Annual Report • Mar 21, 2024
Annual Report
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(Mark One)
☐ REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR 12(g) OF THE SECURITIES EXCHANGE ACT OF 1934
OR
☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2023
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
(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)
(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
EQNR New York Stock Exchange*
American Depositary Shares EQNR New York Stock Exchange Ordinary shares, nominal value of NOK 2.50 each
*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
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.
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
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.
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.
Indicate by check mark whether the registrant has submitted electronically Interactive Data File required to be submitted 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)
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer ☒ 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 whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 762(b)) by the registered public accounting firm that prepared or issued its audit report. ☒
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive based compensation received by any of the registrant's executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
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 ☒
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 ☒ No
Other ☐
☒ Yes ☐ No
☐ Yes ☒ No
☒ Yes ☐ No
☒ Yes ☐ No
USE AND RECONCILIATION OF NON-GAAP FINANCIAL MEASURES
FORWARD-LOOKING STATEMENTS
ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES
ITEM 16G. CORPORATE GOVERNANCE
ITEM 16H. MINE SAFETY DISCLOSURE
ITEM 16I. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
ITEM 16J. INSIDER TRADING POLICIES
ITEM 16K. CYBERSECURITY
ITEM 17. FINANCIAL STATEMENTS
ITEM 18. FINANCIAL STATEMENTS
ITEM 19. EXHIBITS
CONSOLIDATED FINANCIAL STATEMENTS
Unless otherwise indicated, all references herein to "we", "our", the "company", the "group" or "Equinor" are references to Equinor ASA and its consolidated subsidiaries.
This document is our annual report on Form 20-F for the year ended 31 December 2023 ("2023 Form 20-F"). Reference is made to our Norwegian Integrated Annual Report for 2023 which is attached hereto as Exhibit 15.4 (the "2023 Annual Report"), our 2023 Oil and Gas Reserves Report which is attached hereto as exhibit 15.5 (the "2023 Oil and Gas Reserves Report"), our 2023 Remuneration Report which is attached hereto as exhibit 15.6 (the "2023 Remuneration Report"), and our 2023 Board of Governance Report which is attached hereto as exhibit 15.7 (the "2023 Corporate Governance Report"). Only (i) the information included in this 2023 Form 20-F, (ii) the information in the 2023 Annual Report, the 2023 Oil and Gas Reserves Report, the 2023 Remuneration Report and the 2023 Corporate Governance Report that is incorporated by reference in this 2023 Form 20-F (excluding any page references incorporated in the incorporated material unless specifically noted otherwise), and (iii) the other exhibits to this 2023 Form 20-F shall be deemed to be filed with the Securities and Exchange Commission ("SEC") for any purpose, including incorporation by reference into the Registration Statement on Form F-3 filed on May 4, 2023 (File No. 333-271647), and Registration Statement on Form S-8 filed on February 9, 2022 (File No. 333-262601) and any other documents filed by us pursuant to the Securities Act of 1933, as amended, which purport to incorporate by reference the 2023 Form 20-F. Unless otherwise indicated, references to major headings include all information under such major headings, including subheadings, unless such reference is a reference to a subheading, in which case such reference includes only the information contained under such subheading. Any other information shall not be deemed to be so incorporated by reference.
In addition to the information set out below, the information set forth under the heading "Other definitions and abbreviations" in Section 5.7 of Chapter 5 on pages 306 – 309 of the 2023 Annual Report is incorporated herein by reference.
The 2023 Annual Report contains references to our website (https://www.equinor.com). Information on our website or any other website referenced in the 2023 Annual Report is not incorporated into this document and should not be considered part of this document.
The SEC maintains an Internet website that contains reports and other information regarding issuers that file electronically with the SEC. Our filings with the SEC are available to the public through the SEC's website at http://www.sec.gov.
The information about Equinor's competitive position in this 2023 Form 20-F (including the information in the 2023 Annual Report that is incorporated by reference herein) is based on several 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.
Since 2007, Equinor has been preparing its audited consolidated financial statements in accordance with International Financial Reporting Standards (IFRS® Accounting Standards) as adopted by the European Union (EU) and as issued by the International Accounting Standards Board. IFRS Accounting Standards have been applied consistently to all periods in our audited consolidated financial statements as of 31 December 2023 and 2022, and for the three years ended 31 December 2023 included in this 2023 Form 20-F (the "Consolidated financial statements").
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 Accounting Standards in the case of Equinor). The following financial measures included in this 2023 Form 20-F may be considered non-GAAP financial measures:
For more information on the calculation and reconciliation of these non-GAAP financial measures, see "Item 5. Operating and Financial Review and Prospects—B. Liquidity and capital resources—Use and reconciliation of non-GAAP financial measures."
This 2023 Form 20-F F (including information incorporated herein from the 2023 Integrated Annual Report) contains certain forward-looking statements that involve risks and uncertainties, in particular in the sections incorporated by reference in Item 4 of this 2023 Form 20-F. In some cases, we use words such as "aim", "ambition", "anticipate", "believe", "continue", "commit", "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: the commitment to develop as a broad energy company and diversify our energy mix; the ambition to be a leading company in the energy transition; ambition to reach net zero by 2050 and expectations regarding progress on our energy transition plan; our ambitions regarding reduction in operated emissions and net carbon intensity and allocation of gross capex* to renewables and low carbon solutions; our ambitions and expectations regarding decarbonisation; our ambition to maintain value in oil and gas, focus on high value growth in renewables and contribute to maturing CCS and hydrogen markets; ambition to attain a leadership position in the European CCS market and expectations regarding market share for storage and hydrogen; aims, expectations and plans for renewables production capacity and power generation, investments in renewables and low-carbon solutions and the balance between oil and gas and renewables production; our expectations with respect to net carbon intensity, operated emissions, carbon and methane intensity and flaring reductions; our internal carbon price and other financial metrics for investment decisions; break-even considerations and targets; robustness of our portfolio; aims and expectations regarding Equinor's resilience across different climate scenarios; future levels of, and expected value creation from, oil and gas production, scale and composition of the oil and gas portfolio, and development of CCS and hydrogen businesses; plans to develop fields; our intention to optimise and mature our portfolio; future worldwide economic trends, market outlook and future economic projections and assumptions, including commodity price assumptions; expectations and plans regarding capital expenditures; future financial performance, including earnings, cash flow, liquidity and return on average capital employed (ROACE)*; the ambition to grow cash flow and returns; expectations regarding cash flow and returns from our oil and gas portfolio and renewables and low carbon solutions portfolio; organic capital expenditures for 2024; expectations and estimates regarding production and execution of projects; the ambition to keep unit of production cost in the top quartile of our peer group; scheduled maintenance activity and the effects thereof on equity production; business strategy and competitive position; sales, trading and market strategies; research and development initiatives and strategy, including ambitions regarding allocation of research and development capital towards renewables and low carbon-solutions; expectations related to production levels, unit production cost, investments, exploration activities, discoveries and development in connection with our ongoing transactions and projects; our ambitions, expectations and plans regarding diversity and inclusion, employee training and supporting a just energy transition; plans and expectations regarding completion and results of acquisitions, disposals and other contractual arrangements and delivery commitments; plans, ambitions and expectations regarding recovery factors and levels, future margins and future levels or development of capacity, reserves or resources; planned turnarounds and other maintenance activity; expectations regarding growth in oil and gas, , including for volumes lifted and sold to equal entitlement production, and renewable power 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; plans and expectations regarding processes related to human rights laws, corporate structure and organizational policies; digitization, technological innovation, implementation, position and expectations; expectations regarding role and composition of the board and our remuneration policies; 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; future credit ratings; estimated or future liabilities, obligations or expenses; expected impact of currency and interest rate fluctuations; projected outcome, impact or timing of HSE regulations; HSE goals and objectives of management for future operations; our ambitions and plans regarding biodiversity (including our aim to develop a net-positive impact approach for projects) and value creation for society; 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 factors incorporated in Item 3.D of this 2023 Form 20-F.
Forward-looking statements are not guarantees of future performance. They reflect current views about future events, are based on management's current expectations and assumptions 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, in particular in light of significant oil price volatility; unfavourable macroeconomic conditions and inflationary pressures; exchange rate and interest rate fluctuations; levels and calculations of reserves and material differences from reserves estimates; regulatory stability and access to resources, including attractive low carbon opportunities; the effects of climate change and changes in stakeholder sentiment and regulatory requirements regarding climate change; changes in market demand and supply for renewables; inability to meet strategic objectives; the development and use of new technology; social and/or political instability, including as a result of Russia's invasion of Ukraine and the conflict in the Middle East; failure to prevent or manage digital and cyber disruptions to our information and operational technology systems and those of third parties on which we rely; operational problems, including cost inflation in capital and operational expenditures; unsuccessful drilling; availability of adequate infrastructure at commercially viable prices; the actions of field partners and other third-parties; reputational damage; the actions of competitors; the actions of the Norwegian state as majority shareholder and exercise of ownership by the Norwegian state; changes or uncertainty in or non-compliance with laws and governmental regulations; adverse changes in tax regimes; the political and economic policies of Norway and other oil-producing countries; regulations on hydraulic fracturing
and low-carbon value chains; liquidity, interest rate, equity and credit risks; risk of losses relating to trading and commercial supply activities; an inability to attract and retain personnel; ineffectiveness of crisis management systems; inadequate insurance coverage; health, safety and environmental risks; physical security risks to personnel, assets, infrastructure and operations from hostile or malicious acts; failure to meet our ethical and social standards; non-compliance with international trade sanctions; and other factors discussed elsewhere in this 2023 Form 20-F.
The achievement of Equinor's climate ambitions 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 its energy transition plan, Equinor's ability to meet its climate ambitions will be impaired. The calculation of Equinor's net carbon intensity presented in this report includes an estimate of emissions from the use of sold products (GHG protocol category 11) as a means to more accurately evaluate the emission lifecycle of what we produce to respond to the energy transition and potential business opportunities arising from shifting consumer demands. Including these emissions in the calculations should in no way be construed as an acceptance by Equinor of responsibility for the emissions caused by such use.
The reference to any scenario in this report, including any potential net-zero scenarios, does not imply Equinor views any particular scenario as likely to occur. Third-party scenarios discussed in this report reflect the modeling assumptions and outputs of their respective authors, not Equinor, and their use by Equinor is not an endorsement by Equinor of their underlying assumptions, likelihood or probability. Investment decisions are made on the basis of Equinor's separate planning process. Any use of the modeling of a third-party organization within this report does not constitute or imply an endorsement by Equinor of any or all of the positions or activities of such organization.
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. Any forward-looking statement speaks only as of the date on which such statement is made, and, except as required by applicable law, we undertake no obligation to update any of these statements after the date of this 2023 Form 20-F, either to make them conform to actual results or changes in our expectations.
Not applicable.
Not applicable.
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Not applicable.
The information set forth under the heading "Risk Factors" in section 5.2 of chapter 5 on pages 264– 270 of the 2023 Annual Report is incorporated herein by reference.
Equinor ASA was incorporated on 18 September 1972, is a public limited liability company organised under the laws of Norway and is subject to the provisions of the Norwegian Public Limited Liability Companies Act. Equinor's head office is located at Forusbeen 50, 4035 Stavanger, Norway. The telephone number of its principal place of business is +47-5199-00 00.
The information set forth under the following headings of the 2023 Annual Report is incorporated herein by reference:
The information set forth in the third and fourth paragraphs of the section entitled "Introduction" of this 2023 Form 20-F is also incorporated herein by reference. See also notes 5 Segments and 6 Acquisitions and disposals to the Consolidated financial statements.
The information set forth under the following headings of the 2023 Annual Report is incorporated herein by reference:
See also notes 5 Segments and 7 Total revenues and other income to the Consolidated financial statements.
The information about Equinor's competitive position in the sections of the 2023 Annual Report that are incorporated by reference herein is based on several 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 operates in around 30 countries and is exposed and committed to compliance with numerous laws and regulations globally. The first graphic in Section 1.3 ('Our Business') on page 12 in Chapter 1 and the risks set forth under the heading 'Policies and legislation' in Section 5.2 on page 267 of Chapter 5 of the 2023 Annual Report are also incorporated herein by reference.
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.
Currently, Equinor is subject to two main regimes applicable to petroleum activities worldwide:
Equinor is also subject to a wide variety of laws and regulations concerning its products, operations and activities, including without limitations laws and regulations relating to health, safety and environmental (HSE). Relevant laws and regulations include inter alia jurisdiction specific laws and regulations, international regulations, conventions or treaties, as well as EU directives and regulations.
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 licences 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 relevant jurisdiction to royalties, profit tax or special petroleum tax.
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, allocation of profit oil and, in some cases, tax.
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 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.
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).
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 and relevant decisions of the Norwegian State.
The State'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 Ministry of Trade, Industry and Fisheries. The Ministry 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. The information regarding the Norwegian State's ownership in the information set forth under the heading "Major
Shareholders" in Section 5.1 of Chapter 5 and the risks set forth in "Ownership and action by the Norwegian State" in Section 5.2 of Chapter 5 of the 2023 Annual Report are also incorporated herein by reference.
• 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 Petroleum Act sets out the principle that the Norwegian State is the owner of all subsea petroleum on the NCS, that the exclusive right to resource management is vested in the Norwegian State and that the Norwegian State alone is 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 MPE. Production licences are awarded to groups 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 MPE uses the same standard form of joint operating agreement and accounting agreement for all licenses.
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 tax treatment by the Ministry of Finance. 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. An example of this occurred in May 2020, when the Norwegian State imposed a reduction in oil production for the rest of the year, due to the Covid-19 pandemic that led to a lower demand for oil and gas. The reduction in production was distributed between all fields on a pro rata basis.
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.
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.
The information regarding Equinor's activities and shares in Equinor's production licences on the NCS, set forth under the heading 'Exploration & Production Norway' in Section 3.1 of Chapter 3 of the 2023 Annual Report is incorporated herein by reference.
On 1 July 2022, the MPE decided that parts of the Norwegian Security Act would apply to Equinor. This enables Equinor to receive and handle classified information from the authorities. In 2023, the MTIF and the MPE notified that the Security Act will apply in its entirety to Equinor as an undertaking controlling infrastructure and engaging in activities which are of vital importance to fundamental national functions. The Security Act entered into force 1 January 2019 and is designed to protect national security interests. The National Security Authority supervises undertakings which are covered by the act.
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 for booked capacity rather than the volumes actually transported.
The information set forth under the heading 'Marketing, Midstream & Processing' in Section 3.4 of Chapter 3 of the 2023 Annual Report is also incorporated herein by reference.
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 holds 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, Equinor, in its activities on the NCS, take account of these ownership interests in decisions that may affect the execution of this marketing arrangement.
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 through a separate instruction (the Owner's Instruction) adopted by an extraordinary shareholder meeting in 2001, with the Norwegian State as sole shareholder at the time. The Owner's Instruction sets out the specific terms for the marketing and sale of the Norwegian State's oil and gas.
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 utilise its position as majority shareholder of Equinor to withdraw or amend the Owner's Instruction.
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 landowner. 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 US 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 with the applicable governmental agency for federal, state or tribal land, and for private lands, with each owner of the minerals the company wishes to develop. In each 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 US 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) Pennsylvania Department of Environmental Protection's Office of Oil and Gas Management, (b) Ohio Department of Natural Resources, Division of Oil and Gas, and (c) West Virginia Department of Environmental Protection. 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.
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 Brazilian National Agency of Petroleum, 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 program. 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 nonoperators.
The concession agreements are signed by ANP on behalf of the Federal Government. Generally, concessions are granted for a 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 government-controlled 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 appoints 50% of the members of the operating committee, including the chairperson, 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, by law, cannot be extended. Of the two phases of the contract – exploration and production – the exploration phase may 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, companies must obtain an environmental license granted by the Brazilian Institute of Environment and Renewable Natural Resources (IBAMA), which, together with ANP, is responsible for the safety and environmental regulations regarding upstream activities.
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 of installations and vessels. The Petroleum Act specifically requires that petroleum operations are carried out in such a manner that a high level of safety is maintained 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 and Social Inclusion/Norwegian Ministry of Transport/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.
The Norwegian Petroleum Act imposes strict liability for pollution damage regardless of fault. Accordingly, as a holder of licences on the NCS, Equinor is subject to statutory strict liability under the Petroleum Act as a result of pollution caused by spills or discharges of petroleum from petroleum facilities in any of Equinor's licences.
A claim against the license 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 licences.
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 NCS have an obligation to, and are responsible, for establishing sufficient procedures for the monitoring and reporting of any discharge into the sea. The Norwegian 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.
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 is expected to affect energy and industry installations, which include Equinor's installations at the NCS. The price of emissions allowances has increased significantly since the reforms to the EU Emission Trading Scheme in 2018 and is expected to increase further towards 2030.
The Norwegian Climate Act promotes the implementation of Norway's climate targets as part of the transition to a low-emission society in Norway in 2050. This act may influence our activities through plans and actions implemented by the state to achieve these targets. Norway has presented a Climate Plan 2021-2030 with an updated target of 55% reduction in GHG emissions in 2030 compared to 1990- levels. The Climate Plan states that the carbon cost for offshore oil and gas production in Norway is expected to increase to 2000 NOK/t CO2 towards 2030.
EU directive 2009/31/EC on the geological storage of CO2 is implemented in the Pollution Control regulations, the regulations related to the Petroleum Act and in a separate Storage regulation adopted under the 1963 Act relating to scientific research and exploration for and exploitation of subsea natural resources other than petroleum resources. The CO2 capture and storage at Equinor's Sleipner and Snøhvit fields are governed by the Petroleum Act and the Pollution Control regulations, and the CO2 storage at Northern Lights JV DA and Smeaheia projects are governed by the Storage regulations and the Pollution Control regulations.
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 Ohio, Pennsylvania and West Virginia), and 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 (OCS), 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 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 nautical miles from shore. The Bureau of Ocean Energy Management (BOEM) manages federal OCS leasing programs, 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 Biden Administration continues to review and revise these regulations, and Equinor is engaged with relevant governmental and industry stakeholders to ensure that Equinor's operations remain in compliance.
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 Brazilian Petroleum Law, Equinor is also subject to many other laws and regulations issued by different authorities, including 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, without prejudice to any recourse rights which may have been agreed separately among the consortium members (such as in a joint operating agreement).
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 and/or cancellation in case of non-compliance with such conditions.
In Brazil, Equinor is also required to have an emergency response system as per ANP Resolution No. 882/2022 to deal with emergency situations in its petroleum operations, as well as an oil spill response plan in accordance to CONAMA Resolution No. 398/2008, for each asset to minimise the environmental impact of any environmental unexpected situation that may generate spill of oil or chemical to sea.
Discharges from Brazilian petroleum activities are regulated through several acts, including the CONAMA Resolution No. 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 environmental permitting process and the operator must apply for any discharge permit from relevant authorities on behalf of the license group in order to discharge any pollutants into the water.
Although Equinor's operations in Brazil are not subject to emissions taxes (CO2 limit) yet, there are initiatives within the Brazilian congress for the establishment of a carbon market. At this point it is unclear if and when these initiatives will be turned into law.
The CONAMA Regulation No. 382/06 regulates air emissions limits for pollutant gases (e.g. NOx) from all fixed sources that have total power consumption higher than 100MW.
Gas flares must be authorised by the ANP under ANP Resolution No. 806/2020, which also sets out cases in which ANP authorisation is not necessary.
The Brazilian government signed the Paris Agreement in 2015. During COP26, Brazil updated its ambition to reduce its greenhouse gas emissions by 37% until 2025 and 50% 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 and for that Brazil continue to adhere to the Forest for Deal agreement, committing to take actions to reduce illegal deforestation until 2030. The country also adheres to the Global Methane Pledge.
Equinor's renewables positions currently mainly consist of offshore wind farms in operation and development in the UK, the state of New York and Poland. In these 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 entered into 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 2023.
Equinor's profits, both from offshore oil and natural gas activities and from onshore activities, are subject to Norwegian corporate income tax. In addition, a special petroleum tax is levied on profits from petroleum production and pipeline transportation on the NCS. In June 2022 the parliament enacted a cash-flow based tax system for the special petroleum tax with effect from 1 January 2022. After the reform, the Norwegian petroleum income is taxable at a tax rate of 71.8% after deducting a calculated 22% corporate tax. The corporate tax is deductible in the basis for the special petroleum tax, resulting in a 78% marginal tax rate. For further information, see note 11 Income taxes to the Consolidated financial statements.
Investment costs in the ordinary tax base (22%) will continue to be depreciated over six years. In the special tax base, investments are written off immediately in line with the cash-flow based tax system. Projects covered by the temporary rules introduced in 2020 have had a tax uplift of 12.4% in 2023. The temporary rules apply to investments covered by field or infrastructure plans (PDOs and PIOs) submitted to the MPE after 12 May 2020 and before 1 January 2023 and approved before 1 January 2024. The temporary rules will continue to apply until (and including) the year of planned production or project start-up according to the approved plans.
Equinor's international petroleum activities are subject to tax pursuant to local legislation.
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 corporate income tax rate in the US is 21%, and there is an alternative 15% minimum tax on corporate book income for corporations with profits over USD 1 billion. US companies are also subject to the Base Anti-abuse Tax ("BEAT") which imposes tax at 10% until 2026 and 12.5% thereafter on payments to foreign affiliates of US companies if those payments exceed a given threshold of total tax-deductible expenditures.
Corporate income tax and social contribution are levied on taxable net income at a combined rate of 34%. A simplified tax regime with a lower effective tax rate is available for legal entities with gross revenues below a threshold of 78 million Brazilian reais per year. In addition, there are several indirect taxes, but indirect tax rate on exports is set to zero.
The concessionary tax regime in Brazil usually includes government takes such as a 10% royalty, and special participation tax that varies based on time, location and production between 10% and 40%, using a reference price that is established by the Brazilian petroleum regulator (ANP). The Production Sharing Regime in Brazil usually includes a 15% royalty, an annual 80% cost recovery ceiling, and a biddable government profit share.
In December 2023, the Brazilian Congress approved wide-ranging tax legislation which aims to simplify the indirect tax system through the introduction of a multi-tiered value added tax (VAT) system, whereby VAT would be levied with a federal rate and a state and/or municipality rate. The states or municipalities would individually set their respective rates and administer the tax for the local element of the VAT. The VAT will be phased into effect over the next seven years. The new law also includes an excise tax on the extraction, sale or commercialization of goods and services with a "harmful effect on health or environment" of up to 1% of the market value of extracted production. The specific rate of the excise tax will be set with a complimentary law which must be passed within six months of the enactment, and so is expected by the end of June 2024. This excise tax would increase operating costs for Equinor in Brazil.
The new tax law in Brazil also seeks to preserve suspensions or exemptions from certain indirect taxes for importation of capital goods into Brazil. The details of these tax incentives will be contained in the Complimentary Law described above.
Finally, there is a proposal package for direct taxes as well, which would reduce the corporate tax rate, while also introducing a withholding tax on dividends paid by Brazilian incorporated entities. The direct tax legislation is expected to be considered by the Brazilian Congress later in 2024.
The UK government introduced a 25% Energy Profits Levy (EPL) in May 2022, which was increased to 35% from January 2023. The levy is charged on profits from oil and gas operations in the UK or on the UK Continental Shelf and is in addition to existing profitbased taxes on the sector. The EPL increased the rate of tax on oil and gas company profits to 75% from January 2023.
In addition, the UK government also introduced the Electricity Generator Levy (EGL) which took effect from 1 January 2023. The EGL imposes a tax of 45% on exceptional receipts generated from the production of wholesale electricity which is sold at an average price in excess of £75 per MWh.
Both the EPL and EGL are scheduled to expire on 31 March 2028.
The 2023 Oil and Gas Reserves Report is incorporated herein by reference. See also notes 5 Segments and 7 Total revenues and other income to the Consolidated financial statements.
The information set forth under the headings "Operational data", "Sales prices" and "Sales volumes" in Section 2.1 of Chapter 2 on pages 47 – 49 and "Proved oil and gas reserves" in Section 2.1 of Chapter 2 on pages 50 – 54 of the 2023 Annual Report is also incorporated herein by reference.
The following information is reported pursuant to FASB Topic 932.
| At 31 December | |||||
|---|---|---|---|---|---|
| (in USD million) | 2023 | 2022 | 2021 | ||
| Unproved properties | 5,022 | 5,917 | 7,077 | ||
| Proved properties, wells, plants and other equipment | 183,316 | 181,189 | 193,918 | ||
| Total capitalised cost | 188,338 | 187,106 | 200,994 | ||
| Accumulated depreciation, impairment and amortisation | (132,902) | (133,584) | (139,890) | ||
| Net capitalised cost | 55,436 | 53,523 | 61,104 |
Net capitalised cost related to equity accounted investments as of 31 December 2023 was USD 0 million, USD 463 million in 2022 and USD 900 million in 2021. 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.
These expenditures include both amounts capitalised and expensed.
| Eurasia | Americas | |||||
|---|---|---|---|---|---|---|
| (in USD million) | Norway | excluding Norway |
Africa | USA | excluding USA |
Total |
| Full year 2023 | ||||||
| Exploration expenditures | 662 | 16 | 35 | 310 | 253 | 1,276 |
| Development costs | 4,864 | 470 | 509 | 1,084 | 1,279 | 8,206 |
| Acquired proved properties | 0 | 1,271 | 0 | 0 | 0 | 1,271 |
| Acquired unproved properties | 352 | 5 | 0 | 6 | 18 | 381 |
| Total | 5,878 | 1,762 | 544 | 1,400 | 1,550 | 11,134 |
| Full year 2022 | ||||||
| Exploration expenditures | 494 | 27 | 57 | 150 | 360 | 1,088 |
| Development costs | 4,483 | 320 | 379 | 712 | 965 | 6,859 |
| Acquired proved properties | 110 | 226 | 38 | 0 | 0 | 374 |
| Acquired unproved properties | 6 | 0 | 0 | 0 | 0 | 6 |
| Total | 5,093 | 573 | 474 | 862 | 1,325 | 8,327 |
| Full year 2021 | ||||||
| Exploration expenditures | 522 | 61 | 5 | 139 | 299 | 1,026 |
| Development costs | 4,732 | 322 | 256 | 605 | 977 | 6,892 |
| Acquired proved properties | 3 | 5 | 0 | 0 | 0 | 8 |
| Acquired unproved properties | 6 | 9 | 1 | 24 | (3) | 37 |
| Total | 5,263 | 397 | 262 | 768 | 1,273 | 7,963 |
Expenditures incurred in exploration and development activities related to equity accounted investments was USD 0 million in 2023, USD 155 million in 2022 and USD 233 million in 2021.
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 results of operations for oil and gas producing activities are included in the three upstream reporting segments Exploration & Production Norway (E&P Norway), Exploration & Production International (E&P International) and Exploration & Production USA (E&P USA) as presented in note 5 Segments to 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 and royalty payments 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.
| Eurasia | Americas | |||||
|---|---|---|---|---|---|---|
| (in USD million) | Norway | excluding Norway |
Africa | USA | excluding USA |
Total |
| Full year 2023 | ||||||
| Sales | 62 | 107 | 533 | 127 | 92 | 921 |
| Transfers | 37,892 | 1,121 | 2,242 | 3,954 | 2,646 | 47,855 |
| Other revenues | 387 | 129 | 57 | 238 | 76 | 887 |
| Total revenues | 38,341 | 1,357 | 2,832 | 4,319 | 2,814 | 49,663 |
| Exploration expenses | (476) | (20) | (37) | (322) | 30 | (825) |
| Production costs | (2,898) | (250) | (482) | (494) | (593) | (4,717) |
| Depreciation, amortisation and net impairment losses | (5,017) | (840) | (567) | (1,489) | (1,026) | (8,939) |
| Other expenses | (862) | (456) | 19 | (691) | (446) | (2,436) |
| Total costs | (9,253) | (1,566) | (1,067) | (2,996) | (2,035) | (16,917) |
| Results of operations before tax | 29,088 | (209) | 1,765 | 1,323 | 779 | 32,746 |
| Tax expense | (22,543) | 34 | (961) | (358) | (106) | (23,934) |
| Results of operations | 6,545 | (175) | 804 | 965 | 673 | 8,812 |
| Net income/(loss) from equity accounted investments | 0 | (13) | 0 | 0 | 41 | 28 |
| Eurasia | Americas | |||||
|---|---|---|---|---|---|---|
| (in USD million) | Norway | excluding Norway |
Africa | USA | excluding USA |
Total |
| Full year 2022 | ||||||
| Sales | 155 | 554 | 615 | 166 | 88 | 1,578 |
| Transfers | 74,468 | 1,252 | 3,019 | 5,168 | 1,853 | 85,760 |
| Other revenues | 1,308 | (203) | (1) | 213 | 57 | 1,374 |
| Total revenues | 75,931 | 1,603 | 3,633 | 5,547 | 1,998 | 88,712 |
| Exploration expenses | (366) | (249) | (69) | (220) | (320) | (1,224) |
| Production costs | (2,916) | (202) | (470) | (399) | (518) | (4,505) |
| Depreciation, amortisation and net impairment losses | (4,167) | (623) | (530) | (361) | (579) | (6,260) |
| Other expenses | (866) | (201) | 3 | (533) | (413) | (2,010) |
| Total costs | (8,315) | (1,275) | (1,066) | (1,513) | (1,830) | (13,999) |
| Results of operations before tax | 67,616 | 328 | 2,567 | 4,034 | 168 | 74,713 |
| Tax expense | (52,070) | (152) | (1,043) | 2,458 | 361 | (50,447) |
| Results of operations | 15,546 | 176 | 1,524 | 6,492 | 529 | 24,266 |
| Net income/(loss) from equity accounted investments | 0 | 52 | 0 | 0 | 120 | 172 |
Consolidated companies
| Eurasia | Americas | |||||
|---|---|---|---|---|---|---|
| (in USD million) | Norway | excluding Norway |
Africa | USA | excluding USA |
Total |
| Full year 2021 | ||||||
| Sales | 97 | 476 | 638 | 207 | 16 | 1,434 |
| Transfers | 38,578 | 960 | 2,021 | 3,712 | 1,249 | 46,520 |
| Other revenues | 711 | (14) | 0 | 221 | 14 | 932 |
| Total revenues | 39,386 | 1,422 | 2,659 | 4,140 | 1,279 | 48,886 |
| Exploration expenses | (363) | (108) | 23 | (211) | (362) | (1,021) |
| Production costs | (2,600) | (196) | (497) | (397) | (378) | (4,068) |
| Depreciation, amortisation and net impairment losses | (4,900) | (2,462) | (444) | (1,734) | (416) | (9,956) |
| Other expenses | (1,052) | (140) | 53 | (674) | (292) | (2,105) |
| Total costs | (8,915) | (2,906) | (865) | (3,016) | (1,448) | (17,150) |
| Results of operations before tax | 30,471 | (1,484) | 1,794 | 1,124 | (169) | 31,736 |
| Tax expense | (22,887) | 835 | (652) | (14) | (201) | (22,919) |
| Results of operations | 7,585 | (649) | 1,142 | 1,110 | (370) | 8,817 |
| Net income/(loss) from equity accounted investments | 0 | 176 | 0 | 0 | 39 | 215 |
| Average production cost in USD per boe based on entitlement | Eurasia excluding |
Americas excluding |
||||
|---|---|---|---|---|---|---|
| volumes (consolidated) | Norway | Norway | Africa | USA | USA | Total |
| 2023 | 6 | 16 | 12 | 4 | 15 | 7 |
| 2022 | 6 | 13 | 12 | 4 | 21 | 7 |
| 2021 | 5 | 11 | 12 | 3 | 19 | 6 |
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.
Exhibit 8 to this 2023 Form 20-F is incorporated herein by reference. The table within Exhibit 8 shows significant subsidiaries and significant equity accounted companies within the Equinor group as of 31 December 2023.
Equinor has interests in real estate in many countries throughout the world, including as part of certain developments and projects of Equinor or in which Equinor participates.
Equinor's three largest office buildings are (i) its head office located at Forusbeen 50, Stavanger, Norway which comprises approximately 135,000 square meters of office space, (ii) its office building in Sandslivegen 90, Bergen, Norway which comprises approximately 99,488 square meters of office space, and (iii) its office building located at Fornebu on the outskirts of Oslo which comprises approximately 65,500 square meters. All three office buildings are leased by Equinor. Under a new lease agreement entered into in 2022 for the office building at Fornebu, Equinor has reduced its area to 44,500 square meters with effect from around the start of year 2024. The office building in Bergen is owned by Sandsliveien 90 AS, a subsidiary of Equinor Pensjon.
The information set forth under the following headings of the 2023 Annual Report is incorporated herein by reference:
See also notes 12 Property, plant and equipment and 25 Leases to the Consolidated financial statements.
The following tables show the regional production by field.
| E&P Norway - Equinor operated fields, average daily entitlement production | |||||
|---|---|---|---|---|---|
| -- | -- | ---------------------------------------------------------------------------- | -- | -- | -- |
| Field | Geographical area | Equinor's equity interest in % |
On stream |
Licence expiry date |
Average production in 2023 mboe/day |
|---|---|---|---|---|---|
| Johan Sverdrup | The North Sea | 42.63 | 2019 | 2036-2037 | 319 |
| Troll Phase 1 (Gas) | The North Sea | 30.58 | 1996 | 2030 | 198 |
| Oseberg | The North Sea | 49.30 | 1988 | 2031 | 94 |
| Gullfaks | The North Sea | 51.00 | 1986 | 2036 | 76 |
| Visund | The North Sea | 53.20 | 1999 | 2034 | 66 |
| Aasta Hansteen | The Norwegian Sea | 51.00 | 2018 | 2041 | 59 |
| Åsgard | The Norwegian Sea | 35.011) | 1999 | 2027 | 44 |
| Snøhvit | The Barents Sea | 36.79 | 2007 | 2035 | 44 |
| Tyrihans | The Norwegian Sea | 58.84 | 2009 | 2029 | 43 |
| Snorre | The North Sea | 33.28 | 1992 | 2040 | 32 |
| Gina Krog | The North Sea | 58.70 | 2017 | 2032 | 31 |
| Martin Linge | The North Sea | 51.00 | 2021 | 2027 | 29 |
| Kvitebjørn | The North Sea | 39.55 | 2004 | 2031 | 23 |
| Statfjord Unit | The North Sea | 64.102) | 1979 | 2026 | 21 |
| Sleipner West | The North Sea | 58.35 | 1996 | 2028 | 20 |
| Fram | The North Sea | 45.00 | 2003 | 2040 | 16 |
| Grane | The North Sea | 36.61 | 2003 | 2030 | 16 |
| Gudrun | The North Sea | 36.00 | 2014 | 2032 | 15 |
| Troll Phase 2 (Oil) | The North Sea | 30.58 | 1995 | 2030 | 13 |
| Mikkel | The Norwegian Sea | 43.97 | 2003 | 2028 | 11 |
| Heidrun | The Norwegian Sea | 13.04 | 1995 | 2024-2025 | 10 |
| Tordis | The North Sea | 41.50 | 1994 | 2040 | 8 |
| Alve | The Norwegian Sea | 53.00 | 2009 | 2029 | 8 |
| Trestakk | The Norwegian Sea | 59.10 | 2019 | 2029 | 8 |
| Vigdis | The North Sea | 41.50 | 1997 | 2040 | 7 |
| Norne | The Norwegian Sea | 39.10 | 1997 | 2026 | 7 |
| Kristin | The Norwegian Sea | 54.82 | 2005 | 2027-2033 | 7 |
| Hyme | The Norwegian Sea | 42.50 | 2013 | 2029 | 6 |
| Valemon | The North Sea | 66.78 | 2015 | 2031 | 6 |
| Njord | The Norwegian Sea | 27.50 | 1997 | 2034 | 4 |
| Sleipner East | The North Sea | 59.60 | 1993 | 2028 | 4 |
| Statfjord North | The North Sea | 45.002) | 1995 | 2026 | 4 |
| Morvin | The Norwegian Sea | 64.00 | 2010 | 2027 | 3 |
| Breidablikk | The North Sea | 39.00 | 2023 | 2030 | 2 |
| Gungne | The North Sea | 62.00 | 1996 | 2028 | 2 |
| Utgard | The North Sea | 38.442) | 2019 | 2028 | 2 |
| Statfjord East | The North Sea | 43.252) | 1994 | 2026-2040 | 2 |
| Urd | The Norwegian Sea | 63.95 | 2005 | 2026 | 1 |
| Sigyn | The North Sea | 60.00 | 2002 | 2035 | 1 |
| Sindre | The North Sea | 74.66 | 2017 | 2026-2034 | 0 |
| Fram H Nord | The North Sea | 49.20 | 2014 | 2024-2035 | 0 |
| Sygna | The North Sea | 43.432) | 2000 | 2026-2040 | 0 |
| Gimle | The North Sea | 74.66 | 2006 | 2026-2034 | 0 |
| Heimdal | The North Sea | 29.44 | 1985 | 2023 | 0 |
| Byrding | The North Sea | 70.00 | 2017 | 2024-2035 | 0 |
| Tune | The North Sea | 50.00 | 2002 | 2025-2032 | 0 |
| Total Equinor operated fields | 1,261 |
2) The Statfjord and Utgard fields in the North Sea span the boundary between the Norwegian and UK continental shelves. The volumes pertain to Equinor's operating interest in Statfjord and Utgard on the NCS. For the volumes pertaining to Equinor's operating interest in Statfjord and Utgard on the UKCS, please see Exploration & Production International in Section 3.1.2 of Chapter 3.
| Field | Geographical area | Equinor's equity interest in % |
Operator | On stream |
Licence expiry date |
Average production in 2023 mboe/day |
|---|---|---|---|---|---|---|
| Skarv | The Norwegian Sea | 36.17 | Aker BP ASA | 2013 | 2029-2036 | 54 |
| Ormen Lange | The Norwegian Sea | 25.35 | A/S Norske Shell | 2007 | 2040-2041 | 30 |
| Ivar Aasen | The North Sea | 41.47 | Aker BP ASA | 2016 | 2029-2036 | 14 |
| Goliat | The Barents Sea | 35.00 | Vår Energi ASA | 2016 | 2042 | 9 |
| Ærfugl Nord | The Norwegian Sea | 30.00 | Aker BP ASA | 2021 | 2033 | 4 |
| Marulk | The Norwegian Sea | 33.00 | Vår Energi ASA | 2012 | 2030 | 2 |
| Enoch | The North Sea | 11.78 Repsol Sinopec North Sea Ltd. | 2007 | 2024 | 0 | |
| Total partner operated fields | 114 |
|---|---|
| Total E&P Norway including share of equity accounted production | 0 |
| Field | Country | Equinor's equity interest in % |
Operator | On stream |
Licence expiry date |
Average daily equity production in 2023 mboe/day |
|---|---|---|---|---|---|---|
| Americas (excluding US) | 115 | |||||
| Peregrino | Brazil | 60.00 | Equinor Brasil Energia Ltda. | 2011 | 2040 | 53 |
| Roncador | Brazil | 25.00 | Petróleo Brasileiro S.A. | 1999 | 2052 | 33 |
| Bandurria Sur | Argentina | 30.00 | Yacimientos Petrolíferos Fiscales S.A. | 2015 | 2050 | 13 |
| Hebron | Canada | 9.01 | ExxonMobil Canada Properties | 2017 | HPB1) | 11 |
| Hibernia/Hibernia Southern Extension2) |
Canada | Varies | Hibernia Management and Development Company Ltd. |
1997 | HPB1) | 4 |
| Bajo del Toro | Argentina | 50.00 | Yacimientos Petrolíferos Fiscales S.A. | 2022 | 2055 | 1 |
| Africa | 175 | |||||
| Block 17 | Angola | 22.16 | TotalEnergies E&P Angola S.A. | 2001 | 2045 | 76 |
| In Salah | Algeria | 31.85 | Sonatrach3) | 2004 | 2027 | 30 |
| Eni In Salah Limited | ||||||
| Equinor In Salah AS | ||||||
| Agbami7) | Nigeria | 20.21 | Star Deep Water Petroleum Limited (an affiliate of Chevron in Nigeria) |
2008 | 2042 | 20 |
| Block 15 | Angola | 12.00 | Esso Exploration Angola Block 15 Limited | 2004 | 2032 | 17 |
| In Amenas | Algeria | 45.90 | Sonatrach3) | 2006 | 2027 | 14 |
| Eni In Amenas Limited | ||||||
| Equinor In Amenas AS | ||||||
| Block 31 | Angola | 13.33 | BP Exploration (Angola) Ltd | 2012 | 2031 | 9 |
| Murzuq | Libya | 10.00 | Akakus Oil Operations | 2003 | 2037 | 8 |
| Eurasia | 55 | |||||
| ACG8) | Azerbaijan | 7.27 | BP Exploration (Caspian Sea) Limited | 1997 | 2049 | 26 |
| Mariner | UK | 65.11 | Equinor UK Limited | 2019 | HBP1) | 13 |
| Buzzard9) | UK | 29.89 | CNOOC Petroleum Europe Limited | 2007 | 2046 | 7 |
| Corrib4) | Ireland | 37.50 | Vermilion Exploration and Production Ireland Limited |
2015 | 2031 | 2 |
| Utgard5) | UK | 38.00 | Equinor Energy AS | 2019 | HBP1) | 2 |
| Statfjord Unit5) | UK | 14.53 | Equinor Energy AS | 1979 | HBP1) | 4 |
| Barnacle6) | UK | 100.00 | Equinor UK Limited | 2019 | HBP1) | 0 |
| Total E&P International | 345 |
1) Held by Production (HBP): A leasehold interest that is perpetuated beyond its primary term as long as there is production in paying
quantities from well(s) on the lease or lease(s) pooled therewith.
2) Equinor's equity interests are 5.0% in Hibernia and 9.26% in Hibernia Southern Extension.
3) The complete name for Sonatrach is Société nationale de transport et de commercialisation d'hydrocarbures. 4) In March 2023, the transaction to sell the company's non-operated equity position in the Corrib gas project in Ireland closed after receiving
the necessary regulatory approvals. For more information, see note 6 Acquistions and disposals to the Consolidated financial statements. 5) The Utgard and Statfjord Unit fields span the boundary between the Norwegian and UK continental shelves. In this table we report only
volumes pertaining to the Equinor share in UKCS.
6) Actual production for Barnacle was 0.4 mboe/day.
7) In November 2023, Equinor announced its intention to exit its business activities in Nigeria.
8) In December 2023, Equinor and SOCAR signed an agreement whereby Equinor will divest and transfer all its remaining assets in Azerbaijan to SOCAR.
9) Production started in July 2023 following Equinor's acquisition of Suncor Energy UK Limited.
| Field | Country | Equinor's equity interest in % |
Operator | On stream |
Licence expiry date |
Average daily equity production in 2023 mboe/day |
|---|---|---|---|---|---|---|
| Appalachian (APB)1) | US | Varies2) | Equinor/others3) | 2008 | HBP5) | 223 |
| Caesar Tonga | US | 46.00 | Anadarko U.S. Offshore LLC | 2012 | HBP5) | 37 |
| Tahiti | US | 25.00 | Chevron USA Inc. | 2009 | HBP5) | 23 |
| Vito | US | 36.89 | Shell Offshore Inc. | 2023 | HBP5) | 22 |
| Julia | US | 50.00 | ExxonMobil Corporation | 2016 | HBP5) | 14 |
| St. Malo | US | 21.50 | Chevron USA Inc. | 2014 | HBP5) | 14 |
| Jack | US | 25.00 | Chevron USA Inc. | 2014 | HBP5) | 12 |
| Big Foot | US | 27.50 | Chevron USA Inc. | 2018 | HBP5) | 9 |
| Stampede | US | 25.00 | Hess Corporation | 2018 | HBP5) | 7 |
| Titan | US | 100.00 | Equinor USA E&P Inc. | 2018 | HBP5) | 2 |
| Heidelberg4) | US | 12.00 | Anadarko U.S. Offshore LLC | 2016 | HBP5) | 0 |
| Total E&P USA | 363 |
1) Appalachian basin contains Marcellus and Utica formations.
Not applicable.
The discussion does not address certain items in respect of 2021. A discussion of such items may be found in the Annual Report on Form 20-F for the year ended 31 December 2022, filed with the SEC 23 March 2023.
The information set forth under the following headings of the 2023 Annual Report is incorporated herein by reference:
See also the information set forth under the heading "Applicable Laws and Regulations" in "Item 4―Information on the Company―B. Business Overview" of this 2023 Form 20-F, and note 3 Consequences of initiatives to limit climate changes to the Consolidated financial statements.
The following tables show the financial performance by reporting segment.
| For the year ended 31 December | |||
|---|---|---|---|
| (in USD million) | 2023 | 2022 | Change |
| Total revenues and other income | 38,340 | 75,930 | (50%) |
| Operating, selling, general and administrative expenses | (3,759) | (3,782) | (1%) |
| Depreciation, amortisation and net impairment losses | (5,017) | (4,167) | 20% |
| Exploration expenses | (476) | (366) | 30% |
| Net operating income/(loss) | 29,087 | 67,614 | (57%) |
| For the year ended 31 December | |||
| Operational information | 2023 | 2022 | Change |
| E&P Norway entitlement liquid and gas production (mboe/day) | 1,374 | 1,387 | (1%) |
| E&P Norway entitlement liquids production (mboe/day) | 645 | 605 | 7% |
| E&P Norway entitlement gas production (mboe/day) | 729 | 782 | (7%) |
| Average liquids price (USD/bbl) | 78.6 | 97.5 | (19%) |
| Average internal gas price (USD/MMBtu) | 12.20 | 31.22 | (61%) |
Equinor revenues continued to remain strong for 2023 with production on par with 2022, even though lower prices for gas and liquids during the year led to a decrease in net operating income and revenues compared to 2022. Other income was impacted by gain from sale of ownership shares, with USD 222 million in 2023 for the Statfjord area compared to USD 730 million for Martin Linge and Ekofisk in 2022. In addition, other income in 2022 included a significant positive effect on embedded derivatives from higher short term gas prices.
Increased operation and maintenance costs, as well as environmental expenses led to increased operating, selling, general and administrative expenses from 2022 to 2023. The development in interest rates and increased cost estimates impacted the Gassled removal cost negatively, when comparing 2023 to 2022. In contrast, falling energy prices, led to decreased transportation and electricity cost partially offsetting the increases. Exchange rate development in the NOK/USD during the year 2023 offset the cost increases and their visibility in the reported numbers.
The NOK/USD exchange rate development in the year and the sale of ownership shares in Martin Linge and Ekofisk in 2022 reduced depreciation, amortisation and net impairment losses in 2023. However, depreciation, amortisation and net impairment losses were negatively impacted by a USD 588 million impairment of a North Sea asset in 2023 as opposed to net impairment reversals of USD 814 million in 2022 driving an overall increase year-on-year.
Increased exploration drilling activity levels (28 wells this year compared to 21 wells last year) and increased seismic and field development led to an increase in exploration expenses in 2023 compared to 2022. An increased capitalisation rate partially offset the increase.
Additions to PP&E, intangibles and equity accounted investments increased mainly due to increased activity in the sanctioned projects portfolio both for Equinor- and partner operated projects. Decreased investments on the Johan Sverdrup field following completion of phase 2 partially offset this.
| For the year ended 31 December | ||||
|---|---|---|---|---|
| (in USD million) | 2023 | 2022 | 23-22 change | |
| Total revenues and other income | 7,032 | 7,431 | (5%) | |
| Purchases [net of inventory] | (70) | (116) | (40%) | |
| Operating, selling, general and administrative expenses | (2,176) | (1,698) | 28% | |
| Depreciation, amortisation and net impairment losses | (2,433) | (1,731) | 41% | |
| Exploration expenses | (20) | (638) | (97%) | |
| Net operating income/(loss) | 2,332 | 3,248 | (28%) | |
| For the year ended 31 December | ||||
| Operational Information | 2023 | 2022 | 23-22 change | |
| E&P International equity liquid and gas production (mboe/day) | 345 | 328 | 5% |
E&P International entitlement liquid and gas production (mboe/day) 266 235 13% Production sharing agreements (PSA) effects (mboe/day) 79 94 (15%) Average liquids price (USD/bbl) 72.6 92.0 (21%)
The growth in entitlement production across E&P international contributed to strong financial results, despite the impact of lower prices in 2023. The decrease in operating income and revenues was mainly due to the reduction in liquid commodity prices, as liquids constitute 90% of E&P International's entitlement production. The sharp decline in gas prices further contributed to the decrease in revenues.
Increased operation and maintenance expenses associated with turnarounds across various fields led to increased operating expenses from 2022 to 2023. Increased royalties and production fees linked to increased production at the Peregrino field also contributed to the overall rise in costs. This was partially offset by decreased royalties at Roncador due to lower prices in 2023.
The inclusion of Buzzard following the Suncor Energy UK Limited acquisition, increased production from Peregrino in Brazil and Bandurria Sur in Argentina, in addition to several new investments in producing fields resulted in an overall increase in depreciation from 2022 to 2023.
Net impairment related to property, plant, and equipment increased from USD 286 million in 2022 to USD 310 million in 2023. In 2023, the impairment was mainly related to the planned exit from Azerbaijan. In 2022, the main contributors were impairments related to Equinor's exit from Russia, partially offset by an impairment reversal of an asset in the Europe and Asia area, supported by a slight increase in reserves estimates.
Well costs related to Karabagh in Azerbaijan, and drilling costs in Canada expensed in 2022 were the main drivers for the reduction in exploration expenses from 2022 to 2023. The capitalisation of previously expensed exploration wells in Brazil also positively impacted the 2023 numbers.
The Suncor UK acquisition in 2023 further influenced the movement in the additions to PP&E, intangibles and equity accounted investments.
| For the year ended 31 December | |||
|---|---|---|---|
| (in USD million) | 2023 | 2022 | 23-22 change |
| Total revenues and other income | 4,319 | 5,523 | (22%) |
| Operating, selling, general and administrative expenses | (1,178) | (938) | 26% |
| Depreciation, amortisation and net impairment losses | (1,489) | (361) | >100% |
| Exploration expenses | (299) | (201) | 49% |
| Net operating income/(loss) | 1,353 | 4,022 | (66%) |
| For the year ended 31 December | |||
|---|---|---|---|
| Operational information | 2023 | 2022 | 23-22 change |
| E&P USA equity liquids and gas production (mboe/day) | 363 | 324 | 12% |
| E&P USA entitlement liquid and gas production (mboe/day) | 314 | 279 | 12% |
| Royalties | 49 | 44 | 10% |
| Average liquids price (USD/bbl) | 64.4 | 81.0 | (20%) |
| Average internal gas price (USD/mmbtu) | 1.77 | 5.55 | (68%) |
Increased entitlement production due to Vito field start-up, Caesar Tonga flowline installation, and increased well count partially offset the impact of lower realised liquids and gas prices which were the main drivers for the decrease in revenues in 2023 compared to 2022.
Operating expenses increased due the start-up of the Vito platform, combined with increased maintenance activity in the Appalachian basin contributing to increased operations and maintenance expenditure.
Depreciation increased in 2023 due to additional production, decreased impairment reversals, and additional capital expenditures both offshore and onshore. This increase was partially offset by improved reserves.
Impairment reversals related to property, plant, and equipment amounted to USD 290 million in 2023 which were primarily driven by improved expected reserves due to additional well opportunities. In 2022, net impairments reversals amounted to USD 1,071 million mainly driven by increased short-term prices.
Increased exploration expenses were driven by drilling activity for four exploration prospects in the Gulf of Mexico. The four prospects were dry or non-commercial and were expensed accordingly, resulting in a significant increase in exploration cost.
Investments in 2023 in the recently sanctioned Sparta project, St. Malo Water Injection, and Appalachian Basin Partner Operated assets drove the increase in additions to PPE, intangibles and equity accounted investments from 2022.
| For the year ended 31 December | ||||
|---|---|---|---|---|
| (in USD million) | 2023 | 2022 | Change | |
| Total revenues and other income | 105,908 | 148,105 | (28%) | |
| Purchases [net of inventory] | (95,769) | (139,916) | (32%) | |
| Operating, selling, general and administrative expenses | (4,916) | (4,591) | 7% | |
| Depreciation, amortisation and net impairment losses | (1,239) | 14 | N/A | |
| Net operating income/(loss) | 3,984 | 3,612 | 10% |
| For the year ended 31 December | |||
|---|---|---|---|
| Operational information | 2023 | 2022 | Change |
| Liquid sales volume (mmbbl)1) | 956.3 | 815.9 | 17% |
| Natural gas sales Equinor (bcm) | 58.9 | 63.3 | (7%) |
| Natural gas entitlement sales Equinor (bcm) | 53.2 | 56.1 | (5%) |
| Power generation (GWh) Equinor share | 2,298 | 1,012 | N/A |
| Realised piped gas price Europe (USD/MMBtu)1) | 13.86 | 32.84 | (58%) |
| Realise piped gas price US (USD/MMBtu) | 2.09 | 5.89 | (65%) |
1) Restated. Restatement due to a change in definition of the price marker for realised gas price and improved methodology for calculating liquids sales volumes. For more information, see below.
| Full year 2022 |
|---|
| 740.1 |
| 815.9 |
| Average invoiced gas price restatement (mmbtu) | Full year 2022 |
|---|---|
| Average invoice gas price - Europe (old) | 32.46 |
| Realised piped gas price Europe (new) | 32.84 |
Net operating income includes net effects from changes in fair value related to storage and commodity derivatives utilised to manage price risk exposure. During 2023, the net operating income included impairments of USD 342 million, in contrast to USD 895 million of net impairment reversals in the prior year.
Total revenues and other income decreased from 2023 to 2022 due to lower gas and oil sales prices in both Europe and North America and decreased gas volumes. This was partially offset by increased liquid sales.
Purchases [net of inventory] decreased from 2022 to 2023 due to lower prices for both gas and liquids.
The increase in Operating expenses and selling, general and administrative expenses from 2022 to 2023 was mainly due to significant increased transportation costs for liquids and increased selling, general and administrative expenses mainly due to increased activity within Low Carbon Solutions.
Depreciation, amortisation and net impairment increased from 2022 to 2023 driven by the impairment of refinery assets in 2023 and an impairment reversal in 2022.
The main driver for the decrease in additions to PP&E, intangibles and equity accounted investments from 2022 to 2023 are lower investments in projects related to onshore plants.
| For the year ended 31 December | |||
|---|---|---|---|
| (in USD million) | 2023 | 2022 | Change |
| Revenues third party, other revenue and other income | 50 | 127 | (61%) |
| Net income/(loss) from equity accounted investments | (33) | 58 | N/A |
| Total revenues and other income | 17 | 185 | (91%) |
| Operating, selling, general and administrative expenses | (462) | (265) | 74% |
| Depreciation, amortisation and net impairment losses | (312) | (4) | >100% |
| Net operating income/(loss) | (757) | (84) | >(100%) |
| For the year ended 31 December | |||
| Operational information | 2023 | 2022 | Change |
| Renewables power generation (GWh) Equinor share | 1,859 | 1,641 | 13% |
European offshore wind assets in operation within the equity accounted investment portfolio decreased in revenue contribution by 26% within net income/(loss) from equity accounted investments in 2023. This decline was due to lower prices experienced in 2023, increased maintenance costs and increased expenditure associated with early phase projects.
Added revenue from the newly acquired onshore wind farm in Brazil and the start-up of production at solar plants in Poland contributed positively to total revenues in 2023. Combined with the decreased results from equity accounted investments in 2023, total revenues and other income decreased relative to 2022. Favourable effects of divestments early in 2022 significantly impacted the decline.
The notable decrease in net operating income for 2023 compared to the prior year was primarily due to the recognition of a USD 300 million impairment in the third quarter for offshore wind projects in the US Northeast following the rejection of petitions related to offtake agreements. In addition, increased business development expenditures and increased operating activity levels contributed to an upward trend in operating and administrative expenses in 2023. The increased costs associated with maturing projects, which predominantly originated from offshore wind activities in the UK and Asia, contributed to the reduction in adjusted earnings* in 2023 compared to 2022.
The acquisitions of BeGreen and Rio Energy in the year drove the increase in additions to PP&E, intangibles and equity accounted investments compared to 2022.
The information set forth under the following headings of the 2023 Annual Report is incorporated herein by reference:
Any credit rating referred to in this 2023 Form 20-F is not a recommendation to buy, hold or sell any of our or our subsidiaries' securities. Credit ratings may be changed, suspended or withdrawn at any time, and each rating should be evaluated independently of any other rating.
Following Equinor's transition from London Inter-bank Offered Rates (LIBOR) to the new official alternative reference rates, Equinor generally follows guidelines from ISDA and ICMA (International Capital Markets Association).
See also notes 18 Trade and other receivables, 19 Cash and cash equivalents, 21 Finance debt, 23 Provisions and other liabilities, 24 Trade and other payables and provisions, 25 Leases, and 26 Other commitments, contingent liabilities and contingent assets to the Consolidated financial statements.
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 into the future. See note 23 Provisions and other liabilities to the Consolidated financial statements for a maturity profile on asset retirement obligations and other provisions.
Non-current finance debt in the following table represents principal payment obligations, including interest obligations. 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).
| As at 31 December 2023 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) | 2,948 | 6,035 | 5,601 | 17,597 | 32,181 |
| Undiscounted leases3) | 1,369 | 1,434 | 496 | 477 | 3,775 |
| Nominal minimum other long-term commitments4) | 2,659 | 3,587 | 2,197 | 6,775 | 15,218 |
| Total contractual obligations | 6,975 | 11,056 | 8,294 | 24,850 | 51,175 |
1) ''Less than 1 year'' represents 2024; ''1-3 years'' represents 2025 and 2026, ''3-5 years'' represents 2027 and 2028, while ''More than 5 years'' includes amounts for later periods.
Equinor had contractual commitments of USD 11,259 million at 31 December 2023. The contractual commitments reflect Equinor's share and mainly comprise construction and acquisition of property, plant and equipmentas well as committed investments/funding or resources in equity accounted entities.
Equinor's projected pension benefit obligation was USD 8,328 million, and the fair value of plan assets amounted to USD 5,664 million as of 31 December 2023. The company's payments regarding these benefit plans are mainly related to employees in Norway. See note 22 Pensions to the Consolidated financial statements for more information.
Equinor is party to various agreements such as transportation and processing capacity contracts, that are not recognised in the balance sheet. Furthermore, Equinor is lessee in a range of lease contracts, whereas all leases shall be recognised in the balance sheet. Commitments regarding the non-lease components of lease contracts as well as leases that have not yet commenced are not recognised in the balance sheet and represent off balance sheet commitments. Equinor is also party to certain guarantees, commitments and contingencies that, pursuant to IFRS Accounting Standards, are not necessarily recognised in the balance sheet as liabilities. See note 26 Other commitments and contingencies to the Consolidated financial statements for more information.
The following summarised financial information provides financial information of Equinor Energy AS as co-obligor and guarantor as required by SEC Rule 3-10 and 13-01 of Regulation S-X.
Equinor Energy AS is a 100% owned subsidiary of Equinor ASA. Equinor Energy AS is the co-obligor of certain existing debt securities of Equinor ASA and has guaranteed certain existing debt securities of Equinor ASA, including in each case debt securities 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 certain debt held by Equinor ASA. As a guarantor, Equinor Energy AS fully and unconditionally guarantees the payment obligations for certain debt held by Equinor ASA. Total debt at 31 December 2023 is USD 24,442 million, all of which is either guaranteed by Equinor Energy AS (USD 22,611 million), or for which Equinor Energy AS is co-obligor (USD 1,831 million). In the future, Equinor ASA may from time to time issue debt for which Equinor Energy AS will be the co-obligor or guarantor.
The applicable US registered debt securities and related guarantees of Equinor Energy AS are unsecured and rank equally with all other unsecured and unsubordinated indebtedness of Equinor ASA and Equinor Energy AS. The guarantees of Equinor Energy AS are subject to release in limited circumstances upon the occurrence of certain customary conditions. With respect to US registered debt securities (and certain other debt securities) issued on or after 18 November 2019, Equinor Energy AS will automatically and unconditionally be released from all obligations under its guarantee and the guarantee shall thereupon terminate and be discharged of no further force or effect, in the event that at substantially the same time as its guarantee of such debt securities is terminated, the aggregate amount of indebtedness for borrowed money for which Equinor Energy AS is an obligor (as a guarantor, co-issuer or borrower) does not exceed 10% of the aggregate principal amount of indebtedness for borrowed money of Equinor ASA and its subsidiaries, on a consolidated basis, as of such time.
Internal dividends, group contributions and repayment of capital from Equinor Energy AS to Equinor ASA are regulated in the Norwegian Public Limited Liabilities Act §§ 3-1 - 3-5.
The following summarised financial information for the year ended 31 December 2023 provides financial information about Equinor ASA, as issuer, and Equinor Energy AS, as co-obligor and guarantor on a combined basis after elimination of transactions between Equinor ASA and Equinor Energy AS. Investments in non-guarantor subsidiaries are eliminated. Currency gain on transactions between Equinor ASA and Equinor Energy AS of USD 1,939 million is included in financial items in accordance with the IFRS Accounting Standards group principles and are included in external items in the Condensed profit and loss statement.
Intercompany balances and transactions between the obligor group and the non-guarantor subsidiaries are presented on separate lines. Transactions with related parties are also presented on a separate line item and include transactions with the Norwegian State's and the Norwegian State's share of dividend declared but not paid.
The combined summarized financial information is prepared in accordance with Equinor's IFRS Accounting Standards policies as described in note 2 Significant accounting policies to the Consolidated financial statements.
| (unaudited, in USD million) | Full year 2023 |
|---|---|
| Revenues and other income | 87,627 |
| External | 84,213 |
| Non-guarantor subsidiaries | 3,218 |
| Related parties | 196 |
| Operating expenses | (53,687) |
| External (incl depreciation) | (27,343) |
| Non-guarantor subsidiaries | (15,164) |
| Related parties | (11,180) |
| Net operating income | 33,940 |
| Net financial items | 2,613 |
| External | 713 |
| Non-guarantor subsidiaries | 1,900 |
| Related parties | - |
| Income before tax | 36,553 |
| Income tax | (24,668) |
| Net income | 11,885 |
| (unaudited, in USD million) | At 31 December 2023 |
|---|---|
| Non-current assets | 43,867 |
| External | 35,595 |
| Non-guarantor subsidiaries | 8,221 |
| Related parties | 51 |
| Current assets | 56,978 |
| External | 48,189 |
| Non-guarantor subsidiaries | 8,209 |
| Related parties | 580 |
| Non-current liabilities | 51,802 |
| External | 51,342 |
| Non-guarantor subsidiaries | 126 |
| Related parties | 334 |
| Current liabilities | 48,362 |
| External | 27,103 |
| Non-guarantor subsidiaries | 19,323 |
| Related parties | 1,936 |
Use and reconciliation of non-GAAP financial measures
Since 2007, Equinor has been preparing its audited consolidated financial statements in accordance with International Financial Reporting Standards (IFRS Accounting Standards) as adopted by the European Union (EU) and as issued by the International Accounting Standards Board. IFRS Accounting Standards have been applied consistently to all periods in our audited consolidated financial statements as of 31 December 2023 and 2022, and for the three years ended 31 December 2023 included in this 2023 Form 20-F (the "Consolidated financial statements").
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 Accounting Standards in the case of Equinor). The following financial measures included in this 2023 Form 20-F may be considered non-GAAP financial measures:
In Equinor's view, net debt ratios provide a more informative picture of Equinor's financial strength than gross interest-bearing financial debt.
Three different net debt to capital ratios are provided below: 1) net debt to capital employed, 2) net debt to capital employed ratio adjusted, including lease liabilities, and 3) net debt to capital employed ratio adjusted.
These calculations are all based on Equinor's gross interest-bearing financial liabilities as recorded in the Consolidated balance sheet and exclude cash, cash equivalents and current financial investments.
The following adjustments are made in calculating the net debt to capital employed ratio adjusted, including lease liabilities and the net debt to capital employed ratio adjusted: collateral deposits (classified as Cash and cash equivalents in the Consolidated balance sheet), and financial investments held in Equinor Insurance AS (classified as Current financial investments in the Consolidated balance sheet) are treated as non-cash and excluded from the calculation of these non-GAAP measures. Collateral deposits are excluded since they relate to certain requirements of exchanges where Equinor's securities are trading and therefore are presented as restricted cash and cash equivalents. Financial investments in Equinor Insurance are excluded as these investments are not readily available for the group to meet short term commitments. These adjustments result in a higher net debt figure and in Equinor's view provides a more prudent measure of the net debt to capital employed ratio than would be the case without such exclusions.
Additionally, lease liabilities are further excluded in calculating the net debt to capital employed ratio adjusted.
The accompanying table details the calculations for these non-GAAP measures and reconciles them with the most directly comparable IFRS Accounting Standards financial measure or measures.
Forward-looking net debt to capital employed ratio adjusted, including lease liabilities included in this 2023 Form 20-F is not reconcilable to its most directly comparable IFRS Accounting Standards measure without unreasonable efforts, because the amounts excluded from IFRS Accounting Standards measures used to determine net debt to capital employed ratio adjusted, including lease liabilities cannot be predicted with reasonable certainty.
| Calculation of capital employed and net debt to capital employed ratio | For the year ended 31 December |
||
|---|---|---|---|
| (in USD million) | 2023 | 2022 | |
| Shareholders' equity | 48,490 | 53,988 | |
| Non-controlling interests | 10 | 1 | |
| Total equity A |
48,500 | 53,989 | |
| Current finance debt and lease liabilities | 7,275 | 5,617 | |
| Non-current finance debt and lease liabilities | 24,521 | 26,551 |
| Gross interest-bearing debt | B | 31,796 | 32,168 |
|---|---|---|---|
| Cash and cash equivalents | 9,641 | 15,579 | |
| Current financial investments | 29,224 | 29,876 | |
| Cash and cash equivalents and current financial investment | C | 38,865 | 45,455 |
| Net interest-bearing debt before adjustments | B1 = B-C | (7,069) | (13,288) |
| Other interest-bearing elements 1) | 2,030 | 6,538 | |
| Net interest-bearing debt adjusted, including lease liabilities | B2 | (5,040) | (6,750) |
| Lease liabilities | 3,570 | 3,668 | |
| Net interest-bearing debt adjusted | B3 | (8,610) | (10,418) |
| Calculation of capital employed: | |||
| Capital employed | A+B1 | 41,431 | 40,701 |
| Capital employed adjusted, including lease liabilities | A+B2 | 43,460 | 47,239 |
| Capital employed adjusted | A+B3 | 39,890 | 43,571 |
| Calculated net debt to capital employed | |||
| Net debt to capital employed | (B1)/(A+B1) | (17.1%) | (32.6%) |
| Net debt to capital employed ratio adjusted, including lease liabilities | (B2)/(A+B2) | (11.6%) | (14.3%) |
| Net debt to capital employed ratio adjusted | (B3)/(A+B3) | (21.6%) | (23.9%) |
1) The following adjustments are made in calculating the net debt to capital employed adjusted, including lease liabilities ratio and the net debt to capital employed adjusted ratio: collateral deposits (classified as Cash and cash equivalents in the Consolidated balance sheet), and financial investments held in Equinor Insurance AS (classified as Current financial investments in the Consolidated balance sheet) are treated as non-cash and excluded from the calculation of these non-GAAP measures. Collateral deposits are excluded since they relate to certain requirements of exchanges where Equinor is trading and presented as restricted cash and cash equivalents. Financial investments in Equinor Insurance are excluded as these investments are not readily available for the group to meet short term commitments. These adjustments result in a higher net debt figure and in Equinor's view provides a more prudent measure of the net debt to capital employed ratio than would be the case without such exclusions.
Return on average capital employed (ROACE) is the ratio of adjusted earnings after tax to the average capital employed adjusted. The reconciliation for adjusted earnings after tax is presented in section g). Average capital employed adjusted refers to the average of the capital employed adjusted values as of 31 December for both the current and the preceding year, as presented under the heading Calculation of capital employed in section a).
Equinor uses ROACE to evaluate performance by measuring how effectively the company employs its capital, whether financed through equity or debt.
An IFRS Accounting Standards measure most directly comparable to ROACE would be calculated as the ratio of net income/(loss) to average capital employed that is based on Equinor's gross interest-bearing financial liabilities as recorded in the Consolidated balance sheet, excluding cash, cash equivalents and current financial investments.
ROACE is used as a supplementary measure and should not be viewed in isolation or as an alternative to measures calculated in accordance with IFRS Accounting Standards including income before financial items, income taxes and minority interest, or net income, or ratios based on these figures.
| Calculated ROACE based on IFRS Accounting Standards | 31 December | ||
|---|---|---|---|
| (in USD million, except percentages) | 2023 | 2022 | |
| Net income/(loss) | A | 11,904 | 28,744 |
| Average total equity | 1 | 51,244 | 46,506 |
| Average current finance debt and lease liabilities | 6,446 | 6,001 | |
| Average non-current finance debt and lease liabilities | 25,536 | 28,202 | |
| - Average cash and cash equivalents | (12,610) | (14,853) | |
| - Average current financial investments | (29,550) | (25,561) | |
| Average net-interest bearing debt | 2 | (10,178) | (6,210) |
| Average capital employed | B = 1+2 | 41,066 | 40,296 |
| Calculated ROACE based on Net income/loss and capital employed | A/B | 29.0% | 71.3% |
| Calculated ROACE based on Adjusted earnings after tax and capital employed adjusted | 31 December | ||
|---|---|---|---|
| (in USD million, except percentages) | 2023 | 2022 | |
| Adjusted earnings after tax | A | 10,371 | 22,680 |
| Average capital employed adjusted | B | 41,731 | 41,134 |
| Calculated ROACE based on Adjusted earnings after tax and capital employed adjusted | A/B | 24.9% | 55.1% |
Forward-looking ROACE included in this 2023 Form 20-F is not reconcilable to its most directly comparable IFRS Accounting Standards measure without unreasonable efforts, because the amounts included or excluded from IFRS Accounting Standards measures used to determine ROACE cannot be predicted with reasonable certainty.
Organic capital expenditures represent additions to PP&E, intangibles and equity accounted investments, excluding expenditures related to acquisitions, leased assets, and other investments with significantly different cash flow patterns. Equinor believes this measure gives stakeholders relevant information to understand the company's investments in maintaining and developing its existing business operations.
| Calculation of organic capital expenditures | For the year ended 31 December |
||
|---|---|---|---|
| (in USD billion) | 2023 | 2022 | |
| Additions to PP&E, intangibles and equity accounted investments | 14.5 | 10.0 | |
| Acquisition-related additions | (3.2) | (0.6) | |
| Right of use asset additions | (1.1) | (1.3) | |
| Other additions (with unique cash flow patterns) | |||
| Organic capital expenditures | 10.2 | 8.1 |
Forward-looking organic capital expenditures included in this 2023 Form 20-F are not reconcilable to the most directly comparable IFRS Accounting Standards measure without unreasonable efforts, because the amounts excluded from such IFRS Accounting Standards measure to determine organic capital expenditures cannot be predicted with reasonable certainty.
Gross capital expenditures represent capital expenditures, defined as Additions to PP&E, intangibles and equity accounted investments as presented in the financial statements, excluding additions to right of use assets related to leases and capital expenditures financed through government grants. Equinor adds the proportionate share of capital expenditures in equity accounted investments not included in Additions to PP&E, intangibles and equity accounted investments. Equinor believes that by excluding additions to right of use assets related to leases, this measure better reflects the company's investments in the business to drive growth.
| Calculation of gross capital expenditures | For the year ended 31 December |
|
|---|---|---|
| (in USD billion) | 2023 | 2022 |
| Additions to Property, plant and equipment, Intangibles and Equity accounted companies | 14.5 | 10.0 |
| Less adjustments | 0.4 | 0.4 |
| Gross capital expenditures | 14.1 | 9.6 |
Forward-looking gross capital expenditures included in this 2023 Form 20-F are not reconcilable to the most directly comparable IFRS Accounting Standards measure without unreasonable efforts, because the amounts included or excluded from such IFRS Accounting Standards measure to determine gross capital expenditures cannot be predicted with reasonable certainty.
Cash flows from operations after taxes paid represents, and is used by management to evaluate, cash generated from operating activities after taxes paid, which is available for investing activities, for debt servicing and for distribution to shareholders. Cash flows from operations after taxes paid is not a measure of our liquidity under IFRS Accounting Standards and should not be considered in isolation or as a substitute for an analysis of our results as reported in this 2023 Form 20-F. Our definition of Cash flows from operations after taxes paid is limited and does not represent residual cash flows available for discretionary expenditures.
The table below provides a reconciliation of Cash flows from operations after taxes paid to its most directly comparable IFRS Accounting Standards measure, Cash flows provided by operating activities before taxes paid and working capital items, as of the specified dates:
| Cash flow from operations after taxes paid (CFFO after taxes paid) | |||||
|---|---|---|---|---|---|
| (in USD million) | 2023 | 2022 | |||
| Cash flows provided by operating activities before taxes paid and working capital items | 48,016 | 83,608 | |||
| Taxes paid | (28,276) | (43,856) | |||
| Cash flow from operations after taxes paid (CFFO after taxes paid) | 19,741 | 39,752 |
Forward-looking cash flows from operations after taxes paid included in this 2023 Form 20-F is not reconcilable to its most directly comparable IFRS Accounting Standards measure without unreasonable efforts, because the amounts included or excluded from IFRS Accounting Standards measures used to determine cash flows from operations after taxes paid cannot be predicted with reasonable certainty.
Net cash flow represents, and is used by management to evaluate, cash generated from operational and investing activities available for debt servicing and distribution to shareholders. The measure underwent a name change in 2023; however, all other aspects of the measure remain unchanged. Net cash flow is not a measure of our liquidity under IFRS Accounting Standards and should not be considered in isolation or as a substitute for an analysis of our results as reported in this 2023 Form 20-F. Our definition of Net cash flow is limited and does not represent residual cash flows available for discretionary expenditures.
The table below reconciles Net cash flow with its most directly comparable IFRS Accounting Standards measure, Cash flows provided by operating activities before taxes paid and working capital items, as of the specified dates:
| Net cash flow | ||
|---|---|---|
| (in USD billion) | 2023 | 2022 |
| Cash flows provided by operating activities before taxes paid and working capital items | 48.0 | 83.6 |
| Taxes paid | (28.3) | (43.9) |
| Cash used/received in business combinations | (1.2) | 0.1 |
| Capital expenditures and investments | (10.6) | (8.8) |
| (Increase)/decrease in other interest-bearing items | (0.1) | (0.0) |
| Proceeds from sale of assets and businesses | 0.3 | 1.0 |
| Net cash flow before capital distribution | 8.2 | 32.1 |
| Dividends paid | (10.9) | (5.4) |
| Share buy-back | (5.6) | (3.3) |
| Net cash flow | (8.3) | 23.4 |
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 believes adjusted earnings provides an indication of Equinor's underlying operational performance in the period and facilitates comparison of operational trends between periods. The calculation of Adjusted earnings was changed in 2023, as detailed below.
Adjusted earnings after tax equals the sum of net operating income/(loss) less income tax in reporting segments and includes adjustments to operating income to take 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 effects related to tax exposure items not related to the individual reporting period are excluded from adjusted earnings after tax. Management believes adjusted earnings after tax provides an indication of Equinor's underlying operational performance and facilitates comparisons of operational trends between periods as it reflects the tax charge associated with operational performance excluding the impact of financing. 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 Accounting Standards 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 are supplementary measures and should not be viewed in isolation or as substitutes for net operating income/(loss) and net income/(loss), which are the most directly comparable IFRS Accounting Standards measures. There are material limitations associated with the use of adjusted earnings and adjusted earnings after tax compared with the IFRS Accounting Standards measures as these 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 ongoing 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 developments 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 and should therefore not be used in isolation.
Equinor has made the following changes to the items adjusted for within Adjusted earnings:
These changes have been applied retrospectively to the comparative figures. The majority of the impact is due to the revised treatment of commodity derivatives. These changes only affect the MMP reporting segment and currently do not have an impact on other segments. Equinor deems that these changes lead to a better representation of performance in each period by appropriately reflecting the economic impact of its risk management activities.
For further information on Adjusted earnings, see note 28 Financial instruments and fair value measurement to the Consolidated financial statements.
| Impact of change | Full year of 2022 | ||
|---|---|---|---|
| MMP segment | As reported | Impact | Restated |
| Change in Fair Value of derivatives | (149) | 1,801 | 1,651 |
| Periodisation of inventory hedging effect | (349) | 181 | (168) |
| Adjusted total revenues and other income | 147,599 | 1,981 | 149,580 |
| Adjusted earnings/(loss) | 2,253 | 1,981 | 4,234 |
| Adjusted earnings/(loss) after tax | 2,727 | (10) | 2,717 |
|---|---|---|---|
| Impact of change | Full year of 2022 | ||
|---|---|---|---|
| Equinor group | As reported | Impact | Restated |
| Change in Fair Value of derivatives | (207) | 1,801 | 1,593 |
| Periodisation of inventory hedging effect | (349) | 181 | (168) |
| Adjusted total revenues and other income | 149,910 | 1,981 | 151,891 |
| Adjusted earnings/(loss) | 74,940 | 1,981 | 76,921 |
| Adjusted earnings/(loss) after tax | 22,691 | (10) | 22,680 |
| Effective tax rates on adjusted earnings | 69.7% | 0.8% | 70.5% |
No other line items or segments were affected by the change.
Adjusted earnings adjust for the following items:
| Items impacting net operating income/(loss) in the full year of 2023 |
Exploration & |
Exploration & Production |
Exploration & |
Marketing, Midstream |
|||
|---|---|---|---|---|---|---|---|
| (in USD million) | Equinor group |
Production Norway |
Internationa l |
Production USA |
& Processing |
Rene- wables |
Other |
| Total revenues and other income | 107,174 | 38,340 | 7,032 | 4,319 | 105,908 | 17 | (48,442) |
| Adjusting items | (1,303) | (128) | (76) | (32) | (1,049) | (17) | (1) |
| Changes in fair value of derivatives | (711) | 128 | (96) | - | (743) | - | - |
| Periodisation of inventory hedging effect | (183) | - | - | - | (183) | - | - |
| Impairment from associated companies | 1 | - | - | - | - | 1 | - |
| Over-/underlift | 10 | (35) | 45 | - | - | - | - |
| Other adjustments | (100) | - | - | - | (100) | - | - |
| Gain/loss on sale of assets | (319) | (221) | (25) | (32) | (23) | (17) | (1) |
| Adjusted total revenues and other income | 105,871 | 38,213 | 6,956 | 4,286 | 104,860 | (0) | (48,443) |
| Purchases [net of inventory variation] | (48,175) | (0) | (70) | - | (95,769) | 0 | 47,664 |
| Adjusting items | 173 | - | - | - | 36 | - | 137 |
| Operational storage effects | 41 | - | - | - | 41 | - | - |
| Provisions | (5) | - | - | - | (5) | - | - |
| Eliminations | 137 | - | - | - | - | - | 137 |
| Adjusted purchases [net of inventory variation] | (48,003) | (0) | (70) | - | (95,733) | 0 | 47,801 |
| Operating and administrative expenses | (11,800) | (3,759) | (2,176) | (1,178) | (4,916) | (462) | 692 |
| Adjusting items | 260 | 29 | 261 | 22 | (72) | 20 | - |
| Over-/underlift | 7 | 29 | (22) | - | - | - | - |
| Other adjustments | 36 | - | - | 22 | - | 14 | - |
| Gain/loss on sale of assets | 289 | - | 283 | - | - | 6 | - |
| Provisions | (72) | - | - | - | (72) | - | - |
| Adjusted operating and administrative expenses | (11,540) | (3,730) | (1,915) | (1,156) | (4,988) | (442) | 692 |
| Depreciation, amortisation and net impairments | (10,634) | (5,017) | (2,433) | (1,489) | (1,239) | (312) | (143) |
| Adjusting items | 1,259 | 588 | 310 | (290) | 343 | 300 | 9 |
| Impairment | 1,550 | 588 | 310 | - | 343 | 300 | 9 |
| Reversal of impairment | (290) | - | - | (290) | - | - | - |
| Adjusted depreciation, amortisation and net impairments |
(9,374) | (4,429) | (2,123) | (1,779) | (897) | (12) | (134) |
| Exploration expenses | (795) | (476) | (20) | (299) | - | - | - |
| Adjusting items | 61 | - | 36 | 25 | - | - | - |
| Impairment | 61 | - | 36 | 25 | - | - | - |
| Adjusted exploration expenses | (734) | (476) | 16 | (274) | - | - | - |
| Net operating income/(loss) | 35,770 | 29,087 | 2,332 | 1,353 | 3,984 | (757) | (229) |
| Sum of adjusting items | 451 | 490 | 532 | (277) | (742) | 303 | 145 |
| Adjusted earnings/(loss) | 36,220 | 29,577 | 2,863 | 1,076 | 3,242 | (454) | (84) |
| Tax on adjusted earnings | (25,850) | (23,083) | (1,213) | (304) | (1,364) | 63 | 51 |
| Adjusted earnings/(loss) after tax | 10,371 | 6,494 | 1,650 | 773 | 1,877 | (391) | (33) |
| Items impacting net operating income/(loss) in the full year of 2022 |
Exploration & |
Exploration & Production |
Exploration & |
Marketing, Midstream |
|||
|---|---|---|---|---|---|---|---|
| (in USD million) | Equinor group | Production Norway |
Internationa l |
Production USA |
& Processing |
Rene- wables |
Other |
| Total revenues and other income | 150,806 | 75,930 | 7,431 | 5,523 | 148,105 | 185 | (86,367) |
| Adjusting Items | 1,085 | (487) | 185 | - | 1,475 | (110) | 22 |
| Changes in fair value of derivatives | 1,593 1) | (263) | 205 | - | 1,651 1) | - | - |
| Periodisation of inventory hedging effect | (168)1) | - | - | - | (168)1) | - | - |
| Impairment from associated companies | 1 | - | - | - | - | 1 | - |
| Over-/underlift | 510 | 507 | 3 | - | - | - | - |
| Other adjustments | (0) | - | (22) | - | - | - | 22 |
| Gain/loss on sale of assets | (850) | (731) | - | - | (9) | (111) | (0) |
| Adjusted total revenues and other income | 151,891 1) | 75,443 | 7,616 | 5,523 | 149,580 1) | 75 | (86,345) |
| Purchases [net of inventory variation] | (53,806) | 0 | (116) | (0) | (139,916) | - | 86,227 |
| Adjusting Items | (610) | - | - | - | (33) | - | (577) |
| Operational storage effects | (33) | - | - | - | (33) | - | - |
| Eliminations | (577) | - | - | - | - | - | (577) |
| Adjusted purchases [net of inventory variation] | (54,415) | 0 | (116) | (0) | (139,949) | - | 85,650 |
| Operating and administrative expenses | (10,593) | (3,782) | (1,698) | (938) | (4,591) | (265) | 681 |
| Adjusting Items | 64 | (54) | 22 | 6 | 75 | 10 | 5 |
| Over-/underlift | (41) | (54) | 13 | - | - | - | - |
| Change in accounting policy | 7 | - | 2 | - | - | - | 5 |
| Gain/loss on sale of assets | 23 | - | 7 | 6 | - | 10 | - |
| Provisions | 75 | - | - | - | 75 | - | - |
| Adjusted operating and administrative expenses | (10,530) | (3,836) | (1,675) | (933) | (4,516) | (255) | 686 |
| Depreciation, amortisation and net impairments | (6,391) | (4,167) | (1,731) | (361) | 14 | (4) | (142) |
| Adjusting Items | (2,488) | (819) | 286 | (1,060) | (895) | - | - |
| Impairment | 1,111 | 3 | 1,033 | - | 75 | - | - |
| Reversal of impairment | (3,598) | (821) | (747) | (1,060) | (970) | - | - |
| Adjusted depreciation, amortisation and net impairments | (8,879) | (4,986) | (1,445) | (1,422) | (881) | (4) | (142) |
| Exploration expenses | (1,205) | (366) | (638) | (201) | - | - | 0 |
| Adjusting Items | 59 | 4 | 65 | (11) | - | - | - |
| Impairment | 85 | 4 | 65 | 15 | - | - | - |
| Reversal of impairment | (26) | - | - | (26) | - | - | - |
| Adjusted exploration expenses | (1,146) | (361) | (573) | (212) | - | - | 0 |
| Net operating income/(loss) | 78,811 | 67,614 | 3,248 | 4,022 | 3,612 | (84) | 399 |
| Sum of adjusting items | (1,890)1) | (1,355) | 559 | (1,065) | 621 1) | (100) | (550) |
| Adjusted earnings/(loss) | 76,921 1) | 66,260 | 3,806 | 2,957 | 4,234 1) | (184) | (151) |
| Tax on adjusted earnings | (54,241)1) | (51,373) | (1,248) | (79) | (1,517)1) | 14 | (38) |
| Adjusted earnings/(loss) after tax | 22,680 1) | 14,887 | 2,558 | 2,878 | 2,717 1) | (171) | (189) |
1) MMP segment and Equinor group are restated due to amended principles for adjusting items; 'changes in fair value of derivatives' and 'periodisation of inventory hedging effect'.
The information set forth under the following headings of the 2023 Annual Report is incorporated herein by reference:
See also notes 9 Auditor's remuneration and Research and development expenditures and 12 Property, plant and equipment to the Consolidated financial statements.
The information set forth under the heading "Our market perspective" in Section 2.1 of Chapter 2 on pages 37 – 38 of the 2023 Annual Report is incorporated herein by reference. See also "Item 5. Operating and Financial Review―A. Operating Results" of this 2023 Form 20-F.
Not Applicable.
Position: Chair of the Board and chair of the Compensation and Executive Development Committee Term of office: Chair of the Board of Equinor ASA since 1 September 2017. Up for election in 2024.
Year of birth: 1956
Listed companies: Member of the Board of Oceaneering International, Inc.
Non-listed companies: Chair of the Board of Fire Security AS, OPS Solutions AS and Baring Group AS.
Number of shares in Equinor ASA: 4,584 (as of 31 December 2023)
Experience: Reinhardsen is a part-time senior advisor with BearingPoint Capital. Reinhardsen was the Chief Executive Officer of Petroleum Geo-Services (PGS) from 2008 - August 2017. PGS delivers global geophysical- and reservoir services. In the period 2005 - 2008 Reinhardsen was President 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: 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: Reinhardsen is a Norwegian citizen, and resident in Norway.
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 2022 and board member since 1 July 2018. Up for election in 2024.
Year of birth: 1956.
Independent: Yes.
Listed company: Non-executive member of the board of Balfour Beatty plc.
Number of shares in Equinor ASA: 1,100 (as of 31 December 2023)
Experience: Drinkwater was employed with bp in the period 1978-2012, holding a number of different leadership positions in the company. In the period 2009-2012 she was chief executive officer of bp Canada. She has extensive international experience, including being responsible for operations in the US, Norway, Indonesia, the Middle East and Africa. Through her career Drinkwater has acquired a deep understanding of the oil and gas sector, holding both operational roles, and more distinct business responsibilities.
Education: Bachelor of Science in Applied Mathematics and Statistics, 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: Drinkwater is a British citizen, and resident in the United States.
Position: Shareholder-elected member of the board, 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 19 March 2015. Up for election in 2024.
Year of birth: 1970
Independent: Yes
Listed companies: Member of the board of Rockwool International A/S, BW Offshore ASA and Wilh. Wilhelmsen Holding ASA. Non-listed companies: Chair of the board of Norwegian Hull Club (NHC) and Handelsbanken Norge, board member of Torvald Klaveness Group and Egmont Foundation and chair of the Council at DNV.
Number of shares in Equinor ASA: 220 (as of 31 December 2023)
Experience: Herlofsen is an independent board member and consultant. She was previously the Chief Financial Officer in Wallenius Wilhelmsen ASA, an international shipping company. Before joining Wallenius Wilhelmsen, she was the Chief Financial Officer in 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 she held leading positions within M&A, strategy and corporate planning and was part of the group management team. Education: MSc in Economics and Business Administration ("Siviløkonom") and Certified Financial Analyst Program (AFA), the Norwegian School of Economics (NHH). Breakthrough Program for Top Executives at IMD business school, Switzerland. Family relations: No family relations to other members of the Board, members of the Corporate Executive Committee or the Corporate Assembly.
Other matters: Herlofsen is a Norwegian citizen and resident in Norway.
Position: 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 2024.
Year of birth: 1961
Listed company: Member of the Board of Capita plc.
Number of shares in Equinor ASA: None (as of 31 December 2023)
Experience: Lewis was the Chief Executive Officer of Capita plc from December 2017 until January 2024, having previously spent 30 years working for 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 CEO from 2016-2017. Prior to this, he held a number of senior leadership positions at Halliburton, where he was employed in the period 1996-2016. Lewis has previously held several directorships within technology and the oil and gas industry.
Education: Lewis has a PhD in Reservoir Characterisation, from University of Reading and a Bachelor of Science degree in 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: Lewis is a British and US citizen, and resident in the UK.
Position: Member of the Board, 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 2024.
Year of birth: 1964
Independent: Yes
Non-listed companies: Chair of the board of Fornybar Norge AS and board member of Cegal in addition to several companies fully or partly owned by Hafslund.
Number of shares in Equinor ASA: 620 (as of 31 December 2023) Loans from Equinor ASA: None
Experience: Ruyter has since July 2012 been CEO of Hafslund AS. He was CFO in the company 2010-2011. In 2009-2010 he worked in the Philippine hydro power company SN Aboitiz Power. In the period 1996-2009 he led the power trading entity and from 1999 also the energy division in Elkem. From 1991-1996 Ruyter worked with energy trading in Norsk Hydro.
Education: 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: Ruyter is a Norwegian citizen, and resident in Norway.
Position: Member of the Board and the Board's Safety, Sustainability and Ethics Committee.
Term of office: Member of the Board of Equinor ASA since 1 July 2020. Up for election in 2024.
Year of birth: 1970
Independent: Yes
Listed company: Member of the board of Borregaard ASA
Non-listed company: Member of the board of The Norwegian Opera & Ballet
Number of shares in Equinor ASA: 4,700 (as of 31 December 2023)
Experience: Andersen is President & CEO of Tomra Systems ASA as of 16 August 2021. Prior to this, she held the position as Executive Vice President for Europe in Yara International ASA. Andersen was part of the executive management team in Yara since 2016 where she also held positions as Executive Vice President, Production and Executive Vice President, Supply Chain. Previously she has had several management roles within Yara and Norsk Hydro/Yara and she started in Norsk Hydro in 1997. She has extensive international industrial experience, and she has broad board experience.
Education: Master of Science (Sivilingeniør) from Norwegian Institute of Technology (NTNU) and a Master of Business Administration from the BI Norwegian Business School.
Family relations: No family relations to other members of the Board, members of the Corporate Executive Committee or the Corporate Assembly.
Other matters: Andersen is a Norwegian citizen and resident in Norway.
Position: 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 12 December 2022. Up for election in 2024.
Year of birth: 1960
Independent: Yes
Other directorships:
Non-listed companies: Member of the Advisory board at Kongsberg Defence & Aerospace (KDA)
Number of shares in Equinor ASA: None (as of 31 December 2023)
Experience: Bruun-Hanssen held the position as Chief of Norwegian Defence Forces from 2013-2020, previously having held the position as Chief Norwegian Joint Operational Headquarters from 2011-2013 and Chief Royal Norwegian Navy from 2009- 2011, Chief of staff Royal Norwegian Navy from 2007-2009 and Chief Naval Operations centre from 2003-2007. Prior to this he has had an extensive career in the Norwegian Military.
Education: Bruun-Hanssen has a broad education through the Norwegian Military; Petty Officer training school, Norwegian naval Academy, Submarine Commanding officer course and Higher command course, Forsvarets Høyskole. He is also educated at Military Command and Staff college, Instituut Defensie Leergangen in The Netherlands and has participated in work sessions relating to board roles and tasks at Insead In-Board Nordic Academy.
Family relations: No family relations to other members of the Board, members of the Corporate Executive Committee or the Corporate Assembly.
Other matters: Bruun-Hanssen is a Norwegian citizen, and resident in Norway.
Position: Employee representative member of the Board and member of the Safety, Sustainability and Ethics Committee. Term of office: Member of the Board of Equinor ASA since 1 July 2013. Up for election in 2025.
Year of birth: 1963
Independent: No
Other board directorships: None
Number of shares in Equinor ASA: 147 (as of 31 December 2023)
Loans from Equinor ASA: None
Experience: Lægreid is now a full-time employee representative as the leader of NITO, Equinor. He has been occupied as weight estimator for platform design from 2005 and prior to this as project engineer and constructor for production of primary metals. Employed in ÅSV and Norsk Hydro since 1985.
Education: Bachelor's degree, Mechanical Construction from OIH.
Family relations: No family relationships to other board members, members of the Corporate Executive Committee or the Corporate Assembly.
Other matters: Lægreid is a Norwegian citizen and resident in Norway.
Position: Employee representative member of the Board, member of the Safety, Sustainability and Ethics Committee and member of the Board's Compensation and Executive Development Committee.
Term of office: Member of the Board of Equinor ASA since 8 June 2017. Up for election in 2025.
Other directorships: Labråthen is a member of the Executive Committee of the Industry Energy (IE) trade union and holds a number of offices as a result of this.
Number of shares in Equinor ASA: 894 (as of 31 December 2023)
Experience: Labråthen is now a full-time employee representative as the leader of IE Equinor branch. He has previously worked as a process technician at the petrochemical plant on Oseberg field in the North Sea.
Education: Labråthen 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 members of the Corporate Assembly.
Other matters: Labråthen is a Norwegian citizen, and resident in Norway.
Position: Employee representative member of the Board and member of the Board's Audit Committee.
Term of office: Member of the Board of Directors of Equinor ASA since 1 July 2019. Up for election in 2025.
Year of birth: 1966
Independent: No
Other board directorships: Chair of Tekna's ethical board.
Number of shares in Equinor ASA: 3,005 (as of 31 December 2023)
Experience: Møllerstad has been employed by Equinor since 1991 and works within petroleum technology discipline in Exploration & Production International. Møllerstad has been a member of the Corporate Assembly in Equinor from 2013 - 2019 and was a board member of Tekna Private from 2012 - 2017 and she has had several trust offices in Tekna Equinor since 1993. Education: Chartered engineer from NTNU (Norwegian University of Science and Technology) and Project Management Essential (PME) from BI/NTNU (Norwegian Business School BI/ Norwegian University of Science and Technology). Family relations: No family relationships to other board members, members of the Corporate Executive Committee or the Corporate Assembly.
Other matters: Møllerstad is a Norwegian citizen and resident in Norway
Position: President and Chief Executive Officer (CEO) since 2 November 2020
Year of birth: 1968
External offices: None
Number of shares in Equinor ASA: 56,649 (as of 31 December 2023)
Loans from Equinor ASA: None
Experience: Opedal joined Equinor in 1997. From 2018-2020 he held the position as Executive Vice President Technology, Projects and Drilling. From August to October 2018, he was Executive Vice President for Development, Production Brazil and prior to this Senior Vice President for Development, Production International Brazil. He also held the position as Equinor's Chief Operating Officer. In 2011 he took on the role as Senior Vice President in Technology, Projects and Drilling; where he was responsible for Equinor's NOK 300 billion project portfolio. From 2007-2010 he served as Chief Procurement Officer. He has held a range of technical, operational and leadership positions in the company and started as a petroleum engineer in the Statfjord operations. Prior to Equinor, Opedal worked for Schlumberger and Baker Hughes.
Education: MBA from Heriot-Watt University and master's degree in Engineering (sivilingeniør) from the 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.
Position: Executive Vice President and Chief Financial Officer since 6 October 2022
Experience: Reitan joined Equinor in 1995. He comes from the position of Senior Vice President for Finance and Control in Equinor's Renewables business area, which he held since 2020. From 2018 - 2020 he was Executive Vice President for Development and production international, and from 2015 - 2018 Reitan held the position as Executive Vice President of Development and Production USA. Prior to this he held the position as Executive Vice President and Chief Financial Officer from 2010 - 2015. He has held several management positions in Equinor prior to this, including Senior Vice President in trading and operations in the Natural gas business area in 2009 - 2010, Senior Vice President in Performance management and analysis from 2007 - 2009, and from 2005 - 2007 he was Senior Vice President in Performance Management, Tax and M&A. From 1995 - 2004 Reitan held various positions in the Natural Gas business area and corporate functions.
Education: Master of science degree from the Norwegian School of Economics and Business administration (NHH). Family relations: No family relations to other members of the Corporate Executive Committee, members of the Board or the Corporate Assembly.
Other matters: Torgrim Reitan is a Norwegian citizen and resident in Norway.
Jannicke Nilsson
Position: Executive Vice President, Safety, Security & Sustainability (SSU) since 1 June 2021.
Year of birth: 1965
External offices: Member of the Board of Odfjell SE and Jotun A/S.
Number of shares in Equinor ASA: 63,106 (as of 31 December 2023)
Experience: Since joining Equinor in 1999, Nilsson has held a number of central leadership position within operation, projects and technology. From June 2021, Jannicke Nilsson has led the corporate function which shapes and safeguards Equinor's efforts on the areas of safety, security, and sustainability, including Equinor Energy Transition Plan. Prior to this role she was Executive Vice President and Chief Operating Officer (COO) for five years. As COO she drove Equinor's digital transformation and delivered tangible results delivering on the company's strategy. Nilsson has also been a program leader for a company-wide efficiency programme running from 2014 – 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: Nilsson is a Norwegian citizen and resident in Norway.
Position: Executive Vice President, Exploration & Production Norway (EPN) since 1 January 2021
Year of birth: 1965
External offices: Member of the Board of Offshore Norge
Number of shares in Equinor ASA: 23,861 (as of 31 December 2023)
Loans from Equinor ASA: None
Experience: Hove joined Equinor in 1991. He has held several central management positions in Equinor. He comes from the position of Senior Vice President Field Life Extension, which he held since January 2020. Prior to this, Hove was Senior Vice President for Operations Technology in Development & Production Norway. From 2000 - 2012 he worked internationally, including as Country Manager for Equinor in Brazil for 3.5 years. Hove started his career in 1991 in Norsk Hydro within petroleum technology holding various positions within exploration, field development and operations in Norway.
Education: Master's degree in petroleum engineering from Norwegian University of Science and Technology (NTNU).
Family relations: No family relations to other members of the Corporate Executive Committee, members of the Board or the Corporate Assembly.
Other matters: Hove is a Norwegian citizen and resident in Norway.
Position: Executive Vice President, Exploration & Production International (EPI) since 1 January 2023
Year of birth: 1966
External offices: None
Number of shares in Equinor ASA: 7,529 (as of 31 December 2023)
Loans from Equinor ASA: None
Experience: Mathieu joined Equinor in 1995. He comes from the position of Senior Vice President Corporate Strategy, which he had since October 2019. Mathieu has also held the Senior Vice President position for Joint Operations Support in Exploration and Production Norway from 2016 – 2019, Corporate Finance from 2014 – 2016, and Business Development Midstream Infrastructure from 2011 – 2014. Prior to the roles as Senior Vice President, Mathieu held several senior positions within
marketing and supply in commercializing gas contracts in both North Africa and Europe.
Education: Civil Engineer degree from Ecole Nationale des Travaux Publics de l'Etat and a Master's degree in Economics from Université Lumière Lyon and from University of California, Berkeley.
Family relations: No family relations to other members of the Corporate Executive Committee, members of the Board or the Corporate Assembly.
Other matters: Philippe Mathieu is a French citizen and resident in Norway.
Geir Tungesvik
Position: Executive Vice President, Projects, Drilling and Procurement (PDP) since 1 May 2022
Year of birth: 1961
External offices: None
Number of shares in Equinor ASA: 20,702 (as of 31 December 2023)
Loans from Equinor ASA: None
Experience: Geir Tungesvik joined Equinor in 1985. He comes from the position as Senior Vice President Project Development. Previously he has held central management positions in the company including the position as Senior Vice President for Drilling and Well, Vice President for exploration drilling, Vice President for Grane production field and Vice President for health, safety and environment in Exploration.
Education: Master of Science degree in petroleum from the University of Stavanger (UIS) and Master module in strategic management from the Norwegian Business School (BI).
Family relations: No family relations to other members of the Corporate Executive Committee, members of the Board or the Corporate Assembly.
Other matters: Tungesvik is a Norwegian citizen and resident in Norway.
Irene Rummelhoff
Position: Executive Vice President, Marketing, Midstream & Processing (MMP) since 17 August 2018 Year of birth: 1967
External offices: Member of the board of Airbus SE
Number of shares in Equinor ASA: 31,872 (as of 31 December 2023)
Loans from Equinor ASA: None
Experience: Rummelhoff joined Equinor in 1991. She has 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 New Energy Solutions (NES).
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.
Position: Executive Vice President, Renewables (REN) since 17 August 2018
Year of birth: 1971
External offices: Member of the board of the Confederation of Norwegian Enterprise (NHO) and Veidekke ASA.
Number of shares in Equinor ASA: 21,737 (as of 31 December 2023)
Experience: Eitrheim joined Equinor in 1998. He has held a range of leadership positions in Equinor in Azerbaijan, Washington DC, the CEO office, corporate strategy and Brazil. In 2017 - 2018 he was Chief Procurement Officer. Between 2014 - 2017 he led Equinor's upstream business in Brazil. In 2013 Eitrheim led the Secretariat for the investigation into the terrorist attack on the In Amenas gas processing facility in Algeria.
Education: Master's 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, members of the Board or the Corporate Assembly.
Other matters: Eitrheim is a Norwegian citizen and resident in Norway.
Hege Skryseth
Position: Executive Vice President and Chief Technical Officer since 1 September 2022
Year of birth: 1967
External offices: Member of the Board of Tomra and AutoStore
Number of shares in Equinor ASA: 5,364 (as of 31 December 2023)
Experience: Skryseth joined Equinor on 1 September 2022. She comes from the position as Executive Vice President of Kongsberg, and President of Kongsberg Digital, a position which she held since 2013. Prior to Kongsberg, Skryseth held various leadership positions in international tech companies such as Microsoft and Geodata (ESRI).
Education: Executive MBA from NHH and Bachelor from BI, college graduate from NITH.
Family relations: No family relations to other members of the Corporate Executive Committee, members of the Board or the Corporate Assembly.
Other matters: Skryseth is a Norwegian citizen and resident in Norway.
Position: Executive Vice President and General Counsel, Legal & Compliance (LEG) since 1 June 2021.
Year of birth: 1970
External offices: Deputy chair of the Council of Ethics and member of the Government Pension Fund Global Number of shares in Equinor ASA: 19,136 (as of 31 December 2023)
Loans from Equinor ASA: None
Experience: Rygh Torstensen joined Equinor in 1998. She comes from the position of Senior Vice President and General Counsel, which she held since 1 August 2019. Prior to that she held the position as Head of CEO office from July 2016. From 2011 - 2016 she was Vice President Corporate in LEG. From 1998 - 2011 Rygh Torstensen held various positions within LEG, including as Corporate Compliance Office and Acting General Counsel. Before joining Equinor she worked with the law firm Cappelen & Krefting DA and as a lawyer for Stavanger municipal council.
Education: Master of Law from the University of Bergen, Norway, and licensed as an Attorney at Law.
Family relations: No family relations to other members of the Corporate Executive Committee, members of the Board or the Corporate Assembly.
Other matters: Rygh Torstensen is a Norwegian citizen and resident in Norway.
Position: Executive Vice President Communication since 1 March 2022
Year of birth: 1965
External offices: None
Number of shares in Equinor ASA: 11,592 (as of 31 December 2023)
Loans from Equinor ASA: None
Experience: Lindbæk joined Equinor in 2010. He was appointed Senior Vice President Communication 1 January 2021. He was Vice President Corporate Communications Political & Public Affairs Norway from 2019-2021. Prior to this he was Equinor's Vice President for communication in Brussels, before that in the CFO Global Business Services, and as Vice President Media Relations from 2010-2015. Before joining Equinor, Lindbæk was SVP Corporate Communication in Aker Solutions, PR manager in Microsoft and PR consultant in BWPR and GCI Monsen.
Education: Master's degree in Comparative Politics from the University of Bergen and London School of Economics. Family relations: No family relations to other members of the Corporate Executive Committee, members of the Board or the Corporate Assembly.
Other matters: Lindbæk is a Norwegian citizen and resident in Norway.
Position: Executive Vice President, People & Organisation (PO) since 1 March 2022 Year of birth: 1963
External offices: None
Number of shares in Equinor ASA: 11,642 (as of 31 December 2023)
Loans from Equinor ASA: None
Experience: Stenerud joined Equinor in 2008 and has held various leadership roles across the company. His most recent position, which he held from November 2021, was Vice President Employee Relations in Corporate PO. From August 2018, he was Vice President for PO in Exploration and Production International. He has also served as Vice President for Exploration and Production Norway from 2014-2018. Stenerud has had a long international career within HR and prior to this he served as an officer in the Norwegian Airforce.
Education: Graduate from the Air Defense academy. Minor and Intermediate in phsycology with the Norwegian university of science and technology 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: Stenerud is a Norwegian citizen and resident in Norway.
The information set forth in the Corporate Governance Report, section 8, under the heading "Corporate assembly" is also incorporated herein by reference.
The information set forth under the following headings of the 2021 Remuneration Policy included as an appendix to the 2023 Remuneration Report is incorporated herein by reference:
The information set forth under the following headings of the 2023 Remuneration Report is incorporated herein by reference:
See also note 22 Pensions to the Consolidated financial statements.
The information set forth under the following headings of the of the 2023 Annual Report is incorporated herein by reference:
The information set forth under the following headings of the 2023 Corporate Governance Report is also incorporated herein by reference:
See also "Item 6. Directors, Senior Management and Employees—A. Directors and Senior Management" of this 2023 Form 20-F for more information regarding the expiration date of the current term of office of the members of our board of directors and the period during which our directors have served in such capacity, and the composition of the board of directors' committees.
The information set forth under the following headings of the 2023 Annual Report is incorporated herein by reference:
The following table show a breakdown of total workforce by region and employment type.
| Geographic location | Permanent employees |
Consultants | Total workforce |
1) Consultants (%) | |
|---|---|---|---|---|---|
| Norway | 20,231 | 939 | 21,170 | 4 | |
| Rest of Europe | 1,440 | 42 | 1,482 | 3 | |
| Africa | 65 | 6 | 71 | 8 | |
| Asia | 114 | 14 | 128 | 11 | |
| North America | 733 | 64 | 797 | 8 | |
| South America | 865 | 49 | 914 | 5 | |
| Australia | 1 | 1 | 2 | 50 | |
| Total | 23,449 | 1,115 | 24,564 | 5 | |
| Non - OECD | 1,018 | 68 | 1,086 | 6 |
1) Contractor personnel, defined as third-party service provides who work at our onshore and offshore operations, are not included.
The information set forth under the following headings of the 2023 Remuneration Report is incorporated herein by reference:
The information set forth under the heading "Major shareholders" in Section 5.1 of Chapter 5 on pages 260 – 261 of the 2023 Annual Report is incorporated herein by reference.
As part of its general loan arrangement for Equinor employees, Equinor has granted loans to Equinor-employed spouses of certain members of the corporate executive committee. Permanent employees in specified employee categories 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 fees, but not exceeding NOK 400,000. Employees outside the collective labour area are entitled to a car loan up to NOK 600,000 (managers) or NOK 700,000 (vice presidents and senior vice presidents). The car loan is interestfree, 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.
The information set forth under the heading "Equal treatment of shareholders and transactions with close associates" in chapter 4 on pages 6-7 of the 2023 Corporate Governance Report is also incorporated herein by reference. See also note 27 Related parties to the Consolidated financial statements.
Not applicable.
See "Item 18. Financial Statements" of this 2023 Form 20-F.
The information set forth under the heading 'Capital distribution' in Section 2.1 of Chapter 2 on page 41 of the 2023 Annual Report is incorporated herein by reference. The information set forth under the heading 'Equity and dividends' in Chapter 3 on pages 5 – 6 of the 2023 Corporate Governance Report is also incorporated herein by reference.
See also note 20 Shareholders' equity and dividends to the Consolidated financial statements.
Equinor is involved in a number of proceedings globally concerning matters arising in connection with the conduct of its business. 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 11 Income taxes and note 26 Other commitments, contingent liabilities and contingent assets to the Consolidated Financial Statements for a description of certain proceedings, including updated descriptions of litigation previously reported.
None.
Equinor's shares have been listed on the Oslo Børs (ticker: EQNR) and the New York Stock Exchange in the form of American Depositary Shares (ADS) (ticker: EQNR) 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.
Not applicable.
See "Item 9.A―The Offer and Listing―Offer and Listing Details" of this 2023 Form 20-F.
Not applicable.
Not applicable.
Not applicable.
Not applicable.
Equinor's current articles of association were adopted at the annual general meeting of shareholders on 10 May 2023. The articles of association are included as exhibit 1 to this 2023 Form 20-F.
The registered name is Equinor ASA. Equinor is a Norwegian public limited company.
Equinor's registered office is in Stavanger, Norway, registered with the Norwegian Register of Business Enterprises under number 923 609 016.
The objective of Equinor ASA is to develop, produce and market various forms of energy and derived products and services, as well as other business. The activities may also be carried out through participation in or cooperation with other companies.
Equinor's share capital is NOK 7,507,761,512.50 divided into 3,003,104,605 shares.
The nominal value of each ordinary share is NOK 2.50.
Equinor's articles of association provide that the board of directors shall consist of 9 - 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.
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.
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 related to the general meetings do not need to be sent to all shareholders if they 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. Equinor's board of directors adopted guidelines for advance voting in March 2012, and these guidelines are described in the notices of the annual general meetings.
Equinor's articles of association provide that Equinor is responsible for marketing and selling petroleum produced under the State's direct financial interest's (SDFI) 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.
The tasks of the nomination committee are to present a recommendation to:
The general meeting may adopt instructions for the nomination committee.
Exhibit 2.1 to this 2023 Form 20-F is also incorporated herein by reference.
Equinor is the technical service provider (TSP) for the Kårstø and Kollsnes gas processing plants in accordance with the technical service agreement between Equinor and Gassco AS. Equinor holds an ownership interest in Vestprosess (34%), which transports and processes NGL and condensate. Vestprosess is also operated by Gassco, with Equinor as TSP. The technical services agreement between Gassco AS and Equinor is included as Exhibit 4(a)(i), along with the amendments thereto in Exhibit 4(a)(ii), to this 2023 Form 20-F.
See also note 27 Related parties to the Consolidated financial statements.
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 who hold our shares to receive dividends, interest or other similar payments.
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 for the individual shareholder. The outline is based on current law and practice, but these laws and practice are subject to change, possibly also on a retroactive basis. Thus, the actual tax consequences for a shareholder may differ from the description set out below. Shareholders should consult their professional tax advisers for advice about the specific tax consequences of owning and disposing of shares or ADSs in Equinor in their particular situation, in case special regulations may apply.
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 Equinor in the year the dividend is declared. For the tax year 2023, only 3% of the dividends received is subject to tax at the ordinary income tax rate of 22% (the tax rate is 25% for entities subject to the finance tax). The effective tax rate for dividends received by corporate shareholders is thus 0.66% (3% x 22%) for ordinary corporations and 0.75% (3% x 25%) for entities subject to the finance tax. As of today, the same tax rates will apply for the tax year 2024.
Individual shareholders residing in Norway for tax purposes are subject to tax in Norway for dividends received from Equinor exceeding a tax-free allowance (the tax-free allowance is described below). Dividends exceeding the tax-free allowance are generally included in the individual's ordinary taxable income in the year the dividend is declared. For the tax year 2023, dividend income exceeding the tax-free allowance is grossed up with a factor of 1.72 before being included in the ordinary taxable income, resulting in an effective tax rate of 37.84% (22% x 1.72). As of today, the same tax rates will apply for the tax year 2024.
The tax-free allowance is computed for each individual share or ADS. The annual tax-free allowance equals the allowance basis multiplied by a risk-free interest rate set annually by the tax authorities. The allowance basis is equal to the acquisition cost for such share or ADS, as adjusted with inter alia any repayment of capital and any unused allowance. If the calculated allowance for one year exceeds the dividend distributed on the share or ADS, the excess (the "unused allowance") may be carried forward and set off against future dividends received on the same share or ADS (or gains upon the realisation of the same share or ADS, see below). Any unused allowance will also be added to the allowance basis for such share or ADS and thus increase the tax-free allowance in the following year until the unused allowance has been utilised.
Individual shareholders residing in Norway for tax purposes may hold the shares (but not ADS) in Equinor 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.
Non-resident shareholders are as a starting point subject to Norwegian withholding tax in the tax year 2023 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. As of today, the same withholding tax rate will apply for the tax year 2024.
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 in the tax year 2023 subject to the standard income tax of 22% (25% for companies subject to the finance tax). As of today, the same tax rate will apply for the tax year 2024.
Certain other important exceptions and modifications are outlined below.
The 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.
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 (but not ADS) in Equinor through a Norwegian stock savings account. Dividend on shares owned through the stock savings account will only be subject to withholding tax when withdrawn from the account.
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 with 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. Shareholders that believe they are eligible for a reduced rate will in this case have to apply to Skatteetaten (The Norwegian Tax Administration) 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: skatteetaten.no (Reduced withholding tax on share dividends for foreign shareholders – The Norwegian Tax Administration).
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 Equinor. On the other hand, corporate shareholders resident in Norway are not allowed any deduction for losses on shares or ADS in Equinor.
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. Taxable gains or losses in connection with such realisation are included in the individual's ordinary taxable income in the year of disposal. In the tax year 2023, the taxable gain or loss on the realised shares or ADSs is grossed up with a factor of 1.72 before it is included in the ordinary taxable income, resulting in an effective tax rate of 37.84% (22% x 1.72). As of today, the same tax rate will apply to gains and losses realised in the tax year 2024.
The taxable gain or deductible loss (before grossing 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 (as adjusted with inter alia any repayment of capital). Any unused allowance pertaining to a share or ADS 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 other shares or ADSs held by the shareholder.
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 the gain or loss for tax purposes.
Individual shareholders residing in Norway for tax purposes may hold the shares (but not ADS) in Equinor 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 Equinor, unless the shareholder carries on business activities in Norway and such shares or ADSs are or have been effectively connected with such activities.
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.
For the tax year 2023, the net wealth tax is 1.0% for net worth above a minimum threshold of NOK 1,700,000, and 1.1% for net worth above a minimum threshold of NOK 20,000,000. The assessment value of listed shares (including ADSs) is 80% of the listed value of such shares or ADSs on 1 January 2024. As of today, the same rates and thresholds will apply for the tax year 2024.
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.
No inheritance or gift tax is imposed in Norway.
No transfer tax is imposed in Norway in connection with the sale or purchase of shares or ADSs.
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 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 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.
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 longterm 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 is distributed, 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 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 applicable to qualified dividend income.
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.
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.
In general, we will be a PFIC in a taxable year if:
"Passive income" generally includes dividends, interest, gains from the sale or exchange of investment property rents and royalties (other than certain rents and royalties derived in the active conduct of a trade or business) and certain other specified categories of income. If a foreign corporation owns at least 25% by value of the stock of another corporation, the foreign corporation is treated for purposes of the PFIC tests as owning its proportionate share of the assets of the other corporation, and as receiving directly its proportionate share of the other corporation's income.
If we were to be treated as a PFIC, you will generally be subject to special rules with respect to:
Under these rules:
Special rules apply for calculating the amount of the foreign tax credit with respect to excess distributions by a PFIC.
Unless you make certain elections, your shares or ADSs will generally be treated as stock in a PFIC if we were a PFIC at any time during your holding period in your shares or ADSs, even if we are not currently a PFIC.
In addition, notwithstanding any election you make with regard to the shares or ADSs, dividends that you receive from us will not constitute qualified dividend income to you if we are a PFIC (or are treated as a PFIC with respect to you) either in the taxable year of the distribution or the preceding taxable year. Dividends that you receive that do not constitute qualified dividend income are not eligible for taxation at the preferential rates applicable to qualified dividend income. Instead, you must include the gross amount of any such dividend paid by us out of our accumulated earnings and profits (as determined for United States federal income tax purposes) in your gross income, and it will be subject to tax at rates applicable to ordinary income.
If you own shares or ADSs during any year that we are a PFIC with respect to you, you may be required to file Internal Revenue Service ("IRS") Form 8621.
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.
Not applicable.
Not applicable.
Our filings with the SEC are available to the public through the SEC's website at http://www.sec.gov. We also make available on our website, free of charge, our annual reports on Form 20-F, as well as certain other SEC filings, as soon as reasonably practicable after they are electronically filed with or furnished to the SEC. The information on our website is not incorporated by reference in this document.
Documents related to us that are available to the public (this 2023 Form 20-F, the 2023 Annual Report, our Articles of Association, our Code of Conduct, financial statements and our historical financial information for each of the three financial years preceding the publication of this 2023 Form 20-F) can be consulted on our website and at: Equinor ASA, Forusbeen 50, 4035 Stavanger, Norway. Unless stated otherwise, none of these documents form a part of this 2023 Form 20-F.
J. Annual Report to Security Holders.
Not applicable.
See notes 4 Financial risk and capital management and 28 Financial instruments and fair value measurement to the Consolidated financial statements.
A. Debt Securities Not applicable.
Not applicable.
Not applicable.
Exhibit 2.1 to this 2023 Form 20-F is incorporated herein by reference.
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. |
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| 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 |
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| USD 0.05 (or less) per ADS | Any cash distribution made or elective cash/stock dividend offered pursuant to the Deposit Agreement |
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| USD 0.05 (or less) per ADS, per calendar year (or portion thereof) | For the operation and maintenance costs in administering the ADR programme |
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| 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 |
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|---|---|---|---|---|
| Expenses of the Depositary | SWIFT, cable, telex, facsimile transmission and delivery charges (as provided in the deposit agreement). |
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| 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. |
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| 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 |
For the year ended 31 December 2023, J.P. Morgan reimbursed USD 2,000,000 to the company. Other reasonable costs associated with the administration of the ADR programme are borne by the company. For the year ended 31 December 2023, such costs, associated with the administration of the ADR programme, paid by the company, added up to USD 272,095. Under certain circumstances, including the removal of J.P. Morgan as depositary, the company is required to repay to J.P. Morgan certain amounts paid to the company in prior periods.
Not applicable.
Not applicable.
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 31 December 2023. Based on that evaluation, the chief executive officer and chief financial officer have concluded that these disclosure controls and procedures are effective at a reasonable level of assurance.
In 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 control systems, no evaluation of controls can provide absolute assurance that all control issues and any instances of fraud in the company have been detected.
The management 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 IFRS Accounting Standards as adopted by the European Union (EU). The accounting policies applied by the group also comply with IFRS Accounting Standards as issued by the International Accounting Standards Board (IASB).
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 2023 was effective.
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 Accounting Standards, 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. Moreover, projections of any evaluation of the effectiveness of internal control to future periods are subject to a risk that controls may become inadequate because of changes in conditions and that the degree of compliance with policies or procedures may deteriorate.
The effectiveness of internal control over financial reporting as of 31 December 2023 has been audited by Ernst & Young AS, an independent registered accounting firm that also audits Equinor's Consolidated financial statements. Their audit report on the internal control over financial reporting is included in the Consolidated financial statements.
There were no significant changes in our internal control over financial reporting during the year ended 31 December 2023 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Our board of directors has determined that both Anne Drinkwater and Rebekka Glasser Herlofsen qualify as an "audit committee financial expert" as defined in Item 16A of Form 20-F under the Exchange Act and each of them is an independent director under Rule 10A-3 under the Exchange Act.
We have adopted a Code of Conduct, which is approved by our board of directors, and applies to our board members, all of our employees (including our principal executive, principal financial and principal accounting officers) and hired personnel. Our Code of Conduct is filed as Exhibit 11 to this 2023 Form 20-F.
In 2023, our board of directors approved certain amendments to our Code of Conduct, including:
In 2023, we did not grant any waiver, including any implicit waiver, from any provision of the Code of Conduct to our principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions.
The information set forth under the heading "External auditor" in chapter 15 on pages 18 – 19 of the 2023 Corporate Governance Report is incorporated herein by reference. See also note 9 Auditor's remuneration and Research and development expenditures to the Consolidated financial statements.
See "Item 16G. Corporate Governance―Board committees" of this 2023 Form 20-F.
The information set forth under the headings "Equinor's share incentive plans", "Share buybacks" and "Summary of share buybacks" in Section 5.1 of Chapter 5 on pages 261 – 263 of the 2023 Annual Report is also incorporated herein by reference.
Not applicable.
Equinor's primary listing is on Oslo Børs. The American Depositary Receipts (ADRs) are listed on the New York Stock Exchange (NYSE). In addition, Equinor is a foreign private issuer subject to the reporting requirements of the SEC. ADRs representing the company's ordinary shares are 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 exempt 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:
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 Norwegian Code of Practice for Corporate Governance and applicable law. Oversight of the board of directors and management is exercised by the corporate assembly.
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 the corporate assembly both for shareholder and employee representatives. Equinor's board of directors has determined that, in its judgment, all shareholder representatives are independent. In making its determinations of independence, the board focuses, among other things, 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 as they are employees of Equinor. None of these employee representatives are executive officers of the company. For further information about the board of directors, see "Item 6. Directors, Senior Management and Employees—A. Directors and Senior Management" of this 2023 Form 20-F.
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. 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.
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 representative 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 representative 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 under the NYSE rules for such committee are principally carried out by the corporate assembly and the nomination committee. The nomination committee is elected by the general meeting of shareholders, while the corporate assembly is elected partly by the general meeting of shareholders and partly by and among the employees.
NYSE rules require the compensation committee of US companies to comprise independent directors, recommend senior management remuneration and determine 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. The compensation committee consists of four shareholder representatives and one employee representative. Equinor's compensation committee makes recommendations to the board regarding management remuneration, including that of the CEO. Further, the compensation committee assesses its own performance and has the authority to hire external advisors. The nomination committee, which is elected by the general meeting of shareholders, recommends to the corporate assembly the candidates and remuneration of the board of directors.
The nomination committee also recommends to the general meeting of shareholders the candidates and remuneration for the nomination committee and the shareholder representative candidates and remuneration for the corporate assembly.
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.
Not applicable.
Not applicable.
Not applicable.
Our processes for assessing, identifying and managing material risks from cyber security threats are integrated into our enterprise risk management (ERM) framework, which we use to identify, analyze, evaluate and manage risks. We recognize that risks from cyber security threats are interconnected and company-wide, so we seek to ensure shared situational awareness and common prioritization across different business areas. As described further below under "Cyber security Governance", we have a cross-departmental approach to addressing cyber security risk, which includes our employees, management and board of directors.
We use a variety of tools and processes to identify, assess and manage material cyber security risks. We identify cyber security risks based on an evaluation of various cyber security threat scenarios that may cause disruption to our business or operations. These scenarios are developed to represent incremental levels of severity of the estimated monetary, reputational, safety, security or sustainability impact of cyber security threats such as social engineering (phishing), malicious software targeting end-users/network, unauthorized access by insiders, employee/consultant error and/or unintended errors.
We conduct annual company-wide cyber security assessments to assess the threats posed by external actors to our information technology and operational technology systems and promote awareness internally of the cyber security threats faced by the company. We also conduct assessments of cyber security incidents experienced by the company and third parties relevant to the company. These assessments are conducted in collaboration between the technology, digital and innovation business area, the global operations technology excellence unit and the corporate security and crisis management unit. The business area risk owners, regional security managers, country office representatives, political analysis teams, shipping security teams, enterprise data and cyber security professionals and the emergency response-and-support centre are all involved in and contribute to these assessments. The results of these assessments are shared regularly with the board of directors, including the safety, sustainability and ethics committee.
We engage external assessors to conduct maturity testing to evaluate our processes and procedures within specific areas to ensure continuous development of barriers against cyber security threats. We also seek information from national security authorities and work closely with IT vendors, external cyber security advisory services and other companies in the industry with the aim of continuously improving our capabilities to identify, protect, detect, respond to and recover from cyber security threats. We also use input provided by external auditors as part of independent reviews to improve our cyber security barriers.
Actual and/or potential vulnerabilities in our information systems are continuously monitored by our Cyber Defence Center. We follow the ISO27001, IEC62443 and National Institute for Standard and Technology (NIST) cyber security frameworks to build resilience, focusing on capabilities for reducing both the probability and consequences of cyber security incidents. We utilize multiple tools and practices to monitor external developments related to cyber security which may be relevant to the company, such as alerts/publications from national cyber security centres, advice from security risk consulting firms and reports from information technology and cyber security companies, and assess their implications for Equinor with a focus on external factors, such as the threat actors' presence, capability, intent, past targeting and anticipated future targeting, as well as internal factors such as evidence of attacks on our information systems. All relevant updates and developments are disseminated across the company through the company's intranet and e-mails to interested internal stakeholders.
We provide cyber security awareness training to all our employees on an annual basis which is designed to provide guidance for identifying and avoiding cyber security risks, and require employees in certain roles to complete additional role based, specialized cyber security trainings.
We have company-wide management systems detailing protocols and response governance for emergency response and business continuity management. Our management systems reflect industry good practices, internal requirements, national laws and regulations and ISO/IEC standards to identify, protect, detect, respond and recover from cyber security threats. The corporate security and crisis management unit is responsible for setting strategic direction and maintaining the company's corporate framework on crisis and business continuity management. We have adopted business continuity plans and disaster recovery plans which are designed with the goal of minimizing the consequences of cyber security incidents, and are reviewed on a regular basis. We also have a dedicated global cyber security incident response team, comprised of specially trained personnel, that provides assistance and support in dealing with any actual and/or potential cyber security incidents.
In addition to assessing our own cyber security preparedness, we also consider and evaluate cyber security risks associated with our use of third-party service providers. We have integrated cyber security risk management into our procurement process whereby cyber security risks are identified and assessed in the early stages of negotiating contracts and addressed accordingly based on the nature of services provided. Cyber security risks associated with third parties are monitored through the life cycle of the relationships.
In 2023, as in previous years, we experienced several cyber security incidents and other disruptions to our information systems. None of these incidents and systems disruptions, including those reported to us by our third-party partners, had a material impact on our business, operations or financial results. See "Item 3D – Risk Factors" for additional information about digital and cyber security risks.
Our board of directors oversees the company's internal control and overall risk management and assurance, and through its audit committee, reviews and monitors the effectiveness of the ERM framework, which has identified cyber security as one of the top enterprise risks. The board and audit committee discuss the company's ERM framework, and three-lines of control model and learnings from risk-adjusting actions and assurance activities on a bi-annual basis.
The board of directors' safety, sustainability and ethics committee (SSEC) is primarily responsible for the oversight of cyber security risk management, including review of the company's practices and performance related to cyber security, and updates the board of directors on any matters of concern that become apparent in the exercise of its duties. The SSEC reviews and assesses at least annually the developments, implementation, effectiveness and practice of the company's cyber security policies, programmes and strategies, and the effectiveness of internal controls for cyber security matters, including applicable management systems, policies, practices, processes, leadership, and culture, and summarizes its assessments in an annual report to the board of directors. The SSEC also receives regular briefings and updates from the Executive Vice President for Safety, Security & Sustainability (EVP SSU) relating to material risks from cyber security threats and management of cyber security-related risks.
We use a three-line model for risk management (including cyber security risk) in which employees and management work together to contribute to creation and protection of value. As the first line-of-control, cyber security risk is managed in the business areas as an integral part of employee and manager tasks. Technical experts in each business area are responsible for monitoring the relevant business area's cyber security risks and performance, conducting assessments and ensuring a suitable and effective management system that reflects the relevant business area's business scope and context, risks and external regulatory requirements. The first line shares its experiences and findings in a systematic way with the second line. The responsibility for reporting material risks from cyber security threats, regularly and systematically, follows the accountability of the business areas up to their respective executive vice presidents. The executive vice presidents of the business areas meet with the EVP SSU bi-annually to review top enterprise risk from cyber security threats.
The second line-of-control oversees cyber security risks, performance and assurance across the company and provides advice and support to the first line in identifying and executing assurance activities and monitors, supports and challenges the first line in relation to performance and management of cyber security risks. The EVP SSU leads the second line-of-control for cyber security-related matters and oversees cyber security risks across the company and reports to the Corporate Executive Committee (CEC) and the SSEC. The Chief Security Officer (CSO) and Chief Information Security Officer (CISO) assist the EVP SSU in the day-to-day monitoring of cyber security risks, which are reported to the CEC. The CEC is responsible for reviewing and approving the strategy and resourcing of cyber security risk management. Our current EVP SSU holds a Master's degree in Cybernetics and Process Automation and a Bachelor's degree in Automation from the Rogaland Regional College/University of Stavanger. She has held a number of central leadership positions within operations, projects and technology since she joined Equinor in 1999, including Chief Operating Officer, where she drove the company's digital transformation.
Our third line-of-control is the corporate audit unit which performs independent audits across business areas and management roles, including cyber security audits, and reports to the board of directors on a periodic basis.
The Company has responded to Item 18 in lieu of this item.
The audited consolidated financial statements as required under Item 18 are attached hereto starting on page 74 of this 2023 Form 20-F. The audit report of Ernst & Young AS, an independent registered accounting firm, is included herein preceding the audited Consolidated Financial Statements.
| Exhibit no | Description |
|---|---|
| Exhibit 1 | Articles of Association of Equinor ASA, as amended, effective from 10 May 2023 (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 Equinor ASA's (formerly known as Statoil ASA) and Equinor Energy AS's (formerly known as Statoil Petroleum AS) 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 11 May 2023, by and among Equinor ASA, as Issuer, Equinor Energy AS, as Guarantor, the Bank of New York Mellon, London Branch, 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 13 May 2020, of Equinor ASA in respect of a €20,000,000 Euro Medium Term Notes Programme. (incorporated by reference to Exhibit 2.6 of Equinor ASA's 2020 Form 20-F (File no. 001-15200) filed with the Commission on March 19, 2021) |
| Exhibit 2.7 | Deed of Guarantee, dated as of 13 May 2020, of Equinor Energy AS in respect of a €20,000,000 Euro Medium Term Notes Programme (incorporated by reference to Exhibit 2.7 of Equinor ASA's 2020 Form 20-F (File no. 001-15200) filed with the Commission on March 19, 2021). |
| 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 Energy 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 Anders Opedal as of 9 August 2020 (incorporated by reference to Exhibit 4(c) of Equinor ASA's 2020 Form 20-F (File no. 001-15200) filed with the Commission on March 19, 2021). |
| Exhibit 8 | List of subsidiaries |
| Exhibit 11 | Code of Conduct |
| Exhibit 12.1 | Rule 13a-14(a) Certification of the Chief Executive Officer |
| Exhibit 12.2 | Rule 13a-14(a) Certification of Chief Financial Officer |
| Exhibit 13.1 | Rule 13a-14(b) Certification of the Chief Executive Officer1) |
| Exhibit 13.2 | Rule 13a-14(b) Certification of the Chief Financial Officer1) |
| Exhibit 15.1 | Consent of EY AS |
| Exhibit 15.2 | Consent of DeGolyer and MacNaughton |
| Exhibit 15.3 | Report of DeGoyler and MacNaughton |
| Exhibit 15.4 | Equinor 2023 Integrated Annual Report |
| Exhibit 15.5 | Oil and gas reserves report |
| Exhibit 15.6 | Remuneration Report |
| Exhibit 15.7 Exhibit 15.8 |
Board statement on corporate governance Clawback policy |
| Exhibit 17 | List of guarantor subsidiaries |
| Exhibit 101 | Interactive Data Files (formatted in Inline XBRL (Extensible Business Reporting Language)). Submitted electronically with the 2023 Form 20-F. |
| Exhibit 104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101). |
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.
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.
By: /s/ TORGRIM REITAN Name: Torgrim Reitan Title: Executive Vice President and Chief Financial Officer
Dated: 21 March 2024
The reports set out below are provided in accordance with standards of the Public Company Accounting Oversight Board (United States). Ernst & Young AS (PCAOB ID: 1572) has also issued 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, and on other required matters. That report is not included in this 2023 Form 20-F, but only in the 2023 Annual report.
To the Shareholders and the Board of Directors of Equinor ASA
We have audited the accompanying consolidated balance sheets of Equinor ASA and its subsidiaries (Equinor or the Company) as of 31 December 2023 and 2022, the related consolidated statements of income, comprehensive income, changes in equity and cash flows for each of the three years in the period ended 31 December 2023, 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 as of 31 December 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended 31 December 2023, in conformity with IFRS Accounting Standards as issued by the International Accounting Standards Board (IASB) and in conformity with IFRS Accounting Standards as adopted by the European Union.
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 2023, 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 12 March 2024 expressed an unqualified opinion thereon.
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 audits. 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 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.
The critical audit matters communicated below are matters arising from the current period audit of the Consolidated Financial Statements that were communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the Consolidated 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 disclosures to which they relate.
Description of the Matter
As of 31 December 2023, the Company has recognised production plants and oil and gas assets, including assets under development, of USD 39,585 million and USD 13,980 million, respectively, within Property, plant and equipment. Refer to Note 14 to the Consolidated Financial Statements for the related disclosures. As described in Note 14, determining the recoverable amount of an asset involves an estimate of future cash flows, which is dependent upon management's best estimate of the economic conditions that will exist over the asset's useful life. The asset's operational performance and external factors have a significant impact on the estimated future cash flows and therefore, the recoverable amount of the asset.
Auditing management's estimate of the recoverable amount of production plants and oil and gas assets is complex and involves a high degree of judgement. Significant assumptions used in forecasting future cash flows are future commodity prices, currency exchange rates, expected reserves, capital expenditures, and the discount rate.
These significant assumptions are forward-looking and can be affected by future economic and market conditions, including matters related to climate change and energy transition. As described in Note 3 to the Consolidated Financial Statements, the effects of the initiatives to limit climate change and the potential impact of the energy transition are relevant to some of the economic assumptions in the Company's estimation of future cash flows. Climate considerations are included directly in the impairment assessments by estimating the carbon costs in the cash flows, and indirectly as the expected effects of the climate change are included in the estimated commodity prices. As also described in Note 3, commodity price assumptions applied in value-in-use impairment testing are based on management's best estimate, which differs from the price-set required to achieve the goals of the Paris Agreement as described in the International Energy Agency (IEA) World Energy Outlook's Announced Pledges Scenario, or the Net Zero Emissions by 2050 Scenario. The impact of the energy transition and potential restrictions by regulators, market and strategic considerations may also have an effect on the estimated production profiles and the economic lifetime of the Company's assets and projects.
Additionally, the treatment of tax in the estimation of the recoverable amount is challenging, as the Company is subject to different tax structures that are inherently complex, particularly in Norway.
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 testing controls over management's review of assumptions and inputs to the assessments of impairment and impairment reversals.
Our audit procedures performed over the significant assumptions and inputs included, among others, evaluation of the methods and models used in the calculation of the recoverable amount. We also evaluated the relevant tax effects based on the local legislation of the relevant jurisdictions, particularly in Norway, and tested the clerical accuracy of the models through independently recalculating the value in use. We involved valuation specialists to assist us with these procedures. In addition, we compared projected capital expenditures to approved operator budgets or management forecasts. For those assets previously impaired, we compared actual results to the forecasts used in historical impairment analyses. We also compared expected reserve volumes with internal production forecasts and external evaluations of expected reserves and we compared the historical production with management's previous production forecasts, with the involvement of our reserves specialists.
To test price assumptions, we evaluated management's methodology to determine future commodity prices and compared such assumptions to external benchmarks, among other procedures. We involved valuation specialists to assist in evaluating the reasonableness of the Company's assessment of currency exchange rates and the discount rate, by assessing the Company's methodologies and key assumptions used to calculate the rates and by comparing those rates with external information. We also evaluated management's methodology to factor climate-related matters into their determination of future commodity price assumptions.
To test carbon cost assumptions, with the involvement of climate change and sustainability specialists, we evaluated management's methodology to determine future carbon costs, including assessing the impact from climate-related matters, and compared management's assumptions with the current legislation in place in the relevant jurisdictions and the jurisdictions' announced pledges regarding escalation of carbon costs.
We evaluated management's sensitivity analyses over its future commodity prices and carbon cost assumptions by taking into consideration, among other sources, the Net Zero Emissions by 2050 Scenario and Announced Pledges Scenario estimated by the International Energy Agency (IEA). We have also evaluated management's disclosures related to the consequences of initiatives to limit climate change, including the effects of the Company's climate change strategy on the
Consolidated Financial Statements and the energy transition's effects on estimation uncertainty, discussed in more detail in Notes 3 and 14.
Description of the Matter As of 31 December 2023, the Company has recognised a provision for decommissioning and removal activities of USD 12,360 million classified within Provisions and other liabilities. Refer to Note 23 to the Consolidated Financial Statements for the related disclosures. As described in Note 23, the appropriate estimates for such obligations are based on historical knowledge combined with knowledge of ongoing technological developments, expectations about future regulatory and technological development and involve the application of judgement and an inherent risk of significant adjustments. The estimated costs of decommissioning and removal activities require revisions due to changes in current regulations and technology while considering relevant risks and uncertainties. Auditing management's estimate of the decommissioning and removal of offshore installations at the end of the production period is complex and involves a high degree of judgement. Determining the provision for such obligations involves application of considerable 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 rates and the expected future costs, which include the underlying assumptions norms and rates, and time required to decommission and can vary considerably depending on the expected removal complexity. These significant assumptions are forward-looking and can be affected by future economic and market conditions, including matters related to climate change and energy transition. As described in Note 3 to the Consolidated Financial Statements, the effects of the initiatives to limit climate change and the potential impact of the energy transition are relevant to some of the economic assumptions in the Company's estimation of future cash flows. The impact of the energy transition and potential restrictions by regulators, market and strategic considerations may also have an effect on the estimated economic lifetime of the Company's assets and projects. If the Company's business cases for the oil and gas producing assets in the future should change materially due to governmental initiatives to limit climate change, it could affect the timing of cessation of the assets and the asset retirement obligations (ARO). 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 calculate the present value of the estimated future decommissioning and removal expenditures determined in accordance with local conditions and requirements. This included testing controls over management's review of assumptions described above, used in the calculation of the ARO. To test management's estimation of the provision for decommissioning and removal activities, our audit procedures included, among others, evaluating the completeness of the provision by comparing significant additions to property, plant and equipment to management's assessment of new ARO obligations recognized in the period. To assess the expected future costs, 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 the assumptions against historical data. We compared discount rates to external market data. With the support of our valuation specialists, we evaluated the methodology and models used by management to estimate the ARO and performed a sensitivity analysis on the significant assumptions. In addition, we recalculated the formulas in the models. We evaluated management's sensitivity analyses over the effect of performing removal five years
earlier than currently scheduled due to potential governmental initiatives to limit climate change. We have also evaluated management's disclosures related to the consequences of initiatives to limit climate change, including the effects of the Company's climate change strategy on the Consolidated Financial Statements and the energy transition's effects on estimation uncertainty, discussed in more detail in Notes 3 and 23.
/s/ Ernst & Young AS
We have served as the Company's auditor since 2019.
Stavanger, Norway
12 March 2024
To the Shareholders and the Board of Directors of Equinor ASA
We have audited Equinor ASA and subsidiaries' (the Company) internal control over financial reporting as at 31 December 2023, 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, the Company maintained, in all material respects, effective internal control over financial reporting as at 31 December 2023, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the 2023 Consolidated Financial Statements of the Company, and our report dated 12 March 2024 expressed an unqualified opinion thereon.
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 as set out in Item 15. Controls and Procedures. 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.
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
12 March 2024
| (in USD million) | Note | 2023 | 2022 | 2021 |
|---|---|---|---|---|
| Revenues | 7 | 106,848 | 149,004 | 88,744 |
| Net income/(loss) from equity accounted investments | 15 | (1) | 620 | 259 |
| Other income | 6 | 327 | 1,182 | 1,921 |
| Total revenues and other income | 7 | 107,174 | 150,806 | 90,924 |
| Purchases [net of inventory variation] | (48,175) | (53,806) | (35,160) | |
| Operating expenses | (10,582) | (9,608) | (8,598) | |
| Selling, general and administrative expenses | (1,218) | (986) | (780) | |
| Depreciation, amortisation and net impairment | 12, 13, 14 |
(10,634) | (6,391) | (11,719) |
| Exploration expenses | 13 | (795) | (1,205) | (1,004) |
| Total operating expenses | (71,404) | (71,995) | (57,261) | |
| Net operating income/(loss) | 5 | 35,770 | 78,811 | 33,663 |
| Interest income and other financial income | 10 | 2,449 | 1,222 | 38 |
| Interest expenses and other financial expenses | 10 | (1,660) | (1,379) | (1,223) |
| Other financial items | 10 | 1,325 | (50) | (895) |
| Net financial items | 2,114 | (207) | (2,080) | |
| Income/(loss) before tax | 37,884 | 78,604 | 31,583 | |
| Income tax | 11 | (25,980) | (49,861) | (23,007) |
| Net income/(loss) | 11,904 | 28,744 | 8,576 | |
| Attributable to shareholders of the company | 20 | 11,885 | 28,746 | 8,563 |
| Attributable to non-controlling interests | 19 | (3) | 14 | |
| Basic earnings per share (in USD) | 20 | 3.93 | 9.06 | 2.64 |
| Diluted earnings per share (in USD) | 20 | 3.93 | 9.03 | 2.63 |
| Full year | ||||
|---|---|---|---|---|
| (in USD million) | Note | 2023 | 2022 | 2021 |
| Net income/(loss) | 11,904 | 28,744 | 8,576 | |
| Actuarial gains/(losses) on defined benefit pension plans | (276) | 461 | 147 | |
| Income tax effect on income and expenses recognised in OCI1) | 66 | (105) | (35) | |
| Items that will not be reclassified to the Consolidated statement of income | 22 | (211) | 356 | 111 |
| Foreign currency translation effects | (587) | (3,609) | (1,052) | |
| Share of OCI from equity accounted investments | (113) | 424 | 0 | |
| Items that may subsequently be reclassified to the Consolidated statement of income | (701) | (3,186) | (1,052) | |
| Other comprehensive income/(loss) | (911) | (2,829) | (940) | |
| Total comprehensive income/(loss) | 10,992 | 25,914 | 7,636 | |
| Attributable to the shareholders of the company | 10,974 | 25,917 | 7,622 | |
| Attributable to non-controlling interests | 19 | (3) | 14 |
1) Other Comprehensive Income (OCI).
| At 31 December | |||
|---|---|---|---|
| (in USD million) | Note | 2023 | 2022 |
| ASSETS | |||
| Property, plant and equipment Intangible assets |
12 13 |
58,822 5,709 |
56,498 5,158 |
| Equity accounted investments | 15 | 2,508 | 2,758 |
| Deferred tax assets | 11 | 7,936 | 8,732 |
| Pension assets | 22 | 1,260 | 1,219 |
| Derivative financial instruments | 28 | 559 | 691 |
| Financial investments | 16 | 3,441 | 2,733 |
| Prepayments and financial receivables | 16 | 1,291 | 2,063 |
| Total non-current assets | 81,525 | 79,851 | |
| Inventories | 17 | 3,814 | 5,205 |
| Trade and other receivables1) | 18 | 16,933 | 22,452 |
| Derivative financial instruments | 28 | 1,378 | 4,039 |
| Financial investments | 16 | 29,224 | 29,876 |
| Cash and cash equivalents2) | 19 | 9,641 | 15,579 |
| Total current assets | 60,990 | 77,152 | |
| Assets classified as held for sale | 6 | 1,064 | 1,018 |
| Total assets | 143,580 | 158,021 | |
| EQUITY AND LIABILITIES | |||
| Shareholders' equity Non-controlling interests |
48,490 10 |
53,988 1 |
|
| Total equity | 20 | 48,500 | 53,989 |
| Finance debt | 21 | 22,230 | 24,141 |
| Lease liabilities | 25 | 2,291 | 2,409 |
| Deferred tax liabilities | 11 | 13,345 | 11,996 |
| Pension liabilities | 22 | 3,925 | 3,671 |
| Provisions and other liabilities | 23 | 15,304 | 15,633 |
| Derivative financial instruments | 28 | 1,795 | 2,376 |
| Total non-current liabilities | 58,890 | 60,226 | |
| Trade, other payables and provisions | 24 | 11,870 | 13,352 |
| Current tax payable | 12,306 | 17,655 | |
| Finance debt | 21 | 5,996 | 4,359 |
| Lease liabilities | 25 | 1,279 | 1,258 |
| Dividends payable | 20 | 2,649 | 2,808 |
| Derivative financial instruments | 28 | 1,619 | 4,106 |
| Total current liabilities | 35,719 | 43,539 | |
| Liabilities directly associated with the assets classified as held for sale | 6 | 471 | 268 |
| Total liabilities | 95,080 | 104,032 | |
| Total equity and liabilities | 143,580 | 158,021 |
| (in USD million) | Share capital |
Additional paid-in capital |
Retained earnings |
Foreign currency translation reserve |
OCI from equity accounted investments1) |
Shareholders' equity |
Non controlling interests |
Total equity |
|---|---|---|---|---|---|---|---|---|
| At 1 January 2021 | 1,164 | 6,852 | 30,050 | (4,194) | 0 | 33,873 | 19 | 33,892 |
| Net income/(loss) | 8,563 | 8,563 | 14 | 8,576 | ||||
| Other comprehensive income/(loss) | 111 | (1,052) | (940) | (940) | ||||
| Total comprehensive income/(loss) | 7,636 | |||||||
| Dividends | (2,041) | (2,041) | (2,041) | |||||
| Share buy-back | (429) | (429) | (429) | |||||
| Other equity transactions | (15) | (15) | (18) | (33) | ||||
| At 31 December 2021 | 1,164 | 6,408 | 36,683 | (5,245) | 0 | 39,010 | 14 | 39,024 |
| Net income/(loss) | 28,746 | 28,746 | (3) | 28,744 | ||||
| Other comprehensive income/(loss) | 356 | (3,609) | 424 | (2,829) | (2,829) | |||
| Total comprehensive income/(loss) | 25,914 | |||||||
| Dividends | (7,549) | (7,549) | (7,549) | |||||
| Share buy-back | (22) | (3,358) | (3,380) | (3,380) | ||||
| Other equity transactions | (10) | (10) | (10) | (20) | ||||
| At 31 December 2022 | 1,142 | 3,041 | 58,236 | (8,855) | 424 | 53,988 | 1 | 53,989 |
| Net income/(loss) | 11,885 | 11,885 | 19 | 11,904 | ||||
| Other comprehensive income/(loss) | (211) | (587) | (113) | (911) | (911) | |||
| Total comprehensive income/(loss) | 10,992 | |||||||
| Dividends | (10,783) | (10,783) | (10,783) | |||||
| Share buy-back | (42) | (3,037) | (2,606) | (5,685) | (5,685) | |||
| Other equity transactions | (3) | (3) | (10) | (13) | ||||
| At 31 December 2023 | 1,101 | 0 | 56,521 | (9,442) | 310 | 48,490 | 10 | 48,500 |
1) OCI items from equity accounted investments that may subsequently be reclassified to the Consolidated statement of income, are presented as part of OCI from equity accounted investments. OCI items that will not be reclassified to the Consolidated statements of income will be included in retained earnings.
Please refer to note 20 Shareholders' equity, capital distribution and earnings per share for more details.
| (in USD million) | Note | 2023 | Full year 2022 |
2021 |
|---|---|---|---|---|
| Income/(loss) before tax | 37,884 | 78,604 | 31,583 | |
| Depreciation, amortisation and net impairment | 12, 13, 14 | 10,634 | 6,391 | 11,719 |
| Exploration expenditures written off | 13 | (53) | 342 | 171 |
| (Gains)/losses on foreign currency transactions and balances | (852) | (2,088) | (47) | |
| (Gains)/losses on sale of assets and businesses | 6 | 8 | (823) | (1,519) |
| (Increase)/decrease in other items related to operating activities1) | (1,313) | 468 | 106 | |
| (Increase)/decrease in net derivative financial instruments | 28 | 1,041 | 1,062 | 539 |
| Interest received | 1,710 | 399 | 96 | |
| Interest paid | (1,042) | (747) | (698) | |
| Cash flows provided by operating activities before taxes paid and working capital items | 48,016 | 83,608 | 41,950 | |
| Taxes paid | (28,276) | (43,856) | (8,588) | |
| (Increase)/decrease in working capital | 4,960 | (4,616) | (4,546) | |
| Cash flows provided by operating activities | 24,701 | 35,136 | 28,816 | |
| Cash used in business combinations | 6 | (1,195) | 147 | (111) |
| Capital expenditures and investments | 6 | (10,575) | (8,758) | (8,040) |
| (Increase)/decrease in financial investments | 443 | (10,089) | (9,951) | |
| (Increase)/decrease in derivative financial instruments | (1,266) | 1,894 | (1) | |
| (Increase)/decrease in other interest-bearing items | (87) | (23) | 28 | |
| Proceeds from sale of assets and businesses | 6 | 272 | 966 | 1,864 |
| Cash flows provided by/(used in) investing activities | (12,409) | (15,863) | (16,211) | |
| Repayment of finance debt | 21 | (2,818) | (250) | (2,675) |
| Repayment of lease liabilities | 25 | (1,422) | (1,366) | (1,238) |
| Dividends paid | 20 | (10,906) | (5,380) | (1,797) |
| Share buy-back | 20 | (5,589) | (3,315) | (321) |
| Net current finance debt and other financing activities | 2,593 | (5,102) | 1,195 | |
| Cash flows provided by/(used in) financing activities | 21 | (18,142) | (15,414) | (4,836) |
| Net increase/(decrease) in cash and cash equivalents | (5,850) | 3,860 | 7,768 | |
| Foreign currency translation effects | (87) | (2,268) | (538) | |
| Cash and cash equivalents at the beginning of the period (net of overdraft) | 19 | 15,579 | 13,987 | 6,757 |
| Cash and cash equivalents at the end of the period (net of overdraft)2) | 19 | 9,641 | 15,579 | 13,987 |
Interest paid in cash flows provided by operating activities excludes capitalised interest of USD 468 million, USD 382 million, and USD 334 million for the years ending 31 December 2023, 2022 and 2021, respectively. Capitalised interest is included in Capital expenditures and
investments in cash flows used in investing activities. Total interest paid amounts to USD 1,510 million, USD 1,129 million, and USD 1,032 million for the years 2023, 2022 and 2021, respectively.
Notes to the Consolidated financial statements
The Equinor Group (Equinor) consists of Equinor ASA and its subsidiaries. Equinor ASA is incorporated and domiciled in Norway and listed on the Oslo Børs (Norway) and the New York Stock Exchange (USA). The address of its registered office is Forusbeen 50, N-4035 Stavanger, Norway.
Equinor's objective is to develop, produce and market various forms of energy and derived products and services, as well as other businesses. The activities may also be carried out through participation in or cooperation with other companies. Equinor Energy AS, a 100% owned operating subsidiary of Equinor ASA and owner of all of Equinor's oil and gas activities and net assets on the Norwegian continental shelf, is co-obligor or guarantor for certain debt obligations of Equinor ASA.
The Consolidated financial statements of Equinor for the full year 2023 were approved for issuance by the board of directors on 12 March 2024 and is subject to approval by the annual general meeting on 14 May 2024.
2 Accounting policies
The Consolidated financial statements of Equinor ASA and its subsidiaries (Equinor) have been prepared in accordance with IFRS Accounting Standards as adopted by the European Union (EU) and with IFRS Accounting Standards as issued by the International Accounting Standards Board (IASB), IFRIC® Interpretations issued by IASB and the additional requirements of the Norwegian Accounting Act, effective on 31 December 2023.
The Consolidated financial statements are prepared on the historical cost basis with some exceptions where fair value measurement is applied. These exceptions are specifically disclosed in the accounting policies sections in relevant notes. The material accounting policies described in these Consolidated financial statements have been applied consistently to all periods presented.
Certain amounts in the comparable years have been restated or reclassified to conform to current year presentation. All amounts in the Consolidated financial statements are denominated in USD millions, unless otherwise specified. 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.
The line items included in Total operating 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 impairments are presented on 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.
The Consolidated financial statements include the accounts of Equinor ASA and its subsidiaries as well as Equinor's interests in jointly controlled and equity accounted investments. All intercompany balances and transactions, including unrealised profits and losses arising from Equinor's internal transactions, have been eliminated.
Foreign exchange differences arising on translation of transactions, assets and liabilities to the functional currency of individual entities in Equinor are recognised in the Consolidated statement of income as foreign exchange gains or losses within Net financial items. However, foreign exchange differences arising from the translation of estimate-based provisions are generally accounted for as part of the change in the underlying estimate.
When preparing the Consolidated financial statements, the financial statements of entities with functional currencies other than the Group's presentation currency USD are translated into USD, and the foreign exchange differences are recognised separately in the Consolidated statement of comprehensive income within Other comprehensive income (OCI). The cumulative amount of such translation differences relating to an entity is reclassified to the Consolidated statement of income and reflected as a part of the gain or loss on disposal of that entity.
Loans from Equinor ASA to subsidiaries and equity accounted investments 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 OCI in the Consolidated financial statements.
In the statement of cash flows, operating activities are presented using the indirect method, where Income/(loss) before tax is adjusted for changes in inventories and operating receivables and payables, the effects of non-cash items such as depreciations, amortisations and impairments, provisions, unrealised gains and losses and undistributed profits from associates, and items of income or expense for which the cash effects are investing or financing cash flows. Increase/decrease in financial investments, derivative financial instruments, and other interest-bearing items are all presented net as part of Investing activities, either because the transactions are financial investments and turnover is quick, the amounts are large, and the maturities are short, or due to materiality.
The preparation of the Consolidated financial statements requires management to make accounting judgements, estimates and assumptions.
Information about judgements made in applying the accounting policies that have the most significant effects on the amounts recognised in the Consolidated financial statements is described in the following notes:
Note 6 – Acquisitions and disposals Note 7 – Total revenues and other income Note 25 – Leases
Estimates used in the preparation of these Consolidated financial statements are prepared based on customised models. The assumptions on which the estimates are based rely on historical experience, external sources of information and various other factors that management assesses to be reasonable under the current conditions and circumstances. These estimates and assumptions 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 set of conditions.
Equinor is exposed to several underlying economic factors affecting the overall results, such as commodity prices, foreign currency exchange rates, market risk premiums and interest rates as well as financial instruments with fair values derived from changes in these factors. The effects of the initiatives to limit climate changes and the potential impact of the energy transition are relevant to several of these economic assumptions. 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, field developments and operating activities.
The most important matters in understanding the key sources of estimation uncertainty are described in each of the following notes:
Note 3 – Climate change and energy transition Note 11 – Income taxes
Note 12 – Property, plant and equipment
Note 13 – Intangible assets
Note 14 – Impairments
Note 23 – Provisions and other liabilities
Note 26 – Other commitments, contingent liabilities and contingent assets
Equinor from 1 January 2023 do not have significant impact on Equinor's Consolidated financial statements upon adoption. This includes among others IFRS 17 Insurance Contracts and amendments to IAS 12 International Tax Reform – Pillar Two Model Rules (top-up tax).
IFRS Accounting Standards, amendments to IFRS Accounting Standards, and IFRIC Interpretations issued, but not yet effective, are either not expected to materially impact Equinor's Consolidated financial statements upon adoption or are not expected to be relevant. Equinor has not early adopted any IFRS Accounting Standard, amendments to IFRS Accounting Standards, or IFRIC Interpretations issued, but not yet effective.
Policy, legal, regulatory, market and technology developments related to climate change, can affect Equinor's business plans and financial performance. Shifts in stakeholder focus between energy security, affordability and sustainability add uncertainty to delivery and outcomes associated with Equinor's strategy. In its long-term planning, Equinor analyses how the global energy markets may develop, such as future changes in demand for Equinor's products (oil, gas and power in key markets). Commodity price sensitivities are presented in a table below, including the World Energy Outlook 2023 (WEO) scenarios presented by International Energy Agency (IEA), and in note 14 Impairments.
Equinor assesses climate risk from two perspectives: transition risk, which relates to the financial robustness of the company's business model and portfolio in various decarbonisation scenarios; and physical climate risk, which relates to the exposure and potential vulnerability of Equinor's assets to climate-related perils in different climate change scenarios. Equinor's net-zero strategy and climate related ambitions are responses to the challenges and opportunities presented by the energy transition. Below is a summary of relevant risks and risk adjusting actions:
| Risks – upsides and downsides | Risk adjusting actions | |
|---|---|---|
| Transition risks | • Stricter climate laws, regulations, and policies as well as adverse litigation outcomes could adversely impact Equinor's financial results and outlook, including the value of its assets. These might be direct impacts, or indirect impacts through changes in consumer behaviour or technology developments. • Changing demand and more cost-competitive solutions for renewable energy and low-carbon solutions represent both threats and opportunities for Equinor future value creation and the value of Equinor's assets. • Multiple factors in the energy transition contribute to uncertainty in future energy price assumptions and changes in investor and societal sentiment can affect Equinor's access to capital markets and financing costs. • Strong competition for assets, changing levels of policy support, and different commercial/contractual models may lead to diminishing returns within the renewable and low carbon industries and hinder Equinor ambitions. These investments may be exposed to interest rate risk and inflation risk. • Equinor sees opportunities for value creation in the energy transition both through optimisation of Equinor's oil and gas business and through utilising its competitive capabilities across new areas of the energy system. In a decarbonising world with a broad energy mix, the expectation is that policymakers and stakeholders will set a premium on oil and gas produced in a responsible and increasingly carbon efficient way. |
• Equinor monitors trends in relevant policies and regulations and addresses regulatory and policy risk in capital investment processes and through enterprise risk management in the business line. • Equinor has developed its corporate strategy and Energy transition plan (ETP) to demonstrate commitment to a low carbon business transformation that balances investor and societal expectations. • Equinor includes actual or default minimum carbon pricing across investments, applies price robustness criteria and routinely stress tests the portfolio for different future price scenarios towards net zero. Hurdle rates and other financial sensitivity testing are included in decision making. • Equinor has presented an ambitious abatement plan to reduce absolute emissions and emissions intensity from its activities. • Equinor assesses climate-related risks related to external technology development trends and invests in research, innovation and technology ventures that support positive value creation for its portfolio. Examples of relevant technologies within Equinor's portfolio include carbon capture and storage (CCS), blue/green hydrogen, battery technology, solar and wind renewable energy, low CO₂ intensity solutions, improvements in methane emissions and application of renewables in oil and gas production. |
| Physical climate risks | • Changes in physical climate parameters could impact Equinor 's operations, resulting in disruption to operations, increased costs, or incidents. This could be through extreme weather events or chronic physical impacts such as rising sea level accompanied by increased wave heights. As Equinor's renewable portfolio grows, unexpected changes in meteorological parameters, such as average wind speed or changes in wind patterns and cloud cover can affect energy production as well as factors such as maintenance and equipment lifetimes. |
• Physical climate risks are taken into account through technical and engineering functions in design, operations, and maintenance, with consideration of how the external physical environment may be changing. • With assistance from leading expert consultants and climate scenario models, Equinor continues to assess vulnerability of its assets to potential climate related changes in the physical environment. However, there is uncertainty regarding the magnitude of impact and time horizon for the occurrence of physical impacts of climate change, which leads to uncertainty regarding the potential impact for Equinor. |
Equinor's oil & gas operations in Europe are part of the EU Emission Trading System (EU ETS). Equinor buys EU ETS allowances (quotas or carbon credits) for the emissions related to its oil & gas production and processing. Currently Equinor receives a share of free quotas according to the EU ETS regulation, according to which free quotas are to be phased out by 2035.
Purchased CO₂ quotas under the EU Emissions Trading System (EU ETS) are reflected at cost in Operating expenses as incurred in line with emissions. Accruals for CO₂ quotas required to cover emissions to date are valued at market price and reflected as a current liability within Trade, other payables and provisions. Quotas owned, but exceeding the emissions incurred to date, are carried in the balance sheet at cost price, classified as Other current receivables, as long as such purchased quotas are acquired in order to cover own emissions and may be kept to cover subsequent years' emissions.
Obligations resulting from current year emissions and the corresponding amounts for quotas that have been bought, paid, and expensed, but which have not yet been surrendered to the relevant authorities, are reflected net in the balance sheet.
Total expensed CO₂ cost related to emissions and purchase of CO₂ quotas in Equinor related to activities resulting in GHG emissions (Equinor's share of the operating licences in addition to land-based facilities) amounted to USD 486 million in 2023, USD 510 million in 2022 and USD 428 million in 2021. A large portion of the cost of CO₂ is related to the purchase of EU ETS quotas. The table below shows, on a 100% operated basis, an analysis of number of quotas utilised and the related monetary amounts recognised in financial statements by Equinor's operated licences and land-based facilities subject to the requirements under EU ETS. Allocated free quotas consist of actual free quotas received in ETS during the year. The closing balance for the number of quotas consists mainly of purchased quotas for current year and remaining quotas after the settlement of current and previous year(s), including free quotas. The closing balance in USD consists mainly of the value of the remaining quotas after the preliminary allocation of the current year quotas.
| Number of EU ETS quotas in | in USD million | ||||
|---|---|---|---|---|---|
| thousands 2023 |
2022 | 2023 | 2022 | ||
| Opening balance at 1 January | 10,782 | 11,026 | 20 | 59 | |
| Allocated free quotas | 356 | 3,697 | |||
| Purchased quotas on the ETS market | 7,822 | 5,985 | 708 | 509 | |
| Sold quotas on the ETS market | 0 | 0 | |||
| Returned excess free quotas | (544) | 0 | |||
| Settled quotas (offset against emissions) | (9,840) | (9,926) | (635) | (548) | |
| Closing balance at 31 December | 8,576 | 10,782 | 93 | 20 |
All numbers in the table are presented gross (100%) for Equinor operated licenses and include both EU ETS and UK ETS quotas.
Equinor's ambition is to build a focused, carbon efficient oil and gas portfolio complemented with renewable and low-carbon solutions to create long-term value while supplying reliable energy with progressively lower emissions. 2023 saw a significant increase in the power generated from Equinor's renewable portfolio as well as substantial additions to the portfolio pipelines in renewables. However, due to inflation and supply chain constraints, Equinor recognised an impairment in the Renewables segment on the US North East Coast offshore wind projects, see note 14 Impairments for more details.
Equinor's investments in renewables are included as Additions to PP&E, intangibles and equity accounted investments in the RENsegment in note 5 Segments. See table below for details. Over the course of 2023, the acquisition of BeGreen, a commercial-scale offshore wind lease in California, Rio Energy in Brazil and investments related to projects in the US and the UK contributed to the significant increase in the book value compared to the prior year. See note 6 Acquisitions and disposals for more details.
| (in USD million) | 2023 | 2022 |
|---|---|---|
| Offshore, REN | 880 | 146 |
| Onshore, REN | 1,127 | 152 |
| Total Additions to PP&E, intangibles and equity accounted investments - REN | 2,007 | 298 |
| Low carbon solutions (within MMP) | 179 | 36 |
| Total Additions to PP&E, intangibles and equity accounted investments - REN and LCS |
2,186 | 334 |
Equinor is making significant steps to industrialise CCS and is already involved in the Northern Lights project in Norway providing CO₂ transport and storage solutions (in partnership with Shell and TotalEnergies). Equinor is also pursuing CCS projects in other regions that have the necessary frame conditions for low carbon solutions. The acquisition of a 25% stake in Bayou Bend, positions Equinor to be one of the largest US carbon capture and storage projects located along the Gulf Coast in Southeast Texas. Acquisition investments and capital contributions in these projects amounted to USD 179 million in 2023 (USD 36 million in 2022).
During 2023, Equinor invested around USD 200 million in electrification (around USD 250 million in 2022). Equinor's abatement projects primarily include full and partly electrification of offshore assets in Norway at key fields and plants, including the Troll, Oseberg, Sleipner, Njord and the Hammerfest LNG plant, mainly by power from shore. Emissions abatement milestones in 2023 included the start-up of the Hywind Tampen offshore wind supplying carbon-free power to the Gullfaks A field and the electrification of the Gina Krog field with power from shore.
Equinor is involved in several R&D projects aimed at optimizing oil and gas activities, reducing emissions, and developing new business opportunities in renewables and low carbon solutions. Equinor's total R&D activities are presented in note 9 Auditor's remuneration and Research and development expenditures (expensed R&D) and in note 12 Property, Plant & Equipment (capitalised R&D).
The effects of the initiatives to limit climate changes and the potential impact of the energy transition are relevant to some of Equinor's economic assumptions and future cash flow estimations. The resulting effects and Equinor's exposure to them are sources of uncertainty. Estimating global energy demand and commodity prices towards 2050 is challenging due to various complex factors, including technology change, taxation and production limits, which may change over time. This could lead to significant changes in accounting estimates, such as useful life (depreciation period and timing of asset retirement obligations), value-in-use (impairment assessments), and deferred tax assets (see note 11 Income taxes for expected utilisation period of tax losses carried forward and recognised as deferred tax assets).
Equinor's commodity price assumptions applied in value-in-use impairment testing are based on management's best estimate of future market trends. This price-set is currently not equal to the price-set in accordance with achieving net zero emissions by 2050 as outlined in the WEO Net Zero Emissions by 2050 scenario. Changes in how the world acts with regards to achieving the goals in the Paris agreement could have a negative impact on the valuation of Equinor's assets. Calculated possible impairments of upstream production assets and certain intangible assets using assumed prices for two scenarios estimated by the International Energy Agency (IEA) are provided in the sensitivity table below. These illustrative impairment sensitivity calculations are based on a simplified model with limitations as described in note 14 Impairments. A linear bridging was applied between current prices and the first price point in the price sets disclosed in both scenarios. USD 2 per bbl of transportation cost was added to the Brent-prices in the scenarios for comparability with management's current best estimate. The IEA scenarios primarily stress oil and gas prices, not reflecting the potential impact on Equinor's renewable and low carbon projects or trading and refinery margins. Furthermore, the MMP and REN segments represent only around 12% of Equinor's total book value of non-current segment assets and equity accounted investments, as disclosed in note 5 Segments.
The EU ETS price has increased significantly from 25 EUR/tonne in 2020 to an average cost of EU ETS allowances of 86 EUR/tonne in 2023 (81 EUR/tonne in 2022). In its commodity price assumptions Equinor projects the price to remain high, in the region of 80 EUR/tonne for the next couple of years in real 2023 terms. In 2040 the price expected to increase to around 130 EUR/tonne (109 EUR/tonne projected in 2022), thereafter increasing to around 150 EUR/tonne in 2050 (135 EUR/tonne project in 2022) in real 2023 terms. As such, Equinor expects greenhouse gas emission costs to increase from current levels and to have a wider geographical range than today, and a global tax on CO₂ emissions will have a negative impact on the valuation of Equinor's oil and gas assets. Currently, Equinor pays CO₂ fees in Norway, the UK, Germany, Canada and Nigeria. Norway's Climate Action Plan for the period 2021-2030 (Meld. St 13 (2020-2021)) which assumes a gradually increased CO₂ tax (the total of EU ETS + Norwegian CO₂ tax) in Norway to 2,000 NOK/ tonne (real 2020) in 2030 is used for impairment calculations of Norwegian upstream assets.
Equinor's responses to this risk include evaluation of carbon intensity on both project and portfolio level in investment and divestment decisions. Equinor currently uses an internal cost of carbon, set at 82 USD/tonne in 2025 and increasing to 115 USD/ tonne by 2030 and staying flat thereafter (in countries with higher carbon costs, country specific cost expectations are used). This cost-scenario is uncertain but serves as a placeholder for possible future CO₂ pricing systems, making sure the assets are financially robust.
Climate-related considerations are included directly in the impairment calculations by estimating the CO₂ taxes in the cash flows, and indirectly through estimated commodity prices related to supply and demand. The CO₂ prices also have effect on the estimated production profiles and economic cut-off of the projects. To reflect that carbon will have a cost for all Equinor's assets, the current best estimate of CO2 prices is considered to be EU ETS for countries outside EU where carbon is not already subject to taxation or where Equinor has not established specific estimates.
The table below presents some relevant prices and variables compared to management's best estimate, and an illustrative potential impairment effect given these scenarios. The scenario price-sets were retrieved from IEA's report, World Energy Outlook 2023. Prices were adjusted for inflation and presented in Real 2023. See section Profitable portfolio in Chapter 2.2. in the Integrated annual report for more details about the scenarios:
| Management's price assumptions1) | Net Zero Emissions (NZE) by 2050 | Announced Pledges Scenario (APS)5) | |
|---|---|---|---|
| Scenario4) | |||
| Brent blend, 2030 | 78 USD/bbl | 46 USD/bbl | 79 USD/bbl |
| Brent blend, 2040 | 73 USD/bbl | 37 USD/bbl | 72 USD/bbl |
| Brent blend, 2050 | 68 USD/bbl | 28 USD/bbl | 65 USD/bbl |
| TTF, 2030 | 9.1 USD/MMBtu | 4.5 USD/MMBtu | 6.8 USD/MMBtu |
| TTF, 2040 | 9.5 USD/MMBtu | 4.4 USD/MMBtu | 6.2 USD/MMBtu |
| TTF, 2050 | 9.5 USD/MMBtu | 4.3 USD/MMBtu | 5.6 USD/MMBtu |
| EU ETS 2), 3), 2030 | 123 USD/tCO2 | 146 USD/tCO2 | 141 USD/tCO2 |
| EU ETS 2), 3), 2040 | 150 USD/tCO2 | 214 USD/tCO2 | 182 USD/tCO2 |
| EU ETS 2), 3), 2050 | 176 USD/tCO2 | 261 USD/tCO2 | 208 USD/tCO2 |
| Illustrative potential impairment (USD) | ~ 10.0 billion |
~ 3.0 billion |
1) Management's future commodity price assumptions applied when estimating value in use, see note 14 Impairments.
2) Scenarios: Price of CO2 quotas in advanced economies with net zero pledges, not including any other CO2 taxes.
3) EU ETS price assumptions have been translated from EUR to USD using Equinor's assumptions for currency rates, EUR/USD = 1,176.
4) A scenario where all national energy and climate targets made by governments are met on time and in full. Using this scenario, the world is expected to
reach a 1.7ºC increase in the year 2100. 5) A scenario where the world moves on a potential path towards limiting global warming to 1.5 °C relative to pre-industrial levels.
Compared to last year's results, the illustrative potential impairments associated with the APS scenario have increased from less than USD 0.5 billion to around USD 3 billion. Similarly, the NZE scenario has increased to around USD 10 billion, compared to around USD 4 billion last year. This is significantly impacted by the linear bridging between the current commodity prices and the first price point for the WEO scenarios, consistent with previous year's methodology, but with lower current prices this year.
An increase in systematic climate risk may result in a higher discount rate applied for impairment testing purposes. Please see note 14 Impairments for further information on discount rate sensitivity.
The transition to renewable energy, technological development, and the expected reduction in global demand for carbon-based energy, may impact the future profitability of certain upstream oil and gas assets. Equinor uses scenario analysis to outline different possible energy futures, some of which imply lower oil and natural gas prices and higher CO2 tax. If this materialises, it can lead to a decrease in the cash flow from oil and gas, and potentially reduce the economic lifetime of some assets. Equinor seeks to mitigate this risk by improving the resilience of the existing upstream portfolio, maximising the efficiency of the infrastructure on the NCS and optimising the high-quality international portfolio. The project portfolio is robust to low oil and gas prices and actions are in place to maintain cost discipline across the company. Equinor will continue to add high value barrels to the portfolio through exploration and increased recovery, with the expectation to maintain strong oil and gas cash flow from operations until 2035. Equinor aims to maintain significant capex flexibility in the current portfolio, with only sanctioned projects being committed representing less than 50% of the yearly organic capex from 2025. This is expected to allow Equinor to optimise and re-prioritise non-sanctioned projects to ensure continued generation of high value through cycles. Equinor will continuously assess the current and future exposure of its portfolio and take preventative measures to manage physical climate risks.
Based on the current production profiles, approximately 65% of Equinor's proved oil and gas reserves, as defined by the SEC, are expected to be produced in the period 2024-2030 and more than 99% in the period 2024-2050. This indicates a lower risk of early cessation of production and can provide flexibility in adapting to the changing market conditions or a shift in global energy demand.
Equinor aims to continue to selectively explore for new resources with a focus on mature areas with existing infrastructure to minimise emissions and maximise value. During the transition, Equinor anticipates allocating a reducing share of its gross capex to oil and gas in the coming years and the volume of production is likely to decrease over time. Reaching Equinor's net 50% reduction ambition for operated scope 1 and 2 emissions will require a company-wide, coordinated effort to execute and mature the abatement projects, improve energy efficiency, develop new technologies, and strengthen the resilience of the portfolio. Equinor aims to achieve a 20% reduction in net carbon intensity by 2030 and a 40% reduction by 2035, including
scope 3 emissions. The combination of increased renewables and decarbonised energy, the scale up of low carbon solutions such as CCS and optimisation of the oil and gas portfolio provides confidence that Equinor can meet its medium-term ambitions. As such, Equinor's ambition to become a net-zero company by 2050 have currently not resulted in the identification of additional assets being triggered for impairment or earlier cessation.
Any future exploration may be restricted by regulations, market, and strategic considerations. Provided that the economic assumptions would deteriorate to such an extent that undeveloped assets controlled by Equinor should not materialise, assets at risk are mainly comprised of the intangible assets Oil and Gas prospects, signature bonuses and the capitalised exploration costs, with a total carrying value of USD 3,205 million in 2023 (USD 3,634 million in 2022). See note 13 Intangible assets for more information regarding Equinor's intangible assets.
As mentioned above, there are currently no assets triggered for earlier cessation as a result of Equinor's ambition to become a netzero company by 2050. However, if the business cases of Equinor's producing oil and gas assets should change materially, this could affect the timing of cessation of the assets. A shorter production period will increase the carrying value of the liability. To illustrate, performing removal five years earlier than currently scheduled would increase the liability by around USD 1.2 billion before tax (around USD 1 billion in 2022). See note 23 Provisions and other liabilities for more information regarding Equinor's ARO, including expected timing of cash outflows of recognised asset retirement obligations. The most significant cash outflows are expected within the year 2043.
Equinor's business activities naturally expose Equinor to financial risks such as market risk (including commodity price risk, currency risk, interest rate risk and equity price risk), liquidity risk and credit risk. Equinor's approach to risk management includes assessing and managing risk in activities using a holistic risk approach, by considering relevant correlations at portfolio level 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 an advisory body in Enterprise Risk Management, is responsible for Equinor's Enterprise Risk Management and for proposing appropriate measures to adjust risk at the corporate level. This includes assessing Equinor's financial risk policies.
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. Mandates in the trading organisations within crude oil, refined products, natural gas, and electricity are relatively restricted compared to the total market risk of Equinor.
Equinor's most important long-term commodity risk (crude 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. In the longer term, also power price risk is to a large extent expected to contribute to Equinor's commodity price risk portfolio. 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, power and emissions. 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), the CME group, the OTC Brent market, and crude and refined products swap markets. The term of natural gas, power, and emission 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 European Energy Exchange (EEX), NYMEX and ICE.
The table below contains the commodity price risk sensitivities of Equinor's commodity-based derivative contracts. Equinor's assets and liabilities resulting from commodity-based derivative 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 2023 and 2022 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 | At 31 December | |||
|---|---|---|---|---|
| 2023 | 2022 | |||
| (in USD million) | - 30% | + 30% | - 30% | + 30% |
| Crude oil and refined products net gains/(losses) | 442 | (442) | 666 | (666) |
| Natural gas, electricity and CO2 net gains/(losses) | 86 | (52) | (3) | 140 |
Equinor's cash flows from operating activities deriving predominantly 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.
The following currency risk sensitivity for financial instruments has been calculated, by assuming a 11% reasonable possible change in the most relevant foreign currency exchange rates that impact Equinor's financial accounts, based on balances at 31 December 2023. As of 31 December 2022, a change of 12% in the most relevant foreign currency exchange rates was viewed as a reasonable possible change. With reference to the table below, a negative figure represents a negative equity impact / loss, while a positive figure represents a positive equity impact / gain.
| Currency risk sensitivity | At 31 December 2023 | ||
|---|---|---|---|
| (in USD million) | NOK | EUR | GBP |
| Impact from an 11% strengthening of given currency vs USD on: | |||
| Shareholders equity through OCI | 1,519 | 406 | 903 |
| Shareholders equity through P&L | (413) | (418) | (92) |
| Impact from an 11% weakening of given currency vs USD on: | |||
| Shareholders equity through OCI | (1,519) | (406) | (903) |
| Shareholders equity through P&L | 413 | 418 | 92 |
| Currency risk sensitivity | At 31 December 2022 | ||
|---|---|---|---|
| (in USD million) | NOK | EUR | GBP |
| Impact from a 12% strengthening of given currency vs USD on: | |||
| Shareholders equity through OCI | 3,552 | 837 | 750 |
| Shareholders equity through P&L | (889) | (259) | (389) |
| Impact from a 12% weakening of given currency vs USD on: | |||
| Shareholders equity through OCI | (3,552) | (837) | (750) |
| Shareholders equity through P&L | 889 | 259 | 389 |
Bonds are normally issued at fixed rates in a variety of currencies (among others USD, EUR and GBP) and some of these bonds are converted to floating USD bonds by using interest rate and currency swaps. Equinor manages its interest rates exposure on its bond portfolio 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 21 Finance debt.
The following interest rate risk sensitivity has been calculated by assuming a change of 1.3 percentage points as a reasonable possible change in interest rates at the end of 2023. In 2022, a change of 1.2 percentage points in interest rates was 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 will have an estimated negative impact on net financial items in the Consolidated statement of income.
| Interest risk sensitivity | At 31 December | |
|---|---|---|
| 2023 | 2022 |
| (in USD million) | - 1.3 percentage | + 1.3 percentage | - 1.2 percentage | + 1.2 percentage |
|---|---|---|---|---|
| points | points | points | points | |
| Positive/(negative) impact on net financial items | 336 | (333) | 369 | (366) |
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 certain 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.
The following equity price risk sensitivity has been calculated, by assuming a 35% reasonable possible change in equity prices that impact Equinor's financial accounts, based on balances at 31 December 2023. At 31 December 2022, a change of 35% in equity prices was equally viewed as a reasonable possible change. The estimated gains and the estimated losses following from a change in equity prices would impact the Consolidated statement of income.
| Equity price sensitivity | At 31 December | |||||
|---|---|---|---|---|---|---|
| 2023 | 2022 | |||||
| (in USD million) | - 35% | + 35% | - 35% | + 35% | ||
| Net gains/(losses) | (552) | 552 | (450) | 450 |
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 always has sufficient funds available to cover its financial obligations.
The main cash outflows include the quarterly dividend payments and Norwegian petroleum tax payments made six times per year. Trading in collateralised commodities and financial contracts also exposes Equinor to liquidity risk related to potential collateral calls from counterparties.
If the cash flow forecasts indicate that the liquid assets will fall below target levels, new long-term funding will be considered. Equinor raises debt in all major capital markets (USA, 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 21 Finance debt.
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 6.0 billion, supported by 19 core banks, maturing in 2026. The facility supports secure access to funding, supported by the best available short-term rating. As at 31 December 2023 the facility has not been drawn upon.
The table below shows a maturity profile, based on undiscounted contractual cash flows, for Equinor's financial liabilities.
| At 31 December | ||||||||
|---|---|---|---|---|---|---|---|---|
| 2023 | 2022 | |||||||
| (in USD million) | Non-derivative financial liabilities |
Lease liabilities |
Derivative financial liabilities |
Non-derivative financial liabilities |
Lease liabilities |
Derivative financial liabilities |
||
| Year 1 | 20,209 | 1,369 | 857 | 20,172 | 1,325 | 1,065 | ||
| Year 2 and 3 | 6,035 | 1,434 | 636 | 6,292 | 1,421 | 752 | ||
| Year 4 and 5 | 5,601 | 496 | 404 | 5,785 | 504 | 486 | ||
| Year 6 to 10 | 6,846 | 405 | 1,016 | 8,749 | 465 | 1,202 | ||
| After 10 years | 10,751 | 72 | 340 | 11,204 | 120 | 706 | ||
| Total specified | 49,442 | 3,776 | 3,253 | 52,202 | 3,835 | 4,211 |
Credit risk is the risk that Equinor's customers or counterparties will cause Equinor financial loss by failing to honour their obligations. Credit risk arises from credit exposures with customer accounts receivables as well as from financial investments, derivative financial instruments and deposits with financial institutions. 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.
Prior to entering into transactions with new counterparties, Equinor's credit policy requires all counterparties where Equinor has material credit exposure 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 information. All counterparties are re-assessed regularly.
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, material exposures against limits on a daily basis. Equinor's total credit exposure 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.
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 1% overdue receivables of more than 30 days. A provision has been recognised for expected credit losses of trade and other receivables using 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 2023 | ||||
| Investment grade, rated A or above | 193 | 5,857 | 305 | 565 |
| Other investment grade | 8 | 5,132 | 7 | 565 |
| Non-investment grade or not rated | 140 | 5,204 | 247 | 248 |
| Total financial assets | 341 | 16,193 | 559 | 1,378 |
| At 31 December 2022 | ||||
| Investment grade, rated A or above | 1,633 | 6,125 | 390 | 1,715 |
| Other investment grade | 12 | 8,725 | 41 | 1,393 |
| Non-investment grade or not rated | 14 | 6,761 | 259 | 931 |
| Total financial assets | 1,659 | 21,611 | 690 | 4,039 |
For more information about Trade and other receivables, see note 18 Trade and other receivables.
The table below presents the amounts offset under the terms of various offsetting agreements for financial assets and liabilities. These agreements are mainly entered into to manage the credit risks associated with over-the-counter commodity trading as well as regular commodity purchases and sales and enable Equinor and their counterparties to set off financial liabilities against financial assets in the ordinary course of business as well as in case of default. In addition, exchange-traded commodity derivatives are offset towards collateral receipts/payments as a result of day-to-day cash settlements based on change in fair value of open derivative positions. Amounts not qualifying for offsetting consists of collateral receipts or payments which usually is settled on a gross basis. Normally these amounts will offset in a potential default situation. There exist no restrictions on collaterals received.
| (in USD million) | Gross amounts of recognised financial assets/ liabilities |
Gross amounts offset in the balance sheet |
Net amounts presented in the balance sheet |
Amounts of remaining rights to set-off not qualifying for offsetting |
Net amount |
|---|---|---|---|---|---|
| At 31 December 2023 | |||||
| Financial assets | |||||
| Trade receivables | 17,139 | 3,133 | 14,006 | 0 | 14,006 |
| Collateral receivables | 8,713 | 6,526 | 2,186 | 2,186 | 0 |
| Derivative financial instruments | 12,767 | 10,829 | 1,937 | 677 | 1,260 |
| Total financial assets | 38,619 | 20,488 | 18,129 | 2,863 | 15,266 |
| Financial liabilities | |||||
| Trade payables | 14,184 | 3,133 | 11,051 | 0 | 11,051 |
| Collateral liabilities | 7,791 | 7,333 | 458 | 458 | 0 |
| Derivative financial instruments | 13,437 | 10,023 | 3,414 | 2,405 | 1,009 |
| Total financial liabilities | 35,412 | 20,488 | 14,923 | 2,863 | 12,060 |
| (in USD million) | Gross amounts of recognised financial assets/ liabilities |
Gross amounts offset in the balance sheet |
Net amounts presented in the balance sheet |
Amounts of remaining rights to set-off not qualifying for offsetting |
Net amount |
|---|---|---|---|---|---|
| At 31 December 2022 | |||||
| Financial assets | |||||
| Trade receivables | 25,607 | 7,464 | 18,143 | 0 | 18,143 |
| Collateral receivables | 16,923 | 13,455 | 3,468 | 3,468 | 0 |
| Derivative financial instruments | 28,535 | 23,806 | 4,730 | 1,708 | 3,022 |
| 0 | |||||
| Total financial assets | 71,065 | 44,725 | 26,341 | 5,176 | 21,164 |
| Financial liabilities | |||||
| Trade payables | 19,913 | 7,464 | 12,449 | 0 | 12,449 |
| Collateral liabilities | 13,936 | 12,365 | 1,571 | 1,571 | 0 |
| Derivative financial instruments | 31,377 | 24,895 | 6,482 | 3,605 | 2,877 |
| Total financial liabilities | 65,226 | 44,725 | 20,502 | 5,176 | 15,326 |
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 (excluding uplifts for Norwegian Government ownership). Equinor's current long-term ratings are AA- with a stable outlook (including one notch uplift) and Aa2 with a stable outlook (including two notch uplift) from S&P and Moody's, respectively. In order to monitor financial robustness, a key ratio utilised by Equinor is the non-GAAP metric of "Net interest-bearing debt adjusted (ND2) to Capital employed adjusted (CE2)".
| At 31 December | ||
|---|---|---|
| (in USD million) | 2023 | 2022 |
| Net interest-bearing debt adjusted, including lease liabilities (ND1) | (5,040) | (6,750) |
| Net interest-bearing debt adjusted (ND2) | (8,610) | (10,417) |
| Capital employed adjusted, including lease liabilities (CE1) | 43,460 | 47,239 |
|---|---|---|
| Capital employed adjusted (CE2) | 39,890 | 43,571 |
| Net debt to capital employed adjusted, including lease liabilities (ND1/CE1) | (11.6%) | (14.3%) |
| Net debt to capital employed adjusted (ND2/CE2) | (21.6%) | (23.9%) |
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 2,030 million and USD 6,538 million for 2023 and 2022, 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 3,570 million and USD 3,668 million for 2023 and 2022, respectively). CE2 is defined as Equinor's total equity (including non-controlling interests) and ND2.
Equinor's operations are managed through operating segments identified on the basis of those components of Equinor that are regularly reviewed by the chief operating decision maker, Equinor's Corporate Executive Officer (CEO). The reportable segments Exploration & Production Norway (E&P Norway), Exploration & Production International (E&P International), Exploration & Production USA (E&P USA), Marketing, Midstream & Processing (MMP) and Renewables (REN) correspond to the operating segments. The operating segments Projects, Drilling & Procurement (PDP), Technology, Digital & Innovation (TDI) and Corporate staff and functions are aggregated into the reportable segment Other based on materiality. The majority of the costs in PDP and TDI is allocated to the three Exploration & Production segments, MMP and REN.
The accounting policies of the reporting segments equal those described in these Consolidated financial statements, except for the line-item Additions to PP&E, intangibles and Equity accounted investments in which movements related to changes in asset retirement obligations are excluded as well as provisions for onerous contracts which reflect only obligations towards group external parties. The measurement basis of segment profit is net operating income/(loss). Deferred tax assets, pension assets, non-current financial assets, total current assets and total liabilities are not allocated to the segments. Transactions between the segments, mainly from the sale of crude oil, gas, and related products, are performed at defined internal prices which have been derived from market prices. The transactions are eliminated upon consolidation.
The Exploration & Production operating segments are responsible for the discovery and appraisal of new resources, commercial development and safe and efficient operation of the oil and gas portfolios within their respective geographical areas: E&P Norway on the Norwegian continental shelf, E&P USA in USA and E&P International worldwide outside of E&P Norway and E&P USA.
PDP is responsible for global project development, well deliveries, and sourcing across Equinor.
TDI encompasses research, technology development, specialist advisory services, digitalisation, IT, improvement, innovation, and ventures and future business.
MMP is responsible for the marketing, trading, processing and transportation of crude oil and condensate, natural gas, NGL and refined products, and includes refinery, terminals, and processing plant operation. MMP is also managing power and emissions trading and the development of transportation solutions for natural gas, liquids, and crude oil, including pipelines, shipping, trucking and rail. In addition, MMP is in charge of low carbon solutions in Equinor.
REN is developing, exploring, investing in, and operating areas within renewable energy such as offshore wind, green hydrogen, storage solutions, and solar power.
Segment information for the years ended 31 December 2023, 2022, and 2021 are presented below. For revenues per geographical area, please see note 7 Total revenues and other income. For further information on the following items affecting the segments, please refer to the related notes: note 6 Acquisitions and disposals, note 14 Impairments, and note 26 Other commitments, contingent liabilities, and contingent assets.
| 2023 | E&P | E&P | ||||||
|---|---|---|---|---|---|---|---|---|
| (in USD million) | Norway | International | E&P USA | MMP | REN | Other | Eliminations Total group | |
| Revenues third party | 230 | 993 | 277 | 105,242 | 20 | 85 | 0 | 106,848 |
| Revenues and other income inter-segment | 37,999 | 6,009 | 4,009 | 633 | 12 | 33 | (48,695) | 0 |
| Net income/(loss) from equity accounted investments |
0 | 28 | 0 | 12 | (33) | (8) | 0 | (1) |
| Other income | 111 | 1 | 32 | 23 | 18 | 142 | 0 | 327 |
| Total revenues and other income | 38,340 | 7,032 | 4,319 | 105,908 | 17 | 253 | (48,695) | 107,174 |
| Purchases [net of inventory variation] | 0 | (70) | 0 | (95,769) | 0 | (1) | 47,665 | (48,175) |
| Operating, selling, general and | ||||||||
| administrative expenses | (3,759) | (2,176) | (1,178) | (4,916) | (462) | (201) | 893 | (11,800) |
| Depreciation and amortisation | (4,429) | (2,123) | (1,779) | (897) | (12) | (133) | 0 | (9,373) |
| Net impairment (losses)/reversals | (588) | (310) | 290 | (343) | (300) | (10) | 0 | (1,260) |
| Exploration expenses | (476) | (20) | (299) | 0 | 0 | 0 | 0 | (795) |
| Total operating expenses | (9,253) | (4,700) | (2,966) | (101,925) | (774) | (345) | 48,558 | (71,404) |
| Net operating income/(loss) | 29,087 | 2,332 | 1,353 | 3,984 | (757) | (92) | (137) | 35,770 |
| Additions to PP&E, intangibles and equity | ||||||||
| accounted investments | 5,939 | 4,376 | 1,206 | 844 | 2,007 | 128 | 0 | 14,500 |
| Balance sheet information Equity accounted investments |
3 | 0 | 0 | 783 | 1,665 | 57 | 0 | 2,508 |
| Non-current segment assets | 28,915 | 17,977 | 11,049 | 3,997 | 1,575 | 1,018 | 0 | 64,530 |
| Non-current assets not allocated to | ||||||||
| segments | 14,487 | |||||||
| Total non-current assets | 81,525 | |||||||
| Assets classified as held for sale | 0 | 1,064 | 0 | 0 | 0 | 0 | 0 | 1,064 |
| 2022 | E&P | E&P | E&P | |||||
|---|---|---|---|---|---|---|---|---|
| (in USD million) | Norway | International | USA | MMP | REN | Other | Eliminations | Total group |
| Revenues third party | 304 | 1,099 | 305 | 147,164 | 16 | 115 | 0 | 149,004 |
| Revenues and other income inter-segment | 74,631 | 6,124 | 5,217 | 527 | 0 | 55 | (86,554) | 0 |
| Net income/(loss) from equity accounted investments |
0 | 172 | 0 | 406 | 58 | (16) | 0 | 620 |
| Other income | 994 | 35 | 0 | 9 | 111 | 33 | 0 | 1,182 |
| Total revenues and other income | 75,930 | 7,431 | 5,523 | 148,105 | 185 | 187 | (86,554) | 150,806 |
| Purchases [net of inventory variation] | 0 | (116) | 0 | (139,916) | 0 | 0 | 86,227 | (53,806) |
| Operating, selling, general and administrative expenses |
(3,782) | (1,698) | (938) | (4,591) | (265) | (223) | 904 | (10,593) |
| Depreciation and amortisation | (4,986) | (1,445) | (1,422) | (881) | (4) | (142) | 0 | (8,878) |
| Net impairment (losses)/reversals | 819 | (286) | 1,060 | 895 | 0 | 0 | 0 | 2,487 |
| Exploration expenses | (366) | (638) | (201) | 0 | 0 | 0 | 0 | (1,205) |
| Total operating expenses | (8,315) | (4,183) | (1,501) | (144,493) | (269) | (365) | 87,130 | (71,995) |
| Net operating income/(loss) | 67,614 | 3,248 | 4,022 | 3,612 | (84) | (178) | 577 | 78,811 |
| Additions to PP&E, intangibles and equity accounted investments |
4,922 | 2,623 | 764 | 1,212 | 298 | 176 | 0 | 9,994 |
| Balance sheet information | ||||||||
| Equity accounted investments | 3 | 550 | 0 | 688 | 1,452 | 65 | 0 | 2,758 |
| Non-current segment assets | 28,510 | 15,868 | 11,311 | 4,619 | 316 | 1,031 | 0 | 61,656 |
| Non-current assets not allocated to segments |
15,437 | |||||||
| Total non-current assets | 79,851 | |||||||
| Assets classified as held for sale | 0 | 1,018 | 0 | 0 | 0 | 0 | 0 | 1,018 |
| 2021 | E&P | E&P | E&P | |||||
|---|---|---|---|---|---|---|---|---|
| (in USD million) | Norway | International | USA | MMP | REN | Other | Eliminations | Total group |
| Revenues third party | 261 | 1,115 | 377 | 86,883 | 8 | 99 | 0 | 88,744 |
| Revenues and other income inter-segment | 38,972 | 4,230 | 3,771 | 321 | 0 | 41 | (47,335) | 0 |
| Net income/(loss) from equity accounted investments |
0 | 214 | 0 | 22 | 16 | 7 | 0 | 259 |
| Other income | 154 | 5 | 0 | 168 | 1,386 | 208 | 0 | 1,921 |
| Total revenues and other income | 39,386 | 5,565 | 4,149 | 87,393 | 1,411 | 355 | (47,335) | 90,924 |
| Purchases [net of inventory variation] | 0 | (58) | 0 | (80,873) | 0 | (1) | 45,772 | (35,160) |
| Operating, selling, general and | ||||||||
| administrative expenses | (3,653) | (1,405) | (1,074) | (3,753) | (163) | (432) | 1,102 | (9,378) |
| Depreciation and amortisation | (6,002) | (1,734) | (1,665) | (869) | (3) | (158) | 0 | (10,432) |
| Net impairment (losses)/reversals | 1,102 | (1,587) | (69) | (735) | 0 | 2 | 0 | (1,287) |
| Exploration expenses | (363) | (451) | (190) | 0 | 0 | 0 | 0 | (1,004) |
| Total operating expenses | (8,915) | (5,237) | (2,998) | (86,230) | (166) | (590) | 46,873 | (57,261) |
| Net operating income/(loss) | 30,471 | 329 | 1,150 | 1,163 | 1,245 | (234) | (461) | 33,663 |
| Additions to PP&E, intangibles and equity | ||||||||
| accounted investments | 4,943 | 1,834 | 690 | 517 | 457 | 64 | 0 | 8,506 |
| Balance sheet information | ||||||||
| Equity accounted investments | 3 | 1,417 | 0 | 113 | 1,108 | 45 | 0 | 2,686 |
| Non-current segment assets | 36,502 | 15,422 | 11,406 | 4,006 | 157 | 1,032 | 0 | 68,527 |
| Non-current assets not allocated to segments |
13,406 | |||||||
| Total non-current assets | 84,618 | |||||||
| Assets classified as held for sale | 0 | 676 | 0 | 0 | 0 | 0 | 0 | 676 |
| At 31 December | ||
|---|---|---|
| (in USD million) | 2023 | 2022 |
| Norway | 32,977 | 33,242 |
| USA | 12,587 | 12,343 |
| Brazil | 10,871 | 9,400 |
| UK | 5,535 | 3,688 |
| Canada | 1,157 | 1,171 |
| Angola | 1,103 | 895 |
| Denmark | 973 | 497 |
| Argentina | 648 | 615 |
| Algeria | 474 | 622 |
| Poland | 447 | 270 |
| Other | 265 | 1,672 |
| Total non-current assets1) | 67,038 | 64,414 |
1) Excluding deferred tax assets, pension assets and non-current financial assets. Non-current assets are attributed to country of operations.
Business combinations, except for transactions between entities under common control, are accounted for using the acquisition method when control is transferred to the group. The purchase price includes total consideration paid to acquire the entity's assets and liabilities, as well as contingent consideration at fair value. The acquired identifiable assets, liabilities and contingent liabilities are measured at fair value at the date of the acquisition. Acquisition costs incurred are expensed under Selling, general and administrative expenses. Changes in the fair value of contingent consideration resulting from events after the acquisition date are recognised in the Consolidated statement of income under Other income.
Equinor recognises a gain or loss on disposal of a subsidiary when control is lost. Any interest retained in the former subsidiary is measured at fair value at the time of loss of control. However, when partially divesting subsidiaries that do not constitute a business, and where the retained investment in the former subsidiary is an associate or a jointly controlled investment, Equinor recognises the gain or loss only on the divested part within Other income or Operating expenses, respectively. The interest retained in the former subsidiary is initially not remeasured, and subsequently accounted for using the equity method.
On the NCS, all disposals of assets are performed including the tax base (after-tax). Any gain includes the release of tax liabilities previously recognised related to the assets in question and is recognised in full in Other income in the Consolidated statement of income.
Non-current assets are classified separately as held for sale in the Consolidated balance sheet when a sale is highly probable. This condition is met when an asset is available for immediate sale in its present condition, Equinor's management is committed to the sale, and the sale is expected to be completed within one year from the date of classification. In Equinor, these requirements are normally met when management has approved a negotiated letter of intent with the counterparties (a 'DGC'). Liabilities directly associated with the assets classified as held for sale and expected to be included as part of the sales transaction, are also classified separately.
Determining whether an acquisition meets the definition of a business combination requires judgement to be applied on a case-bycase basis. Acquisitions are assessed 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 subsequent periods. Similar assessments are performed upon the acquisition of an interest in a joint operation. Depending on the specific facts, acquisitions of oil and gas exploration and evaluation licences for which a development decision has not yet been made have largely been concluded to represent asset purchases, while purchases of producing assets have largely been concluded to represent business acquisitions.
The policy regarding partial divestments of subsidiaries is based on careful consideration of the requirements and scope of IFRS 10 Consolidated Financial Statements and IAS 28 Investments in Associates and Joint Ventures. The assessment requires judgement to be applied on a case-by-case basis, considering the substance of the transactions. In evaluating the IFRS Accounting Standards' requirements, Equinor acknowledges pending considerations related to several relevant and similar issues which have been postponed by the IASB in anticipation of concurrent consideration at a later date. Where assets are transferred into separate legal entities concurrently with a portion of the entities' shares being sold to a third party, thereby resulting in Equinor's loss of control of those asset-owning subsidiaries, and where investments in joint ventures are established simultaneously, Equinor has concluded to recognise the gain only on the divested portion.
On 3 November 2023, Equinor closed a transaction with Denham Capital to acquire 100% of the shares in Horus Investimentos S.A., the parent company of Rio Energy Participações S.A., a leading onshore renewables company in Brazil. The cash consideration amounted to USD 82 million in addition to USD 268 million in capital contribution to settle Rio Energy's external financing. The acquired portfolio includes a producing onshore wind farm in the north-eastern state of Bahia, a pre-construction solar photovoltaic (PV) portfolio and a pipeline of 1.2 GW of onshore wind and solar projects. This transaction resulted in an increase in Equinor's property, plant and equipment of USD 350 million. The transaction has been accounted for as a business combination within the REN segment. The purchase price and the purchase price allocation are preliminary.
On 30 June 2023, Equinor closed a transaction with Suncor Energy UK Holdings Ltd to acquire 100% of the shares in Suncor Energy UK Limited for a total consideration of USD 847 million after customary adjustments for working capital. The transaction includes a nonoperated interest in the producing Buzzard oil field (29.89%) and an additional interest in the operated Rosebank development (40%). The transaction has been accounted for within the E&P International segment as a business combination, resulting in an increase in Equinor's property, plant and equipment of USD 1,490 million and deferred tax liabilities of USD 672 million. The purchase price allocation remains preliminary.
On 26 January 2023, Equinor closed a transaction with the Bregentved Group and members of the executive board of BeGreen Solar Aps to acquire 100% of the shares in the Danish solar developer BeGreen Solar Aps. The cash consideration amounted to USD 252 million (EUR 235 million), in addition to a consideration contingent on the successful delivery of future solar projects above an agreed megawatt threshold. The transaction has been accounted for within the REN segment as a business combination, resulting in an increase of Equinor's intangible assets of USD 423 million.
On 31 March 2023, Equinor closed the transaction with Vermilion Energy Inc (Vermillion) to sell Equinor's non-operated equity position in the Corrib gas project in Ireland, covering 100% of the shares in Equinor Energy Ireland Limited (EEIL). Prior to closing, Equinor received an extraordinary dividend of USD 371 million from EEIL. Total consideration amounted to USD 362 million, including cash settlement of contingent consideration. A loss of USD 258 million has been recognised within the E&P International segment and presented in the line item Operating expenses in the Consolidated statement of income.
On 22 December 2023, Equinor entered into an agreement with the State Oil Company of the Republic of Azerbaijan (SOCAR) to sell its interest in its Azerbaijan assets. The assets comprise a 7.27% non-operated interest in the Azeri Chirag Gunashli (ACG) oil fields in the Azerbaijan sector of the Caspian Sea, 8.71% interest in the Baku-Tbilisi-Ceyhan (BTC) pipeline and 50% in the Karabagh oil field. Closing is expected during 2024 subject to regulatory and contractual approvals. The assets have been classified as held for sale resulting in a USD 310 million impairment within the E&P International segment, presented in the line item Depreciation, amortisation and net impairments in the Consolidated statement of income.
On 1 September 2022, Equinor and SSE Thermal Generation Holdings Limited (SSE Thermal) closed a transaction to acquire the UK power company Triton Power Holdings Ltd (Triton Power) from Triton Power Partners LP owned by Energy Capital Partners (ECP). Equinor's share of the consideration was USD 141 million (GBP 120 million), after adjustments that mainly related to net debt and working capital. The key plant included in the purchase of Triton Power is the Saltend Power Station with an installed capacity of 1.2 GW. Equinor and SSE Thermal own 50% each of Triton Power, and Equinor is accounting for the investment under the equity method as a joint venture in the MMP segment.
On 31 May 2022, Equinor closed a transaction to acquire all of Spirit Energy's ownership interests in production licences in the Statfjord area which covers the Norwegian and UK Continental Shelves ranging from 11.56% to 48.78%. All licences are operated by Equinor. The cash consideration received was USD 168 million. The assets and liabilities acquired have been reflected in accordance with the principles in IFRS 3 Business Combinations. The transaction is reflected in the E&P Norway and E&P International segments. In the segment E&P Norway, the acquisition resulted in an increase of USD 98 million in property, plant and equipment, an increase of USD 390 million in asset retirement obligation, a reduction of deferred tax liability of USD 298 million and an increase in taxes payable of USD 98 million. In the segment E&P International, the acquisition resulted in an increase of USD 98 million in property, plant and equipment, an increase of USD 241 million in asset retirement obligation and an increase of deferred tax asset of USD 86 million.
On 30 September 2022, Equinor closed a transaction with Sval Energi AS to divest Equinor's entire ownership share in the Greater Ekofisk Area including its share in Norpipe Oil AS, and a 19% ownership share in Martin Linge. The cash consideration at closing amounted to USD 293 million. Equinor retained a 51% ownership share in Martin Linge and continues as operator of the field. The disposal resulted in a decrease in property, plant and equipment of USD 1,493 million, a decrease in asset retirement obligation of USD 376 million, a decrease in deferred tax liability of USD 597 million and a decrease in taxes payable of USD 686 million. A post-tax gain of USD 655 million is presented in the line item Other income in the Consolidated statement of income in the E&P Norway segment.
Following Russia's invasion of Ukraine in February 2022, Equinor announced that it had decided to stop new investments in Russia and start the process of exiting Equinor's joint arrangements. Based on this decision, Equinor evaluated its assets in Russia and recognised net impairments of USD 1,083 million in the first quarter, of which USD 251 million was related to property, plant and equipment and intangible assets and USD 832 million was related to investments accounted for using the equity method. The impairments were net of contingent consideration from the time of acquiring the assets. The impairments were recognised in the line items Depreciation, amortisation and net impairment losses and Exploration expenses in the Consolidated statement of income based on the nature of the impaired assets and reflected in the E&P International segment. During the second quarter, Equinor transferred its participating interests in four Russian entities to Rosneft and was released from all future commitments and obligations with no material impact on the financial statements. The ownership interests in Kharyaga were transferred to the operator.
Equinor has stopped trading in Russian oil. This means that Equinor will not enter into any new trades or engage in new transport of oil and oil products from Russia. Equinor has assessed the accounting impact of certain commitments arising from such contracts entered into prior to the invasion and deem the impact to be immaterial.
On 10 February 2022, Equinor closed the transaction with Eni to sell a 10% equity interest in the Dogger Bank C project in the UK for a total consideration of USD 91 million (GBP 68 million), resulting in a gain of USD 87 million (GBP 65 million). After closing, Equinor's ownership share is 40%. Equinor continues to equity account for the remaining investment as a joint venture. The gain is presented in the line item Other income in the Consolidated statement of income in the REN segment.
Equinor presents Revenue from contracts with customers and Other revenue as a single caption, Revenues, in the Consolidated statement of income.
Revenue from the sale of crude oil, natural gas, petroleum products, power and other merchandise is recognised when a customer obtains control of those products, which for tangible products 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 as well as power, which is delivered on a continuous basis through pipelines and grid, sales are completed over time in line with the delivery of the actual physical quantities.
Sales and purchases of physical commodities are presented on a gross basis as Revenues from contracts with customers and Purchases [net of inventory variation] respectively in the Consolidated statement of income. When the contracts are deemed financial instruments or part of Equinor's trading activities, they are settled and presented on a net basis as Other revenue. Reference is made to note 28 Financial instruments and fair value measurement for a description of accounting policies regarding derivatives. 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 in which Equinor shares an interest with other companies are recognised on the basis of volumes lifted and sold to customers during the period (the sales method). Where Equinor has lifted and sold more than the ownership interest, an accrual is recognised for the cost of the overlift. Where Equinor has lifted and sold less than the ownership interest, costs are deferred for the underlift.
Certain long-term LNG and natural gas sales contracts include clauses which entail price reviews at regular intervals at the discretion of either party. Where updated prices have not yet been agreed upon for volumes already delivered, it is necessary to estimate the amount of variable consideration Equinor expects to be entitled to for these volumes. In the frequently volatile markets, there is a degree of estimation uncertainty and reasoned judgement in establishing the expected variable consideration.
Items representing a form of revenue, or which are related to 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 related to sales contracts or revenue-related risk management.
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 Norwegian State's Direct Financial Interests (SDFI). All purchases and sales of the SDFI's oil and natural gas liquids 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 SDFI's account and risk, the SDFI's production of natural gas including Liquefied Natural Gas (LNG). These gas sales and related expenditures refunded by the SDFI are presented net in the Consolidated financial statements. Natural gas sales made in the name of Equinor's 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.
Whether to account for the transactions gross or net involves the use of significant accounting judgement. 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 SDFI, Equinor purchases the crude oil volumes from the SDFI and obtains substantially all the remaining benefits. On that basis, Equinor has concluded that it acts as principal in these sales.
Regarding gas sales, 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 SDFI. On that basis, Equinor is not considered the principal in the sale of the SDFI's natural gas volumes.
Reference is made to note 27 Related parties for detailed financial information regarding transactions performed between Equinor and SDFI.
Equinor has business operations in around 30 countries. When attributing the line-item Revenues from contracts with customers for 2023 to the country of the legal entity executing the sale, Norway constitutes 79% and USA constitutes 18%. For 2022 the revenues to Norway and USA constituted 84% and 13% respectively, and for 2021 81% and 13% respectively. Revenues from contracts with customers are mainly reflecting such revenues from the reporting segment MMP.
| (in USD million) | Note | 2023 | 2022 | 2021 |
|---|---|---|---|---|
| Crude oil | 56,861 | 58,524 | 38,307 | |
| Natural gas | 26,386 | 65,232 | 28,050 | |
| - European gas | 23,174 | 58,239 | 24,900 | |
| - North American gas | 1,111 | 2,884 | 1,783 | |
| - Other incl LNG | 2,102 | 4,109 | 1,368 | |
| Refined products | 10,083 | 11,093 | 11,473 | |
| Natural gas liquids | 8,345 | 9,240 | 8,490 | |
| Transportation | 1,425 | 1,470 | 921 | |
| Other sales | 3,032 | 4,702 | 1,006 | |
| Total revenues from contracts with customers | 106,132 | 150,262 | 88,247 | |
| Taxes paid in-kind | 342 | 412 | 345 | |
| Physically settled commodity derivatives | 1,331 | (2,534) | (1,075) | |
| Gain/(loss) on commodity derivatives | (1,041) | 739 | 951 | |
| Change in fair value of trading inventory | (334) | (194) | 0 | |
| Other revenues | 418 | 319 | 276 | |
| Total other revenues | 716 | (1,258) | 497 | |
| Revenues | 106,848 | 149,004 | 88,744 | |
| Net income/(loss) from equity accounted investments | 15 | (1) | 620 | 259 |
| Other income | 6 | 327 | 1,182 | 1,921 |
| Total revenues and other income | 107,174 | 150,806 | 90,924 |
| (in USD million, except average number of employees) | 2023 | 2022 | 2021 |
|---|---|---|---|
| Salaries1) | 2,876 | 2,875 | 2,962 |
| Pension costs2) | 441 | 458 | 488 |
| Payroll tax | 511 | 433 | 414 |
| Other compensations and social costs | 375 | 324 | 288 |
| Total payroll expenses | 4,203 | 4,090 | 4,152 |
| Average number of employees3) | 22,600 | 21,500 | 21,400 |
1) Salaries include bonuses and expatriate costs in addition to base pay.
2) See note 22 Pensions.
3) Part time employees amount to 2% for 2023 and 3% for 2022 and 2021.
Total payroll expenses are accumulated in cost-pools and partially charged to partners of Equinor operated licences on an hours incurred basis.
| (in USD million)1) | 2023 | 2022 | 2021 |
|---|---|---|---|
| Current employee benefits | 10.7 | 12.9 | 12.2 |
| Post-employment benefits | 0.3 | 0.4 | 0.4 |
| Other non-current benefits | 0.0 | 0.0 | 0.0 |
| Share-based payment benefits | 0.3 | 0.2 | 0.1 |
| Total benefits | 11.3 | 13.5 | 12.7 |
1) All figures in the table are presented on accrual basis.
At 31 December 2023, 2022, and 2021 there are no loans to the members of the BoD or the CEC.
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 share 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 78 million, USD 85 million, and USD 79 million related to the 2023, 2022 and 2021 programmes, respectively. For the 2024 programme (granted in 2023), the estimated compensation expense is USD 83 million. At 31 December 2023 the amount of compensation cost yet to be expensed throughout the vesting period is USD 176 million.
See note 20 Shareholders' equity, capital distribution and earnings per share for more information about share-based compensation.
| Full year | |||
|---|---|---|---|
| (in USD million, excluding VAT) | 2023 | 2022 | 2021 |
| Audit fee | 14.9 | 11.4 | 14.4 |
| Audit related fee | 1.2 | 1.8 | 1.1 |
| Tax fee | - | - | - |
| Other service fee | - | - | - |
| Total remuneration | 16.1 | 13.2 | 15.5 |
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 0.6 million and USD 0.5 million for 2023, 2022 and 2021, respectively.
Equinor has R&D activities within exploration, subsurface, drilling and well, facilities, low carbon and renewables. R&D activities contribute to maximising and developing long-term value from Equinor's assets. R&D expenditures are partially financed by partners of Equinor operated licences.
R&D expenditures including amounts charged to partners were USD 311 million, USD 308 million and USD 291 million in 2023, 2022 and 2021, respectively. Equinor's share of the expenditures has been recognised within Total operating expenses in the Consolidated statement of income.
| Full year | |||
|---|---|---|---|
| (in USD million) | 2023 | 2022 | 2021 |
| Foreign currency exchange gains/(losses) derivative financial instruments | (1,476) | 797 | 870 |
| Other foreign currency exchange gains/(losses) | 2,328 | 1,291 | (823) |
| Net foreign currency exchange gains/(losses) | 852 | 2,088 | 47 |
| Dividends received | 218 | 93 | 39 |
| Interest income financial investments, including cash and cash equivalents | 1,468 | 398 | 38 |
| Interest income non-current financial receivables | 31 | 30 | 26 |
| Interest income other current financial assets and other financial items | 732 | 701 | 48 |
| Interest income and other financial income | 2,449 | 1,222 | 151 |
| Gains/(losses) financial investments | 123 | (394) | (348) |
| Gains/(losses) other derivative financial instruments | 351 | (1,745) | (708) |
| Interest expense bonds and bank loans and net interest on related derivatives | (1,263) | (1,029) | (896) |
| Interest expense lease liabilities | (132) | (90) | (93) |
| Capitalised borrowing costs | 468 | 382 | 334 |
| Accretion expense asset retirement obligations | (538) | (449) | (453) |
| Interest expense current financial liabilities and other financial expense | (195) | (192) | (114) |
| Interest expenses and other financial expenses | (1,660) | (1,379) | (1,223) |
| Net financial items | 2,114 | (207) | (2,080) |
Equinor's main financial items relate to assets and liabilities in the fair value through profit or loss and the amortised cost categories. For more information about financial instruments by category see note 28 Financial instruments and fair value measurement.
Foreign currency exchange gains/(losses) derivative financial instruments include fair value changes of currency derivatives related to liquidity and currency risk. Other foreign currency exchange gains/(losses) includes a fair value gain from derivatives related to noncurrent debt of USD 315 million in 2023, and a loss of USD 691 million and USD 702 million in 2022 and 2021 respectively.
Interest income financial investments, including cash and cash equivalents includes interest income related to balances at amortised cost of USD 1,410 million, USD 364 million, and USD 12 million for 2023, 2022 and 2021, respectively.
Gains/(losses) other derivative financial instruments primarily include fair value changes from interest rate related derivatives, with a gain of USD 332 million in 2023 and a loss of USD 1,760 million and USD 724 million in 2022 and 2021 respectively.
Interest expense bonds and bank loans and net interest on related derivatives includes interest expenses of USD 857 million, USD 918 million, and USD 990 million for 2023, 2022 and 2021, respectively, on financial liabilities at amortised cost. It also includes net interest on related derivatives at fair value through profit or loss, amounting to a net interest expense of USD 405 million for 2023 and USD 111 million for 2022, and a net interest income of USD 94 million for 2021.
Income tax in the Consolidated statement of income comprises current income tax and effects of changes in deferred tax positions. Income tax is recognised in the Consolidated statement of income except when it relates to items recognised in other comprehensive income (OCI).
Current tax consists of the expected tax payable for the year and any adjustment to tax payable for previous years. Uncertain tax positions and potential tax exposures are analysed individually. The outcomes of tax disputes are mostly binary in nature, and in each case the most likely amount for probable liabilities to be paid (including penalties) or assets to be received (disputed tax positions for which payment has already been made) is recognised within Current tax or Deferred tax as appropriate.
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. 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. For a deferred tax asset to be recognised based on future taxable income, convincing evidence is required, considering the existence of contracts, production of oil or gas in the near future based on volumes of expected reserves, observable prices in active markets, expected volatility of trading profits, expected foreign 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 recognised simultaneously and accounted for in line with other deferred tax items.
Equinor has adopted amendments to IAS 12 – International Tax Reform – Pillar Two Model Rules (top-up tax) with effect from 1 January 2023. Equinor has applied the mandatory exception and does not recognise or disclose information about deferred tax assets and liabilities related to Pillar Two income taxes.
The mandatory exception applies retrospectively. However, since no new legislation to implement the top-up tax was enacted or substantively enacted on 31 December 2022 in any jurisdiction in which Equinor operates, and no related deferred tax was recognised at that date, the retrospective application has no impact on the Consolidated financial statements.
Equinor incurs significant amounts of income taxes payable to various jurisdictions and may recognise 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 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 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. Climate-related matters and the transition to carbon-neutral energy-consumption globally have increased the uncertainty in determining key business assumptions used to assess the recoverability of deferred tax assets through sufficient future taxable income before tax losses expire.
| Full year | |||
|---|---|---|---|
| (in USD million) | 2023 | 2022 | 2021 |
| Current income tax expense in respect of current year | (24,028) | (52,124) | (21,271) |
| Prior period adjustments | (121) | (112) | (28) |
| Current income tax expense | (24,149) | (52,236) | (21,299) |
| Origination and reversal of temporary differences | (1,529) | (2,136) | (1,778) |
| Recognition / derecognition of previously (un)recognised deferred tax assets | (137) | 4,401 | 126 |
| Change in tax regulations | 4 | 0 | 4 |
| Prior period adjustments | (169) | 110 | (60) |
| Deferred tax income/(expense) | (1,831) | 2,375 | (1,708) |
| Income tax | (25,980) | (49,861) | (23,007) |
On 24 November 2023 the Norwegian Ministry of Finance published a draft resolution on the implementation of the OECD Pillar Two Model Rules into Norwegian legislation. The rules are introducing a global minimum tax of 15%. The proposal was sanctioned in January 2024 and the Norwegian Top Up Tax Act (No: "Suppleringsskatteloven") has entered into effect for the income year 2024. The Pillar Two rules will be applicable to the Equinor group, but Equinor's preliminary assessment is that we do not expect any significant economic impact from the rules.
| Full year | ||||
|---|---|---|---|---|
| (in USD million) | 2023 | 2022 | 2021 | |
| Income/(loss) before tax | 37,884 | 78,604 | 31,583 | |
| Calculated income tax at statutory rate1) | (8,833) | (18,168) | (7,053) | |
| Calculated Norwegian Petroleum tax2) | (17,226) | (36,952) | (17,619) | |
| Tax effect uplift3) | 160 | 259 | 914 | |
| Tax effect of permanent differences regarding divestments | 82 | 417 | 90 | |
| Tax effect of permanent differences caused by functional currency different from tax currency | 5 | 145 | 150 | |
| Tax effect of other permanent differences | 453 | 403 | 228 | |
| Recognition / derecognition of previously (un)recognised deferred tax assets4) | (137) | 4,401 | 126 | |
| Change in unrecognised deferred tax assets | (29) | (34) | 619 | |
| Change in tax regulations | 4 | 0 | 4 | |
| Prior period adjustments | (290) | (3) | (88) | |
| Other items including foreign currency effects | (169) | (327) | (378) | |
| Income tax | (25,980) | (49,861) | (23,007) | |
| Effective tax rate | 68.6 % | 63.4 % | 72.8 % |
1) The weighted average of statutory tax rates was 23.3% in 2023, 23.1% in 2022 and 22.3% in 2021. The rates are influenced by earnings composition between tax regimes with lower statutory tax rates and tax regimes with higher statutory tax rates.
2) The Norwegian petroleum income is taxable at a tax rate of 71.8% after deducting a calculated 22% corporate tax.
| (in USD million) | Tax losses carried forward |
Property, plant and equipment and intangible assets |
Asset retirement obligations |
Lease liabilities |
Pensions | Derivatives | Other | Total |
|---|---|---|---|---|---|---|---|---|
| Deferred tax assets | 8,575 | 514 | 7,816 | 1,298 | 747 | 446 | 1,495 | 20,892 |
| Deferred tax liabilities | (28) | (26,042) | 0 | (2) | (6) | 0 | (300) | (26,378) |
| Net asset/(liability) at 31 December 2023 |
8,547 | (25,528) | 7,816 | 1,296 | 741 | 446 | 1,195 | (5,485) |
| Deferred tax assets | 8,105 | 694 | 7,356 | 1,306 | 694 | 1,131 | 1,348 | 20,634 |
| Deferred tax liabilities | (28) | (23,356) | 0 | (3) | (12) | (3) | (411) | (23,813) |
| Net asset/(liability) at 31 December 2022 |
8,077 | (22,662) | 7,356 | 1,303 | 682 | 1,128 | 937 | (3,179) |
| (in USD million) | 2023 | 2022 | 2021 |
|---|---|---|---|
| Net deferred tax liability at 1 January | 3,179 | 7,655 | 6,250 |
| Charged/(credited) to the Consolidated statement of income | 1,831 | (2,375) | 1,708 |
| Charged/(credited) to Other comprehensive income | (66) | 105 | 35 |
| Acquisitions and disposals | 981 | (968) | 36 |
| Foreign currency translation effects and other effects | (440) | (1,239) | (374) |
| Net deferred tax liability at 31 December | 5,485 | 3,179 | 7,655 |
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 and reclassification to Assets held for sale, deferred taxes are presented on the Consolidated balance sheet as follows:
| At 31 December | |||
|---|---|---|---|
| (in USD million) | 2023 | 2022 | |
| Deferred tax assets | 7,936 | 8,732 | |
| Deferred tax liabilities | 13,345 | 11,996 | |
| Net deferred tax classified as held for sale | (76) | 85 |
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 2023, the deferred tax assets of USD 7,952 million were primarily recognised in the US, the UK, Norway, Angola, Canada and Brazil. Of this amount, USD 965 million was recognised in entities which have suffered a tax loss in either the current or the preceding period. The corresponding amounts for 2022, were USD 8,817 million and USD 1,953 million, respectively. The tax losses will be utilised through reversal of taxable temporary differences and future taxable income, mainly from production of oil and gas. Around 80% of the tax losses carried forward and recognised as deferred tax assets are expected to be fully utilised within 10 years.
| At 31 December | |||||
|---|---|---|---|---|---|
| 2023 | 2022 | ||||
| (in USD million) | Basis | Basis | Tax | ||
| Deductible temporary differences | 2,555 | 1,030 | 2,558 | 968 | |
| Unused tax credits | 0 | 185 | 0 | 129 | |
| Tax losses carried forward | 3,944 | 947 | 3,458 | 930 | |
| Total unrecognised deferred tax assets | 6,499 | 2,162 | 6,016 | 2,027 |
Approximately 90% of the unrecognised carry forward tax losses can be carried forward indefinitely. The majority of the unrecognised tax losses that cannot be carried forward indefinitely expire after 2027. The unrecognised tax credits expire from 2030, while 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 2023, unrecognised deferred tax assets in Angola and Canada represents USD 712 million and USD 415 million, respectively, of the total unrecognised deferred tax assets of USD 2,162 million. Similar amounts for 2022 were USD 636 million in Angola and USD 346 million in Canada of a total of USD 2,027 million. The remaining unrecognised deferred tax assets originate from several different tax jurisdictions.
Property, plant and equipment is reflected at cost, less accumulated depreciation and impairment. 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, 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 production sharing agreements (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.
Expenditure on major maintenance refits or repairs comprises the cost of replacement assets or parts of assets, inspection costs and overhaul costs. 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 (UoP) based on proved reserves expected to be recovered from the area during the concession or contract period. Depreciation of production wells uses the UoP method based on proved developed reserves, and capitalised acquisition costs of proved properties are depreciated using the UoP method based on total proved reserves. In the rare circumstances where the use of proved reserves fails to provide an appropriate basis reflecting the pattern in which the asset's future economic benefits are expected to be consumed, a more appropriate reserve estimate is used. Depreciation of other assets and transport systems used by several fields is calculated on the basis of their estimated useful lives, normally using the straight-line method. Each part of an item of property, plant and equipment with a cost that is significant in relation to the total cost of the item is depreciated separately. For exploration and production assets, 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 derecognised upon disposal. Any gain or loss arising on derecognition of the asset is included in Other income or Operating expenses, respectively, in the period the item is derecognised.
Monetary or non-monetary grants from governments, when related to property, plant and equipment and considered reasonably certain, are recognised in the Consolidated balance sheet as a deduction to the carrying value of the asset and subsequently recognised in the Consolidated statement of income over the life of the depreciable asset as a reduced depreciation expense.
Equinor undertakes research and development both on a funded basis for licence holders and on an unfunded basis for projects at its own risk, developing innovative technologies to create opportunities and enhance the value of current and future assets. Expenses relate both to in-house resources and the use of suppliers. 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 Accounting Standard requirements. Subsequent to initial recognition, any capitalised development costs are accounted for in the same manner as Property, plant and equipment. Costs not qualifying for capitalisation are expensed as incurred, see note 9 Auditor's remuneration and Research and development expenditures for more details.
Reserves quantities are, by definition, discovered, remaining, recoverable and economic. Recoverable oil and gas quantities are always uncertain. Estimating reserves is complex and based on a high degree of professional judgement involving geological and engineering assessments of in-place hydrocarbon volumes, the production, historical recovery and processing yield factors and installed plant operating capacity. The reliability of these estimates depends on both the quality and availability of the technical and economic data and the efficiency of extracting and processing the hydrocarbons.
Proved oil and gas reserves may impact the carrying amounts of oil and gas producing assets, as changes in the proved reserves, 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 proved reserves only reflect the period before
the contracts providing the right to operate expire. 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.
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. 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 based on 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). 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.
Changes in the expected oil and gas reserves may materially impact the amounts of asset retirement obligations, as a consequence of timing of the removal activities. It will also impact value-in-use calculations for oil and gas assets, possibly affecting impairment testing and the recognition of deferred tax 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. As per Equinor's internal guidelines, expected reserves are defined as the 'forward looking mean reserves' when based on a stochastic prediction approach. In some cases, a deterministic prediction method is used, in which case the expected reserves are the deterministic base case or best estimate. Expected reserves are therefore typically larger than proved reserves as defined by the SEC, which are high confidence estimates with at least a 90% probability of recovery when a probabilistic approach is used. Expected oil and gas reserves have been estimated by internal qualified professionals based on industry standards and classified in accordance with the Norwegian resource classification system issued by the Norwegian Petroleum Directorate.
| (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 1 January 2023 | 1,343 | 171,948 | 8,285 | 562 | 10,815 | 6,633 | 199,586 |
| Additions through business acquisition7) | 48 | 1,121 | 339 | 38 | 370 | 8 | 1,923 |
| Additions and transfers6) | 113 | 7,286 | 60 | 19 | 3,196 | 1,087 | 11,761 |
| Changes in asset retirement obligations | 0 | 772 | 0 | 0 | 55 | 0 | 827 |
| Disposals at cost | (64) | (3,567) | (446) | (29) | (30) | (634) | (4,771) |
| Assets reclassified to held for sale8) | (1) | (3,944) | 0 | 0 | (245) | (8) | (4,198) |
| Foreign currency translation effects | 0 | (2,705) | (133) | 1 | (64) | (36) | (2,937) |
| Cost at 31 December 2023 | 1,438 | 170,911 | 8,105 | 591 | 14,097 | 7,050 | 202,191 |
| Accumulated depreciation and impairment at 1 January 2023 |
(1,203) | (131,455) | (6,763) | (338) | (135) | (3,194) | (143,088) |
| Depreciation | (44) | (7,976) | (224) | (26) | 0 | (1,079) | (9,350) |
| Impairment | (2) | (844) | (323) | 0 | (18) | (1) | (1,188) |
| Reversal of impairment | 0 | 288 | 0 | 0 | 3 | 0 | 290 |
| Transfers6) | 1 | (11) | 0 | (1) | 10 | 0 | (2) |
| Accumulated depreciation and impairment on disposed assets Accumulated depreciation and impairment |
52 | 3,355 | 442 | 28 | 22 | 634 | 4,533 |
| assets classified as held for sale8) | 1 | 3,176 | 0 | 0 | 0 | 6 | 3,183 |
| Foreign currency translation effects | 7 | 2,142 | 88 | 0 | 3 | 10 | 2,251 |
| Accumulated depreciation and impairment at 31 December 20235) |
(1,188) | (131,325) | (6,780) | (337) | (117) | (3,623) | (143,369) |
| Carrying amount at 31 December 2023 | 250 | 39,585 | 1,325 | 254 | 13,980 | 3,427 | 58,822 |
| Estimated useful lives (years) | 3 - 20 | UoP1) | 15 - 30 | 10 - 332) | 1 - 203) |
| Machinery, equipment and |
Production plants and oil |
Refining and | |||||
|---|---|---|---|---|---|---|---|
| (in USD million) | transportation equipment |
and gas assets |
manufacturing plants |
Buildings and land |
Assets under development |
Right of use assets |
Total |
| Cost at 1 January 2022 | 1,335 | 183,358 | 8,481 | 596 | 12,614 | 5,850 | 212,234 |
| Additions and transfers6) | 52 | 9,390 | 378 | 6 | (813) | 1,319 | 10,332 |
| Changes in asset retirement obligations | 0 | (4,756) | 0 | 0 | (48) | 0 | (4,805) |
| Disposals at cost | (9) | (3,487) | 2 | (20) | (5) | (347) | (3,865) |
| Foreign currency translation effects | (36) | (12,557) | (576) | (19) | (934) | (188) | (14,310) |
| Cost at 31 December 2022 | 1,343 | 171,948 | 8,285 | 562 | 10,815 | 6,633 | 199,586 |
| Accumulated depreciation and impairment | |||||||
| at 1 January 2022 | (1,188) | (137,763) | (7,926) | (320) | (344) | (2,619) | (150,159) |
| Depreciation | (52) | (7,643) | (160) | (33) | 0 | (969) | (8,856) |
| Impairment | (8) | (187) | (39) | 0 | (49) | (4) | (286) |
| Reversal of impairment | 4 | 2,585 | 802 | 0 | 207 | 0 | 3,599 |
| Transfers6) | (2) | (20) | 2 | 0 | 20 | (8) | (8) |
| Accumulated depreciation and impairment on disposed assets |
8 | 2,002 | (4) | 5 | 0 | 347 | 2,359 |
| Foreign currency translation effects | 34 | 9,571 | 562 | 9 | 30 | 59 | 10,264 |
| Accumulated depreciation and impairment | |||||||
| at 31 December 20225) | (1,203) | (131,455) | (6,763) | (338) | (135) | (3,194) | (143,088) |
| Carrying amount at 31 December 2022 | 140 | 40,493 | 1,522 | 224 | 10,679 | 3,439 | 56,498 |
| Estimated useful lives (years) | 3 - 20 | UoP1) | 15 - 20 | 10 - 332) | 1 - 203) |
1) Depreciation according to unit of production method.
2) Land is not depreciated. Buildings include leasehold improvements.
3) Depreciation linearly over contract period.
4) Right of use assets at 31 December 2023 mainly consist of Land and buildings USD 1,038 million, Vessels USD 1,578 million and Drilling rigs USD 504 million.
5) See note 14 Impairments.
6) The carrying amount of assets transferred to Property plant and equipment from Intangible assets in 2023 and 2022 amounted to USD 1,280 million and USD 982 million, respectively.
7) For additions through business acquisition, see note 6 Acquisitions and disposals.
8) For assets reclassified to held for sale, see note 6 Acquisitions and disposals.
Intangible assets are stated at cost, less accumulated amortisation and impairment. 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, related intangible exploration and evaluation assets are reclassified to Property, plant and equipment.
Goodwill acquired in a business combination 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. 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 tax depreciation basis transferred from the seller. 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.
Other intangible assets with a finite useful life, are depreciated over their useful life using the straight-line method.
Equinor uses the successful efforts method of accounting for oil and gas exploration costs. Expenditures to acquire mineral interests in oil and gas properties, including signature bonuses, expenditures to drill and equip exploratory wells and evaluation expenditures are capitalised within Intangible assets as Exploration expenditures and Acquisition costs - oil and gas prospects. Geological and geophysical costs and other exploration and evaluation expenditures are expensed as incurred.
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. Any derecognition or impairment is classified as Exploration expenses in the Consolidated statement of income.
Capitalised exploration and evaluation expenditures related to offshore wells that find proved reserves, are transferred to Property, plant and equipment at the time of sanctioning of the development project. The timing from evaluation of a discovery until a project is sanctioned could take several years depending on the location and maturity, including existing infrastructure, of the area of discovery, whether a host government agreement is in place, the complexity of the project and the financial robustness of the project. For onshore wells where no sanction is required, the transfer 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 decided 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 disposals (farm-out arrangements) on a historical cost basis with no gain or loss recognition. Consideration from the sale of an undeveloped part of an asset reduces the carrying amount of the asset. If the consideration exceeds the carrying amount of the asset, the excess amount is reflected in the Consolidated statement of income under Other income. Equal-valued exchanges (swaps) of exploration and evaluation assets with only immaterial cash considerations are accounted for at the carrying amounts of the assets given up with no gain or loss recognition.
Exploratory wells that have found reserves, but where classification of those reserves as proved depends on whether a major capital expenditure can be justified, will remain capitalised during the evaluation phase for the findings on the exploration wells. Thereafter it will be considered a trigger for impairment evaluation of the well if no development decision is planned for the near future, and there moreover are no concrete plans for future drilling in the licence. Judgements as to whether these expenditures should remain capitalised, be derecognised or impaired in the period may materially affect the carrying values of these assets and consequently, the operating income for the period.
| Exploration | Acquisition costs - oil and |
||||
|---|---|---|---|---|---|
| (in USD million) | expenses | gas prospects | Goodwill | Other | Total |
| Cost at 1 January 2023 | 1,599 | 2,035 | 1,380 | 528 | 5,542 |
| Additions through business acquisition | 0 | 5 | 348 | 446 | 799 |
| Additions | 410 | 360 | 9 | 210 | 989 |
| Disposals at cost | 0 | 0 | (10) | (124) | (135) |
| Transfers | (961) | (319) | 4 | (4) | (1,280) |
| Expensed exploration expenditures previously capitalised | 114 | (61) | 0 | 0 | 53 |
| Foreign currency translation effects | 7 | 16 | 2 | 16 | 41 |
| Cost at 31 December 2023 | 1,169 | 2,036 | 1,733 | 1,072 | 6,010 |
| Accumulated amortisation and impairment at 31 December 20231) | (302) | (302) | |||
| Carrying amount at 31 December 2023 | 1,169 | 2,036 | 1,733 2) | 770 | 5,709 |
| Exploration | Acquisition costs - oil and |
||||
|---|---|---|---|---|---|
| (in USD million) | expenses | gas prospects | Goodwill | Other | Total |
| Cost at 1 January 2022 | 1,958 | 2,670 | 1,467 | 722 | 6,816 |
| Additions | 227 | 4 | 36 | 57 | 324 |
| Disposals at cost | (10) | (50) | 0 | 1 | (58) |
| Transfers | (227) | (516) | 0 | (239) | (982) |
| Expensed exploration expenditures previously capitalised | (283) | (59) | 0 | 0 | (342) |
| Impairment of goodwill | 0 | 0 | (3) | 0 | (3) |
| Foreign currency translation effects | (65) | (14) | (121) | (13) | (213) |
| Cost at 31 December 2022 | 1,599 | 2,035 | 1,380 | 528 | 5,542 |
| Accumulated amortisation and impairment at 31 December 20221) | (384) | (384) | |||
| Carrying amount at 31 December 2022 | 1,599 | 2,035 | 1,380 | 144 | 5,158 |
1) See note 14 Impairments.
2) Goodwill at 31 December 2023 mainly consists of technical goodwill related to business acquisitions in 2019, of which USD 533 million in the Exploration & Production Norway area and USD 440 million in the Marketing Midstream & Processing area.
The table below shows the aging of capitalised exploration expenditures.
| (in USD million) | 2023 | 2022 |
|---|---|---|
| Less than one year | 345 | 250 |
| Between one and five years | 458 | 340 |
| More than five years | 366 | 1,009 |
| Total capitalised exploration expenditures | 1,169 | 1,599 |
The table below shows the components of the exploration expenses.
| Full year | |||||
|---|---|---|---|---|---|
| (in USD million) | 2023 | 2022 | 2021 | ||
| Exploration expenditures | 1,275 | 1,087 | 1,027 | ||
| Expensed exploration expenditures previously capitalised | (53) | 342 | 171 | ||
| Capitalised exploration | (427) | (224) | (194) | ||
| Exploration expenses | 795 | 1,205 | 1,004 |
Equinor assesses individual assets or groups of assets for impairment whenever events or changes in circumstances indicate that the carrying value may not be recoverable. Assets are grouped into cash generating units (CGUs). Normally, separate CGUs are individual oil and gas fields or plants, or equity accounted investments. 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.
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. If, following evaluation, an exploratory well has not found proved reserves, the previously capitalised costs are tested for impairment. After 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.
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. When impairment testing goodwill originally recognised as an offsetting item to the computed deferred tax provision in a posttax transaction on the NCS, the remaining amount of the deferred tax provision will factor into the impairment valuation.
Impairment and reversals of impairment are presented in the Consolidated statement of income as Exploration expenses or Depreciation, amortisation and net impairment, on the basis of the nature of the impaired assets as either exploration assets (intangible exploration assets) or development and producing assets (property, plant and equipment and other intangible assets), respectively.
The recoverable amount applied in Equinor's impairment assessments is normally estimated value in use. Equinor may also apply the assets' fair value less cost of disposal as the recoverable amount when such a value is available, reasonably reliable, and based on a recent and comparable transactions.
Value in use is determined using a discounted cash flow model. The estimated future cash flows 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 forecasts. Assumptions and economic conditions in establishing the forecasts are reviewed by management on a 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 five 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.
The estimated future cash flows are adjusted for risks specific to the asset or CGU and discounted using a real post-tax discount rate which is based on Equinor's post-tax weighted average cost of capital (WACC). Country risk specific to a project is included as a monetary adjustment to the projects' cash flow. Equinor considers country risk primarily as an unsystematic risk. The cash flow is
adjusted for risk that influences the expected cash flow of a project and which is not part of the project itself. 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.
A previously recognised impairment is reversed only if there has been a change in the estimates used to determine the asset's recoverable amount since the last impairment was recognised. Previously recognised impairments of goodwill are not reversed in future periods.
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. 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 splitting one original CGU into several CGUs.
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 and discount rates, and uncertainty in asset specific factors such as reserve estimates and operational decisions impacting the production profile or activity levels. Changes in foreign currency exchange rates will also affect value in use, especially for assets on the NCS, where the functional currency is NOK. When estimating the recoverable amount, the expected cash flow approach is applied to reflect uncertainties in timing and amounts inherent in the assumptions used in the estimated future cash flows. For example, climate-related matters (see also Note 3 Climate change and energy transition) are expected to have a pervasive effect on the energy industry, affecting not only supply, demand and commodity prices, but also technology changes, increased emissionrelated levies, and other matters with mainly mid-term and long-term effects. These effects have been factored into the price assumptions used for estimating future cash flows using probability-weighted scenario analyses.
The estimated future cash flows, reflecting Equinor's, market participants' and other external sources' assumptions about the future and discounted to their present value, involve complexity. In order to establish relevant future cash flows, impairment testing requires long-term assumptions to be made concerning a number of economic factors such as future market prices, refinery margins, foreign currency exchange rates and future output, discount rates, impact of the timing of tax incentive regulations, and political and country risk among others. 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.
| Net impairments/(reversal of impairments) | |||
|---|---|---|---|
| Full year | |||
| (in USD million) | 2023 | 2022 | 2021 |
| Property, plant and equipment | 897 | (3,313) | 1,285 |
| Intangible assets | 61 | 62 | 154 |
| Equity accounted investments | 363 | 832 | 0 |
| Total net impairments/(reversals) including exploration expenses | 1,321 | (2,419) | 1,439 |
1) The intangible assets line includes Goodwill, amortizable intangible assets, and certain acquisition costs related to oil and gas prospects.
For impairment purposes, the asset's carrying amount is compared to its recoverable amount. The table below describes, per area, the Producing and development assets being impaired/(reversed), net impairment/(reversal), and the carrying amount after impairment.
| At 31 December 2023 | At 31 December 2022 | At 31 December 2021 | ||||||
|---|---|---|---|---|---|---|---|---|
| (in USD million) | Carrying amount after impairment |
Net impairment loss/ (reversal) |
Carrying amount after impairment |
Net impairment loss/ (reversal) |
Carrying amount after impairment |
Net impairment loss/ (reversal) |
||
| Exploration & Production Norway | 887 | 588 | 3,201 | (819) | 5,379 | (1,102) | ||
| Exploration & Production USA - onshore | 0 | 0 | 546 | (204) | 1,979 | 48 | ||
| Exploration & Production USA - offshore Gulf of Mexico | 1,165 | (290) | 2,691 | (882) | 798 | 18 | ||
| Europe and Asia | 0 | 310 | 1,551 | 295 | 1,566 | 1,609 | ||
| Marketing, Midstream & Processing | 949 | 343 | 1,416 | (895) | 868 | 716 | ||
| Renewables USA - offshore | 134 | 300 | 0 | 0 | 0 | 0 | ||
| Other | 112 | 10 | 30 | 0 | 20 | (7) | ||
| Total | 3,247 | 1,261 | 9,435 | (2,505) | 10,611 | 1,282 |
In 2023, the net impairment mainly relates to reduced expected reserves on a producing asset on the Norwegian Continental Shelf. 2022, the net impairment reversal was mainly caused by increased price estimates and changed gas export strategy. In 2021, the net impairment reversal was mainly due to increased price estimates and an upward reserve revision.
In 2023, there were no impairments related to exploration and production assets USA – onshore. In 2022, the impairment reversal was caused by increased gas price assumptions, while in 2021 the net impairment was caused by revision of reserves and sale of an asset.
In 2023, impairment reversals mainly relate to increased expected reserves on a producing asset. In 2022, the impairment reversal was caused by increased price assumptions and higher reserves estimates, while in 2021, the impairment was due to a negative reserve revision.
In 2023, the impairment relates to the held for sale reclassification of Azerbaijan assets at the end of the year (see note 6 Acquisitions and disposals). In 2022, the net impairment was mainly caused by the decision to exit Russia. This was to a large extent offset by a reversal on Mariner in the UK mainly due to optimisation of the production profile and higher prices, supported by a slight increase in reserves estimates. In 2021, the net impairment was mainly caused by downward reserve revisions partially offset by higher prices.
In 2023, net impairment mainly relates to expectations of stabilizing refinery margins at a lower level than the margins consumed in recent periods. In 2022 the net impairment reversal was mainly related to increased refinery margin assumptions, while in 2021, the impairment losses were caused by increased CO2 fees and – quotas on a refinery and a classification to held for sale.
In 2023, Equinor's offshore wind projects on the US North East Coast are facing increased costs due to inflation and supply chain constraints. On 12 October 2023, the New York State Public Service Commission (PSC) rejected price increase petitions related to offtake agreements from several offshore and onshore wind farm developers, including Equinor's joint ventures. As a consequence, an impairment of USD 300 million has been recognised. The recoverable amount of Equinor's investments in the offshore wind projects on the US North East Coast has been established applying a fair value approach. These investments are accounted for using the equity method.
There are inherent uncertainties in the assumptions, however the commodity price assumptions as well as currency assumptions reflect management's best estimate of the price and currency development over the life of the Group's assets based on its view of relevant current circumstances and the likely future development of such circumstances, including energy demand development, energy and climate change policies as well as the speed of the energy transition, population and economic growth, geopolitical risks, technology and cost development and other factors. Management's best estimate also takes into consideration a range of external forecasts.
Equinor has performed a thorough and broad analysis of the expected development in drivers for the different commodity markets and exchange rates. Significant uncertainty exists regarding future commodity price development due to the transition to a lower carbon economy, future supply actions by OPEC+ and other factors. Such analysis resulted in changes in the long-term price assumptions with effect from the second quarter of 2023. The main price assumptions applied in impairment and impairment reversal assessments are disclosed in the table below as price-points on price curves. Previous price-points applied from the third quarter of 2022 and up to and including the first quarter of 2023 are provided in brackets.
| Year | ||||||||
|---|---|---|---|---|---|---|---|---|
| Prices in real term 1) | 2025 | 2030 | 2040 | 2050 | ||||
| Brent Blend (USD/bbl) | 79 | (78) | 78 | (78) | 73 | (73) | 68 | (68) |
| European gas (USD/MMBtu) - TTF | 15.5 | 20.9 | 9.1 | (9.9) | 9.5 | (9.4) | 9.5 | (9.4) |
| Henry Hub (USD/MMBtu) | 3.6 | (4.2) | 4.3 | (3.9) | 4.3 | (3.9) | 4.3 | (3.9) |
| Electricity Germany (EUR/MWh) | 106 | (122) | 78 | (74) | 71 | (60) | 71 | (60) |
| EU ETS (EUR/tonne) | 90 | (84) | 105 | (84) | 128 | (111) | 150 | (137) |
1) Basis year 2023. The prices in the table are price-points on price-curves.
Climate considerations are included in the impairment calculations directly by estimating the CO2 taxes in the cash flows. Indirectly, the expected effect of climate change is also included in the estimated commodity prices where supply and demand are considered. The prices also have effect on the estimated production profiles and economic cut-off of the projects. Furthermore, climate considerations are a part of the investment decisions following Equinor's strategy and commitments to the energy transition.
Norway's Climate Action Plan for the period 2021-2030 (Meld. St 13 (2020-2021)) which assumes a gradually increased CO2 tax (the total of EU ETS + Norwegian CO2 tax) in Norway to 2,000 NOK/tonne in 2030 is used for impairment calculations of Norwegian upstream assets.
To reflect that carbon will have a cost for all our assets the current best estimate is considered to be EU ETS for countries outside EU where carbon is not already subject to taxation or where Equinor has not established specific estimates.
The long-term NOK currency exchange rates are expected to be unchanged compared to previous long-term assumptions. The NOK/USD rate from 2026 and onwards is kept at 8.50, the NOK/EUR at 10.00. The USD/GBP rate is kept at 1.35.
The base discount rate applied in value in use calculations is 5.0% real after tax. The discount rate is derived from Equinor's weighted average cost of capital. For projects, mainly within the REN segment in periods with fixed low risk income, a lower discount rate will be considered. A derived pre-tax discount rate is in the range of 24% for E&P Norway, 6% for E&P USA and 7% for MMP depending on the asset's characteristics, such as specific tax treatments, cash flow profiles, and economic life. The pre-tax rates for 2022 were 42- 102%, 6-9% and 7% respectively, in addition to 8-9% for E&P International.
Significant downward adjustments in Equinor's commodity price assumptions would result in impairment losses on certain producing and development assets, including intangible assets subject to impairment assessment, while an opposite adjustment could lead to impairment-reversals. Assuming a reasonably possible 30% decline in commodity price forecasts over the assets' lifetime could result in an illustrative impairment recognition of approximately USD 11 billion before tax effects. See note 3 Climate change and energy transition for possible effect of using the prices in a 1.5ºC compatible Net Zero Emission by 2050 scenario and the Announced Pledges.
Similarly, for illustrative purposes, Equinor assessed the sensitivity of the discount rate used in the value in use calculations for upstream producing assets and certain related intangible assets. It was determined an increase in the discount rate from 5.0% to 6% real after tax, in isolation, the impairment amount recognised could have a potential impact of USD 2 billion before tax effects.
The illustrative impairment sensitivities above are based on a simplified method, which assumes no changes to other input factors. However, Equinor notes a price reduction of 30% or those representing Net Zero Emission scenario and Announced Pledges Scenario would likely impact business plans and other factors used in estimating an asset's recoverable amount. The correlated changes reduce the stand-alone impact of the price sensitivities. Changes in such input factors would likely include a reduction in the cost level in the oil and gas industry and offsetting foreign currency effects, which has historically occurred following significant changes in commodity prices.
A joint arrangement is a contractual arrangement whereby Equinor and other parties undertake an activity subject to joint control, i.e. when decisions about the relevant activities require the unanimous consent of the parties sharing control. Such joint arrangements are classified as either joint operations or joint ventures. In determining the appropriate classification, Equinor considers the nature of products and markets of the arrangements and whether the substance of the agreements is that the parties involved have rights to substantially all the arrangement's assets and obligations for the liabilities, or whether the parties involved have rights to the net assets of the arrangement. 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.
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, Equinor uses IFRS 11 by analogy for all such unincorporated licence arrangements whether these are in scope of IFRS 11 or not. Reference is made to note 5 Segments for financial information related to Equinor's participation in joint operations within upstream activities.
Joint ventures, in which Equinor has rights to the net assets currently include the majority of Equinor's investments in the Renewables (REN) operating and reporting segment. Equinor's participation in joint arrangements that are joint ventures and 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, are classified and accounted for as equity accounted investments.
Under the equity method, the investment is carried on the Consolidated 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. Equinor also reflects its share of the investment's other comprehensive income (OCI) arisen after the acquisition. 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.
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. In case of material differences in accounting policies, adjustments are made in order to bring the accounts of the equity accounted investment in line with Equinor's accounting policies. Net income/loss from equity accounted investments is presented on a separate line as part of Total revenues and other income, as investments in and participation with significant influence in other companies engaged in energy-related business activities is considered to be part of Equinor's main operating activities.
Acquisition of ownership shares in joint ventures and other equity accounted investments in which the activity constitutes a business, are accounted for in accordance with the requirements applicable to business combinations. Please refer to note 6 Acquisitions and disposals for more details on acquisitions.
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 are reimbursed and 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.
| (in USD million) | 2023 | 2022 |
|---|---|---|
| Net investments at 1 January | 2,758 | 2,686 |
| Net income/(loss) from equity accounted investments | (1) | 620 |
| Impairment1) | (363) | (832) |
| Acquisitions and increase in capital | 926 | 337 |
| Dividend and other distributions | (286) | (210) |
| Other comprehensive income/(loss) | (10) | 384 |
| Divestments, derecognition and decrease in paid in capital2) | (517) | (22) |
| Other | 0 | (205) |
| Net investments at 31 December | 2,507 | 2,758 |
1) Mainly related to Renewable offshore wind industry in US, see also note 14 Impairments.
2) Mainly related to change in accounting treatment for Bandurria Sur (accounted for by proportionally consolidation from 1st of April 2023).
Equity accounted investments consist of several investments, none above USD 0.5 billion. None of the investments are significant on an individual basis. Voting rights correspond to ownership share.
| At 31 December | ||
|---|---|---|
| (in USD million) | 2023 | 2022 |
| Bonds | 1,863 | 1,448 |
| Listed equity securities | 1,035 | 794 |
| Non-listed equity securities | 543 | 491 |
| Financial investments | 3,441 | 2,733 |
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.
| At 31 December | ||
|---|---|---|
| (in USD million) | 2023 | 2022 |
| Interest-bearing financial receivables | 341 | 1,658 |
| Other interest-bearing receivables | 40 | 66 |
| Prepayments and other non-interest-bearing receivables | 910 | 339 |
| Prepayments and financial receivables | 1,291 | 2,063 |
Prepayments and other non-interest-bearing receivables mainly relate to commodity sales contracts with customers and lease prepayments. Interest-bearing financial receivables primarily relate to loans to employees and project financing of equity accounted companies. Other interest-bearing receivables primarily relate to financial sublease and tax receivables.
| At 31 December | ||
|---|---|---|
| (in USD million) | 2023 | 2022 |
| Time deposits | 17,846 | 12,373 |
| Interest-bearing securities | 11,378 | 17,504 |
| Financial investments | 29,224 | 29,876 |
At 31 December 2023, current financial investments include USD 458 million in 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 2022 was USD 410 million.
For information about financial instruments by category, see note 28 Financial instruments and fair value measurement.
Commodity inventories not held for trading purposes 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.
Commodity inventories held for trading purposes are measured at fair value less cost to sell (FVLCS), with subsequent changes in fair value recognised in the Consolidated statement of income as part of Revenues. These inventories are categorised within level 2 of the fair value hierarchy.
| At 31 December | ||
|---|---|---|
| (in USD million) | 2023 | 2022 |
| Crude oil | 2,051 | 2,115 |
| Petroleum products | 380 | 451 |
| Natural gas | 54 | 127 |
| Commodity inventories at the lower of cost and net realisable value | 2,485 | 2,693 |
| Natural gas held for trading purposes measured at fair value | 810 | 1,994 |
| Other | 520 | 517 |
| Total inventories | 3,814 | 5,205 |
Inventories held for trading purposes consist of natural gas storages held by Danske Commodities.
| At 31 December | ||
|---|---|---|
| (in USD million) | 2023 | 2022 |
| Trade receivables from contracts with customers1) | 10,706 | 15,213 |
| Other current receivables | 1,774 | 992 |
| Collateral receivables2) | 2,186 | 3,468 |
| Receivables from participation in joint operations and similar arrangements | 471 | 661 |
| Receivables from equity accounted associated companies and other related parties | 1,056 | 1,276 |
| Total financial trade and other receivables | 16,193 | 21,611 |
| Non-financial trade and other receivables | 740 | 841 |
| Trade and other receivables | 16,933 | 22,452 |
1) Trade receivables from contracts with customers are shown net of an immaterial provision for expected losses.
2) Mainly related to cash paid as security for a portion of Equinor's credit exposure.
For more information about the credit quality of Equinor's counterparties, see note 4 Financial risk and capital management. For currency sensitivities, see note 28 Financial instruments and fair value measurement. For further information on receivables from equity accounted associated companies and other related parties, see note 27 Related parties.
Cash and cash equivalents are accounted for at amortised cost and include cash in hand, bank deposits, and short-term highly liquid investments with original maturity of three months or less which are readily convertible to known amounts of cash and subject to insignificant risk of changes in fair value. Contractually mandatory deposits in escrow bank accounts are included as restricted cash and cash equivalents if the deposits are provided as part of the Group's operating activities and therefore are deemed as held for the purpose of meeting short‑term cash commitments, and the deposits can be released from the escrow account without undue expenses.
| At 31 December | |||
|---|---|---|---|
| (in USD million) | 2023 | 2022 | |
| Cash at bank available | 2,295 | 2,220 | |
| Time deposits | 1,337 | 836 | |
| Money market funds | 1,875 | 3,106 | |
| Interest-bearing securities | 2,563 | 3,276 | |
| Restricted cash and cash equivalents, including collateral deposits | 1,572 | 6,140 | |
| Cash and cash equivalents | 9,641 | 15,579 |
Restricted cash and cash equivalents at 31 December 2023 includes collateral deposits of USD 1,572 million related to trading activities. Correspondingly, collateral deposits at 31 December 2022 were USD 6,128 million. Collateral deposits are related to certain requirements of exchanges where Equinor is trading. The terms and conditions related to these requirements are determined by the respective exchanges.
| Number of shares |
NOK per value | NOK | USD | |
|---|---|---|---|---|
| Share capital at 1 January 2023 | 3,175,470,159 | 2.50 | 7,938,675,397.50 | 1,142,036,265 |
| Capital reduction | (172,365,554) | 2.50 | (430,913,885.00) | (41,519,325) |
| Share capital at 31 December 2023 | 3,003,104,605 | 2.50 | 7,507,761,512.50 | 1,100,516,940 |
| Number of shares |
NOK per value | Common Stock | |
|---|---|---|---|
| Authorised and issued | 3,003,104,605 | 2.50 | 7,507,761,512.50 |
| Treasury shares | |||
| Share buy-back programme | (49,486,793) | 2.50 | (123,716,982.50) |
| Employees share saving plan | (8,884,668) | 2.50 | (22,211,670.00) |
| Total outstanding shares | 2,944,733,144 | 2.50 | 7,361,832,860.00 |
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.
During 2023, dividend for the third and for the fourth quarter of 2022 and dividend for the first and second quarter of 2023 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 2023 relates to the fourth quarter of 2022 and to the first three quarters of 2023.
On 6 February 2024, the board of directors proposed to the annual general meeting on 14 May 2024 an ordinary cash dividend for the fourth quarter of 2023 of USD 0.35 per share and an extraordinary cash dividend of USD 0.35 per share. The Equinor share will trade ex-dividend 15 May 2024 on Oslo Børs and for ADR holders on New York Stock Exchange. Record date will be 16 May 2024 and payment date will be 28 May 2024.
| At 31 December | ||
|---|---|---|
| (in USD million) | 2023 | 2022 |
| Dividends declared | 10,783 | 7,549 |
| USD per share or ADS | 3.6000 | 2.4000 |
| Dividends paid | 10,906 | 5,380 |
| USD per share or ADS | 3.6000 | 1.6800 |
| NOK per share | 37.8522 | 16.4837 |
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. Treasury shares are not included in the weighted average number of ordinary shares outstanding in the calculation of Earnings per share. The remaining outstanding part of an irrevocable order to acquire shares is accrued for and classified as Trade, other payables and provisions.
The purpose of the share buy-back programme is to reduce the issued share capital of the company. All shares repurchased as part of the programme will be cancelled. According to an agreement between Equinor and the Norwegian State, the Norwegian State will participate in share buy-backs on a proportionate basis, ensuring that its ownership interest in Equinor remains unchanged at 67%.
On 6 February 2024, the board of directors decided to announce a two-year share buy-back programme for 2024-2025 of USD 10-12 billion in total, with USD 6 billion for 2024. The share buy-back programme will be subject to market outlook and balance sheet strength.
The first tranche of up to USD 1.2 billion of the 2024 share buy-back programme will commence on 8 February and end no later than 5 April 2024. The first tranche of the 2024 share buy-back programme is based on the authorisation from the annual general meeting in May 2023, valid until the next annual general meeting, but no later than 30 June 2024. Commencement of new share buy-back tranches after the first tranche in 2024 will be decided by the board of directors on a quarterly basis in line with the company's dividend policy and will be subject to existing and new board authorisations for share buy-back from the company's annual general meeting and agreement with the Norwegian State regarding share buy-back.
| Number of shares | 2023 | 2022 | |
|---|---|---|---|
| Share buy-back programme at 1 January | 42,619,172 | 13,460,292 | |
| Purchase | 63,748,254 | 56,290,671 | |
| Cancellation | (56,880,633) | (27,131,791) | |
| Share buy-back programme at 31 December | 49,486,793 | 42,619,172 |
| (in USD million) | 2023 | 2022 | |
|---|---|---|---|
| First tranche | 330 | 330 | |
| Second tranche | 550 | 440 | |
| Third tranche | 550 | 605 | |
| Fourth tranche | 550 | 605 | |
| Total open market share | 1,980 | 1,980 | |
| Norwegian state share1) | 3,705 | 1,399 | |
| Total | 5,685 | 3,380 |
1) Relates to second to fourth tranche of previous year programme and first tranche of current year programme.
Based on the authorisation from the annual general meeting on 10 May 2023, the Board of directors has, on a quarterly basis, decided on share buy-back tranches. The 2023 programme was up to USD 6 billion, including shares to be redeemed from the Norwegian State.
During 2023, four tranches of in total USD 6 billion were launched, including shares to be redeemed from the Norwegian State. The acquisition of the fourth tranche in the open market was finalised in January 2024. As of 31 December 2023, USD 410 million of the fourth tranche had been purchased in the open market, of which USD 388 million had been settled. Due to an irrevocable agreement with a third party, the remaining order of USD 162 million is accrued for and classified as Trade, other payables and provisions.
In order to maintain the Norwegian State's ownership share in Equinor, a proportionate share of the second, third and fourth tranche of the 2022 programme as well as the first tranche of the 2023 programme was redeemed and annulled after approval by the annual general meeting on 10 May 2023. The liability to the Norwegian State of USD 3.705 billion (NOK 39.071 billion) was settled in June 2023.
| Number of shares | 2023 | |
|---|---|---|
| 2022 | ||
| Share saving plan at 1 January | 10,908,717 | 12,111,104 |
| Purchase | 2,204,207 | 2,127,172 |
| Allocated to employees | (4,228,256) | (3,329,559) |
| Share saving plan at 31 December | 8,884,668 | 10,908,717 |
In 2023 and 2022 treasury shares were purchased to employees participating in the share saving plan for USD 68 million and USD 72 million, respectively. For further information, see note 8 Salaries and personnel expenses.
| (in USD million) | 2023 | 2022 |
|---|---|---|
| Basic earnings per share | ||
| Net income (loss) attributable to shareholders of the company | 11,885 | 28,746 |
| Weighted average number of ordinary shares outstanding | 3,021 | 3,174 |
| Basic earnings per share (in USD) | 3.93 | 9.06 |
| Diluted earnings per share | ||
| Net income (loss) attributable to shareholders of the company | 11,885 | 28,746 |
| Weighted average number of ordinary shares outstanding, diluted | 3,027 | 3,183 |
| Diluted earnings per share (in USD) | 3.93 | 9.03 |
Basic and diluted earnings per share amounts are calculated by dividing the Net income (loss) for the year attributable to shareholders by relevant weighted average number of ordinary shares outstanding during the year. Shares purchased to employees participating in the share saving plan is the only diluting element.
| Weighted average interest rates in %1) |
Carrying amount in USD millions at 31 December |
Fair value in USD millions at 31 December2) |
||||
|---|---|---|---|---|---|---|
| 2023 | 2022 | 2023 | 2022 | 2023 | 2022 | |
| Unsecured bonds | ||||||
| United States Dollar (USD) | 3.82 | 3.82 | 15,705 | 17,190 | 15,037 | 16,167 |
| Euro (EUR) | 1.51 | 1.42 | 6,633 | 7,465 | 6,177 | 6,782 |
| Great Britain Pound (GBP) | 6.08 | 6.08 | 1,747 | 1,652 | 2,013 | 1,836 |
| Norwegian Kroner (NOK) | 4.18 | 4.18 | 295 | 304 | 302 | 311 |
| Total unsecured bonds | 24,380 | 26,612 | 23,529 | 25,097 | ||
| Unsecured loans | ||||||
| Brazilian real (BRL) | 10.10 | - | 179 | - | 179 | - |
| Japanese Yen (JPY) | 4.30 | 4.30 | 71 | 76 | 83 | 90 |
| Total unsecured loans | 250 | 76 | 262 | 90 |
|---|---|---|---|---|
| Total | 24,630 | 26,688 | 23,791 | 25,187 |
| Non-current finance debt due within one year | 2,400 | 2,547 | 2,415 | 2,597 |
| Non-current finance debt | 22,230 | 24,141 | 21,376 | 22,590 |
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 28 Financial instruments and fair value measurement.
Unsecured bonds amounting to USD 15,705 million are denominated in USD and unsecured bonds denominated in other currencies amounting to USD 7,848 million are swapped into USD. One bond denominated in EUR amounting to USD 827 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 28 Financial instruments and fair value measurement.
Substantially all unsecured bonds 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. No new bonds were issued in 2023.
Out of Equinor's total outstanding unsecured bond portfolio, 34 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 24,076 million at the 31 December 2023 closing currency exchange rate.
For more information about the revolving credit facility, maturity profile for undiscounted cash flows and interest rate risk management, see note 4 Financial risk and capital management.
| At 31 December | ||
|---|---|---|
| (in USD million) | 2023 | 2022 |
| Year 2 and 3 | 4,683 | 4,794 |
| Year 4 and 5 | 4,511 | 4,510 |
| After 5 years | 13,035 | 14,837 |
| Total repayment of non-current finance debt | 22,230 | 24,141 |
| Weighted average maturity (years - including current portion) | 9 | 9 |
| Weighted average annual interest rate (% - including current portion) | 3.41 | 3.29 |
| At 31 December | ||
|---|---|---|
| (in USD million) | 2023 | 2022 |
| Collateral liabilities | 458 | 1,571 |
| Non-current finance debt due within one year | 2,400 | 2,547 |
| Other including US Commercial paper programme and bank overdraft | 3,138 | 241 |
| Total current finance debt | 5,996 | 4,359 |
| Weighted average interest rate (%) | 3.77 | 2.22 |
Collateral liabilities and other current liabilities mainly relate 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 1,895 million as of
31 December 2023 and USD 227 million as of 31 December 2022.
| (in USD million) | Non-current finance debt |
Current finance debt |
Financial receivable Collaterals1) |
Additional paid in capital2) |
Non controlling interest |
Dividend payable |
Lease liabilities3) |
Total |
|---|---|---|---|---|---|---|---|---|
| At 1 January 2023 | 24,140 | 4,359 | (3,468) | 3,041 | 1 | 2,808 | 3,667 | |
| Repayment of finance debt | (2,818) | (2,818) | ||||||
| Repayment of lease liabilities | (1,422) | (1,422) | ||||||
| Dividend paid | (10,906) | (10,906) | ||||||
| Share buy-back | (5,589) | (5,589) | ||||||
| Net current finance debt and other finance activities |
1,385 | 1,287 | (69) | (10) | 2,593 | |||
| Net cash flow from financing activities | (2,818) | 1,385 | 1,287 | (5,658) | (10) | (10,906) | (1,422) | (18,142) |
| Transfer to current portion | 147 | (147) | ||||||
| Effect of exchange rate changes | 321 | 44 | (5) | - | (25) | |||
| Dividend declared | 10,783 | |||||||
| Debt in RIO Energy | 437 | |||||||
| New leases | 1,379 | |||||||
| Other changes | 2 | 354 | (1) | 2,617 | 19 | (36) | (29) | |
| Net other changes | 907 | 251 | (6) | 2,617 | 19 | 10,747 | 1,325 | |
| At 31 December 2023 | 22,230 | 5,995 | (2,185) | - | 10 | 2,649 | 3,570 |
| (in USD million) | Non-current finance debt |
Current finance debt |
Financial receivable Collaterals1) |
Additional paid in capital2) |
Non controlling interest |
Dividend payable |
Lease liabilities3) |
Total |
|---|---|---|---|---|---|---|---|---|
| At 1 January 2022 | 27,404 | 5,273 | (1,577) | 6,408 | 14 | 582 | 3,562 | |
| Repayment of finance debt | (250) | (250) | ||||||
| Repayment of lease liabilities | (1,366) | (1,366) | ||||||
| Dividend paid | (5,380) | (5,380) | ||||||
| Share buy-back | (3,315) | (3,315) | ||||||
| Net current finance debt and other finance activities |
- | (2,982) | (2,038) | (73) | (8) | (5,102) | ||
| Net cash flow from financing activities | (250) | (2,982) | (2,038) | (3,388) | (8) | (5,380) | (1,366) | (15,414) |
| Transfer to current portion | (2,297) | 2,297 | ||||||
| Effect of exchange rate changes | (710) | (78) | 145 | (3) | (149) | |||
| Dividend declared | 7,549 | |||||||
| New leases | 1,644 | |||||||
| Other changes | (7) | (151) | 21 | (2) | 57 | (24) |
| Net other changes | (3,014) | 2,068 | 145 | 21 | (5) | 7,606 | 1,471 |
|---|---|---|---|---|---|---|---|
| At 31 December 2022 | 24,140 | 4,359 | (3,468) | 3,041 | 1 | 2,808 | 3,667 |
1) Financial receivable collaterals are included in Trade and other receivables in the Consolidated balance sheet. See note 18 Trade and other receivables for more information.
2) Other changes in additional paid in capital have been moved to retained earnings.
3) See note 25 Leases for more information.
Accounting policies
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 is recognised as liabilities in the Consolidated balance sheet as sufficient information is considered available, and a reliable estimate of the obligation can be made.
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. Equinor's net obligation from 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 recognition of a net surplus for the funded plan is based on the assumption that the net assets represent a future value for Equinor, either as a possible distribution to premium fund which can be used for future funding of new liabilities, or as disbursement of equity in the pension fund.
Contributions to defined contribution schemes are recognised in the Consolidated statement of income as pension costs 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 Consolidated statement of income as periodic pension cost, while changes in fair value of the employees' notional assets are reflected in the Consolidated statement of income under Net financial items.
Periodic pension cost is accumulated in cost pools and allocated to business areas and Equinor's operated joint operations (licences) on an hours' incurred basis and recognised in the Consolidated statement of income based on the function of the cost.
------------------------------------------------------------------------------------------------------------------------------------ Pension plans in Equinor
The main pension plans for Equinor ASA and its most significant subsidiaries are defined contribution plans which includes certain unfunded elements (notional contribution plans). In addition, several employees and former employees of the Equinor Group is a member of certain defined benefit plans. The benefit plan in Equinor ASA was closed in 2015 for new employees and for employees with more than 15 years 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 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. In this note pension costs are presented 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.
Equinor is also 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.
Total pension costs amount to USD 441 million in 2023, USD 458 million in 2022 and USD 488 million in 2021. In addition, interest cost and interest income related to defined benefit plans are included in the Consolidated statement of income within Net financial items.
| Changes in pension liabilities and plan assets during the year | ||
|---|---|---|
| (in USD million) | 2023 | 2022 |
| Pension liabilities at 1 January | 7,664 | 9,358 |
| Current service cost | 145 | 183 |
| Interest cost | 318 | 105 |
| Actuarial (gains)/losses and currency effects | 338 | (1,785) |
| Changes in notional contribution liability and other effects | 56 | 67 |
| Benefits paid | (284) | (258) |
| Losses/(gains) from curtailment, settlement or plan amendment | 91 | (5) |
| Pension liabilities at 31 December | 8,328 | 7,664 |
| Fair value of plan assets at 1 January | 5,213 | 6,404 |
| Interest income | 190 | 116 |
| Return on plan assets (excluding interest income) | 202 | (622) |
| Company contributions | 211 | 104 |
| Benefits paid | (141) | (121) |
| Losses (gains) from curtailment, settlement or plan amendment | 113 | (5) |
| Other effects | - | 6 |
| Foreign currency translation effects | (124) | (669) |
| Fair value of plan assets at 31 December | 5,664 | 5,213 |
| Net pension liability at 31 December | 2,665 | 2,452 |
| Represented by: | ||
| Asset recognised as non-current pension assets (funded plan) | 1,260 | 1,219 |
| Liability recognised as non-current pension liabilities (unfunded plans) | 3,925 | 3,671 |
| Pension liabilities specified by funded and unfunded pension plans | 8,328 | 7,664 |
| Funded | 4,404 | 3,994 |
| Unfunded | 3,925 | 3,670 |
Equinor recognised an actuarial loss from changes in financial assumptions in 2023. No changes in interest rate compared to year end 2022, but other assumptions increased with 50 basis points. An actuarial gain was recognised in 2022.
Actuarial assumptions
| Assumptions used to determine benefit obligations in % |
||||
|---|---|---|---|---|
| Rounded to the nearest quartile | 2023 | 2022 | ||
| Discount rate | 3.75 | 3.75 | ||
| Rate of compensation increase | 4.00 | 3.50 | ||
| Expected rate of pension increase | 3.25 | 2.75 | ||
| Expected increase of social security base amount (G-amount) | 3.75 | 3.25 | ||
| Weighted-average duration of the defined benefit obligation | 13.25 | 13.50 |
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.
The table below presents an estimate of the potential effects of changes in discount rate and expected rate of pension increase for the defined benefit plans. The following estimates are based on facts and circumstances as of 31 December 2023.
| Discount rate | Expected rate of pension increase |
|||
|---|---|---|---|---|
| (in USD million) | 0.50% | -0.50% | 0.50% | -0.50% |
| Effect on: | ||||
| Defined benefit obligation at 31 December 2023 | (521) | 587 | 494 | (451) |
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.
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 2023. The portfolio weight during a year will depend on the risk capacity.
| (in %) | 2023 | 2022 | Target portfolio weight |
|---|---|---|---|
| Equity securities | 33.6 | 32.9 | 30-38 |
| Interest bearing investments | 61.7 | 60.5 | 52-65 |
| Real estate | 4.7 | 6.6 | 5-10 |
| Total | 100.0 | 100.0 |
In 2023, 100% of the equity securities and 13% of bonds had quoted market prices in an active market. 87% 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 2022, 44% of the equity securities and 3% of bonds had quoted market prices in an active market. 54% of the equity securities, 97% of bonds and 100% of money market instruments had market prices based on inputs other than quoted prices.
For definition of the various levels, see note 28 Financial instruments and fair value measurement.
Estimated company contributions to be made to Equinor Pension in 2024 is approximately USD 109 million.
Provisions for asset retirement obligations (ARO) 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. Normally an obligation arises for a new facility, such as an oil and natural gas production or transportation facility, upon construction or installation. An obligation may also 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 amount recognised is the present value of the estimated future expenditures determined in accordance with local conditions and requirements. The 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 market-based risk-free rate based on the applicable currency and time horizon of the underlying cash flows. The provisions are classified under Provisions in the Consolidated balance sheet.
When a provision for ARO is recognised, a corresponding amount is recognised as an increase of the related asset within property, plant and equipment and is subsequently depreciated over the useful life of the asset. Any change in the present value of the estimated expenditure is reflected as an adjustment to the provision and the corresponding adjustment to the carrying value of the property, plant and equipment. When a decrease in the ARO 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 in the Consolidated statement of income. When an asset has reached the end of its useful life, all subsequent changes to the ARO 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.
Establishing the appropriate estimates for such obligations are based on historical knowledge combined with knowledge of ongoing technological developments, expectations about future regulatory and technological development and involve the application of judgement and an inherent risk of significant adjustments. The costs of 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 speed of the transition to renewable energy sources may also influence the production period, hence the timing of the removal activities. The estimates include assumptions of norms, rates and time required which can vary considerably depending on the assumed removal complexity. Moreover, changes in the discount rate and foreign currency exchange rates may impact the estimates significantly. As a result, the initial recognition of ARO and subsequent adjustments involve the application of significant judgement.
| Asset retirement | Other provisions and |
||
|---|---|---|---|
| (in USD million) | obligations | liabilities | Total |
| Non-current portion at 31 December 2022 | 11,569 | 4,064 | 15,633 |
| Current portion at 31 December 2022 reported as Trade, other payables and provisions |
165 | 494 | 659 |
| Provisions and other liabilities at 31 December 2022 | 11,734 | 4,558 | 16,292 |
| New or increased provisions and other liabilities | 488 | 443 | 931 |
| Change in estimates | 845 | 25 | 870 |
| Amounts charged against provisions and other liabilities | (126) | (301) | (427) |
| Effects of change in the discount rate | (276) | 13 | (263) |
| Reduction due to divestments | (403) | 97 | (306) |
| Accretion expenses | 462 | 76 | 538 |
| Reclassification, transfer and other | (174) | (1,387) | (1,561) |
| Foreign currency translation effects | (190) | 62 | (128) |
| Provisions and other liabilities at 31 December 2023 | 12,360 | 3,586 | 15,946 |
| Non-current portion at 31 December 2023 | 12,171 | 3,133 | 15,304 |
| Current portion at 31 December 2023 reported as Trade, other payables and provisions |
190 | 452 | 642 |
Equinor's estimated asset retirement obligations (ARO) have increased by USD 626 million to USD 12,360 million at 31 December 2023 compared to year-end 2022. Changes in ARO are reflected within Property, plant and equipment and Provisions and other liabilities in the Consolidated balance sheet.
In certain production sharing agreements (PSA), Equinor's estimated share of asset retirement obligation (ARO) is paid into an escrow account over the producing life of the field. These payments are considered down-payments of the liabilities and included in the line item Amounts charged against provisions and other liabilities.
Claims and litigations mainly relate 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. For further information on provisions and contingent liabilities, see note 26 Other commitments, contingent liabilities and contingent assets.
The timing of cash outflows of asset retirement obligations depends on the expected cease of production at the various facilities.
Line item Reclassification, transfer and other includes USD 1,388 million related to SDFI liability. See note 27 Related parties for further details.
The discount rate sensitivity has been calculated by assuming a reasonably possible change of 1.3 percentage points. An increase in the discount rate of 1.3 percentage points would reduce the ARO liability by USD 1,994 million. A corresponding reduction would increase the liability by USD 2,507 million. See note 3 Climate change and energy transition for sensitivity with regards to change in the removal year.
| (in USD million) | Asset retirement obligations |
Other provisions and liabilities |
Total |
|---|---|---|---|
| 2024 - 2028 | 1,512 | 2,580 | 4,092 |
| 2029 - 2033 | 997 | 342 | 1,339 |
| 2034 - 2038 | 2,605 | 134 | 2,739 |
| 2039 - 2043 | 4,610 | (42) | 4,568 |
| Thereafter | 2,636 | 572 | 3,208 |
| At 31 December 2023 | 12,360 | 3,586 | 15,946 |
| At 31 December | ||
|---|---|---|
| (in USD million) | 2023 | 2022 |
| Trade payables | 5,317 | 6,207 |
| Non-trade payables and accrued expenses | 2,210 | 2,688 |
| Payables due to participation in joint operations and similar arrangements | 2,283 | 2,074 |
| Payables to equity accounted associated companies and other related parties | 1,242 | 1,479 |
| Total financial trade and other payables | 11,052 | 12,449 |
| Current portion of provisions and other non-financial payables | 819 | 903 |
| Trade, other payables and provisions | 11,870 | 13,352 |
Included in Current portion of provisions and other non-financial payables are certain provisions that are further described in note 23 Provisions and other liabilities and in note 26 Other commitments, contingent liabilities and contingent assets. For information
regarding currency sensitivities, see note 28 Financial instruments and fair value measurement. For further information on payables to equity accounted associated companies and other related parties, see note 27 Related parties.
A lease is defined as a contract that conveys the right to control the use of an identified asset for a period of time in exchange for consideration. At the date at which the underlying asset is made available for Equinor, the present value of future lease payments (including extension options considered reasonably certain to be exercised) is recognised as a lease liability. The present value is calculated using Equinor's incremental borrowing rate. A corresponding right-of-use (RoU) asset is recognised, including lease payments and direct costs incurred at the commencement date. 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.
Short term leases (12 months or less) and leases of low value assets are expensed or (if appropriate) capitalised as incurred, depending on the activity in which the leased asset is used.
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. Non-lease components within lease contracts are 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.
In the oil and gas industry, where activity frequently is carried out through joint arrangements or similar arrangements, the application of IFRS 16 Leases requires evaluations of whether the joint arrangement or its operator is the lessee in each lease agreement and consequently whether such contracts should be reflected gross (100%) in the operator's financial statements, or according to each joint operation partner's proportionate share of the lease.
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 as 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. Where all partners in a licence are considered to share the primary responsibility for lease payments under a contract, Equinor's proportionate share of the related lease liability and RoU asset will be recognised net by Equinor. When Equinor is considered to have the primary responsibility for the full external lease payments, the lease liability is recognised gross (100%).
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.
| (in USD million) | 2023 | 2022 | ||
|---|---|---|---|---|
| Lease liabilities at 1 January | 3,667 | 3,562 | ||
| New leases, including remeasurements and cancellations | 1,379 | 1,644 | ||
| Gross lease payments | (1,590) | (1,484) | ||
| Lease interest | 138 | 95 | ||
| Lease repayments | (1,451) | (1,451) | (1,389) | (1,389) |
| Foreign currency translation effects | (25) | (149) |
| Lease liabilities at 31 December | 3,570 | 3,667 |
|---|---|---|
| Current lease liabilities | 1,279 | 1,258 |
| Non-current lease liabilities | 2,291 | 2,409 |
Equinor recognised revenues of USD 337 million in 2023 and USD 319 million in 2022 related to lease costs recovered from licence partners related to lease contracts being recognised gross by Equinor.
Commitments relating to lease contracts which had not yet commenced at year-end are included within Other commitments in note 26 Other commitments, contingent liabilities and contingent assets.
A maturity profile based on undiscounted contractual cash flows for lease liabilities is disclosed in note 4 Financial risk and capital management.
| At 31 December | |||
|---|---|---|---|
| (in USD million) | 2023 | 2022 | |
| Year 2 and 3 | 1,342 | 1,360 | |
| Year 4 and 5 | 470 | 483 | |
| After 5 years | 478 | 566 | |
| Total repayment of non-current lease liabilities | 2,291 | 2,409 |
The Right of use assets are included within the line item Property, plant and equipment in the Consolidated balance sheet. See also note 12 Property, plant and equipment.
Equinor's global business activities are subject to taxation on income and indirect taxes in various jurisdictions around the world. In these jurisdictions, governments can respond to global or local development, including climate related matters and public fiscal balances, by issuing new laws or other regulations stipulating changes in income tax, value added tax, tax on emissions, customs duties or other levies which may affect profitability and even the viability of Equinor's business in that jurisdiction. Equinor mitigates this risk by using local legal representatives and staying up to date with the legislation in the jurisdictions where activities are carried out. Occasionally, legal disputes arise from difference in interpretations. Equinor's legal department, together with local legal representatives, estimate the outcome from such legal disputes based on first-hand knowledge. Such estimates may differ from the actual results.
Contractual commitments Equinor had contractual commitments of USD 11,259 million as of 31 December 2023. 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. It also includes Equinors' estimated expenditures related to commitments to drill a certain number of wells, commitments which sometimes can be a prerequisite to be awarded oil and gas exploration and production licences.
At the end of 2023, Equinor was committed to participate in 34 wells, with an average ownership interest of approximately 46%. Equinor's share of estimated expenditures to drill these wells amounts to USD 609 million. Additional wells that Equinor may become committed to participating in depending on future discoveries in certain licences are not included in these numbers.
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 2060.
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 also includes USD 3,600 million as the non-lease components of lease agreements reflected in the accounts according to IFRS 16, as well as leases not yet commenced. For commenced leases, please refer to note 25 Leases.
Nominal minimum other long-term commitments at 31 December 2023:
| (in USD million) | |
|---|---|
| 2024 | 2,659 |
| 2025 | 1,972 |
| 2026 | 1,615 |
| 2027 | 1,187 |
| 2028 | 1,010 |
| Thereafter | 6,775 |
| Total other long-term commitments | 15,218 |
Equinor has guaranteed for its proportionate share of some of our associates' long-term bank debt, payment obligations under contracts, and certain third-party obligations. The total amount guaranteed at year-end 2023 is USD 1,564 million. The book value of the guarantees is immaterial.
Petrofac International (UAE) LLC ("PIUL") was awarded the EPC Contract to execute the ISSF Project (the In Salah Southern Fields Project in central Algeria). Following a suspension of activity in 2013, PIUL issued multiple Variation Order Requests ("VoRs") related to the costs incurred for stand-by and remobilization costs. Several VoRs have been paid, but the settlement of the remaining has been unsuccessful. PIUL initiated arbitration in August 2020 claiming an estimated amount of USD 533 million, of which Equinor holds a 31.85% share. Equinor's maximum exposure amounts to USD 163 million. Equinor has provided for its best estimate in the matter.
Remittances made from Brazil for services are normally subject to withholding income tax. In 2012, Equinor's subsidiaries in Brazil filed a lawsuit to avoid paying this tax on remittances made to Equinor ASA and Equinor Energy AS under the Double Tax Treaty Brazil has with Norway. The lawsuit relates to services without transfer of technology on fields where Equinor is a partner. Court proceedings through several levels in the legal system have been ongoing, and a final verdict has not yet been reached. Withholding tax has not been paid since 2014. Equinor's share of maximum exposure in the case at year end 2023 is estimated at approximately USD 159 million. Although Equinor continues to be of the view that all applicable tax regulations have been applied in the case, recent developments in similar litigation in Brazil have led to an updated evaluation of the likelihood of loss, and Equinor has provided for the best estimate in the case as income tax expense.
In March 2017, an individual connected to the Union of Oil Workers 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. In February 2022, sentence in the annulment case was issued at the first instance level, and Equinor won on all merits. The case was appealed by the plaintiff and Equinor has filed counter arguments. At the end of 2023, the acquired interest remains on Equinor's balance sheet, where the assets related to phase 1 have been reclassified to property, plant and equipment and the assets related to phase 2 are presented as intangible assets, all of which are part of the Exploration & Production International (E&P International) segment.
Equinor is currently part in two legal matters in the state of Rio de Janeiro in Brazil related to a law requiring taxpayers that benefits from ICMS tax incentives (i.e. Repetro) to deposit 10% of the savings made from such benefits into a state fund. Equinor is of the opinion that specific incentives so far relevant for the Roncador and Peregrino fields are not in scope of the law, while the state of Rio de Janeiro requires deposits to be paid with the addition of fines and interest. While legal developments in 2023 have included clarification from the Supreme Court that the law is constitutional, subject to a final ruling, Equinor's litigation in the matter continues, mainly related to the law's impact specifically for Repetro and other state tax incentives. Equinor believes that our view in the matter will ultimately be upheld by the courts, and no amounts have consequently been provided for in the financial statements. At year-end 2023, the maximum exposure for Equinor in the matter has been estimated to be a total of USD 114 million.
Canadian tax authorities have issued a notice of reassessment for 2014 for Equinor's Canadian subsidiary which was party to Equinor's divestment of 40% of the KKD Oil Sands partnership at that time. The reassessment adjusts the allocation of the proceeds of disposition of certain Canadian resource properties from the partnership. Maximum exposure is estimated to be approximately USD 380 million. Following an administrative appeal process with Canadian tax authorities, Equinor commenced court proceedings in the matter in 2023. While the court process may take several years, the reassessment will impact Equinor's tax paying position while the proceedings are ongoing. Equinor is of the view that all applicable tax regulations have been applied in the case and that Equinor has a strong position. No amounts have consequently been provided for in the financial statements.
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 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 23 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.
The Norwegian State is the majority shareholder of Equinor and also holds major investments in other Norwegian companies. As of 31 December 2023, the Norwegian State had an ownership interest in Equinor of 67.0% (excluding Folketrygdfondet, the Norwegian national insurance fund, of 3.6%). 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.
For accounting policies and accounting judgement related to transactions with the Norwegian State, see note 7 Total revenues and other income. Total purchases of oil and natural gas liquids from the Norwegian State amounted to USD 10.1 billion, USD 12.6 billion and USD 9.6 billion in 2023, 2022 and 2021, respectively. Payables to equity accounted associated companies and other related parties specified in note 24 Trade and other payables are mostly related to these purchases, and is included in the below table within Trade, other payables and provisions. In addition, Equinor sells in its own name, but for the Norwegian State's account and risk, the Norwegian State's gas production.
Trade and other receivables include a receivable from the Norwegian State under the Marketing Instruction in relation to the state's (SDFI) participation in the gas sales activities of a foreign subsidiary of Equinor, estimated at USD 0.1 billion. At year-end 2022, the corresponding estimated amount of USD 1.5 billion was classified as a non-current item and included within Prepayments and financial receivables. The decrease is mainly related to reduced cost price for gas storage volume and realised gains in the period. A corresponding non-current liability of USD 0.1 billion has been recognised, representing SDFI's estimated interest in the gas sales activities in the foreign subsidiary, and is included within Provisions and other liabilities in the below table. The estimated total noncurrent liabilities to SDFI amount to USD 0.8 billion at 31 December 2023 (USD 2.1 billion at year end 2022).
In addition, the line-item Finance debt, which form part of the sub-total Total current liabilities, includes a liability of USD 0.9 billion to SDFI due to cash received for collateral deposits requirement (0 at year end 2022).
Transactions with the Norwegian State related to Equinor's share buy-back programme are presented in note 20 Shareholders' equity, capital distribution and earnings per share.
In 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.
Gassled and certain other infrastructure assets are operated by Gassco AS, which is an entity under common control by the Norwegian Ministry of 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 1.0 billion in 2023, USD 1.2 billion and USD 1.0 billion in 2022 and 2021 respectively. The stated amounts represent Equinor's capacity payment net of Equinor's own ownership interests in Gassco operated infrastructure. In addition, Equinor manages, 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.
Equinor has had transactions with other associated companies and joint ventures in the course of its ordinary business, for which amounts have not been disclosed due to materiality. In addition, Equinor has had transactions with joint operations and similar arrangements where Equinor is operator. Indirect operating expenses incurred as operator are charged to the joint operation or similar arrangement based on the "no-gain/no-loss" principle.
Related party transactions with management are presented in note 8 Salaries and personnel expenses. Related party transactions due to Equinor's share buy-back programme are presented in note 20 Shareholders' equity, capital distribution and earnings per share. Outstanding balances to related parties split on SDFI and other related parties are presented in the below table. All related party transactions are carried out on market terms.
| At 31 December 2023 (in USD million) |
Norwegian State's Direct Financial Interests |
Equity accounted associated companies and other related parties |
Third parties | Total amount |
|---|---|---|---|---|
| Assets | ||||
| Prepayments and financial receivables | - | 103 | 1,188 | 1,291 |
| Trade and other receivables | 1,007 | 49 | 15,877 | 16,933 |
| Liabilities | ||||
| Non-current provisions and other liabilities | 850 | - | 14,454 | 15,304 |
| Trade, other payables and provisions | 1,195 | 47 | 10,628 | 11,870 |
| Current finance debt | 893 | - | 5,103 | 5,996 |
| At 31 December 2022 (in USD million) |
Norwegian State's Direct Financial Interests |
Equity accounted associated companies and other related parties |
Third parties | Total amount |
|---|---|---|---|---|
| Assets | ||||
| Prepayments and financial receivables | 1,461 | 61 | 541 | 2,063 |
| Trade and other receivables | 1,103 | 173 | 21,176 | 22,452 |
| Liabilities | ||||
| Non-current provisions and other liabilities | 2,072 | - | 13,561 | 15,633 |
| Trade, other payables and provisions | 1,419 | 60 | 11,873 | 13,352 |
| Current finance debt | - | - | 4,359 | 4,359 |
Financial assets are initially recognised at fair value when Equinor becomes a party to the contractual provisions of the asset.
Short-term highly liquid investments with original maturity exceeding 3 months are classified as current financial investments. Current financial investments are primarily accounted for at amortised cost.
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.
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.
Gains and losses arising on the sale, settlement or cancellation of financial assets are recognised within Net financial items.
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 is either as financial liabilities at fair value through profit or loss or financial liabilities measured at amortised cost using the effective interest method, depending on classification. The latter applies to Equinor's noncurrent bank loans and bonds.
Financial liabilities are presented as current if the liability is expected to be settled as part of Equinor's normal operating cycle, the liability is due to be settled within 12 months after the balance sheet date, Equinor does not have the right to defer settlement of the liability more than 12 months after the balance sheet date, or if the liabilities are held for the purpose of being traded.
Gains and losses arising on the repurchase, settlement or cancellation of liabilities are recognised within Net financial items.
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 remeasured at fair value through profit and loss. The impact of commoditybased derivative financial instruments is recognised in the Consolidated statement of income as part of 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 settled, 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 current.
Contracts to buy or sell a non-financial item that can be settled net in cash or another financial instrument 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 and power are reflected in the Consolidated 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, as well as for some contracts for the purchase or sale of power.
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 are included in Gain/loss on commodity derivatives. When these derivatives are physically settled, the previously recognised unrealised gain/loss is included in Physically settled commodity derivatives. Both these elements are included as part of Revenues. The physical deliveries made 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 indexation to other markets or products will however result in the recognition of a separate derivative. In Equinor, this mainly relates to certain natural gas sales contracts where the pricing formula references power.
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. 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 21 Finance debt for fair value information of non-current bonds and bank loans.
| At 31 December 2023 | Fair value through profit |
Non-financial | Total carrying | ||
|---|---|---|---|---|---|
| (in USD million) | Note Amortised cost | or loss | assets | amount | |
| Assets | |||||
| Non-current derivative financial instruments | 559 | 559 | |||
| Non-current financial investments | 16 | 75 | 3,366 | 3,441 | |
| Prepayments and financial receivables | 16 | 341 | 950 | 1,291 | |
| Trade and other receivables | 18 | 16,193 | 740 | 16,933 | |
| Current derivative financial instruments | 1,378 | 1,378 |
| Current financial investments | 16 | 28,822 | 402 | 29,224 | |
|---|---|---|---|---|---|
| Cash and cash equivalents | 19 | 7,767 | 1,875 | 9,641 | |
| Total | 53,198 | 7,580 | 1,690 | 62,467 |
| At 31 December 2022 | Fair value | ||||
|---|---|---|---|---|---|
| (in USD million) | Note Amortised cost | through profit or loss |
Non-financial assets |
Total carrying amount |
|
| Assets | |||||
| Non-current derivative financial instruments | 691 | 691 | |||
| Non-current financial investments | 16 | 117 | 2,616 | 2,733 | |
| Prepayments and financial receivables | 16 | 1,658 | 404 | 2,063 | |
| Trade and other receivables | 18 | 21,611 | 841 | 22,452 | |
| Current derivative financial instruments | 4,039 | 4,039 | |||
| Current financial investments | 16 | 29,577 | 300 | 29,876 | |
| Cash and cash equivalents | 19 | 12,473 | 3,106 | 15,579 | |
| Total | 65,436 | 10,752 | 1,245 | 77,433 |
| At 31 December 2023 | Fair value | Total | |||
|---|---|---|---|---|---|
| (in USD million) | Note | Amortised cost |
through profit or loss |
Non-financial liabilities |
carrying amount |
| Liabilities | |||||
| Non-current finance debt | 21 | 22,230 | 22,230 | ||
| Non-current derivative financial instruments | 1,795 | 1,795 | |||
| Trade, other payables and provisions | 24 | 11,052 | 819 | 11,870 | |
| Current finance debt | 21 | 5,996 | 5,996 | ||
| Dividend payable | 2,649 | 2,649 | |||
| Current derivative financial instruments | 1,619 | 1,619 | |||
| Total | 41,927 | 3,414 | 819 | 46,159 |
| At 31 December 2022 | Fair value | Total | |||
|---|---|---|---|---|---|
| (in USD million) | Note | Amortised cost |
through profit or loss |
Non-financial liabilities |
carrying amount |
| Liabilities | |||||
| Non-current finance debt | 21 | 24,141 | 24,141 | ||
| Non-current derivative financial instruments | 2,376 | 2,376 | |||
| Trade, other payables and provisions | 24 | 12,449 | 903 | 13,352 | |
| Current finance debt | 21 | 4,359 | 4,359 | ||
| Dividend payable | 2,808 | 2,808 | |||
| Current derivative financial instruments | 4,106 | 4,106 | |||
| Total | 43,757 | 6,482 | 903 | 51,142 |
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.
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 2023 | ||||||||
| Level 1 | 1,294 | 0 | - | 6 | 0 | - | 1,300 | |
| Level 2 | 1,528 | 104 | 402 | 1,195 | 1,875 | (1,754) | (1,577) | 1,773 |
| Level 3 | 543 | 455 | 177 | (42) | (41) | 1,092 | ||
| Total fair value | 3,366 | 559 | 402 | 1,378 | 1,875 | (1,795) | (1,619) | 4,166 |
| At 31 December 2022 | ||||||||
| Level 1 | 903 | - | - | 25 | - | (60) | 868 | |
| Level 2 | 1,222 | 97 | 300 | 3,722 | 3,106 | (2,352) | (3,952) | 2,143 |
| Level 3 | 491 | 594 | 292 | (24) | (94) | 1,259 | ||
| Total fair value | 2,616 | 691 | 300 | 4,039 | 3,106 | (2,376) | (4,106) | 4,270 |
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 recognized 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 currency exchange rates as inputs to the valuation models to determine the fair value of it 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 observable forward prices with inflation. If Equinor had applied this assumption, the fair value of the contracts included would have increased by approximately USD 0.3 billion at end of 2023, while at end of 2022 the increase in fair value was approximately USD 0.5 billion.
During 2023 the financial instruments within level 3 have had a net decrease in fair value of USD 167 million, of which a loss of USD 191 million was recognised in the Consolidated statement of income, mainly due to changes in fair value of certain embedded derivatives and earn-out agreements. During 2022, the same financial instruments had a net increase in fair value of USD 416 million, of which a gain of USD 370 million was recognised in the Consolidated statement of income.
In January 2024, Equinor entered into a swap agreement with bp. Equinor will acquire bp's 50% share and take full ownership of Empire Offshore Wind Holdings LLC, including the Empire Wind lease and projects, while bp will acquire Equinor's 50% share and take full ownership of Beacon Wind Holdings LLC, including the Beacon Wind lease and projects. It is anticipated that Equinor will consolidate Empire Wind and derecognise its 50% share of Beacon Wind in the first quarter of 2024. Equinor will also acquire bp's 50% interest in the South Brooklyn Marine Terminal (SBMT) lease. The transaction, pending regulatory approvals, is anticipated to be cash neutral, with the exception of standard cash and working capital settlements and will be recognised in the REN segment.
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