,570) | (9,217) | (20,022) | 21,392 | (47,416)
Net operating income/(loss) | 5,232 | 10,961 | 2,216 | (4,637) | 13,771
Net financial items | 311 | (378) | 439 | (724) | (351)
Income/(loss) before tax | 5,543 | 10,583 | 2,655 | (5,361) | 13,420
Income tax | (230) | (8,094) | (539) | 40 | (8,822)
Net income/(loss) | 5,314 | 2,489 | 2,116 | (5,321) | 4,598
Other comprehensive income/(loss) | 1,017 | 355 | 878 | (509) | 1,741
Total comprehensive income/(loss) | 6,330 | 2,843 | 2,995 | (5,830) | 6,339

236 Equinor, Annual Report on Form 20-F 2019

CONDENSED CONSOLIDATED BALANCE SHEET
| Equinor ASA | Equinor Energy AS | Non-guarantor subsidiaries | Consolidation adjustments | The Equinor group
At 31 December 2019 (in USD million)
ASSETS |  |  |  |  |
Property, plant, equipment and intangible assets | 1,930 | 37,560 | 41,311 | (110) | 80,691
Equity accounted companies | 44,131 | 22,400 | 1,377 | (66,467) | 1,442
Other non-current assets | 4,097 | 336 | 6,569 | 150 | 11,152
Non-current receivables from subsidiaries | 23,387 | (0) | 24 | (23,411) | 0
Total non-current assets | 73,545 | 60,297 | 49,281 | (89,838) | 93,285
Current receivables from subsidiaries | 5,441 | 6,257 | 12,510 | (24,208) | 0
Other current assets | 14,325 | 857 | 5,264 | (845) | 19,601
Cash and cash equivalents | 3,272 | 15 | 1,890 | 0 | 5,177
Total current assets | 23,038 | 7,129 | 19,665 | (25,053) | 24,778
Total assets | 96,583 | 67,426 | 68,946 | (114,891) | 118,063
EQUITY AND LIABILITIES |  |  |  |  |
Total equity | 41,139 | 26,528 | 40,767 | (67,274) | 41,159
Non-current liabilities to subsidiaries | 22 | 11,976 | 11,413 | (23,411) | 0
Other non-current liabilities | 28,518 | 20,395 | 8,442 | (9) | 57,346
Total non-current liabilities | 28,540 | 32,371 | 19,855 | (23,420) | 57,346
Other current liabilities | 8,298 | 6,039 | 5,209 | 11 | 19,557
Current liabilities to subsidiaries | 18,605 | 2,489 | 3,114 | (24,208) | (0)
Total current liabilities | 26,903 | 8,527 | 8,324 | (24,197) | 19,557
Total liabilities | 55,443 | 40,898 | 28,179 | (47,616) | 76,904
Total equity and liabilities | 96,582 | 67,426 | 68,946 | (114,891) | 118,063

Equinor, Annual Report on Form 20-F 2019 237

CONDENSED CONSOLIDATED BALANCE SHEET
| Equinor ASA | Equinor Energy AS | Non-guarantor subsidiaries | Consolidation adjustments | The Equinor group
At 31 December 2018 (in USD million)
ASSETS |  |  |  |  |
Property, plant, equipment and intangible assets | 502 | 33,309 | 41,140 | (17) | 74,934
Equity accounted companies | 46,828 | 23,668 | 1,697 | (69,330) | 2,863
Other non-current assets | 2,741 | 381 | 5,572 | (39) | 8,655
Non-current receivables from subsidiaries | 25,524 | (0) | 22 | (25,547) | 0
Total non-current assets | 75,595 | 57,358 | 48,432 | (94,933) | 86,452
Current receivables from subsidiaries | 2,379 | 6,529 | 13,215 | (22,123) | 0
Other current assets | 13,082 | 927 | 4,780 | (288) | 18,501
Cash and cash equivalents | 6,287 | 27 | 1,242 | 0 | 7,556
Total current assets | 21,747 | 7,483 | 19,237 | (22,411) | 26,056
Total assets | 97,342 | 64,841 | 67,668 | (117,343) | 112,508
EQUITY AND LIABILITIES |  |  |  |  |
Total equity | 42,970 | 26,706 | 42,838 | (69,524) | 42,990
Non-current liabilities to subsidiaries | 20 | 13,847 | 11,679 | (25,547) | (0)
Other non-current liabilities | 28,416 | 17,033 | 7,536 | (71) | 52,914
Total non-current liabilities | 28,436 | 30,880 | 19,216 | (25,618) | 52,914
Other current liabilities | 6,955 | 6,511 | 3,216 | (78) | 16,605
Current liabilities to subsidiaries | 18,981 | 744 | 2,398 | (22,123) | (0)
Total current liabilities | 25,936 | 7,256 | 5,614 | (22,201) | 16,605
Total liabilities | 54,372 | 38,135 | 24,830 | (47,819) | 69,519
Total equity and liabilities | 97,342 | 64,841 | 67,668 | (117,343) | 112,508

238 Equinor, Annual Report on Form 20-F 2019

CONDENSED CONSOLIDATED CASH FLOW STATEMENT
| Equinor ASA | Equinor Energy AS | Non-guarantor subsidiaries | Consolidation adjustments | The Equinor group
Full year 2019 (in USD million)
Cash flows provided by/(used in) operating activities | 1,728 | 8,433 | 6,389 | (2,802) | 13,749
Cash flows provided by/(used in) investing activities | 734 | (8,258) | (5,418) | 2,347 | (10,594)
Cash flows provided by/(used in) financing activities | (5,465) | (186) | (300) | 455 | (5,496)
Net increase/(decrease) in cash and cash equivalents | (3,002) | (11) | 672 | 0 | (2,341)
Effect of exchange rate changes on cash and cash equivalents | (13) | (1) | (24) | 0 | (38)
Cash and cash equivalents at the beginning of the period (net of overdraft) | 6,287 | 27 | 1,242 | 0 | 7,556
Cash and cash equivalents at the end of the period (net of overdraft) | 3,272 | 15 | 1,890 | 0 | 5,177
| Equinor ASA | Equinor Energy AS | Non-guarantor subsidiaries | Consolidation adjustments | The Equinor group
Full year 2018 (in USD million)
Cash flows provided by/(used in) operating activities | 4,565 | 12,421 | 7,224 | (4,516) | 19,694
Cash flows provided by/(used in) investing activities | 1,046 | (8,281) | (6,649) | 2,672 | (11,212)
Cash flows provided by/(used in) financing activities | (2,840) | (4,140) | 112 | 1,844 | (5,024)
Net increase/(decrease) in cash and cash equivalents | 2,771 | 0 | 687 | 0 | 3,458
Effect of exchange rate changes on cash and cash equivalents | (243) | 0 | (49) | 0 | (292)
Cash and cash equivalents at the beginning of the period (net of overdraft) | 3,759 | 27 | 603 | 0 | 4,390
Cash and cash equivalents at the end of the period (net of overdraft) | 6,287 | 27 | 1,242 | 0 | 7,556
| Equinor ASA | Equinor Energy AS | Non-guarantor subsidiaries | Consolidation adjustments | The Equinor group
Full year 2017 (in USD million)
Cash flows provided by/(used in) operating activities | 339 | 9,506 | 5,242 | (286) | 14,802
Cash flows provided by/(used in) investing activities | 3,227 | (9,070) | (4,718) | 444 | (10,117)
Cash flows provided by/(used in) financing activities | (4,459) | (478) | (727) | (158) | (5,822)
Net increase/(decrease) in cash and cash equivalents | (892) | (42) | (203) | 0 | (1,137)
Effect of exchange rate changes on cash and cash equivalents | 377 | 23 | 36 | 0 | 436
Cash and cash equivalents at the beginning of the period (net of overdraft) | 4,274 | 46 | 770 | 0 | 5,090
Cash and cash equivalents at the end of the period (net of overdraft) | 3,759 | 27 | 603 | 0 | 4,390

#

Equinor, Annual Report on Form 20-F 2019 239

# 4.2 Supplementary oil and gas information (unaudited)

In accordance with the US Financial Accounting Standards Board Accounting Standards Codification "Extractive Activities - Oil and Gas" (Topic 932), Equinor 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 Equinor 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 within the Consolidated financial statements.

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 24 Other commitments, contingent liabilities and contingent assets to the Consolidated financial statements. The effect of the redetermination on proved reserves, which is estimated to be less than 10 million boe, is not yet included.

No new events have occurred since 31 December 2019 that would result in a significant change in the estimated proved reserves or other figures reported as of that date.

Oil and gas reserve quantities

Equinor's proved oil and gas reserves have been estimated by its qualified professionals in accordance with industry standards under the requirements of the US Securities and Exchange Commission (SEC), Rule 4-10 of Regulation S-X. Statements of reserves are forward-looking statements. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

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.

Equinor's proved reserves are recognised under various forms of contractual agreements, including production sharing agreements (PSAs) where Equinor'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 Equinor has access (cost oil and profit oil), limited to available market access. At 31 December 2019, 5% of total proved reserves were related to such agreements (8% of total oil, condensate and natural gas liquids (NGL) reserves and 1% of total gas reserves). This compares with 5% of total proved reserves also for 2018 and 6% in 2017. Net entitlement oil and gas production from fields with such agreements was 68 million boe during 2019 (83 million boe for 2018 and 94 million boe for 2017). Equinor participates in such agreements in Algeria, Angola, Azerbaijan, Libya, Nigeria and Russia.

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

Rule 4-10 of Regulation S-X requires that the estimation of reserves is based on existing economic conditions, including a 12-month average price determined as an unweighted arithmetic average of the first-of-the month price for each month within the reporting period, unless prices are defined by contractual arrangements. The proved reserves at year end 2019 have been determined based on a Brent blend price equivalent of USD 63.04/bbl, compared to USD 71.59 and USD 54.32/bbl for 2018 and 2017 respectively. The volume weighted average gas price for proved reserves at year end 2019 was USD 5.12/mmBtu. The comparable gas price used to determine gas reserves at year end 2018 and 2017 was USD 6.19/mmBtu and USD 4.65/mmBtu, respectively. The volume weighted average NGL price for proved reserves at year end 2019 was USD 29.96/boe. The corresponding NGL price used to determine NGL reserves at year end 2018 and 2017 was USD 39.81/boe and USD 32.02/boe, respectively. The decrease in commodity prices affects the profitable reserves to be recovered from accumulations, resulting in lower proved reserves. The negative revisions due to price are in general a result of limitation to 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 decrease of Equinor’s proved reserves at year end.

From the Norwegian continental shelf (NCS), Equinor 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 Equinor reserves. As part of this arrangement, Equinor delivers and sells gas to customers in accordance with various types of sales contracts on behalf of

240 Equinor, Annual Report on Form 20-F 2019

the SDFI. In order to fulfil the commitments, Equinor utilises a field supply schedule which provides the highest possible total value for the joint portfolio of oil and gas between Equinor and the SDFI.

Equinor 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 Equinor 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 Equinor. The price Equinor 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 Equinor ASA's general meeting. Due to this uncertainty and the Norwegian State's estimate of proved reserves not being available to Equinor, it is not possible to determine the total quantities to be purchased by Equinor under the owner's instruction.

Topic 932 requires the presentation of reserves and certain other supplemental oil and gas disclosures by geographic area, defined as country or continent containing 15% or more of total proved reserves. At 31 December 2019 Norway is the only country in this category, with 71% of the total proved reserves. Since the US contained 16% of the Proved reserves in 2017, management has determined that the most meaningful presentation of geographic areas also in 2019 would be Norway, US, and the continents of Eurasia (excluding Norway), Africa, and Americas (excluding US).

The following tables reflect the estimated proved reserves of oil and gas at 31 December 2016 through 2019, and the changes therein.

The reason for the most significant changes to our proved reserves at year end 2019 were:

· Revisions of previously booked reserves, including the effect of improved recovery, increased the proved reserves by 327 million boe in 2019. This includes the effect of lower commodity prices, decreasing the proved reserves by approximately 35 million boe through a slightly reduced economic life time on several fields. Many producing fields also have positive revisions due to better performance, maturing of new wells and improved recovery projects, as well as reduced uncertainty due to further drilling and production experience. About two thirds of the total revisions come from fields in Norway, where many of the larger offshore fields continue to decline less than previously assumed for the proved reserves.

· A total of 253 million boe of new proved reserves are added through extensions and new discoveries booking proved reserves for the first time. The largest addition comes from the North Komsomolskoye field in Russia where the first stage of the full field development was sanctioned in 2019. This category also includes extensions of the proved areas through drilling of new wells in previously undrilled areas in the US onshore plays and at some producing fields offshore Norway. Sanctioning of the Ærfugl phase 2 and Gudrun phase 2 developments in Norway also adds proved reserve sin this category. New discoveries with proved reserves booked in 2019 are all expected to start production within a period of five years, and some are already producing.

· Purchase of 72 million boe of proved reserves include an increased ownership share of 2.6% in the Johan Sverdrup field in Norway through a transaction with Lundin Petroleum, purchase of a 22.45% share in the Caesar-Tonga field in the US Gulf of Mexico from Shell Offshore Inc and a swap agreement with Faroe Petroleum increasing Equinor’s ownership share in the Njord area in the Norwegian Sea.

· Sale of 125 million boe of reserves includes the sale of a 16% stake in Lundin Petroleum, through which all proved reserves previously included as equity accounted in Norway are removed, and sale of all Equinor’s interests in the Eagle Ford onshore asset in the US.

· The 2019 entitlement production was 698 million boe, a decrease of 2.1% compared to 2018.

Changes to the proved reserves in 2019 are also described in some detail by each geographic area in section 2.8 Operational performance, Proved oil and gas reserves. Development of the proved reserves are described in section 2.8 Operational performance, Development of reserves.

Equinor, Annual Report on Form 20-F 2019 241

| Consolidated companies | Equity accounted | Total
Net proved oil and condensate reserves (in million boe) | Norway | Eurasia excluding Norway | Africa | US | Americas excluding US | Subtotal | Norway | Eurasia excluding Norway | Americas excluding US | Subtotal | Total
At 31 December 2016 | 1,174 | 71 | 221 | 303 | 177 | 1,945 | 58 | - | 30 | 88 | 2,033
Revisions and improved recovery | 212 | 2 | 32 | 55 | 54 | 354 | 1 | 0 | (28) | (27) | 327
Extensions and discoveries | 159 | - | - | 31 | 65 | 256 | - | - | - | - | 256
Purchase of reserves-in-place | - | 34 | - | - | - | 34 | - | - | - | - | 34
Sales of reserves-in-place | - | - | - | - | (38) | (38) | - | - | - | - | (38)
Production | (165) | (10) | (68) | (38) | (21) | (302) | (6) | (0) | (2) | (8) | (310)
At 31 December 2017 | 1,380 | 97 | 185 | 351 | 237 | 2,249 | 53 | - | - | 53 | 2,302
Revisions and improved recovery | 114 | 36 | 35 | 7 | 60 | 251 | 4 | - | - | 4 | 256
Extensions and discoveries | 99 | - | 3 | 59 | - | 161 | 10 | - | - | 10 | 171
Purchase of reserves-in-place | 21 | - | - | 2 | 111 | 133 | - | - | - | - | 133
Sales of reserves-in-place | (0) | (2) | - | (0) | - | (2) | - | - | - | - | (2)
Production | (155) | (8) | (57) | (48) | (29) | (298) | (5) | - | - | (5) | (303)
At 31 December 2018 | 1,458 | 124 | 165 | 371 | 378 | 2,496 | 62 | - | - | 62 | 2,558
Revisions and improved recovery | 113 | 50 | 19 | 35 | 27 | 244 | 3 | (0) | - | 3 | 247
Extensions and discoveries | 5 | 3 | - | 25 | - | 33 | - | 57 | - | 57 | 91
Purchase of reserves-in-place | 41 | - | - | 18 | - | 59 | - | - | - | - | 59
Sales of reserves-in-place | (4) | - | - | (13) | - | (17) | (62) | - | - | (62) | (80)
Production | (151) | (9) | (47) | (54) | (36) | (296) | (3) | (1) | - | (4) | (300)
At 31 December 2019 | 1,463 | 168 | 137 | 383 | 369 | 2,518 | - | 56 | - | 56 | 2,575

242 Equinor, Annual Report on Form 20-F 2019

| Consolidated companies | Equity accounted | Total
Net proved NGL reserves (in million boe) | Norway | Eurasia excluding Norway | Africa | US | Americas excluding US | Subtotal | Norway | Eurasia excluding Norway | Americas excluding US | Subtotal | Total
At 31 December 2016 | 287 | - | 16 | 67 | - | 370 | 2 | - | - | 2 | 372
Revisions and improved recovery | 31 | - | (2) | 6 | 0 | 36 | (1) | - | - | (1) | 35
Extensions and discoveries | 8 | - | - | 25 | - | 33 | - | - | - | - | 33
Purchase of reserves-in-place | - | - | - | - | - | - | - | - | - | - | -
Sales of reserves-in-place | - | - | - | - | - | - | - | - | - | - | -
Production | (48) | - | (4) | (9) | (0) | (61) | - | - | - | - | (61)
At 31 December 2017 | 278 | - | 10 | 90 | - | 378 | 1 | - | - | 1 | 379
Revisions and improved recovery | 25 | - | 15 | (9) | - | 30 | (0) | - | - | (0) | 30
Extensions and discoveries | 21 | - | - | 16 | - | 37 | 0 | - | - | 0 | 37
Purchase of reserves-in-place | 8 | - | - | 0 | - | 8 | - | - | - | - | 8
Sales of reserves-in-place | - | - | - | (0) | - | (0) | - | - | - | - | (0)
Production | (46) | - | (4) | (12) | - | (62) | (0) | - | - | (0) | (62)
At 31 December 2018 | 286 | - | 21 | 85 | - | 392 | 1 | - | - | 1 | 393
Revisions and improved recovery | 5 | - | 0 | (2) | - | 3 | - | - | - | - | 3
Extensions and discoveries | 1 | - | - | 11 | - | 12 | - | - | - | - | 12
Purchase of reserves-in-place | 4 | - | - | 1 | - | 5 | - | - | - | - | 5
Sales of reserves-in-place | (1) | - | - | (18) | - | (18) | (1) | - | - | (1) | (20)
Production | (41) | - | (3) | (12) | - | (57) | - | - | - | - | (57)
At 31 December 2019 | 254 | - | 18 | 65 | - | 337 | - | - | - | - | 337

Equinor, Annual Report on Form 20-F 2019 243

| Consolidated companies | Equity accounted | Total
Net proved gas reserves (in million cf) | Norway | Eurasia excluding Norway | Africa | US | Americas excluding US | Subtotal | Norway | Eurasia excluding Norway | Americas excluding US | Subtotal | Total
At 31 December 2016 | 12,836 | 188 | 280 | 1,318 | - | 14,623 | 15 | - | - | 15 | 14,637
Revisions and improved recovery | 824 | 13 | 102 | 425 | 0 | 1,363 | (1) | 0 | - | (1) | 1,363
Extensions and discoveries | 198 | - | - | 659 | - | 857 | - | - | - | - | 857
Purchase of reserves-in-place | - | - | - | 90 | - | 90 | - | - | - | - | 90
Sales of reserves-in-place | - | - | - | - | - | - | - | - | - | - | -
Production | (1,515) | (41) | (72) | (240) | (0) | (1,868) | (4) | (0) | - | (5) | (1,873)
At 31 December 2017 | 12,343 | 159 | 310 | 2,252 | - | 15,064 | 9 | - | - | 9 | 15,073
Revisions and improved recovery | 1,033 | 15 | 40 | (9) | - | 1,079 | 3 | - | - | 3 | 1,082
Extensions and discoveries | 3,141 | - | - | 446 | - | 3,587 | 2 | - | - | 2 | 3,588
Purchase of reserves-in-place | 274 | - | - | 3 | 26 | 303 | - | - | - | - | 303
Sales of reserves-in-place | (0) | - | - | (0) | - | (0) | - | - | - | - | (0)
Production | (1,502) | (39) | (84) | (318) | (5) | (1,949) | (4) | - | - | (4) | (1,953)
At 31 December 2018 | 15,290 | 134 | 266 | 2,373 | 20 | 18,084 | 10 | - | - | 10 | 18,094
Revisions and improved recovery | 432 | 8 | 31 | (39) | (3) | 429 | 2 | 1 | - | 3 | 432
Extensions and discoveries | 36 | - | - | 506 | - | 542 | - | 298 | - | 298 | 840
Purchase of reserves-in-place | 37 | - | - | 11 | - | 48 | - | - | - | - | 48
Sales of reserves-in-place | (18) | - | - | (118) | - | (135) | (10) | - | - | (10) | (145)
Production | (1,447) | (31) | (57) | (363) | (9) | (1,907) | (2) | (4) | - | (6) | (1,913)
At 31 December 2019 | 14,330 | 111 | 241 | 2,371 | 8 | 17,060 | - | 295 | - | 295 | 17,355

244 Equinor, Annual Report on Form 20-F 2019

| Consolidated companies | Equity accounted | Total
Net proved reserves (in million boe) | Norway | Eurasia excluding Norway | Africa | US | Americas excluding US | Subtotal | Norway | Eurasia excluding Norway | Americas excluding US | Subtotal | Total
At 31 December 2016 | 3,748 | 104 | 287 | 605 | 177 | 4,921 | 62 | - | 30 | 92 | 5,013
Revisions and improved recovery | 390 | 4 | 48 | 137 | 54 | 633 | 0 | 0 | (28) | (28) | 605
Extensions and discoveries | 202 | - | - | 174 | 65 | 441 | - | - | - | - | 441
Purchase of reserves-in-place | - | 34 | - | 16 | - | 50 | - | - | - | - | 50
Sales of reserves-in-place | - | - | - | - | (38) | (38) | - | - | - | - | (38)
Production | (483) | (17) | (85) | (90) | (21) | (696) | (6) | (0) | (2) | (9) | (705)
At 31 December 2017 | 3,857 | 125 | 250 | 842 | 237 | 5,311 | 56 | - | - | 56 | 5,367
Revisions and improved recovery | 323 | 39 | 57 | (4) | 60 | 474 | 5 | - | - | 5 | 479
Extensions and discoveries | 680 | - | 3 | 154 | - | 837 | 11 | - | - | 11 | 848
Purchase of reserves-in-place | 78 | - | - | 3 | 115 | 196 | - | - | - | - | 196
Sales of reserves-in-place | (0) | (2) | - | (0) | - | (2) | - | - | - | - | (2)
Production | (469) | (15) | (76) | (116) | (30) | (707) | (6) | - | - | (6) | (713)
At 31 December 2018 | 4,468 | 148 | 233 | 879 | 382 | 6,110 | 66 | - | - | 66 | 6,175
Revisions and improved recovery | 195 | 52 | 25 | 26 | 26 | 324 | 3 | (0) | - | 3 | 327
Extensions and discoveries | 13 | 3 | - | 126 | - | 142 | - | 110 | - | 110 | 253
Purchase of reserves-in-place | 51 | - | - | 21 | - | 72 | - | - | - | - | 72
Sales of reserves-in-place | (8) | - | - | (51) | - | (59) | (66) | - | - | (66) | (125)
Production | (450) | (15) | (60) | (131) | (38) | (693) | (3) | (1) | - | (5) | (698)
At 31 December 2019 | 4,270 | 187 | 198 | 870 | 370 | 5,895 | - | 109 | - | 109 | 6,004

Equinor, Annual Report on Form 20-F 2019 245

| Consolidated companies | Equity accounted | Total
| Norway | Eurasia excluding Norway | Africa | US | Americas excluding US | Subtotal | Norway | Eurasia excluding Norway | Americas excluding US | Subtotal | Total
Net proved oil and condensate reserves (in million boe) |  |  |  |  |  |  |  |  |  |  |
At 31 December 2016 |  |  |  |  |  |  |  |  |  |  |
Developed | 536 | 43 | 200 | 182 | 121 | 1,082 | 7 | - | 16 | 23 | 1,105
Undeveloped | 638 | 28 | 22 | 121 | 55 | 863 | 51 | - | 13 | 65 | 928
At 31 December 2017 |  |  |  |  |  |  |  |  |  |  |
Developed | 514 | 55 | 173 | 252 | 118 | 1,112 | - | - | - | - | 1,112
Undeveloped | 866 | 42 | 12 | 99 | 119 | 1,138 | 53 | - | - | 53 | 1,191
At 31 December 2018 |  |  |  |  |  |  |  |  |  |  |
Developed | 493 | 46 | 152 | 279 | 247 | 1,216 | 0 | - | - | 0 | 1,216
Undeveloped | 966 | 78 | 13 | 91 | 131 | 1,279 | 62 | - | - | 62 | 1,342
At 31 December 2019 |  |  |  |  |  |  |  |  |  |  |
Developed | 691 | 44 | 124 | 278 | 254 | 1,392 | - | 5 | - | 5 | 1,396
Undeveloped | 772 | 123 | 13 | 104 | 115 | 1,127 | - | 52 | - | 52 | 1,178
Net proved NGL reserves (in million boe) |  |  |  |  |  |  |  |  |  |  |
At 31 December 2016 |  |  |  |  |  |  |  |  |  |  |
Developed | 213 | - | 10 | 53 | - | 276 | 1 | - | - | 1 | 277
Undeveloped | 74 | - | 6 | 14 | - | 94 | 1 | - | - | 1 | 95
At 31 December 2017 | - | - | - | - | - | - | - | - | - | - | -
Developed | 199 | - | 10 | 68 | - | 278 | - | - | - | - | 278
Undeveloped | 78 | - | - | 21 | - | 100 | 1 | - | - | 1 | 101
At 31 December 2018 | - | - | - | - | - | - | - | - | - | - | -
Developed | 192 | - | 18 | 68 | - | 277 | 0 | - | - | 0 | 277
Undeveloped | 94 | - | 3 | 18 | - | 115 | 1 | - | - | 1 | 116
At 31 December 2019 | - | - | - | - | - | - | - | - | - | - | -
Developed | 175 | - | 15 | 49 | - | 240 | - | - | - | - | 240
Undeveloped | 78 | - | 3 | 16 | - | 97 | - | - | - | - | 97
Net proved gas reserves (in million cf) |  |  |  |  |  |  |  |  |  |  |
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
At 31 December 2017 |  |  |  |  |  |  |  |  |  |  |
Developed | 8,852 | 159 | 273 | 1,675 | - | 10,958 | - | - | - | - | 10,958
Undeveloped | 3,492 | - | 37 | 577 | - | 4,106 | 9 | - | - | 9 | 4,115
At 31 December 2018 |  |  |  |  |  |  |  |  |  |  |
Developed | 10,459 | 111 | 240 | 1,740 | 20 | 12,569 | 0 | - | - | 0 | 12,570
Undeveloped | 4,831 | 24 | 26 | 634 | - | 5,514 | 10 | - | - | 10 | 5,524
At 31 December 2019 |  |  |  |  |  |  |  |  |  |  |
Developed | 9,417 | 111 | 217 | 1,645 | 8 | 11,398 | - | 67 | - | 67 | 11,465
Undeveloped | 4,912 | 0 | 23 | 726 | - | 5,662 | - | 228 | - | 228 | 5,889
Net proved reserves (in million boe) |  |  |  |  |  |  |  |  |  |  |
At 31 December 2016 |  |  |  |  |  |  |  |  |  |  |
Developed | 2,392 | 76 | 240 | 414 | 121 | 3,244 | 8 | - | 16 | 24 | 3,268
Undeveloped | 1,357 | 28 | 47 | 191 | 55 | 1,678 | 54 | - | 13 | 68 | 1,746
At 31 December 2017 |  |  |  |  |  |  |  |  |  |  |
Developed | 2,290 | 83 | 231 | 619 | 118 | 3,342 | - | - | - | - | 3,342
Undeveloped | 1,567 | 42 | 19 | 223 | 119 | 1,969 | 56 | - | - | 56 | 2,025
At 31 December 2018 |  |  |  |  |  |  |  |  |  |  |
Developed | 2,548 | 66 | 212 | 657 | 250 | 3,733 | 0 | - | - | 0 | 3,733
Undeveloped | 1,920 | 82 | 21 | 222 | 131 | 2,377 | 65 | - | - | 65 | 2,442
At 31 December 2019 |  |  |  |  |  |  |  |  |  |  |
Developed | 2,544 | 64 | 178 | 621 | 255 | 3,663 | - | 17 | - | 17 | 3,679
Undeveloped | 1,725 | 123 | 20 | 250 | 115 | 2,233 | - | 92 | - | 92 | 2,325

246 Equinor, Annual Report on Form 20-F 2019

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) | 2019 | 2018 | 2017
Unproved properties | 11,304 | 11,227 | 12,627
Proved properties, wells, plants and other equipment | 188,425 | 180,463 | 173,954
Total capitalised cost | 199,730 | 191,690 | 186,581
Accumulated depreciation, impairment and amortisation | (129,383) | (122,803) | (120,170)
Net capitalised cost | 70,347 | 68,887 | 66,411

Net capitalised cost related to equity accounted investments as of 31 December 2019 was USD 385 million, USD 1,446 million in 2018 and USD 1,351 million in 2017. The reported figures are based on capitalised costs within the upstream segments in Equinor, 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 | US | Americas excluding US | Total
Full year 2019 |  |  |  |  |  |
Exploration expenditures | 617 | 381 | 72 | 153 | 362 | 1,585
Development costs | 4,955 | 679 | 350 | 1,947 | 601 | 8,532
Acquired proved properties | 1,129 | 0 | 0 | 845 | 0 | 1,974
Acquired unproved properties | 10 | 338 | 0 | 133 | 427 | 908
Total | 6,711 | 1,398 | 422 | 3,078 | 1,390 | 12,999
Full year 2018 |  |  |  |  |  |
Exploration expenditures | 573 | 190 | 48 | 138 | 489 | 1,438
Development costs | 4,717 | 704 | 192 | 2,078 | 471 | 8,162
Acquired proved properties | 1,333 | 0 | 0 | 21 | 2,133 | 3,487
Acquired unproved properties | 108 | 10 | 10 | 411 | 886 | 1,425
Total | 6,731 | 904 | 250 | 2,648 | 3,979 | 14,512
Full year 2017 |  |  |  |  |  |
Exploration expenditures | 472 | 223 | 77 | 199 | 264 | 1,235
Development costs | 4,565 | 599 | 417 | 2,146 | 376 | 8,102
Acquired proved properties | 0 | 333 | 0 | 32 | 0 | 365
Acquired unproved properties | 1 | 13 | 0 | 122 | 726 | 862
Total | 5,038 | 1,168 | 494 | 2,499 | 1,366 | 10,564

Equinor, Annual Report on Form 20-F 2019 247

Expenditures incurred in exploration and development activities related to equity accounted investments was USD 166 million in 2019, USD 249 million in 2018 and USD 284 million in 2017. These figures include Lundin with USD 117 million incurred prior to the divestment of 16% stake in the third quarter of 2019, USD 241 million in 2018 and USD 265 million in 2017.

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 Equinor.

The result of operations for oil and gas producing activities contains the two upstream reporting segments Exploration & Production Norway (E&P Norway) and Exploration & Production International (E&P International) as presented in note 3 Segments within the Consolidated financial statements. 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 | US | Americas excluding US | Total
Full year 2019 |  |  |  |  |  |
Sales | 15 | 243 | 555 | 302 | 853 | 1,968
Transfers | 17,754 | 562 | 2,666 | 3,732 | 1,139 | 25,853
Other revenues | 1,151 | 27 | 2 | 199 | 51 | 1,430
Total revenues | 18,920 | 832 | 3,223 | 4,233 | 2,043 | 29,251
Exploration expenses | (478) | (394) | (43) | (724) | (225) | (1,864)
Production costs | (2,297) | (163) | (519) | (658) | (413) | (4,050)
Depreciation, amortisation and net impairment losses | (5,617) | (517) | (1,032) | (4,140) | (771) | (12,077)
Other expenses | (895) | (164) | (46) | (1,012) | (329) | (2,446)
Total costs | (9,287) | (1,238) | (1,640) | (6,534) | (1,738) | (20,437)
Results of operations before tax | 9,633 | (406) | 1,583 | (2,301) | 305 | 8,814
Tax expense | (6,197) | 199 | (685) | (68) | (13) | (6,764)
Results of operations | 3,436 | (207) | 898 | (2,369) | 292 | 2,050
Net income/(loss) from equity accounted investments | 15 | 24 | 0 | 6 | 0 | 45

248 Equinor, Annual Report on Form 20-F 2019

Consolidated companies
(in USD million) | Norway | Eurasia excluding Norway | Africa | US | Americas excluding US | Total
Full year 2018 |  |  |  |  |  |
Sales | 45 | 360 | 1,693 | 305 | 540 | 2,943
Transfers | 21,814 | 558 | 3,474 | 3,934 | 1,142 | 30,922
Other revenues | 606 | 97 | 59 | 175 | 32 | 968
Total revenues | 22,465 | 1,015 | 5,226 | 4,413 | 1,714 | 34,833
Exploration expenses | (431) | (195) | (40) | (407) | (349) | (1,422)
Production costs | (2,416) | (162) | (526) | (586) | (349) | (4,039)
Depreciation, amortisation and net impairment losses | (4,370) | (354) | (1,458) | (2,197) | (584) | (8,962)
Other expenses | (852) | (196) | (56) | (852) | (287) | (2,243)
Total costs | (8,069) | (907) | (2,079) | (4,042) | (1,569) | (16,665)
Results of operations before tax | 14,396 | 108 | 3,147 | 372 | 145 | 18,167
Tax expense | (10,185) | 282 | (1,460) | (1) | 277 | (11,088)
Results of operations | 4,211 | 390 | 1,687 | 371 | 421 | 7,079
Net income/(loss) from equity accounted investments | 10 | 23 | 0 | 8 | 0 | 41

Equinor, Annual Report on Form 20-F 2019 249

Consolidated companies
(in USD million) | Norway | Eurasia excluding Norway | Africa | US | Americas excluding US | Total
Full year 2017 |  |  |  |  |  |
Sales | 47 | 236 | 1,373 | 217 | 0 | 1,873
Transfers | 17,578 | 518 | 3,345 | 2,375 | 944 | 24,759
Other revenues | (62) | 53 | 3 | 186 | (15) | 164
Total revenues | 17,563 | 806 | 4,721 | 2,778 | 928 | 26,796
Exploration expenses | (379) | (236) | (143) | 25 | (327) | (1,059)
Production costs | (2,213) | (157) | (523) | (457) | (259) | (3,610)
Depreciation, amortisation and net impairment losses | (3,874) | (426) | (1,910) | (1,664) | (423) | (8,297)
Other expenses | (742) | (123) | (18) | (680) | (594) | (2,156)
Total costs | (7,207) | (941) | (2,595) | (2,776) | (1,603) | (15,122)
Results of operations before tax | 10,356 | (135) | 2,126 | 3 | (675) | 11,674
Tax expense | (7,479) | 179 | (741) | 1 | (15) | (8,056)
Results of operations | 2,877 | 44 | 1,385 | 3 | (690) | 3,619
Net income/(loss) from equity accounted investments | 129 | 13 | 0 | 10 | 0 | 151

Average production cost in USD per boe based on entitlement volumes (consolidated) | Norway | Eurasia excluding Norway | Africa | US | Americas excluding US | Total
2019 | 5 | 11 | 9 | 5 | 11 | 6
2018 | 5 | 11 | 7 | 5 | 11 | 6
2017 | 5 | 9 | 6 | 5 | 12 | 5

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 pre-tax 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 Equinor's expected future cash flows or the value of its proved reserves and therefore should not be relied upon as an indication of Equinor’s future cash flow or value of its proved reserves.

250 Equinor, Annual Report on Form 20-F 2019

(in USD million) | Norway | Eurasia excluding Norway | Africa | US | Americas excluding US | Total
At 31 December 2019 |  |  |  |  |  |
Consolidated companies |  |  |  |  |  |
Future net cash inflows | 187,897 | 10,506 | 10,752 | 27,547 | 19,977 | 256,679
Future development costs | (13,068) | (3,075) | (684) | (2,338) | (2,667) | (21,832)
Future production costs | (50,316) | (4,501) | (4,180) | (11,678) | (11,453) | (82,128)
Future income tax expenses | (91,386) | (378) | (2,194) | (2,955) | (932) | (97,846)
Future net cash flows | 33,127 | 2,553 | 3,694 | 10,575 | 4,925 | 54,873
10% annual discount for estimated timing of cash flows | (12,854) | (772) | (883) | (3,586) | (1,605) | (19,699)
Standardised measure of discounted future net cash flows | 20,273 | 1,781 | 2,811 | 6,989 | 3,320 | 35,173
Equity accounted investments |  |  |  |  |  |
Standardised measure of discounted future net cash flows | - | 475 | - | - | - | 475
Total standardised measure of discounted future net cash flows including equity accounted investments | 20,273 | 2,256 | 2,811 | 6,989 | 3,320 | 35,648
|  |  |  |  |  | +
(in USD million) | Norway | Eurasia excluding Norway | Africa | US | Americas excluding US | Total
At 31 December 2018 |  |  |  |  |  |
Consolidated companies |  |  |  |  |  |
Future net cash inflows | 225,928 | 9,585 | 14,050 | 32,306 | 23,651 | 305,520
Future development costs | (16,403) | (3,029) | (614) | (2,548) | (3,184) | (25,777)
Future production costs | (55,332) | (4,074) | (4,947) | (12,445) | (12,237) | (89,035)
Future income tax expenses | (113,522) | (416) | (2,968) | (3,530) | (1,036) | (121,471)
Future net cash flows | 40,671 | 2,067 | 5,522 | 13,783 | 7,194 | 69,237
10% annual discount for estimated timing of cash flows | (16,303) | (789) | (1,372) | (5,014) | (2,460) | (25,937)
Standardised measure of discounted future net cash flows | 24,368 | 1,278 | 4,150 | 8,769 | 4,734 | 43,299
Equity accounted investments |  |  |  |  |  |
Standardised measure of discounted future net cash flows | 607 | - | - | - | - | 607
Total standardised measure of discounted future net cash flows including equity accounted investments | 24,975 | 1,278 | 4,150 | 8,769 | 4,734 | 43,907
|  |  |  |  |  | +
(in USD million) | Norway | Eurasia excluding Norway | Africa | US | Americas excluding US | Total
At 31 December 2017 |  |  |  |  |  |
Consolidated companies |  |  |  |  |  |
Future net cash inflows | 150,953 | 6,144 | 11,504 | 24,085 | 10,301 | 202,987
Future development costs | (15,642) | (1,992) | (594) | (2,020) | (2,499) | (22,747)
Future production costs | (49,229) | (2,792) | (5,240) | (10,342) | (6,564) | (74,167)
Future income tax expenses | (58,774) | (288) | (1,456) | (3,962) | (333) | (64,813)
Future net cash flows | 27,307 | 1,072 | 4,215 | 7,761 | 904 | 41,259
10% annual discount for estimated timing of cash flows | (10,152) | (315) | (874) | (2,925) | (331) | (14,596)
Standardised measure of discounted future net cash flows | 17,155 | 757 | 3,341 | 4,836 | 573 | 26,663
Equity accounted investments |  |  |  |  |  |
Standardised measure of discounted future net cash flows | 333 | - | - | - | - | 333
Total standardised measure of discounted future net cash flows including equity accounted investments | 17,488 | 757 | 3,341 | 4,836 | 573 | 26,995

Equinor, Annual Report on Form 20-F 2019 251

Changes in the standardised measure of discounted future net cash flows from proved reserves
(in USD million) | 2019 | 2018 | 2017
Consolidated companies |  |  |
Standardised measure at 1 January | 43,299 | 26,663 | 21,092
Net change in sales and transfer prices and in production (lifting) costs related to future production | (22,147) | 39,646 | 22,640
Changes in estimated future development costs | (3,433) | (7,751) | (5,572)
Sales and transfers of oil and gas produced during the period, net of production cost | (24,117) | (29,556) | (22,446)
Net change due to extensions, discoveries, and improved recovery | 1,333 | 12,046 | 3,836
Net change due to purchases and sales of minerals in place | 987 | 4,815 | (167)
Net change due to revisions in quantity estimates | 8,176 | 11,622 | 10,798
Previously estimated development costs incurred during the period | 8,341 | 8,066 | 7,597
Accretion of discount | 11,066 | 6,525 | 4,415
Net change in income taxes | 11,668 | (28,775) | (15,530)
Total change in the standardised measure during the year | (8,126) | 16,637 | 5,571
Standardised measure at 31 December | 35,173 | 43,299 | 26,663
Equity accounted investments |  |  |
Standardised measure at 31 December | 475 | 607 | 333
Standardised measure at 31 December including equity accounted investments | 35,648 | 43,907 | 26,995

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 standardised 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 2018. The proved reserves at 31 December 2018 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’.

#

252 Equinor, Annual Report on Form 20-F 2019

# 5.1 Shareholder information

Equinor is the largest company listed on the Oslo Børs where it trades under the ticker code EQNR. Equinor is also listed on the New York Stock Exchange under the ticker code EQNR, trading in the form of American Depositary Shares (ADS).

Equinor's shares have been listed on the Oslo Børs and the New York Stock Exchange 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.

### Dividend policy and dividends

It is Equinor's ambition to grow the annual cash dividend measured in USD per share in line with long-term underlying earnings.

Equinor’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 Equinor’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, Equinor 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. Equinor 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 has proposed to the AGM a dividend of USD 0.27 per share for the fourth quarter 2019 which is an increase from the previous quarter.

The following table shows the cash dividend amounts to all shareholders since 2015 on a per share basis and in aggregate.

|  | Ordinary dividend per share |  |  | Ordinary dividend per share
Fiscal year | Curr. | Q1 |  | Curr. | Q2 |  | Curr. | Q3 |  | Curr. | Q4 |  | Curr.
2015 | NOK | 1.8000 |  | NOK | - |  | NOK | - |  | NOK | - |  | NOK | 1.8000
2015 | USD | - |  | 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
2017 | USD | 0.2201 |  | USD | 0.2201 |  | USD | 0.2201 |  | USD | 0.2300 |  | USD | 0.8903
2018 | USD | 0.2300 |  | USD | 0.2300 |  | USD | 0.2300 |  | USD | 0.2600 |  | USD | 0.9500
2019 | USD | 0.2600 |  | USD | 0.2600 |  | USD | 0.2600 |  | USD | 0.2700 |  | USD | 1.0500

On 5 February 2020 the board of directors proposed to declare a dividend for the fourth quarter of 2019 of USD 0.27 per share (subject to approval by the AGM). The Equinor share will trade ex-dividend 15 May 2020 on OSE and 18 May 2020 for ADR holders on NYSE. Record date will be 20 May 2019 on OSE and NYSE. Payment date will be around 29 May 2019.

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 exchange rates from Norges Bank in the period plus/minus three business days from record date, in total seven business dates.

Share buy-back

For the period 2013-2019, the board of directors has been authorised by the annual general meeting of Equinor to repurchase Equinor shares in the market for subsequent annulment. It is Equinor’s intention to renew this authorisation at the annual general meeting in May, 2020.

Equinor, Annual Report on Form 20-F 2019 253

On 4 September, 2019 the board of directors approved a share buy-back programme of up to USD 5 billion over a period until the end of 2022, subject to annual renewal of the authorisation from the annual general meeting. The first tranche of the programme of around USD 1.5 billion commenced on 5 September, 2019 and per 31 December, 2019 88% of the market operations of the first tranche (of USD 500 million) was complete, with 23,578,410 shares purchased at an average price of NOK 170.97

##

254 Equinor, Annual Report on Form 20-F 2019

## S hares 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 2019.

### Equinor's share savings plan

Since 2004, Equinor 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 Equinor 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 180). 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 authorised to acquire Equinor shares in the market on behalf of the company. The authorisation is valid until the next annual general meeting, but not beyond 30 June 2020. This authorisation replaces the previous authorisation to acquire Equinor’s own shares for implementation of the share savings plan granted by the annual general meeting 11 May 2017. It is Equinor’s intention to renew this authorisation at the annual general meeting on 14 May 2020.

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-19 | 515,550 | 191.2129 | 3,613,740 | 10,386,260
Feb-19 | 498,958 | 200.0165 | 4,112,698 | 9,887,302
Mar-19 | 521,209 | 192.1568 | 4,633,907 | 9,366,093
Apr-19 | 515,865 | 196.3206 | 5,149,772 | 8,850,228
May-19 | 557,325 | 182.0840 | 5,707,097 | 8,292,903
Jun-19 | 597,064 | 169.8610 | 597,064 | 13,402,936
Jul-19 | 592,725 | 171.1045 | 1,189,789 | 12,810,211
Aug-19 | 689,472 | 147.0617 | 1,879,261 | 12,120,739
Sep-19 | 582,712 | 174.3638 | 2,461,973 | 11,538,027
Oct-19 | 615,154 | 166.7386 | 3,077,127 | 10,922,873
Nov-19 | 587,646 | 177.3872 | 3,664,773 | 10,335,227
Dec-19 | 625,599 | 168.3426 | 4,290,372 | 9,709,628
Jan-20 | 595,692 | 179.1109 | 4,886,064 | 9,113,936
Feb-20 | 670,130 | 161.0881 | 5,556,194 | 8,443,806
TOTAL | 8,165,101 1) | 176.9178 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.

Equinor, Annual Report on Form 20-F 2019 255

Equinor ADR programme fees

Fees and charges payable by a holder of ADSs.

JPMorgan Chase Bank N.A. (JPMorgan), serves as the depositary for Equinor’s ADR programme having replaced the Deutsche Bank Trust Company Americas (Deutsche Bank) pursuant to the Further Amended and Restated Deposit Agreement dated 4 February 2019. JPMorgan 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 other fees from investors by billing ADR holders, by deducting such fees and charges from the amounts distributed or by deducting such fees from cash dividends or other cash distributions. 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:

ADR holders, persons depositing or withdrawing shares, and/or persons whom ADSs are issued, must pay: | For:
USD 5.00 (or less) per 100 ADSs (or portion of 100 ADSs) | Issuance of ADSs, including issuances resulting from a deposit of shares, a distribution of shares or rights or other property, and issuances pursuant to stock dividends, stock splits, mergers, exchanges of securities or any other transactions or events affecting the ADSs or the deposited securities.
| Cancellation of ADSs for the purpose of withdrawal of deposited securities, including if the deposit agreement terminates, or a cancellation or reduction of ADSs for any other reason
USD 0.05 (or less) per ADS | Any cash distribution made or elective cash/stock dividend offered pursuant to the Deposit Agreement
USD 0.05 (or less) per ADS, per calendar year (or portion thereof) | 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 to registered ADR holders of (i) securities distributed by the company to holders of deposited securities or (ii) cash proceeds from the sale of such securities
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 | SWIFT, cable, telex, facsimile transmission and delivery charges (as provided in the deposit agreement).
| Fees, expenses and other charges of JPMorgan or its agent (which may be a division, branch or affiliate) for converting foreign currency to USD, which shall be deducted out of such foreign currency.
Taxes and other governmental charges the Depositary or the custodian have to pay, for example, stock transfer taxes, stamp duty or withholding taxes | As necessary
Any fees, charges and expenses incurred by the Depositary or its agents for the servicing of the deposited securities, the sale of securities, the delivery of deposited securities or in connection with the depositary's or its custodian's compliance with applicable law, rule or regulation, including without limitation expenses incurred on behalf of ADR holders in connection with compliance with foreign exchange control regulations or any law or regulation relating to foreign investment | As necessary

Direct and indirect payments by the depositary

Under our arrangements with Deutsche Bank, our previous depositary, we were entitled to reimbursement of 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

256 Equinor, Annual Report on Form 20-F 2019

December 2019, the depositary reimbursed approximately USD 1.648 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.

Deutsche Bank had also agreed to waive fees for costs associated with the administration of the ADR programme, and it had 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, reregistration costs borne by the custodian and costs in relation to printing and mailing AGM materials. For the year ended 31 December 2019, Deutsche Bank paid expenses of approximately USD 203,650 directly to third parties.

Under our arrangements with JPMorgan, as our current depositary, the company will each year receive from JPMorgan the lesser of (a) USD 2,000,000 and (b) the difference between revenues and expenses of the ADR programme. For the year ended 31 December 2019, JPMorgan reimbursed USD 900,000 to the company. For the year ending 31 December 2019, total reimbursement to the company from Deutsche Bank and JPMorgan in aggregate was thus approximately USD 2.548 million. JPMorgan has also agreed to reimburse the company for up to USD 25,000 in legal fees incurred in connection with the transfer of the ADR programme. Other reasonable costs associated with the administration of the ADR programme are borne by the company. For the year ended 31 December 2019, such costs, associated with the administration of the ADR programme, paid by the company, added up to approximately USD 905,402. Under certain circumstances, including the removal of JPMorgan as depositary, the company is required to repay to JPMorgan certain amounts paid to the company in prior periods.

## Taxation

Norwegian tax consequences

This section describes material Norwegian tax consequences for shareholders in connection with the acquisition, ownership and disposal of shares and American Depositary Shares (“ADS”) in Equinor. The term “shareholders” refers to both holders of shares and holders of ADSs, unless otherwise explicitly stated.

The outline does not provide a complete description of all Norwegian tax regulations that might be relevant (i.e. for investors to whom special regulations may apply, including shareholders that carry on business activities in Norway, and whose shares or ADSs are effectively connected with such business activities), and is based on current law and practice. Shareholders should consult their professional tax advisers for advice about individual tax consequences.

Taxation of dividends received by Norwegian shareholders

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 of 22% (reduced from 23% with effect from and including 2019).

Individual shareholders residing in Norway for tax purposes are subject to the standard income tax rate of 22% (reduced from 23% with effect from and including 2019) for dividend income exceeding a basic tax free allowance. However, in 2019 dividend income exceeding the basic tax free allowance is grossed up with a factor of 1.44 before being included in the ordinary taxable income, resulting in an effective tax rate of 31.68% (22% x 1.44). 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 on (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.

Individual shareholders residing in Norway for tax purposes may hold the listed shares in companies resident within the EEA through a stock savings account. Dividend on shares owned through the stock savings account is only taxable when the dividend is withdrawn from the account.

Taxation of dividends received by foreign shareholders

Non-resident shareholders are as a starting point subject to Norwegian withholding tax at a rate of 25% on dividends from Norwegian companies. The distributing company is responsible for deducting the withholding tax upon distribution to non-resident shareholders.

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 of 22% (reduced from 23% with effect from and including 2019).

Certain other important exceptions and modifications are outlined below.

This withholding tax does not apply to corporate shareholders in the EEA that are comparable to Norwegian limited liability companies or certain other types of Norwegian entities, and are further able to demonstrate that they are genuinely established and carry on genuine economic business activity within the EEA, provided that Norway is entitled to receive information from the country of residence

Equinor, Annual Report on Form 20-F 2019 257

pursuant to a tax treaty or other international treaty. If no such treaty exists with the country of residence, the shareholder may instead present confirmation issued by the tax authorities of the country of residence verifying the documentation.

The withholding rate of 25% is often reduced in tax treaties between Norway and other countries. The reduced withholding tax 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.

Individual shareholders residing for tax purposes in the EEA 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.

Individual shareholders residing for tax purposes in the EEA may hold the listed shares in companies resident within the EEA through a stock savings account. Dividend on shares owned through the stock savings account will only be subject to withholding tax when withdrawn from the account.

Procedure for claiming a reduced withholding tax rate on dividends

A foreign shareholder that is entitled to an exemption from or reduction of withholding tax on dividends, may request that the exemption or reduction is applied at source by the distributor. Such request must be accompanied by satisfactory documentation which supports that the foreign shareholder is entitled to a reduced withholding tax rate. Specific documentation requirements apply.

For holders of shares and ADSs deposited JPMorgan Chase Bank N.A. (JPMorgan), documentation establishing that the holder is eligible for the benefits under a tax treaty with Norway, may be provided to JPMorgan. JPMorgan 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.

The statutory 25% withholding tax rate will be levied on 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 a reduced rate. 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. Please refer to the tax authorities’ web page for more information and the requirements of such application: www.skatteetaten.no/en/person.

Taxation on 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 of 22% (reduced from 23% with effect from and including 2019). However, in 2019 the taxable gain or deductible loss is grossed up with a factor of 1.44 before included in the ordinary taxable income, resulting in an effective tax rate of 31.68% (22% x 1.44).

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 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 a 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.

Individual shareholders residing in Norway for tax purposes may hold listed the shares in companies resident within the EEA through a stock savings account. Gain on shares owned through the stock savings account will only be taxable when withdrawn from the account whereas loss on shares will be deductible when the account is terminated.

A corporate shareholder or an individual shareholder who ceases to be tax resident in Norway due to Norwegian law or tax treaty provisions may, in certain circumstances, become subject to Norwegian exit taxation on unrealised 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 residing in Norway for tax purposes. Norwegian limited liability companies and certain similar entities are not subject to wealth tax. The current marginal wealth tax

258 Equinor, Annual Report on Form 20-F 2019

rate is 0.85% of the value assessed. The assessment value of listed shares (including ADSs) is 75% (reduced from 80% with effect from and including the income year 2019) 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 liability 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 the ownership and disposition of shares or ADSs. It only applies to you if you hold your shares or ADSs as capital assets for United States federal income tax purposes. This discussion addresses only United States federal income taxation and does not discuss all of the tax consequences that may be relevant to you in light of your individual circumstances, including foreign, state or local tax consequences, estate and gift tax consequences, and tax consequences arising under the Medicare contribution tax on net investment income or the alternative minimum tax. This section does not apply to you if you are a member of a special class of holders subject to special rules, including dealers in securities, traders in securities that elect to use a mark-to-market method of accounting for securities holdings, tax-exempt organisations, insurance companies, partnerships or entities or arrangements that are treated as partnerships for United States federal income tax purposes, persons that actually or constructively own 10% of the combined voting power of voting stock of Equinor or of the total value of stock of Equinor, persons that hold shares or ADSs as part of a straddle or a hedging or conversion transaction, persons that purchase or sell shares or ADSs as a part of a wash sale for tax purposes, 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, all as currently in effect, 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, for United States federal income tax purposes: (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.

The tax treatment of the shares or ADSs will depend in part on whether or not we are classified as a passive foreign investment company, or PFIC, for United States federal income tax purposes. Except as discussed below, under “—PFIC rules”, this discussion assumes that we are not classified as a PFIC for United States federal income tax purposes.

Taxation of distributions

Under the United States federal income tax laws, the gross amount of any distribution (including any Norwegian tax withheld from the distribution payment) paid by Equinor out of its current or accumulated earnings and profits (as determined for United States federal income tax purposes), other than certain pro-rata distributions of its shares, will be treated as a dividend that 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 that constitute qualified dividend income 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 Equinor is eligible for benefits under the Treaty. We believe that Equinor is currently eligible for the benefits of the Treaty and we therefore expect that dividends on the ordinary shares or ADSs will be qualified dividend income. 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 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 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. However, Equinor does not expect to calculate

Equinor, Annual Report on Form 20-F 2019 259

earnings and profits in accordance with United States federal income tax principles. Accordingly, you should expect to generally treat distributions we make as dividends.

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 reduction or refund of the tax withheld is available to you under Norwegian law. Special rules apply in determining the foreign tax credit limitation with respect to dividends that are subject to the preferential tax rates. Dividends will generally be income from sources outside the United States and will generally be “passive” 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. 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 currently be treated as stock of a PFIC for United States federal income tax purposes and we do not expect to become a PFIC in the foreseeable future. However, this conclusion is a factual determination that is made annually and thus may be subject to change. It is therefore possible that we could become a PFIC in a future taxable year. 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 generally 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, under proposed Treasury regulations, such withholding will not apply to payments made before the date that is two years after the date on which final regulations defining the term “foreign passthru payment” are enacted. The rules for the implementation of these requirements have not yet been fully finalised, so it is impossible to determine at this time what impact, if any, these requirements will have on holders of the shares and ADSs.

## Major shareholders

The Norwegian State is the largest shareholder in Equinor, with a direct ownership interest of 67%. Its ownership interest is managed by the Norwegian Ministry of Petroleum and Energy.

260 Equinor, Annual Report on Form 20-F 2019

As of 31 December 2019, the Norwegian State had a 67% direct ownership interest in Equinor and a 3.4% indirect interest through the National Insurance Fund (Folketrygdfondet), totalling 70.4%.

Equinor 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 resolutions.

Shareholders at December 2019 | Number of Shares | Ownership in %
1 | Government of Norway | 2,236,903,016 | 67.00%
2 | Folketrygdfondet | 113,846,697 | 3.41%
3 | Dodge & Cox | 43,526,704 | 1.30%
4 | Fidelity Management & Research Company | 39,121,616 | 1.17%
5 | BlackRock Institutional Trust Company, N.A. | 33,746,216 | 1.01%
6 | The Vanguard Group, Inc. | 29,105,110 | 0.87%
7 | Lazard Asset Management, L.L.C. | 23,734,615 | 0.71%
8 | SAFE Investment Company Limited | 22,872,440 | 0.69%
9 | KLP Forsikring | 18,942,979 | 0.57%
10 | Storebrand Kapitalforvaltning AS | 17,979,456 | 0.54%
11 | T. Rowe Price Associates, Inc. | 16,475,072 | 0.49%
12 | INVESCO Asset Management Limited | 14,442,919 | 0.43%
13 | UBS Asset Management (UK) Ltd. | 12,733,393 | 0.38%
14 | State Street Global Advisors (US) | 12,208,894 | 0.37%
15 | Marathon Asset Management LLP | 11,449,280 | 0.34%
16 | Renaissance Technologies LLC | 11,064,361 | 0.33%
17 | DNB Asset Management AS | 10,397,297 | 0.31%
18 | Legal & General Investment Management Ltd. | 10,022,099 | 0.30%
19 | Templeton Investment Counsel, L.L.C. | 9,068,425 | 0.27%
20 | BlackRock Investment Management (UK) Ltd. | 8,521,589 | 0.26%
Source: Data collected by third party, authorised by Equinor, December 2019. |  |

Equinor, Annual Report on Form 20-F 2019 261

## 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.

#

262 Equinor, Annual Report on Form 20-F 2019

# 5.2 Use and reconciliation of non-GAAP financial measures

Since 2007, Equinor has been preparing the Consolidated financial statements in accordance with International Financial Reporting Standards (IFRS) as adopted by the European union (EU) and as issued by the International Accounting Standards Board. I FRS has been applied consistently to all periods presented in the 2019 Consolidated financial statements.

Equinor 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: (i.e, IFRS in the case of Equinor). The following financial measures may be considered non-GAAP financial measures:

a) Net debt to capital employed ratio, Net debt to capital employed ratio adjusted, including lease liabilities and Net debt to capital employed ratio adjusted

b) Return on average capital employed (ROACE)

c) Organic capital expenditures

d) Free cash flow and organic free cash flow

e) Adjusted earnings and adjusted earnings after tax

### a) Net debt to capital employed ratio

In Equinor’s view, the calculated net debt to capital employed ratio, net debt to capital employed ratio adjusted, including lease liabilities and net debt to capital employed ratio adjusted gives an alternative picture of the current debt situation than gross interest-bearing financial debt.

The calculation is based on gross interest-bearing financial debt in the balance sheet and adjusted for cash, cash equivalents and current financial investments. Certain adjustments are made, e.g. collateral deposits classified as cash and cash equivalents in the Consolidated balance sheet are considered non-cash in the non-GAAP calculations. The financial investments held in Equinor Insurance AS are excluded in the non-GAAP calculations as they are deemed restricted. These two adjustments increase net debt and give a more prudent definition of the net debt to capital employed ratio than if the IFRS based definition was to be used. Following implementation of IFRS16 Equinor presents a “net debt to capital employed adjusted” excluding lease liabilities from the gross interest-bearing debt. N et interest-bearing debt adjusted for these items is included in the average capital employed. The table below reconciles the net interest-bearing debt adjusted, the capital employed and the net debt to capital employed adjusted ratio with the most directly comparable financial measure or measures calculated in accordance with IFRS.

Equinor, Annual Report on Form 20-F 2019 263

Calculation of capital employed and net debt to capital employed ratio |  | For the year ended 31 December
(in USD million) |  | 2019 | 2018 | 2017
Shareholders' equity |  | 41,139 | 42,970 | 39,861
Non-controlling interests |  | 20 | 19 | 24
Total equity | A | 41,159 | 42,990 | 39,885
Current finance debt |  | 4,087 | 2,463 | 4,091
Non-current finance debt |  | 24,945 | 23,264 | 24,183
Gross interest-bearing debt | B | 29,032 | 25,727 | 28,274
Cash and cash equivalents |  | 5,177 | 7,556 | 4,390
Current financial investments |  | 7,426 | 7,041 | 8,448
Cash and cash equivalents and current financial investment | C | 12,604 | 14,597 | 12,837
Net interest-bearing debt before adjustments | B1 = B-C | 16,429 | 11,130 | 15,437
Other interest-bearing elements 1) |  | 791 | 1,261 | 1,014
Marketing instruction adjustment 2) |  | - | (146) | (164)
Net interest-bearing debt adjusted, including lease liabilities | B2 | 17,219 | 12,246 | 16,287
Lease liabilities |  | 4,339 | - | -
Net interest-bearing debt adjusted | B3 | 12,880 | 12,246 | 16,287
Calculation of capital employed: |  |  |  |
Capital employed | A+B1 | 57,588 | 54,120 | 55,322
Capital employed adjusted, including lease liabilities | A+B2 | 58,378 | 55,235 | 56,172
Capital employed adjusted3) | A+B3 | 54,039 | 55,235 | 56,172
Calculated net debt to capital employed |  |  |  |
Net debt to capital employed | (B1)/(A+B1) | 28.5% | 20.6% | 27.9%
Net debt to capital employed adjusted, including lease liabilities | (B2)/(A+B2) | 29.5% | 22.2% | 29.0%
Net debt to capital employed adjusted3) | (B3)/(A+B3) | 23.8% | 22.2% | 29.0%
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 Equinor Insurance 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 Equinor's Consolidated balance sheet.
3) | Following implementation of IFRS16 Equinor presents a “net debt to capital employed adjusted” excluding lease liabilities from the gross interest-bearing debt. Comparable numbers presented in this table include finance lease according to IAS17, adjusted for marketing instruction agreement, which in total represent 0.4%-point of the Net debt to capital employed by 31 December 2019. “Net debt to capital employed adjusted” based on similar adjustments as for 31 December 2018 is 24.2% by 31 December 2019.

### b) Return on average capital employed (ROACE)

This measure provides useful information for both the group and investors about performance during the period under evaluation. Equinor uses ROACE to measure the return on capital employed adjusted, 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 IFRS or ratios based on these figures. For a reconciliation for adjusted earnings after tax, see e) later in this section.

ROACE was 9.0% in 2019, compared to 12.0% in 2018 and 8.2% in 2017. The change from 2018 is due to a decrease in adjusted earnings after tax.

264 Equinor, Annual Report on Form 20-F 2019

Calculated ROACE based on Adjusted earnings after tax and capital employed adjusted | For the year ended 31 December
(in USD million, except percentages) | 2019 | 2018 | 2017
Adjusted earnings after tax (A) | 4,925 | 6,693 | 4,528
Average capital employed adjusted (B) | 54,637 | 55,704 | 55,330
Calculated ROACE based on Adjusted earnings after tax and capital employed adjusted (A/B) | 9.0% | 12.0% | 8.2 %

### c) Organic capital expenditures

Capital expenditures, defined as Additions to PP&E, intangibles and equity accounted investments in note 3 Segments to the Consolidated financial statements, amounted to USD 14.8 billion in 2019.

Organic capital expenditures are capital expenditures excluding acquisitions, capital leases and other investments with significant different cash flow pattern.

In 2019, a total of USD 4.8 billion were excluded from the organic capital expenditures. Among items excluded from the organic capital expenditure in 2019 were acquisition of a 40% operated interest in the Rosebank project, a cquisition of 100% shares in Danske Commodities, acquisition of 10% interest in the BM-S-8 licence in Brazil, acquisition of a 22.45% interest in the Caesar Tonga field, acquisition of 2.6% interest in the Johan Sverdrup field, and additions of Right of Use (RoU) assets related to leases, resulting in organic capital expenditure of USD 10.0 billion.

In 2018, capital expenditures were USD 15.2 billion as per note 3 Segments to the Consolidated financial statements. A total of USD 5.3 billion were excluded from the organic capital expenditures. Among items excluded from the organic capital expenditure in 2018 were acquisition of a 51% operated interest in the Martin Linge field, acquisition of a 25% interest in the Roncador field in Brazil, signature bonus for the Dois Irmãos and Uirapuru exploration blocks in Brazil and acquisition of 40% interest of the North Platte oil discovery in the US Gulf of Mexico resulting in organic capital expenditure of USD 9.9 billion.

### d) Free cash flow and organic free cash flow

Free cash flow includes the following line items in the Consolidated statement of cash flows: Cash flows provided by operating activities before taxes paid and working capital items (USD 21.8 billion), taxes paid (negative USD 8.3 billion), cash used in business combinations (negative USD 2.3 billion), capital expenditures and investments (negative USD 10.2 billion), (increase) decrease in other items interest bearing (USD 0.0 billion), proceeds from sale of assets and businesses (USD 2.6 billion), dividend paid (negative USD 3.3 billion) and share buy-back (negative USD 0.4 billion), resulting in a negative free cash flow of USD 0.2 billion in 2019.

Organic free cash flow is Free cash flow excluding proceeds from sale of assets and businesses and cash flow to acquisitions (additions through business combinations and the inorganic investments included in capital expenditures and investments), of total USD 0.6 billion, resulting in an organic free cash flow of USD 0.4 billion in 2019.

### e) Adjusted earnings and adjusted earnings after tax

Management considers adjusted earnings and adjusted earnings after tax together with other non-GAAP financial measures as defined below, to provide a better indication of the underlying operational and financial performance in the period (excluding financing), and therefore better facilitate comparisons between periods.

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

Adjusted earnings are based on net operating income/(loss) 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 Equinor’s underlying operational performance in the individual reporting period. Management considers adjusted earnings to be a supplemental measure to Equinor’s IFRS measures, which provides an indication of Equinor’s underlying operational performance in the period and facilitates an alternative understanding of operational trends between the periods, and uses this metric in determining variable remuneration and awards of LTI grants to members of the corporate executive committee. Adjusted earnings adjusts for the following items:

· Changes in fair value of derivatives: Certain gas contracts are, due to pricing or delivery conditions, deemed to contain embedded derivatives, required to be carried at fair value. Also, certain transactions related to historical divestments include contingent consideration, are carried at fair value. The accounting impacts of changes in fair value of the aforementioned are excluded from adjusted earnings. In addition, a djustments 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

Equinor, Annual Report on Form 20-F 2019 265

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 and is accounted for using the lower of cost or market price. If market prices increase above cost price, the inventory will not reflect this increase in value. There will be a loss on the derivative hedging the inventory since the derivatives always reflect changes in the market price. An adjustment is made to reflect the unrealised market increase 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 of the inventory and the derivative effect in the IFRS income statement will offset each other and no adjustment is made

· Over/underlift: Over/underlift is accounted for using the sales method and therefore revenues were reflected in the period the product was sold rather than in the period it was produced. The over/underlift position depended on a number of factors related to our lifting programme and the way it corresponded 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 to reflect operational performance and comparability with peers. Following the first quarter of 2019, Equinor changed the accounting policy for lifting imbalances. Adjusted earnings now include the over/underlift adjustment

· The operational storage is not hedged and is not part of the trading portfolio. 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 of assets 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 within 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 consequently impact net operating income. Write-down to production cost 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 Equinor’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 are carefully assessed and can include transactions such as provisions related to reorganisation, early retirement, etc.

· Change in accounting policy are adjusted when the impacts on income in the period are unusual or infrequent, and not reflective of Equinor’s underlying operational performance in the reporting period

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. 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 Equinor’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. 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.

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 as such non-GAAP measures do not include all the items of revenues/gains or expenses/losses of Equinor that 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. Equinor reflects 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. These measures should therefore not be used in isolation.

266 Equinor, Annual Report on Form 20-F 2019

Calculation of adjusted earnings after tax | For the year ended 31 December
(in USD million) | 2019 | 2018 | 2017
Net operating income | 9,299 | 20,137 | 13,771
Total revenues and other income | (1,022) | (2,141) | (405)
Changes in fair value of derivatives | (291) | (95) | (197)
Periodisation of inventory hedging effect | 306 | (280) | (43)
Impairment from associated companies | 23 | - | -
Change in accounting policy1) | - | (287) | -
Over-/underlift | 166 | - | (155)
Gain/loss on sale of assets | (1,227) | (656) | (10)
Provisions | - | (823) | -
Purchases [net of inventory variation] | 508 | 29 | (35)
Operational storage effects | (121) | 132 | (94)
Eliminations | 628 | (103) | 59
Operating and administrative expenses | 619 | 114 | 418
Over-/underlift | (32) | - | 11
Other adjustments | - | 1 | 9
Change in accounting policy1) | 123 | - | -
Gain/loss on sale of assets | 43 | 2 | 382
Provisions | 485 | 111 | 12
Cost accrual changes | - | - | 4
Depreciation, amortisation and impairment | 3,429 | (457) | (1,055)
Impairment | 3,549 | 794 | 917
Reversal of impairment | (120) | (1,399) | (1,972)
Provisions | - | 148 | -
Exploration expenses | 651 | 276 | (56)
Impairment | 651 | 287 | 435
Reversal of impairment | - | - | (517)
Cost accrual changes | - | (11) | 25
Sum of adjustments to net operating income | 4,185 | (2,178) | (1,132)
Adjusted earnings | 13,484 | 17,959 | 12,639
Tax on adjusted earnings | (8,559) | (11,265) | (8,110)
Adjusted earnings after tax | 4,925 | 6,693 | 4,529
1) Change in accounting policy for lifting imbalances. |  |  |

#

Equinor, Annual Report on Form 20-F 2019 267

# 5.3 L egal proceedings

Equinor 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. Equinor does not believe such proceedings will, individually or in the aggregate, have a significant effect on Equinor’s financial position, profitability, results of operations or liquidity. See also note 9 Income taxes and note 24 Other commitments, contingent liabilities and contingent assets to the Consolidated financial statements.

268 Equinor, Annual Report on Form 20-F 2019

5.6 T erms and abbreviations

Organisational abbreviations

· ADS – American Depositary Share

· ADR – American Depositary Receipt

· ACG - Azeri-Chirag-Gunashli

· AFP - Agreement-based early retirement plan

· AGM - Annual general meeting

· ARO - Asset retirement obligation

· BTC - Baku-Tbilisi-Ceyhan pipeline

· CCS - Carbon capture and storage

· CLOV - Cravo, Lirio, Orquidea and Violeta

· CO2 - Carbon dioxide

· CO2eq - Carbon dioxide equivalent

· DKK - Danish Krone

· DPB – Development & Production Brazil

· DPI - Development & Production International

· DPN - Development & Production Norway

· DPUSA - Development & Production USA

· 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

· GDP - Gross domestic product

· GHG - Greenhouse gas

· GSB - Global Strategy & Business Development

· HSE - Health, safety and environment

· IASB - International Accounting Standards Board

· ICE - Intercontinental Exchange

· IFRS - International Financial Reporting Standards

· IOGP - The International Association of Oil & Gas Producers

· IOR - Improved oil recovery

· LNG - Liquefied natural gas

· LPG - Liquefied petroleum gas

· MMP - Marketing, Midstream & Processing

· MPE - Norwegian Ministry of Petroleum and Energy

· NCS - Norwegian continental shelf

· NES – New Energy Solutions

· NIOC - National Iranian Oil Company

· NOK - Norwegian kroner

· NOx- Nitrogen oxide

· NYSE – New York stock exchange

· OECD - Organisation of Economic Co-Operation and Development

· OML - Oil mining lease

· OPEC - Organization of the Petroleum Exporting Countries

· OPEX – Operating expense

· OSE – Oslo stock exchange

· OTC - Over-the-counter

· OTS - Oil trading and supply department

· PDO - Plan for development and operation

· PIO - Plan for installation and operation

· PSA - Production sharing agreement

· PSC – Production sharing contract

· PSVM - Plutão, Saturno, Vênus and Marte

· R&D - Research and development

· ROACE - Return on average capital employed

· RRR - Reserve replacement ratio

· SDFI - Norwegian State's Direct Financial Interest

Equinor, Annual Report on Form 20-F 2019 269

· SEC - Securities and Exchange Commission

· SEK - Swedish Krona

· SG&A - Selling, general & administrative

· SIF - Serious Incident Frequency

· TPD - Technology, projects and drilling

· TRIF - Total recordable injuries per million hours worked

· TSP - Technical service provider

· UKCS - UK continental shelf

· US - United States of America

· USD - United States dollar

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

· mcm - thousand cubic metres

· mmcm - million cubic metres

· bcm - billion cubic metres

· km - kilometre

· one billion - one thousand million

· MW - Mega watt

· GW – Giga watt

· TW – Terra watt

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

· 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

· 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 Equinor's percentage ownership in a particular field. Entitlement volumes, on the other hand, represent Equinor'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

270 Equinor, Annual Report on Form 20-F 2019

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 Equinor 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

· Oslo Børs: Oslo stock exchange (OSE)

· Peer group: Equinor’s peer group consists of Equinor, Shell, ExxonMobil, OMV, ConocoPhillips, BP, Marathon, Chevron, Total, Repsol 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

· Storting: the Norwegian Parliament

· 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)

#

Equinor, Annual Report on Form 20-F 2019 271

# 5.7 F orward-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, including with respect to our net carbon intensity, carbon efficiency, methane emissions and flaring reductions, renewable energy capacity, carbon-neutral global operations, internal carbon price on investment decisions, future levels of, and expected value creation from, oil and gas production, scale and composition of the oil and gas portfolio, development of CCUS and hydrogen businesses, use of offset mechanisms and natural sinks and support of TCFD recommendations; organic investments, organic capital expenditure, capital investment, results of operations and cash flows, including plans to grow ROACE to 15% in 2023; future financial ratios and information; future financial or operational performance; the impact of Covid-19; future credit rating; future worldwide economic trends and market conditions, including the importance of trade tensions and emerging economies; future development and maturity of the portfolio; business strategy and competitive position; sales, trading and market strategies; research and development initiatives and strategy; expectations related to production levels, unit production cost, investment, exploration activities, discoveries and development in connection with our transactions and projects in Angola, Argentina, Azerbaijan, Brazil, Germany, the Gulf of Mexico, the NCS, the North Sea, Poland, the United Kingdom and the United States; employee training and KPIs; plans to redesign the CHP; completion and results of acquisitions, disposals and other contractual arrangements and delivery commitments; recovery factors and levels; future margins; future levels or development of capacity, reserves or resources; planned turnarounds and other maintenance activity; plans for renewables production capacity and the balance between oil and renewables production; oil and gas volume growth, including for volumes lifted and sold to equal entitlement production; estimates related to production and development, forecasts, reporting levels and dates; operational expectations, estimates, schedules and costs; expectations relating to licences and leases; oil, gas, alternative fuel and energy prices, volatility, supply and demand; environmental cleanup timing; processes related to human rights laws; organisational structure and policies; technological innovation, implementation, position and expectations; expectations regarding board composition, remuneration and application of the company performance modifier future levels of diversity; 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 of liquidity reserves; estimated or future liabilities, obligations or expenses; expected impact of currency and interest rate fluctuations and LIBOR discontinuation; 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, share buy-backs and amounts and timing 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; levels and calculations of reserves and material differences from reserves estimates; unsuccessful drilling; operational problems; health, safety and environmental risks; natural disasters, adverse weather conditions, climate change, and other changes to business conditions; the effects of climate change; regulations on hydraulic fracturing; security breaches, including breaches of our digital infrastructure (cybersecurity); ineffectiveness of crisis management systems; the actions of competitors; the development and use of new technology, particularly in the renewable energy sector; inability to meet strategic objectives; the difficulties involving transportation infrastructure; political and social stability and economic growth in relevant areas of the world; an inability to attract and retain personnel; inadequate insurance coverage; changes or uncertainty in or non-compliance with laws and governmental regulations; the actions of the Norwegian state as majority shareholder; failure to meet our ethical and social standards; the political and economic policies of Norway and other oil-producing countries; non-compliance with international trade sanctions; the actions of field partners; adverse changes in tax regimes; exchange rate and interest rate fluctuations; factors relating to trading, supply and financial risk; general economic conditions; and other factors discussed elsewhere in this report.

We use certain terms in this document, such as “resource” and “resources” that the SEC’s rules prohibit us from including in our filings with the SEC. U.S. investors are urged to closely consider the disclosures in our Form 20-F, SEC File No. 1-15200. This form is available on our website or by calling 1-800-SEC-0330 or logging on to www.sec.gov.

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.

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272 Equinor, Annual Report on Form 20-F 2019

# 5.8 S ignature 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.

EQUINOR ASA

(Registrant)

By: /s/ LARS CHRISTIAN BACHER

Name: Lars Christian Bacher

Title: Executive Vice President and Chief Financial Officer

Dated: 20 March 2020

#

Equinor, Annual Report on Form 20-F 2019 273

# 5.9 E xhibits

The following exhibits are filed as part of this annual report:

Exhibit no | Description
Exhibit 1 | Articles of Association of Equinor ASA, as amended, effective from 15 May 2018 (English translation).
Exhibit 2.1 | Description of Securities registered under Section 12 of the Exchange Act.
Exhibit 2.2 | Form of Indenture among Equinor ASA (formerly known as Statoil ASA and StatoilHydro ASA), Equinor Energy AS (formerly known as Statoil Petroleum AS and StatoilHydro 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 2 April 2009).
Exhibit 2.3 | Supplemental Indenture No. 3 (incorporated by reference to Exhibit 4.1 of Equinor ASA’s Report on Form 6-K (File No. 001-15200) filed with the Commission on 10 September 2018).
Exhibit 2.4 | Form of Supplemental Indenture No. 4 (incorporated by reference to Exhibit 4.1 of Equinor ASA’s Report on Form 6-K (File No. 001-15200) filed with the Commission on 13 November 2019).
Exhibit 2.5 | Amended and Restated Agency Agreement, dated as of 10 May 2019, by and among Equinor ASA (formerly known as Statoil ASA), as Issuer, Equinor Energy AS (formerly known as Statoil Petroleum AS) as Guarantor, the Bank of New York Mellon, as Agent and the Bank of New York Mellon SA/NV, Luxembourg Branch as Paying Agent in respect of a ?20,000,000 Euro Medium Term Note Programme.
Exhibit 2.6 | Deed of Covenant, dated as of 10 May 2019, of Equinor ASA (formerly known as Statoil ASA) in respect of a ?20,000,000 Euro Medium Term Notes Programme
Exhibit 2.7 | Deed of Guarantee, dated as of 10 May 2019, of Equinor Energy AS (formerly known as 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 Equinor Energy AS (formerly known as Statoil Petroleum AS), dated November 24, 2010 (incorporated by reference to Exhibit 4(a)(i) of Equinor's (formerly known as Statoil) 2016 Form 20-F (File no. 001-15200) filed with the Commission on March 17, 2017).
Exhibit 4(a)(ii) | Amendment no. 1, 2, 3, 4, 5 and 6, dated 17 October 2010, 19 February 2013, 15 December 2012, 17 September 2014, 15 December 2017 and 22 December 2017, respectively, to Technical Services Agreement between Gassco AS and Equinor Petroleum AS (formerly known as Statoil Petroleum AS), dated November 24, 2010 (incorporated by reference to Exhibit 4(a)(ii) of Equinor's (formerly known as Statoil) 2017 Form 20-F (File no. 001-15200) filed with the Commission on March 23, 2018)
Exhibit 4(c) | Employment agreement with Eldar Sætre as of 4 February 2015 (incorporated by reference to Exhibit 4(c) of Equinor's (formerly known as Statoil) 2016 20-F (File no. 001-15200) filed with the Commission on March 17, 2017).
Exhibit 8 | Subsidiaries (see Significant subsidiaries included in section 2.7 Corporate in this annual report).
Exhibit 11 | Code of Conduct.
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 EY AS.
Exhibit 15(a)(ii) | Consent of KPMG AS
Exhibit 15(a)(iii) | Consent of DeGolyer and MacNaughton
Exhibit 15(a)(iv) | Report of DeGolyer and MacNaughton
Exhibit 101 | Interactive Data Files (formatted in XBRL (Extensible Business Reporting Language)). Submitted electronically with the annual report on Form 20-F.
1) | Furnished only.
The total amount of long term debt securities of Equinor ASA and its subsidiaries authorised under instruments other than those listed above does not exceed 10% of the total assets of Equinor ASA and its subsidiaries on a consolidated basis. The company agrees to furnish copies of any such instruments to the Commission upon request.

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274 Equinor, Annual Report on Form 20-F 2019

# 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 | 2.2 (Business overview—Key figures); 2.9 (Financial review); 4.1 (Consolidated financial statements of the Equinor Group); 5.1 (Shareholder information - Dividend policy and dividends)
| B. Capitalisation and Indebtedness | N/A
| C. Reasons for the Offer and Use of Proceeds | N/A
| D. Risk Factors | 2.11 (Risk review—Risk factors)
Item 4. | Information on the Company |
| A. History and Development of the Company | About the Report; 2.1 (Strategy and market overview); 2.2 (Business overview); 2.3 (Exploration & Production Norway (E&P Norway)); 2.4 (Exploration & Production International (E&P International)); 2.5 (Marketing, Midstream & Processing (MMP)); 2.6 (Other group); 2.7 (Corporate); 2.10 (Liquidity and capital resources—Review of cash flows); 2.10 (Liquidity and Capital Resources—Investments); note 4 (Acquisitions and disposals) to 4.1 (Consolidated financial statements of the Equinor Group)
| B. Business Overview | 2.1 (Strategy and market overview); 2.2 (Business overview); 2.3 (Exploration & Production Norway (E&P Norway)); 2.4 (Exploration & Production International (E&P International)); 2.5 (Marketing, Midstream & Processing (MMP)); 2.6 (Other group); 2.7 (Corporate)
| C. Organisational Structure | 2.2 (Business overview—Corporate structure, —Segment reporting); 2.7 (Corporate—Subsidiaries and properties)
| D. Property, Plants and Equipment | 2.3 (Exploration & Production Norway (E&P Norway)); 2.4 (Exploration & Production International (E&P International)); 2.5 (Marketing, Midstream & Processing (MMP)); 2.6 (Other group); 2.7 (Corporate—Real estate); 2.10 (Liquidity and capital resources—Investments); notes 10 (Property, plant and equipment) and 22 (Leases) to 4.1 (Consolidated financial statements of the Equinor Group)
| Oil and Gas Disclosures | 2.8 (Operational performance—Proved oil and gas reserves); 2.8 (Operational performance—Production volumes and prices)
Item 4A. | Unresolved Staff Comments | None
Item 5. | Operating and Financial Review and Prospects | The discussion does not address certain items in respect of 2017 in reliance on amendments to disclosure requirements adopted by the SEC in 2019. A discussion of such items in respect of 2017 may be found in the Annual Report on Form 20-F for the year ended December 31, 2018, filed with the SEC on March 15, 2018
| A. Operating Results | 2.7 (Corporate—Applicable laws and regulations); 2.9 (Financial review); 2.11 (Risk review—Liquidity, market and financial risks—Foreign exchange, —Financial risk)
| B. Liquidity and Capital Resources | 2.10 (Liquidity and capital resources); 2.11 (Risk review—Liquidity, market and financial risks); notes 2 (Financial risk management and measurement of financial instruments), 5 (Financial risk management), 15 (Trades and other receivables), 16 (Cash and cash equivalents), 18 (Finance debt) and 24 (Other commitments, contingent liabilities and contingent assets) to 4.1 (Consolidated financial statements of the Equinor Group)
| C. Research and development, Patents and Licences, etc. | 2.2 (Business overview—Research and development); note 7 (Other expenses) to 4.1 (Consolidated financial statements of the Equinor Group)
| D. Trend Information | passim
| E. Off-Balance Sheet Arrangements | 2.10 (Liquidity and capital resources—Principal Contractual obligations, —Off balance sheet arrangements); notes 22 (Leases), 23 (Implementation of IFRS 16 Leases) and 24 (Other commitments, contingent liabilities and contingent assets) to 4.1 (Consolidated financial statements of the Equinor Group)
| F. Tabular Disclosure of Contractual Obligations | 2.10 (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 | 3.8 (Corporate assembly, board of directors and management)
| B. Compensation | 3.11 (Remuneration to the board of directors and corporate assembly); 3.12 (Remuneration to the corporate executive committee); notes 6 (Remuneration) and 19 (Pensions) to 4.1 (Consolidated financial statements of the Equinor Group)
| C. Board Practices | 3.8 (Corporate assembly, board of directors and management); 3.9 (The work of the board of directors—Audit committee, —Compensation and executive development committee)
| D. Employees | 2.13 (Our people)
| E. Share Ownership | 3.8 (Corporate assembly, board of directors and management); note 6 (Remuneration) to 4.1 (consolidated financial statements of the Equinor Group); 5.1 (Shareholder information—Shares purchased by the issuer—Equinor’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 25 (Related parties) to 4.1 (Consolidated financial statements of the Equinor Group)
| 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 the Equinor Group); 5.1 (Shareholder information); 5.3 (Legal proceedings)
| B. Significant Changes | Note 27 (Subsequent events) to 4.1 (Consolidated financial statements of the Equinor Group)
Item 9. | The Offer and Listing |
| A. Offer and Listing Details | 5.1 (Shareholder information)
| 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 | 2.11 (Risk review—Risks related to state ownership); 3.1 (Implementation and reporting—Articles of association); 3.6 (General meeting of shareholders); 5.1 (Shareholder information); note 17 (Shareholders’ Equity and dividends) to 4.1 (Consolidated financial statements of the Equinor Group)
| C. Material Contracts | 2.5 (Marketing, Midstream & Processing (MMP))
| 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 the Report
| I. Subsidiary Information | N/A
Item 11. | Quantitative and Qualitative Disclosures About Market Risk | 2.11 (Risk review); notes 5 (Financial risk management) and 26 (Financial instruments: fair value measurement and sensitivity analysis of market risk) to 4.1 (Consolidated financial statements of the Equinor Group)
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 | Exhibit 2.5 (Description of registered securities); 5.1 (Shareholder information—Equinor 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 (Risk management and internal control); note 27 (Condensed consolidated financial information related to guaranteed debt securities) to 4.1 (Consolidated financial statements of the Equinor Group)
Item 16A. | Audit Committee Financial Expert | 3.9 (The work of the board of directors—Audit Committee)
Item 16B. | Code of Ethics | 3.1 (Implementation and reporting —Code of Conduct)
Item 16C. | Principal Accountant Fees and Services | 3.15 (External auditor)
Item 16D. | Exemptions from the Listing Standards for Audit Committees | 3.1 (Implementation and reporting —Compliance with NYSE listing rules)
Item 16E. | Purchases of Equity Securities by the Issuer and Affiliated Purchases | 5.1 (Shareholder Information—Shares purchased by issuer)
Item 16F. | Changes in Registrant’s Certifying Accountant | N/A
Item 16G. | Corporate Governance | 3.1 (Implementation and reporting—Compliance with NYSE listing rules)
Item 16H | Mine Safety Disclosure | N/A
Item 17. | Financial Statements | N/A
Item 18. | Financial Statements | 4.1 (Consolidated financial statements of the Equinor Group)

Equinor, Annual Report on Form 20-F 2019 275

276 Equinor, Annual Report on Form 20-F 2019